PINNACLE WEST CAPITAL CORP, 10-K filed on 2/24/2021
Annual Report
v3.20.4
Cover Page - USD ($)
12 Months Ended
Dec. 31, 2020
Feb. 17, 2021
Jun. 30, 2020
Entity Information [Line Items]      
Document Type 10-K    
Document Annual Report true    
Document Period End Date Dec. 31, 2020    
Current Fiscal Year End Date --12-31    
Document Transition Report false    
Entity File Number 1-8962    
Entity Registrant Name PINNACLE WEST CAPITAL CORPORATION    
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    
Title of 12(b) Security Common Stock,No Par Value    
Trading Symbol PNW    
Security Exchange Name NYSE    
Entity Well-known Seasoned Issuer Yes    
Entity Voluntary Filers No    
Entity Current Reporting Status Yes    
Entity Interactive Data Current Yes    
Entity Filer Category Large Accelerated Filer    
Entity Small Business false    
Entity Emerging Growth Company false    
ICFR Auditor Attestation Flag true    
Entity Shell Company false    
Entity Public Float     $ 8,231,813,171
Entity Common Stock, Shares Outstanding   112,691,601  
Documents Incorporated by Reference Portions of Pinnacle West Capital Corporation’s definitive Proxy Statement relating to its Annual Meeting of Shareholders to be held on May 19, 2021 are incorporated by reference into Part III hereof.    
Entity Central Index Key 0000764622    
Amendment Flag false    
Document Fiscal Year Focus 2020    
Document Fiscal Period Focus FY    
Entity Incorporation, State or Country Code AZ    
ARIZONA PUBLIC SERVICE COMPANY      
Entity Information [Line Items]      
Document Type 10-K    
Document Period End Date Dec. 31, 2020    
Current Fiscal Year End Date --12-31    
Entity File Number 1-4473    
Entity Registrant Name ARIZONA PUBLIC SERVICE COMPANY    
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 Well-known Seasoned Issuer Yes    
Entity Voluntary Filers No    
Entity Current Reporting Status Yes    
Entity Interactive Data Current Yes    
Entity Filer Category Non-accelerated Filer    
Entity Small Business false    
Entity Emerging Growth Company false    
Entity Shell Company false    
Entity Public Float     $ 0
Entity Common Stock, Shares Outstanding   71,264,947  
Documents Incorporated by Reference Arizona Public Service Company meets the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and is therefore filing this form with the reduced disclosure format allowed under that General Instruction.    
Entity Central Index Key 0000007286    
Amendment Flag false    
Document Fiscal Year Focus 2020    
Document Fiscal Period Focus FY    
Entity Incorporation, State or Country Code AZ    
v3.20.4
CONSOLIDATED STATEMENTS OF INCOME - USD ($)
shares in Thousands, $ in Thousands
12 Months Ended
Dec. 31, 2020
Dec. 31, 2019
Dec. 31, 2018
OPERATING REVENUES (NOTE 2) $ 3,586,982 $ 3,471,209 $ 3,691,247
OPERATING EXPENSES      
Fuel and purchased power 993,419 1,042,237 1,076,116
Operations and maintenance 958,910 941,616 1,036,744
Depreciation and amortization 614,378 590,929 582,354
Taxes other than income taxes 224,835 218,579 212,849
Other expenses 7,288 5,888 9,497
Total 2,798,830 2,799,249 2,917,560
Operating loss 788,152 671,960 773,687
OTHER INCOME (DEDUCTIONS)      
Allowance for equity funds used during construction (Note 1) 33,776 31,431 52,319
Pension and other postretirement non-service credits - net (Note 8) 56,341 22,989 49,791
Other income (Note 17) 56,703 50,263 24,896
Other expense (Note 17) (57,776) (17,880) (17,966)
Total 89,044 86,803 109,040
INTEREST EXPENSE      
Interest charges 247,501 235,251 243,465
Allowance for borrowed funds used during construction (Note 1) (18,530) (18,528) (25,180)
Total 228,971 216,723 218,285
INCOME BEFORE INCOME TAXES 648,225 542,040 664,442
Income tax benefit 78,173 (15,773) 133,902
NET INCOME 570,052 557,813 530,540
Less: Net income attributable to noncontrolling interests (Note 18) 19,493 19,493 19,493
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS $ 550,559 $ 538,320 $ 511,047
Net effect of dilutive securities:      
Weighted Average common shares outstanding — basic (in shares) 112,666 112,443 112,129
Weighted Average common shares outstanding — diluted (in shares) 112,942 112,758 112,550
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING      
Net income attributable to common shareholders - basic (in dollars per share) $ 4.89 $ 4.79 $ 4.56
Net income attributable to common shareholders — diluted (in dollars per share) $ 4.87 $ 4.77 $ 4.54
ARIZONA PUBLIC SERVICE COMPANY      
OPERATING REVENUES (NOTE 2) $ 3,586,982 $ 3,471,209 $ 3,688,342
OPERATING EXPENSES      
Fuel and purchased power 993,419 1,042,237 1,094,020
Operations and maintenance 945,181 926,716 969,227
Depreciation and amortization 614,293 590,844 580,694
Taxes other than income taxes 224,790 218,540 212,136
Other expenses 7,288 5,888 2,497
Total 2,784,971 2,784,225 2,858,574
Operating loss 802,011 686,984 829,768
OTHER INCOME (DEDUCTIONS)      
Allowance for equity funds used during construction (Note 1) 33,776 31,431 52,319
Pension and other postretirement non-service credits - net (Note 8) 57,359 24,529 51,242
Other income (Note 17) 51,755 46,884 22,746
Other expense (Note 17) (53,694) (12,990) (15,292)
Total 89,196 89,854 111,015
INTEREST EXPENSE      
Interest charges 233,452 220,174 231,391
Allowance for borrowed funds used during construction (Note 1) (18,530) (18,528) (25,180)
Total 214,922 201,646 206,211
INCOME BEFORE INCOME TAXES 676,285 575,192 734,572
Income tax benefit 88,764 (9,572) 144,814
NET INCOME 587,521 584,764 589,758
Less: Net income attributable to noncontrolling interests (Note 18) 19,493 19,493 19,493
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS $ 568,028 $ 565,271 $ 570,265
v3.20.4
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($)
$ in Thousands
12 Months Ended
Dec. 31, 2020
Dec. 31, 2019
Dec. 31, 2018
NET INCOME $ 570,052 $ 557,813 $ 530,540
Derivative instruments:      
Net unrealized loss, net of tax benefit (expense) (2,089) 0 (78)
Reclassification of net realized gain, net of tax expense 592 1,137 1,527
Pension and other postretirement benefits activity, net of tax benefit (expense) (4,203) (10,525) 4,397
Total other comprehensive income (loss) (5,700) (9,388) 5,846
COMPREHENSIVE INCOME 564,352 548,425 536,386
Less: Comprehensive income attributable to noncontrolling interests 19,493 19,493 19,493
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS 544,859 528,932 516,893
ARIZONA PUBLIC SERVICE COMPANY      
NET INCOME 587,521 584,764 589,758
Derivative instruments:      
Net unrealized loss, net of tax benefit (expense) (18) 0 (78)
Reclassification of net realized gain, net of tax expense 592 1,137 1,527
Pension and other postretirement benefits activity, net of tax benefit (expense) (5,970) (9,552) 3,465
Total other comprehensive income (loss) (5,396) (8,415) 4,914
COMPREHENSIVE INCOME 582,125 576,349 594,672
Less: Comprehensive income attributable to noncontrolling interests 19,493 19,493 19,493
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS $ 562,632 $ 556,856 $ 575,179
v3.20.4
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($)
$ in Thousands
12 Months Ended
Dec. 31, 2020
Dec. 31, 2019
Dec. 31, 2018
Net unrealized loss, tax benefit (expense) $ 662 $ 0 $ (78)
Reclassification of net realized gain, tax expense 171 375 473
Pension and other postretirement benefits activity, tax benefit (expense) 1,371 3,452 (1,585)
ARIZONA PUBLIC SERVICE COMPANY      
Net unrealized loss, tax benefit (expense) (18) 0 (78)
Reclassification of net realized gain, tax expense (171) (375) (473)
Pension and other postretirement benefits activity, tax benefit (expense) $ 1,955 $ 3,136 $ (1,159)
v3.20.4
CONSOLIDATED BALANCE SHEETS - USD ($)
$ in Thousands
Dec. 31, 2020
Dec. 31, 2019
CURRENT ASSETS    
Cash and cash equivalents $ 59,968 $ 10,283
Customer and other receivables 313,576 266,426
Accrued unbilled revenues 132,197 128,165
Allowance for doubtful accounts (19,782) (8,171)
Materials and supplies (at average cost) 314,745 331,091
Fossil fuel (at average cost) 19,552 14,829
Income tax receivable (Note 5) 6,792 21,727
Assets from risk management activities (Note 16) 2,931 515
Deferred fuel and purchased power regulatory asset (Note 4) 175,835 70,137
Other regulatory assets (Note 4) 115,878 133,070
Other current assets 76,627 61,958
Total current assets 1,198,319 1,030,030
INVESTMENTS AND OTHER ASSETS    
Nuclear decommissioning trust (Notes 13 and 19) 1,138,435 1,010,775
Other special use funds (Notes 13 and 19) 254,509 245,095
Other assets 92,922 96,953
Total investments and other assets 1,485,866 1,352,823
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 7 and 10)    
Plant in service and held for future use 20,837,885 19,836,292
Accumulated depreciation and amortization (7,110,310) (6,637,857)
Net 13,727,575 13,198,435
Construction work in progress 937,384 808,133
Palo Verde sale leaseback, net of accumulated depreciation 98,036 101,906
Intangible assets, net of accumulated amortization 282,570 290,564
Nuclear fuel, net of accumulated amortization 113,645 123,500
Total property, plant and equipment 15,159,210 14,522,538
DEFERRED DEBITS    
Regulatory assets (Notes 1, 4 and 5) 1,133,987 1,304,073
Operating lease right-of-use assets (Note 9) 505,064 145,813
Assets for pension and other postretirement benefits (Note 8) 502,992 90,570
Other 34,983 33,400
Total deferred debits 2,177,026 1,573,856
Total Assets 20,020,421 18,479,247
CURRENT LIABILITIES    
Accounts payable 318,585 346,448
Accrued taxes 159,551 144,899
Accrued interest 56,962 53,534
Common dividends payable 93,531 87,982
Short-term borrowings (Note 6) 169,000 114,675
Current maturities of long-term debt (Note 7) 0 800,000
Customer deposits 48,340 64,908
Liabilities from risk management activities (Note 16) 7,557 38,946
Liabilities for asset retirements (Note 12) 15,586 11,025
Operating lease liabilities (Note 9) 74,785 12,713
Regulatory liabilities (Note 4) 229,088 234,912
Other current liabilities 187,448 168,323
Total current liabilities 1,360,433 2,078,365
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 7) 6,314,266 4,832,558
DEFERRED CREDITS AND OTHER    
Deferred income taxes (Note 5) 2,135,403 1,992,339
Regulatory liabilities (Notes 1, 4, 5 and 8) 2,450,169 2,267,835
Liabilities for asset retirements (Note 12) 689,497 646,193
Liabilities for pension benefits (Note 8) 166,484 280,185
Liabilities from risk management activities (Note 16) 11,062 33,186
Customer advances 221,032 215,330
Coal mine reclamation 170,097 165,695
Deferred investment tax credit 191,372 196,468
Unrecognized tax benefits (Note 5) 5,834 6,189
Operating lease liabilities (Note 9) 361,336 51,872
Other 190,643 159,844
Total deferred credits and other 6,592,929 6,015,136
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
EQUITY    
Common stock, no par value; authorized 150,000,000 shares, 112,760,051 and 112,540,126 issued at respective dates 2,677,482 2,659,561
Treasury stock at cost; 72,006 shares at end of 2020 and 103,546 shares at end of 2019 (6,289) (9,427)
Total common stock 2,671,193 2,650,134
Retained earnings 3,025,106 2,837,610
Accumulated other comprehensive loss (62,796) (57,096)
Total shareholders’ equity 5,633,503 5,430,648
Noncontrolling interests (Note 18) 119,290 122,540
Total equity 5,752,793 5,553,188
Total Liabilities and Equity 20,020,421 18,479,247
ARIZONA PUBLIC SERVICE COMPANY    
CURRENT ASSETS    
Cash and cash equivalents 57,310 10,169
Customer and other receivables 312,644 255,479
Accrued unbilled revenues 132,197 128,165
Allowance for doubtful accounts (19,782) (8,171)
Materials and supplies (at average cost) 314,745 331,091
Fossil fuel (at average cost) 19,552 14,829
Income tax receivable (Note 5) 0 7,313
Assets from risk management activities (Note 16) 2,931 515
Deferred fuel and purchased power regulatory asset (Note 4) 175,835 70,137
Other regulatory assets (Note 4) 115,878 133,070
Other current assets 47,593 38,895
Total current assets 1,158,903 981,492
INVESTMENTS AND OTHER ASSETS    
Nuclear decommissioning trust (Notes 13 and 19) 1,138,435 1,010,775
Other special use funds (Notes 13 and 19) 254,509 245,095
Other assets 46,010 43,781
Total investments and other assets 1,438,954 1,299,651
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 7 and 10)    
Plant in service and held for future use 20,834,424 19,832,805
Accumulated depreciation and amortization (7,107,058) (6,634,597)
Net 13,727,366 13,198,208
Construction work in progress 937,384 808,133
Palo Verde sale leaseback, net of accumulated depreciation 98,036 101,906
Intangible assets, net of accumulated amortization 282,415 290,409
Nuclear fuel, net of accumulated amortization 113,645 123,500
Total property, plant and equipment 15,158,846 14,522,156
DEFERRED DEBITS    
Regulatory assets (Notes 1, 4 and 5) 1,133,987 1,304,073
Operating lease right-of-use assets (Note 9) 503,475 144,024
Assets for pension and other postretirement benefits (Note 8) 495,673 86,736
Other 34,413 32,591
Total deferred debits 2,167,548 1,567,424
Total Assets 19,924,251 18,370,723
CURRENT LIABILITIES    
Accounts payable 311,699 338,006
Accrued taxes 148,970 136,328
Accrued interest 56,322 52,619
Common dividends payable 93,500 88,000
Current maturities of long-term debt (Note 7) 0 350,000
Customer deposits 48,340 64,908
Liabilities from risk management activities (Note 16) 7,557 38,946
Liabilities for asset retirements (Note 12) 15,586 11,025
Operating lease liabilities (Note 9) 74,695 12,549
Regulatory liabilities (Note 4) 229,088 234,912
Other current liabilities 190,420 164,736
Total current liabilities 1,176,177 1,492,029
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 7) 5,817,945 4,833,133
DEFERRED CREDITS AND OTHER    
Deferred income taxes (Note 5) 2,143,673 2,033,096
Regulatory liabilities (Notes 1, 4, 5 and 8) 2,450,169 2,267,835
Liabilities for asset retirements (Note 12) 689,497 646,193
Liabilities for pension benefits (Note 8) 148,943 262,243
Liabilities from risk management activities (Note 16) 11,062 33,186
Customer advances 221,032 215,330
Coal mine reclamation 170,097 165,695
Deferred investment tax credit 191,372 196,468
Unrecognized tax benefits (Note 5) 39,410 40,188
Operating lease liabilities (Note 9) 359,653 50,092
Other 160,036 136,432
Total deferred credits and other 6,584,944 6,046,758
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
EQUITY    
Common stock 178,162 178,162
Additional paid-in capital 2,871,696 2,721,696
Retained earnings 3,216,955 3,011,927
Accumulated other comprehensive loss (40,918) (35,522)
Total shareholders’ equity 6,225,895 5,876,263
Noncontrolling interests (Note 18) 119,290 122,540
Total equity 6,345,185 5,998,803
Total capitalization 12,163,130 10,831,936
Total Liabilities and Equity $ 19,924,251 $ 18,370,723
v3.20.4
CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($)
$ in Thousands
Dec. 31, 2020
Dec. 31, 2019
PROPERTY, PLANT AND EQUIPMENT    
Accumulated depreciation of Palo Verde sale leaseback $ 253,014 $ 249,144
Accumulated amortization on intangible assets 698,500 647,276
Accumulated amortization on nuclear fuel $ 137,207 $ 137,330
EQUITY    
Common stock, authorized shares (in shares) 150,000,000 150,000,000
Common stock, issued shares (in shares) 112,760,051 112,540,126
Treasury stock at cost, shares (in shares) 72,006 103,546
ARIZONA PUBLIC SERVICE COMPANY    
PROPERTY, PLANT AND EQUIPMENT    
Accumulated depreciation of Palo Verde sale leaseback $ 253,014 $ 249,144
Accumulated amortization on intangible assets 697,366 646,142
Accumulated amortization on nuclear fuel $ 137,207 $ 137,330
v3.20.4
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)
$ in Thousands
12 Months Ended
Dec. 31, 2020
Dec. 31, 2019
Dec. 31, 2018
CASH FLOWS FROM OPERATING ACTIVITIES      
Net income $ 570,052 $ 557,813 $ 530,540
Adjustments to reconcile net income to net cash provided by operating activities:      
Depreciation and amortization including nuclear fuel 686,253 664,140 650,955
Deferred fuel and purchased power (93,651) (82,481) (78,277)
Deferred fuel and purchased power amortization (12,047) 49,508 116,750
Allowance for equity funds used during construction (33,776) (31,431) (52,319)
Deferred income taxes 69,469 (1,479) 117,355
Deferred investment tax credit (5,096) (3,938) (5,170)
Stock compensation 18,292 18,376 19,547
Changes in current assets and liabilities:      
Customer and other receivables (18,191) (12,789) 37,530
Accrued unbilled revenues (4,032) 9,005 (24,736)
Materials, supplies and fossil fuel 11,623 (51,826) (6,103)
Income tax receivable 14,935 (21,727) 0
Other current assets (30,640) (3,507) 33,844
Accounts payable (6,059) 50,641 (14,602)
Accrued taxes 14,652 (9,920) 6,597
Other current liabilities 22,520 (84,651) 28,174
Change in margin and collateral accounts — assets 404 (247) 143
Change in margin and collateral accounts — liabilities 100 (125) (2,211)
Change in unrecognized tax benefits 2,220 2,704 (1,235)
Change in long-term regulatory liabilities 13,017 124,221 (109,284)
Change in other long-term assets (67,453) (82,895) 78,604
Change in other long-term liabilities (186,227) (132,666) (48,958)
Net cash flow provided by operating activities 966,365 956,726 1,277,144
CASH FLOWS FROM INVESTING ACTIVITIES      
Capital expenditures (1,326,584) (1,191,447) (1,178,169)
Contributions in aid of construction 62,503 70,693 27,716
Allowance for borrowed funds used during construction (18,530) (18,528) (25,180)
Proceeds from nuclear decommissioning trust sales and other special use funds 819,518 719,034 653,033
Investment in nuclear decommissioning trust and other special use funds (822,608) (722,181) (672,165)
Other 7,883 11,452 1,941
Net cash flow used for investing activities (1,277,818) (1,130,977) (1,192,824)
CASH FLOWS FROM FINANCING ACTIVITIES      
Issuance of long-term debt 1,596,672 1,092,188 445,245
Repayment of long-term debt (915,150) (600,000) (182,000)
Short-term borrowings and (repayments) — net 73,325 54,275 (7,000)
Short-term debt borrowings under revolving credit facility 751,690 49,000 45,000
Short-term debt repayments under revolving credit facility (770,690) (65,000) (57,000)
Dividends paid on common stock (350,577) (329,643) (308,892)
Common stock equity issuance and purchases — net (1,389) 692 (5,055)
Distributions to noncontrolling interests (22,743) (22,744) (22,744)
Net cash flow provided by (used for) financing activities 361,138 178,768 (92,446)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 49,685 4,517 (8,126)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 10,283 5,766 13,892
CASH AND CASH EQUIVALENTS AT END OF YEAR 59,968 10,283 5,766
ARIZONA PUBLIC SERVICE COMPANY      
CASH FLOWS FROM OPERATING ACTIVITIES      
Net income 587,521 584,764 589,758
Adjustments to reconcile net income to net cash provided by operating activities:      
Depreciation and amortization including nuclear fuel 686,168 664,055 649,295
Deferred fuel and purchased power (93,651) (82,481) (78,277)
Deferred fuel and purchased power amortization (12,047) 49,508 116,750
Allowance for equity funds used during construction (33,776) (31,431) (52,319)
Deferred income taxes 36,462 48,367 59,927
Deferred investment tax credit (5,096) (3,938) (5,170)
Changes in current assets and liabilities:      
Customer and other receivables (28,206) (12,075) 35,406
Accrued unbilled revenues (4,032) 9,005 (24,736)
Materials, supplies and fossil fuel 11,623 (51,826) (6,206)
Income tax receivable 7,313 (7,313) 0
Other current assets (24,669) (1,461) 31,707
Accounts payable (4,503) 53,258 (15,608)
Accrued taxes 12,642 (40,029) 19,008
Other current liabilities 29,587 (82,138) 25,070
Change in margin and collateral accounts — assets 404 (247) 143
Change in margin and collateral accounts — liabilities 100 (125) (2,211)
Change in unrecognized tax benefits 2,220 2,704 (1,235)
Change in long-term regulatory liabilities 13,017 124,221 (109,284)
Change in other long-term assets (65,139) (85,725) 77,952
Change in other long-term liabilities (186,871) (129,682) (55,169)
Net cash flow provided by operating activities 929,067 1,007,411 1,254,801
CASH FLOWS FROM INVESTING ACTIVITIES      
Capital expenditures (1,326,584) (1,191,447) (1,169,061)
Contributions in aid of construction 62,503 70,693 27,716
Allowance for borrowed funds used during construction (18,530) (18,528) (25,180)
Proceeds from nuclear decommissioning trust sales and other special use funds 819,518 719,034 653,033
Investment in nuclear decommissioning trust and other special use funds (822,608) (722,181) (672,165)
Other (554) 6,336 (1,789)
Net cash flow used for investing activities (1,286,255) (1,136,093) (1,187,446)
CASH FLOWS FROM FINANCING ACTIVITIES      
Issuance of long-term debt 1,099,722 1,092,188 295,245
Repayment of long-term debt (465,150) (600,000) (182,000)
Short-term debt borrowings under revolving credit facility 540,000 0 25,000
Short-term debt repayments under revolving credit facility (540,000) 0 (25,000)
Dividends paid on common stock (357,500) (336,300) (316,000)
Equity infusion from Pinnacle West 150,000 0 150,000
Distributions to noncontrolling interests (22,743) (22,744) (22,744)
Net cash flow provided by (used for) financing activities 404,329 133,144 (75,499)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 47,141 4,462 (8,144)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 10,169 5,707 13,851
CASH AND CASH EQUIVALENTS AT END OF YEAR $ 57,310 $ 10,169 $ 5,707
v3.20.4
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 (in shares) at Dec. 31, 2017   111,816,170 64,463         71,264,947        
Beginning 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
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 (in shares)   343,726                    
Issuance of common stock 19,460 $ 19,460                    
Purchase of treasury stock (in shares) [1]     (129,903)                  
Purchase of treasury stock [1] (10,338)   $ (10,338)                  
Reissuance of treasury stock for stock-based compensation and other (in shares)     136,231                  
Reissuance of treasury stock for stock-based compensation and other 11,137   $ 11,137                  
Equity infusion from Pinnacle West             150,000   150,000      
Reclassification of income tax effects related to new tax reform 0 [2]     8,552 [2] (8,552) [2]   0 [3]     5,038 [3] (5,038) [3]  
Capital activities by noncontrolling interests (22,743)         (22,743) (22,743)         (22,743)
Ending balance (in shares) at Dec. 31, 2018   112,159,896 58,135         71,264,947        
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
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 (in shares)   380,230                    
Issuance of common stock 25,296 $ 25,296                    
Purchase of treasury stock (in shares) [1]     (121,493)                  
Purchase of treasury stock [1] (11,202)   $ (11,202)                  
Reissuance of treasury stock for stock-based compensation and other (in shares)     76,082                  
Reissuance of treasury stock for stock-based compensation and other 6,600   $ 6,600                  
Capital activities by noncontrolling interests $ (22,743)         (22,743) (22,743)         (22,743)
Ending balance (in shares) at Dec. 31, 2019 112,540,126 112,540,126 103,546         71,264,947        
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
Increase (Decrease) in Shareholders' Equity                        
Net income 570,052     550,559   19,493 587,521     568,028   19,493
Other comprehensive income (loss) (5,700)       (5,700)   (5,396)       (5,396)  
Dividends on common stock (363,063)     (363,063)     (363,000)     (363,000)    
Issuance of common stock (in shares)   219,925                    
Issuance of common stock 17,921 $ 17,921                    
Purchase of treasury stock (in shares) [1]     (81,256)                  
Purchase of treasury stock [1] (7,181)   $ (7,181)                  
Reissuance of treasury stock for stock-based compensation and other (in shares)     112,796                  
Reissuance of treasury stock for stock-based compensation and other 10,319   $ 10,319                  
Equity infusion from Pinnacle West             150,000   150,000      
Capital activities by noncontrolling interests $ (22,743)         (22,743) (22,743)         (22,743)
Ending balance (in shares) at Dec. 31, 2020 112,760,051 112,760,051 72,006         71,264,947        
Ending balance at Dec. 31, 2020 $ 5,752,793 $ 2,677,482 $ (6,289) $ 3,025,106 $ (62,796) $ 119,290 $ 6,345,185 $ 178,162 $ 2,871,696 $ 3,216,955 $ (40,918) $ 119,290
[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.
v3.20.4
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Parenthetical) - $ / shares
12 Months Ended
Dec. 31, 2020
Dec. 31, 2019
Dec. 31, 2018
Statement of Stockholders' Equity [Abstract]      
Dividends declared per common share (in dollars per share) $ 3.23 $ 3.04 $ 2.87
v3.20.4
Summary of Significant Accounting Policies
12 Months Ended
Dec. 31, 2020
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 18 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
 
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 accounts receivable and accrued unbilled revenues that will ultimately be uncollectible due to credit loss risk. The allowance includes a write-off component that is calculated by applying an estimated write-off factor to retail electric revenues. The write-off factor used to estimate uncollectible accounts is based upon consideration of historical collections experience, the current and forecasted economic environment, changes to our collection policies, and management’s best estimate of future collections success. (See Note 2.)
 
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, 2020 and 2019 Consolidated Balance Sheets is composed of the following (dollars in thousands):

Property, Plant and Equipment:20202019
Generation$9,199,012 $8,916,872 
Transmission3,290,477 3,095,907 
Distribution7,107,007 6,690,697 
General plant1,241,389 1,132,816 
Plant in service and held for future use
20,837,885 19,836,292 
Accumulated depreciation and amortization(7,110,310)(6,637,857)
Net
13,727,575 13,198,435 
Construction work in progress937,384 808,133 
Palo Verde sale leaseback, net of accumulated depreciation98,036 101,906 
Intangible assets, net of accumulated amortization282,570 290,564 
Nuclear fuel, net of accumulated amortization113,645 123,500 
Total property, plant and equipment$15,159,210 $14,522,538 

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, 2020 were as follows:
Fossil plant — 17 years;
Nuclear plant — 20 years;
Other generation — 20 years;
Transmission — 38 years;
Distribution — 34 years; and
General plant — 7 years.
 
Depreciation of utility property, plant and equipment is computed on a straight-line, remaining-life basis. Depreciation expense was $553 million in 2020, $522 million in 2019, and $486 million in 2018. For the years 2018 through 2020, the depreciation rates ranged from a low of 0.18% to a high of 32.43%.  The weighted-average depreciation rate was 2.84% in 2020, 2.81% in 2019, and 2.81% in 2018.

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 6.72% for 2020, 6.98% for 2019, and 7.03% for 2018.  APS compounds AFUDC semi-annually and ceases to accrue AFUDC when construction work is completed and the property is placed in service.

On June 30, 2020, the United States Federal Energy Regulatory Commission (“FERC”) issued an order granting a waiver request related to the existing Allowance for Funds Used During Construction (“AFUDC”) rate calculation beginning March 1, 2020 through February 28, 2021.  The order provides a simplified approach that companies may elect to implement in order to minimize the significant distorted effect on the AFUDC formula resulting from increased short-term debt financing during the COVID-19 pandemic.  APS has adopted this simplified approach to computing the AFUDC composite rate by using a simple average of the actual historical short-term debt balances for 2019, instead of current period short-term debt balances, and has left all other aspects of the AFUDC formula composite rate calculation unchanged. This change impacts the AFUDC composite rate in 2020 but does not impact prior years.  Furthermore, the change in the composite rate calculation does not impact our accounting treatment for these costs. The change did not have a material impact on our financial statements.
 
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 13 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 natural gas.  The changes in market value of such contracts have a high correlation to price changes in the hedged transactions.  We also enter into derivative instruments for economic hedging purposes.  Contracts that have the same terms (quantities, delivery points and delivery periods) and for which power does not flow are netted, which reduces both revenues and fuel and purchased power expenses in our Consolidated Statements of Income, but does not impact our financial condition, net income or cash flows.
 
We account for our derivative contracts in accordance with derivatives and hedging guidance, which requires all derivatives not qualifying for a scope exception to be measured at fair value on the balance sheet as either assets or liabilities.  Transactions with counterparties that have master netting arrangements are reported net on the balance sheet.  (See Note 16 for additional information about our derivative instruments.)
 
Loss Contingencies and Environmental Liabilities
 
Pinnacle West and APS are involved in certain legal and environmental matters that arise in the normal course of business.  Contingent losses and environmental liabilities are recorded when it is determined that it is probable that a loss has occurred and the amount of the loss can be reasonably estimated.  When a range of the probable loss exists and no amount within the range is a better estimate than any other amount, Pinnacle West and APS record a loss contingency at the minimum amount in the range.  Unless otherwise required by GAAP, legal fees are expensed as incurred.
 
Retirement Plans and Other Postretirement Benefits
 
Pinnacle West sponsors a qualified defined benefit and account balance pension plan for the employees of Pinnacle West and its subsidiaries, in addition to a non-qualified pension plan.  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 for interim storage, we now accrue a receivable and an offsetting regulatory liability through the settlement period ending December of 2022. (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,
 202020192018
Cash paid (received) during the period for:   
Income taxes, net of refunds$(3,019)$12,535 $21,173 
Interest, net of amounts capitalized216,951 218,664 208,479 
Significant non-cash investing and financing activities:   
Accrued capital expenditures$113,502 $141,297 $132,620 
Dividends declared but not paid93,531 87,982 82,675 
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,
 202020192018
Cash paid (received) during the period for:   
Income taxes, net of refunds$41,176 $(15,042)$77,942 
Interest, net of amounts capitalized206,328 204,261 196,419 
Significant non-cash investing and financing activities:   
Accrued capital expenditures$113,502 $141,297 $132,620 
Dividends declared but not paid93,500 88,000 82,700 

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 $70 million in 2020, $66 million in 2019, and $68 million in 2018.  Estimated amortization expense on existing intangible assets over the next five years is $68 million in 2021, $56 million in 2022, $48 million in 2023, $33 million in 2024, and $25 million in 2025.  At December 31, 2020, the weighted-average remaining amortization period for intangible assets was 7 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 accounts and active union employee medical account, are accounted for in accordance with guidance on accounting for investments in debt and equity securities. (See Notes 13 and 19 for more information on these investments.)

Leases

We determine if an agreement is a lease at contract inception. A lease is defined as a contract, or part of a contract, that conveys the right to control the use of an identified asset for a period of time in exchange for consideration. To control the use of an identified asset an entity must have both a right to obtain substantially all of the benefits from the use of the asset and the right to direct the use of the asset. If we determine an agreement is a lease, and we are the lessee, we recognize a right-of-use lease asset and a lease liability at the lease commencement date. Lease liabilities are recognized based on the present value
of the fixed lease payments over the lease term. To present value lease liabilities we use the implicit rate in the lease if the information is readily available, otherwise we use our incremental borrowing rate determined at lease commencement. Our incremental borrowing rate is based on the rate of interest we would have to borrow on a collateralized basis over a similar term an amount equal to the lease payments in a similar economic environment. When measuring right-of-use assets and lease liabilities we exclude variable lease payments, other than those that depend on an index or rate or are in-substance fixed payments. For short-term leases with terms of 12 months or less, we do not recognize a right-of-use lease asset or lease liability. We recognize operating lease expense using a straight-line pattern over the periods of use.

APS enters into purchased power contracts that may contain leases. This occurs when a purchased power agreement designates a specific power plant, APS obtains substantially all of the economic benefits from the use of the plant and has the right to direct the use of the plant. Lease costs relating to purchased power lease contracts are reported in fuel and purchased power on the Consolidated Statements of Income, and are subject to recovery under the PSA or RES (see Note 4). We also may enter into lease agreements related to vehicles, office space, land, and other equipment. (See Note 9 for information on our lease agreements.)

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, 2020, 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.
v3.20.4
Revenue
12 Months Ended
Dec. 31, 2020
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,Year Ended December 31,
202020192018
Retail Electric Service
Residential$1,929,178 (a)$1,761,122 $1,867,370 
Non-Residential1,486,098 1,509,514 1,628,891 
Wholesale Energy Sales93,345 121,805 109,198 
Transmission Services for Others65,859 62,460 60,261 
Other Sources12,502 16,308 25,527 
Total Operating Revenues$3,586,982 $3,471,209 $3,691,247 

(a) Residential revenues for the year ended December 31, 2020 reflect a $24 million reduction related to the Arizona Attorney General matter. (See Note 11).

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. See “Allowance for Doubtful Accounts” discussion below for additional details regarding payment terms.

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 into the wholesale markets generation 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, 2020, 2019 and 2018 were $3,533 million, $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, 2020, 2019 and 2018, our revenues that do not qualify as revenue from contracts with customers were $54 million, $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, 2020 and 2019.

Allowance for Doubtful Accounts

On March 13, 2020, due to the COVID-19 pandemic we voluntarily suspended disconnections of customers for nonpayment. The suspension of customer disconnections was extended from March 13, 2020 through December 31, 2020. Our disconnection policies are also impacted by the Summer Disconnection Moratorium. The suspension of disconnection of customers for nonpayment ended on January 1, 2021 and certain customers with past due balances were placed on eight-month payment arrangements. These circumstances and the on-going COVID-19 pandemic have impacted our allowance for doubtful accounts including our write-off factor. We continue to monitor the impacts of COVID-19, our disconnection policies, payment arrangements, among other considerations impacting our estimated write-off factor and allowance for doubtful accounts. (See Note 1 for our accounting policies on allowance for doubtful accounts. See Note 4 for additional discussion on the COVID-19 pandemic and the Summer Disconnection Moratorium.)

The following table provides a rollforward of Pinnacle West’s allowance for doubtful accounts all of which primarily relates to APS (dollars in thousands):
Year Ended December 31, 2020Year Ended December 31, 2019Year Ended December 31, 2018
Allowance for doubtful accounts, balance at beginning of period$8,171 $4,069 $2,513 
Bad debt expense20,633 11,819 10,870 
Actual write-offs(9,022)(7,717)(9,314)
Allowance for doubtful accounts, balance at end of period$19,782 $8,171 $4,069 
v3.20.4
New Accounting Standards
12 Months Ended
Dec. 31, 2020
Accounting Standards Update and Change in Accounting Principle [Abstract]  
New Accounting Standards New Accounting Standards
 
Standards 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 and resulted in additional disclosures, these changes did not have a material impact on our financial statements. (See Note 2 for allowance for doubtful accounts related credit loss disclosures.)

ASU 2018-14, Retirement Benefits: Changes to the Disclosure Requirements for Defined Benefit Plans

In August 2018, a new accounting standard was issued that amends certain disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. The amendments remove disclosures that are no longer considered beneficial, clarifies specific disclosure requirements and adds new disclosure requirements relating to defined benefit plans. The new standard is effective for fiscal years ending after December 15, 2020. We adopted and implemented the standard on a retrospective basis in our financial statements for the year ended December 31, 2020. While the adoption of this guidance modified the disclosure requirements relating to defined benefit plans, these changes did not have a material impact on our financial statements. (See Note 8 for Retirement Plans and Other Postretirement Benefits disclosure.)
v3.20.4
Regulatory Matters
12 Months Ended
Dec. 31, 2020
Regulated Operations [Abstract]  
Regulatory Matters Regulatory Matters
COVID-19 Pandemic

Due to the COVID-19 pandemic, APS voluntarily suspended disconnections of customers for nonpayment beginning March 13, 2020.  In addition, APS waived all late payment fees during this suspension period.  On September 14, 2020, APS extended this suspension of disconnection of customers for nonpayment and waiver of late payment fees until December 31, 2020. The suspension of disconnection of customers for nonpayment ended on January 1, 2021 and customers were automatically placed on eight-month payment arrangements if they had past due balances at the end of the disconnection period of $75 or greater. APS will continue to waive late payment fees until October 15, 2021. APS has experienced and is continuing to experience an increase in bad debt expense associated with the COVID-19 pandemic. The Summer Disconnection Moratorium (see below for discussion of the Summer Disconnection Moratorium), the suspension of disconnections during the COVID-19 pandemic and the increased bad debt expense associated with both events resulted in a negative impact to its 2020 operating results of approximately $23 million pre-tax above the impact of disconnections on its operating results for years that did not have the Summer Disconnection Moratorium or COVID-19 pandemic. Additionally, due to COVID-19, APS delayed the reset of the EIS adjustor and suspended the discontinuation of TEAM Phase II to the first billing cycle in May 2020 rather than April 2020 and also delayed the reset of the PSA to the first billing cycle of April 2021 rather than February 2021 (see below for discussion of EIS, TEAM Phase II and PSA).

On April 17, 2020, APS filed an application with the ACC requesting a COVID-19 emergency relief package to provide additional assistance to its customers. On May 5, 2020, the ACC approved APS returning $36 million that had been collected through the DSM Adjustor Charge, but not allocated for current DSM programs, directly to customers through a bill credit in June 2020. As of December 31, 2020, APS had refunded approximately $43 million to customers. The additional $7 million over the approved amount of $36 million was the result of the kWh credit being based on historic consumption, which was different than actual consumption in the refund period. This difference was recorded to the DSM balancing account and will be addressed in subsequent DSM filings (see below for discussion of the DSM Adjustor Charge).

APS has spent more than $15 million to assist customers and local non-profits and community organizations to help with the impact of the COVID-19 pandemic, with $12.4 million of these dollars directly committed to bill assistance programs (the “COVID Customer Support Fund”). The COVID Customer Support Fund was comprised of a series of voluntary commitments of funds that are not recoverable through rates throughout 2020 of approximately $8.8 million. An additional $3.6 million in bill credits for limited income customers was ordered by the ACC in December 2020 of which 50%, up to a maximum of $2.5 million, was committed to be funds that are not recoverable through rates with the remaining being deferred for potential future recovery in rates. Included in the COVID Customer Support Fund were programs that assisted customers that had a delinquency of two or more months with a one-time credit of $100, an expanded credit of $300 for limited income customers, programs to assist extra small and small non-residential customers with a one-time credit of $1,000, and other targeted programs allocated to assist with other COVID-19 needs in support of utility bill assistance. The December 2020 ACC order further assisted delinquent limited income customers with an additional bill credit of up to $250 or their delinquent balance, whichever was less. As of December 31, 2020, APS had distributed all funds for all COVID Customer Support Fund programs combined. Beyond the COVID Customer Support Fund, APS
has also provided $2.7 million to assist local non-profits and community organizations working to mitigate the impacts of the COVID-19 pandemic.

2019 Retail Rate Case Filing with the Arizona Corporation Commission

In accordance with the requirements of the 2019 rate review order described below, APS filed an application with the ACC on October 31, 2019 seeking 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 annual 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 were:
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;
a rate of $0.030168 per kWh for the portion of APS’s retail base rates attributable to fuel and purchased power costs (“Base Fuel Rate”);
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. 
On October 2, 2020, the ACC Staff, the Residential Utility Consumer Office (“RUCO”) and other intervenors filed their initial written testimony with the ACC in this rate case. The ACC Staff recommends, among other things, a (i) $89.7 million revenue increase, (ii) average annual customer bill increase of 2.7%, (iii) return on equity of 9.4%, (iv) a 0.3% or, as an alternative, a 0% return on the increment of fair value rate base greater than original cost, (v) recovery of the deferral and rate base effects of the construction and operating costs of the Four Corners SCR project and (vi) recovery of the rate base effects of the construction and ongoing consideration of the deferral of the Ocotillo modernization project. RUCO recommends, among other things, a (i) $20.8 million revenue decrease, (ii) average annual customer bill decrease of 0.63%, (iii) return on equity of 8.74%, (iv) a 0% return on the increment of fair value rate base, (v) nonrecovery of the deferral and rate base effects of the construction and operating costs of the Four Corners SCR project pending further consideration, and (vi) recovery of the deferral and rate base effects of the construction and operating costs of the Ocotillo modernization project.

The filed ACC Staff and intervenor testimony include additional recommendations, some of which materially differ from APS’s filed application. On November 6, 2020, APS filed its rebuttal testimony and the principal provisions which differ from its initial application include, among other things, a (i) $169 million revenue increase, (ii) average annual bill increase of 5.14%, (iii) return on equity of 10%, (iv) return on the increment of fair value rate base of 0.8%, (v) new cost recovery adjustor mechanism, the Advanced Energy Mechanism (“AEM”), to enable more timely recovery of clean investments as APS pursues its clean energy commitment, (vi) recognition that securitization is a potentially useful financing tool to recover the remaining book value of retiring assets and effectuate a transition to a cleaner energy future that APS intends to pursue, provided legislative hurdles are addressed, and (vii) a Coal Community Transition (“CCT”) plan related to the closure or future closure of coal-fired generation facilities, of which $25 million would be funds that are not recoverable through rates with a proposal that the remainder be funded by customers over 10 years.

The CCT plan includes the following proposed components: (i) $100 million that will be paid over 10 years to the Navajo Nation for a sustainable transition to a post-coal economy, which would be funded by customers, (ii) $1.25 million that will be paid over five years to the Navajo Nation to fund an economic development organization, which would be funds not recoverable through rates, (iii) $10 million to facilitate electrification projects within the Navajo Nation, which would be funded equally by funds not recoverable through rates and by customers, (iv) $2.5 million per year in transmission revenue sharing to be paid to the Navajo Nation beginning after the closure of the Four Corners Power Plant through 2038, which would be funds not recoverable through rates, (v) $12 million that will be paid over five years to the Navajo County Communities surrounding Cholla Power Plant, which would primarily be funded by customers, and (vi) $3.7 million that will be paid over five years to the Hopi Tribe related to APS’s ownership interests in the Navajo Generating Station, which would primarily be funded by customers. The commitment of funds that would not be recoverable through rates of $25 million were recognized in our December 31, 2020 financials.

The hearing began January 14, 2021. Unfavorable ACC Staff and intervenor positions and recommendations could have a material impact on APS’s financial statements if ultimately adopted by the ACC. APS cannot predict the outcome of this proceeding.
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 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”). The Complaint was later amended alleging that the rates and charges in the 2017 Rate Case Decision are not just and reasonable. The ACC held a hearing on this matter, and the Administrative Law Judge issued a Recommended Opinion and Order recommending that the Complaint be dismissed. 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 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.

See “Rate Plan Comparison Tool and Investigation” below for information regarding a review and investigation pertaining to the rate plan comparison tool offered to APS customers and other related issues.

ACC Review of APS 2017 Rate Case Decision

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. 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 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 filed its rate case on October 31, 2019 (see “2019 Retail Rate Case Filing with the Arizona Corporation Commission” above for more information). APS does not believe that the implementation of the other key provisions of the amended order regarding the rate review will have a material impact on its financial position, results of operations or cash flows.

On May 19, 2020, the ACC Staff filed a third-party consultant’s report which evaluated the effectiveness of APS’s customer outreach and education program related to the 2017 Rate Case Decision. On May 29, 2020, the Chairman of the ACC filed a letter with the ACC in response to this report and is alleging that APS is out of compliance with the 2017 Rate Case Decision and is over-earning. The Chairman proposed that the current rates should be classified as interim rates and customers held harmless if APS’s activities have caused the rates set in the 2017 Rate Case Decision to not be just and reasonable. Also, on May 29, 2020, a second commissioner filed a letter with the ACC agreeing with the Chairman’s assertions and further asserting that the 2017 Rate Case Decision should be re-opened. On June 18, 2020, at an ACC Open Meeting, the matters raised in these letters were discussed. The ACC did not vote to move forward with any adjustments to APS’s current rates. APS is monitoring this matter, but believes that the proposals are not legal and further that APS has not over-earned. The ACC voted to administratively close this docket on November 4, 2020. 

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 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 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. On September 23, 2020, the ACC approved the 2020 RES Implementation Plan including a waiver of the residential distributed energy requirements for the 2020 implementation year. In addition, the ACC approved the implementation of a new pilot program that incentivizes Arizona households to install at-home battery systems. Recovery of the costs associated with the pilot will be addressed in the 2021 DSM Plan.

On July 1, 2020, APS filed its 2021 RES Implementation Plan and proposed a budget of approximately $84.7 million. APS’s budget request supports existing approved projects and commitments and requests a permanent waiver of the residential distributed energy requirement for 2021 contained in the RES rules. In the 2021 RES Implementation Plan, APS requests $4.5 million to meet revenue requirements associated with the APS Solar Communities program to complete installations delayed as a result of the COVID-19 pandemic in 2020. The ACC has not yet ruled on the 2021 RES Implementation Plan.

On July 15, 2020, ACC Staff issued final draft rules which, if approved, would require APS to meet certain clean energy standards, obtain approval for its action plan included in its IRP, and seek cost recovery in a rate process. APS cannot predict the outcome of this matter. See “Energy Modernization Plan” below for more information.

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 proposed 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 sought a requested budget of $52.6 million and requested 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.

On December 31, 2018, APS filed its 2019 DSM Plan, which requested a budget of $34.1 million and focused on DSM strategies to better meet system and customer needs, such as peak demand reduction, load shifting, storage and electrification strategies.
On December 31, 2019, APS filed its 2020 DSM Plan, which requested a budget of $51.9 million and continued APS’s focus on DSM strategies such as peak demand reduction, load shifting, storage and electrification strategies. The 2020 DSM Plan addressed all components of the pending 2018 and 2019 DSM plans, which enabled the ACC to review the 2020 DSM Plan only. On May 15, 2020, APS filed an amended 2020 DSM Plan to provide assistance to customers experiencing economic impacts of the COVID-19 pandemic. The amended 2020 DSM Plan requested the same budget amount of $51.9 million. On September 23, 2020, the ACC approved the amended 2020 DSM Plan.

On April 17, 2020, APS filed an application with the ACC requesting a COVID-19 emergency relief package to provide additional assistance to its customers. On May 5, 2020, the ACC approved APS returning $36 million that had been collected through the DSM Adjustor Charge, but not allocated for current DSM programs, directly to customers through a bill credit in June 2020. As of December 31, 2020, APS had refunded approximately $43 million to customers. The additional $7 million over the approved amount was the result of the kWh credit being based on historic consumption which was different than actual consumption in the refund period. This difference was recorded to the DSM balancing account and will be addressed in subsequent DSM filings. See “COVID-19 Pandemic” above for more information.

On December 31, 2020, APS filed its 2021 DSM Plan, which requested a budget of $63.7 million and continues APS’s focus on DSM strategies, such as peak demand reduction, load shifting, storage and electrification strategies, as well as enhanced assistance to customers impacted economically by COVID-19. The ACC has not yet ruled on the APS 2021 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 2020 and 2019 (dollars in thousands):
 Twelve Months Ended
December 31,
 20202019
Beginning balance$70,137 $37,164 
Deferred fuel and purchased power costs — current period93,651 82,481 
Amounts refunded/(charged) to customers12,047 (49,508)
Ending balance$175,835 $70,137 

The PSA rate for the PSA year beginning February 1, 2019 was $0.001658 per kWh, as compared to the $0.004555 per kWh for the prior year. This rate was comprised 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. These rates went into effect as filed on February 1, 2019.

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 November 30, 2020, APS filed its PSA rate for the PSA year beginning February 1, 2021. That rate was $0.003544 per kWh and consisted of a forward component of $0.003434 per kWh and a historical component of $0.000110 per kWh. The 2021 PSA rate is a $0.004 per kWh increase compared to the 2020 PSA year. These rates were to be effective on February 1, 2021 but APS delayed the effectiveness of these rates until the first billing cycle of April 2021.

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. On December 29, 2020, the ACC Staff filed its report and recommended the storage costs be included in the PSA once the systems are in-service. On January 12, 2021, the ACC approved this application.

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 1 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 million to 14 million per year).  APS’s February 1, 2021 application requested an increase in the charge to $10.3 million, or $1.5 million over the charge in effect for the 2020-2021 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. On March 17, 2020, APS made a filing to make further modifications to its annual transmission formula to provide additional transparency for excess and deficient Accumulated Deferred Income Taxes resulting from the Tax Act, as well as for future local, state, and federal statutory tax rate changes. This filing is pending with FERC.

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.  Of this amount, retail customer rates decreased by approximately $26.9 million. 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 $25.8 million for the twelve-month period beginning June 1, 2019 in accordance with the FERC-approved formula. Of this amount, retail customer rates increased by approximately $4.7 million. An adjustment to APS’s retail rates to recover FERC approved transmission charges went into effect automatically on June 1, 2019.

Effective June 1, 2020, APS’s annual wholesale transmission rates for all users of its transmission system decreased by approximately $6.1 million for the twelve-month period beginning June 1, 2020 in accordance with the FERC-approved formula.  Of this amount, retail customer rates decreased by approximately $10.9 million. An adjustment to APS’s retail rates to recover FERC approved transmission charges went into effect automatically on June 1, 2020.

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 are currently 2.5 cents for both lost residential and non-residential kWh as set forth in the 2017 Settlement Agreement. 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). On April 14, 2020, the ACC approved the 2020 LFCR adjustment as filed, effective with the first billing cycle in May 2020. On February 15, 2021, APS filed its 2021 annual LFCR adjustment, requesting that effective May 1, 2021, the annual LFCR recovery amount be increased to $38.5 million (an $11.8 million increase from previous levels).

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 last billing cycle in March 2020. On March 19, 2020, due to the COVID-19 pandemic, APS delayed the discontinuation of TEAM Phase II until the first billing cycle in May 2020.  Amounts credited to customers after the last billing cycle in March 2020 will be recorded as a part of the balancing account and will be addressed for recovery as part of APS’s 2019 retail rate case. 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. On November 20, 2020, APS filed an application to continue the TEAM Phase III monthly bill credit through the earlier of December 31, 2021, or at the conclusion of APS’s 2019 pending rate case. On December 9, 2020, the ACC approved this request. Both the timing of the reduction in revenues refunded through the TEAM Phase III monthly bill credit and the offsetting income tax benefit are recognized based upon APS’s seasonal kWh sales pattern.

Net Metering

APS’s 2017 Rate Case 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. APS filed its request for a fourth-year export energy price of 9.4 cents per kWh on May 1, 2020, with a requested effective date of September 1, 2020. This price reflects the 10% annual reduction discussed above. On
September 23, 2020, the ACC approved the annual reduction of the export energy price but voted to delay the effectiveness of the reduction in export prices until October 1, 2021. APS’s export energy price will remain at 10.5 cents per kWh until October 1, 2021.

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 Former Arizona Corporation Commissioner Robert Burns

On August 25, 2016, then-Commissioner Robert 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 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, 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, 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, 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 Burns’ suit against APS and Pinnacle West. In response to the motion to dismiss, the
court stayed the suit and ordered 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, 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 Burns’ amended complaint. On March 6, 2018, 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 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. 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, Burns filed a notice of appeal. On July 12, 2019, 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 originally granted the request for oral argument; however, on March 31, 2020, the court vacated the date scheduled for oral argument given the COVID-19 pandemic.  The court determined that the matter could be submitted without oral argument and has taken the matter under advisement and will issue a decision without oral argument.

Burns’ position as an ACC commissioner ended on January 4, 2021. Nevertheless, Burns filed a motion with the Court of Appeals arguing that the appeal was not mooted by this fact and the court should decide the matter. Both APS and the ACC filed responses opposing the motion and asserting that the matter is moot. Pinnacle West and APS 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.

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 an initial set of draft energy rules and held various workshops to incorporate feedback from stakeholders and ACC Commissioners from April 2019 through July 2020. At the March 11-12, 2020 workshop, the ACC Staff committed to filing a final draft of proposed rules by July 2020. On July 30, 2020, the ACC Staff issued final draft energy rules which proposed 100% of retail kWh sales from clean energy resources by the end of 2050. Nuclear is defined as a clean energy resource. The proposed rules also require 50% of retail energy served be renewable by the end of 2035. A new energy efficiency standard was not included in the proposed rules. APS would be required to obtain approval of its action plan included in its IRP and seek recovery of prudently incurred costs in a rate process. If approved by the ACC Commissioners, the rules would require utilities to file a Clean Energy Implementation Plan and Energy Efficiency Report as part of their IRP every three years beginning in 2023. In addition, the ACC Staff proposed changing the IRP planning horizon from 15 years to 10 years.

The ACC has discussed the final draft energy rules at several different meetings in 2020. On October 14, 2020, the ACC passed one amendment to ACC Staff’s final draft energy rules that will require electric utilities to obtain 35% of peak load (as measured in 2020) by 2030 from DSM resources, including traditional energy efficiency, demand response and other programs aimed at reducing energy usage, peak demand management and load shifting. This standard aligns with the proposed rules’ three-year resource planning cycle and allows recovery of costs through existing mechanisms until the ACC issues a decision in a future rate proceeding. On October 29, 2020, the ACC approved an amendment that will require electric utilities to reduce their carbon emissions over 2016-2018 levels by 50% by 2032; 75% by 2040; and 100% by 2050. The ACC also approved an amendment that will require utilities to install energy storage systems with an aggregate capacity equal to 5% of each utility’s 2020 peak demand by 2035, of which 40% must be derived from customer-owned or customer-leased distributed storage. Another approved amendment modifies the resource planning process, including requirements for the ACC to approve a utility’s load forecast and resource plan, and for a utility to perform an all-source request for information to guide its resource plan. On November 13, 2020, the ACC approved a final draft energy rules package, and additional procedural steps in the rulemaking process are required to be completed before the rules may take effect. APS cannot predict the outcome of this matter.

Integrated Resource Planning

ACC rules require utilities to develop 15-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. On June 26, 2020, APS filed its final IRP. On July 15, 2020, the ACC extended the schedule for final ACC review of utility IRPs to February 2021. The ACC has taken no
action on APS’s IRP. APS cannot predict the outcome of this matter. See “Energy Modernization Plan” above for information regarding proposed changes to the IRP filings.

Public Utility Regulatory Policies Act

Under the Public Utility Regulatory Policies Act of 1978 (“PURPA”), qualifying facilities are provided the right to sell energy and/or capacity to utilities and are granted relief from certain regulatory burdens. On December 17, 2019, the ACC mandated a minimum contract length of 18 years for qualifying facilities over 100 kW in Arizona, and established that the rate paid to qualifying facilities must be based on the long-term avoided cost. “Avoided cost” is generally defined as the price at which the utility could purchase or produce the same amount of power from sources other than the qualifying facility on a long-term basis. During calendar year 2020, APS entered into two 18-year power purchase agreements with qualified facilities, each for 80 MW solar facilities. These agreements are pending ACC approval.

On July 16, 2020, FERC issued a final rule revising FERC’s regulations implementing PURPA. The final rule went into effect on December 31, 2020. APS is evaluating how the revised regulations may impact its operations.

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 June 1 through October 15 (“Summer Disconnection Moratorium”). During the Summer Disconnection Moratorium, 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. Although the emergency rules expired in December 2019, the Summer Disconnection Moratorium will remain in effect through utility tariffs for 2021 and beyond until the ACC adopts permanent rules or determines otherwise.

In June 2019, 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.

Due to the COVID-19 pandemic, APS voluntarily suspended disconnections of customers for nonpayment beginning March 13, 2020. On September 14, 2020, APS extended this suspension of disconnection of customers for nonpayment until December 31, 2020. The suspension of disconnection of customers for nonpayment ended on January 1, 2021 and customers were placed automatically on eight-month payment arrangements if they had past due balances at the end of the disconnection period of $75 or greater. APS will continue to waive late payment fees until October 15, 2021. The Summer Disconnection Moratorium, the suspension of disconnections during the COVID-19 pandemic and the increased bad debt
expense associated with both events resulted in a negative impact to its 2020 operating results of  approximately $23 million pre-tax above the impact of disconnections on its operating results for years that did not have the Summer Disconnection Moratorium or COVID-19 pandemic. See “COVID-19 Pandemic” above for more information.

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 held a workshop on February 25-26, 2020 on further consideration and discussion of the retail electric competition rules. During a July 15, 2020 ACC Staff meeting, the ACC Commissioners discussed the possible development of a retail competition pilot program, but no action was taken. The ACC Commissioners are continuing to explore 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 and Investigation

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 APS’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 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. By the middle of May 2020, APS provided 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, as applicable, and a $25 payment for any inconvenience that the customer may have experienced. The refunds and payment for inconvenience being provided did not have a material impact on APS’s financial statements. APS developed a new tool for comparing customers’ rate plan options.  APS had an independent third party verify that the new rate comparison tool works correctly.  In February 2020, APS launched the new online rate comparison tool, which is now available for its customers. The ACC hired an outside consultant to evaluate the extent of the error and the overall effectiveness of the tool. On August 20, 2020, ACC Staff filed the outside consultant’s report on APS’s rate comparison tool. The report concluded APS’s new rate comparison tool is working as intended. The report also identified a small population of additional customers that may have been affected by the error and APS has provided refunds and the $25 inconvenience payment to approximately 3,800 additional customers. These additional refunds and payment for inconvenience did not have a material impact on APS’s financial statements. On September 28, 2020, the ACC discussed this report but did not take any action. APS cannot predict if any action will be taken by the ACC at this time.
APS received civil investigative demands from the Office of the Arizona Attorney General, Civil Litigation Division, Consumer Protection & Advocacy Section (“Attorney General”) seeking information pertaining to the rate plan comparison tool offered to APS customers and other related issues including implementation of rates from the 2017 Settlement Agreement and its Customer Education and Outreach Plan associated with the 2017 Settlement Agreement. APS fully cooperated with the Attorney General’s Office in this matter. On February 22, 2021 APS entered into a consent agreement with the Attorney General as a way to settle the matter. The settlement results in APS paying $24.75 million, $24 million of which is being returned to customers as restitution. While this matter has been resolved with the Attorney General, APS cannot predict whether additional inquiries or actions may be taken by the ACC.

Four Corners 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. On March 18, 2020, the ACC agreed to take administrative notice to include in the pending rate case portions of the record in this prior proceeding that are relevant to the SCRs. 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 planned to retire Cholla Unit 4 by the end of 2020. Cholla Unit 4 was retired on December 24, 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 ($57 million as of December 31, 2020), 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.
Navajo Plant
The Navajo Plant ceased operations in November 2019. 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.

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 ($72 million as of December 31, 2020) plus a return on the net book value as well as other costs related to retirement and closure, including the Navajo coal reclamation regulatory asset ($18 million as of December 31, 2020). 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):
SDecember 31, 2020December 31, 2019
 Amortization ThroughCurrentNon-CurrentCurrentNon-Current
Pension (a)$— $469,953 $— $660,223 
Deferred fuel and purchased power (b) (c)2021175,835 — 70,137 — 
Income taxes — AFUDC equity20507,169 158,776 6,800 154,974 
Retired power plant costs203328,181 114,214 28,182 142,503 
Ocotillo deferralN/A— 95,723 — 38,144 
SCR deferralN/A— 81,307 — 52,644 
Deferred property taxes20278,569 49,626 8,569 58,196 
Lost fixed cost recovery (b)202141,807 — 26,067 — 
Deferred compensation2036— 36,195 — 36,464 
Four Corners cost deferral20248,077 24,075 8,077 32,152 
Income taxes — investment tax credit basis adjustment20491,113 24,291 1,098 24,981 
Palo Verde VIEs (Note 18)2046— 21,255 — 20,635 
Coal reclamation20261,068 16,999 1,546 17,688 
Deferred fuel and purchased power — mark-to-market (Note 16)20243,341 9,244 36,887 33,185 
Loss on reacquired debt20381,689 10,877 1,637 12,031 
Mead-Phoenix transmission line — contributions in aid of construction2050332 9,380 332 9,712 
Demand side management (b)2022— 7,268 — — 
Tax expense adjustor mechanism (b)20216,226 — 1,612 — 
Tax expense of Medicare subsidy20241,235 3,704 1,235 4,940 
PSA interest20214,355 — 1,917 — 
TCA balancing account (b)2021— — 6,324 2,885 
OtherVarious2,716 1,100 2,787 2,716 
Total regulatory assets (d) $291,713 $1,133,987 $203,207 $1,304,073 
(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, 2020December 31, 2019
 Amortization ThroughCurrentNon-CurrentCurrentNon-Current
Excess deferred income taxes - ACC — Tax Cuts and Jobs Act (a)2046$41,330 $1,012,583 $59,918 $1,054,053 
Excess deferred income taxes - FERC — Tax Cuts and Jobs Act (a)20587,240 229,147 6,302 237,357 
Asset retirement obligations2057— 506,049 — 418,423 
Other postretirement benefits(d)37,705 349,588 37,575 139,634 
Removal costs(c)52,844 103,008 47,356 136,072 
Income taxes — change in rates20502,839 66,553 2,797 68,265 
Four Corners coal reclamation20385,460 49,435 1,059 51,704 
Spent nuclear fuel20276,768 44,221 6,676 51,019 
Income taxes — deferred investment tax credit20492,231 48,648 2,202 50,034 
Renewable energy standard (b)202139,442 103 39,287 10,300 
Sundance maintenance20312,989 11,508 5,698 11,319 
Property tax deferralN/A— 13,856 — 7,046 
Demand side management (b)202110,819 — 15,024 24,146 
FERC transmission true up20226,598 3,008 1,045 2,004 
TCA balancing account (b)20222,902 4,672 — — 
Tax expense adjustor mechanism (b) (e)20217,089 — 7,018 — 
Active union medical trustN/A— 6,057 — 2,041 
Deferred gains on utility property20222,423 1,544 2,423 4,163 
OtherVarious409 189 532 255 
Total regulatory liabilities $229,088 $2,450,169 $234,912 $2,267,835 

(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.
(e)Pursuant to Decision 77852, the ACC has authorized APS to return to customers up to $7 million of liability recorded to the TEAM balancing account through December 31, 2021. Should new base rates become effective prior to December 31, 2021, any remaining unreturned balance is anticipated to be included in the new base rates.
v3.20.4
Income Taxes
12 Months Ended
Dec. 31, 2020
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 this net regulatory liability 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. The Company recorded $14 million and $57 million of income tax benefit related to the amortization of these non-depreciation related net excess deferred tax liabilities in 2020 and 2019, respectively. 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. The Company recorded $31 million and $62 million of income tax benefit related to amortization of these depreciation related liabilities in 2020 and 2019, respectively. (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.

In September 2020, U.S. Treasury issued final 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 final 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 continues to be eligible for bonus depreciation under the rules and bonus depreciation phase-downs in effect prior to enactment of the Tax Act. These final regulations do not materially impact any tax position taken by the Company for property which was under construction prior to September 28, 2017 and placed in service between January 1, 2018 and December 31, 2020.
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 Statements 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 18 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 ConsolidatedAPS Consolidated
 202020192018202020192018
Total unrecognized tax benefits, January 1$43,435 $40,731 $41,966 $43,435 $40,731 $41,966 
Additions for tax positions of the current year3,418 3,373 3,436 3,418 3,373 3,436 
Additions for tax positions of prior years1,431 1,843 2,696 1,431 1,843 2,696 
Reductions for tax positions of prior years for:      
Changes in judgment(1,965)(2,078)(1,764)(1,965)(2,078)(1,764)
Settlements with taxing authorities— — — — — — 
Lapses of applicable statute of limitations(664)(434)(5,603)(664)(434)(5,603)
Total unrecognized tax benefits, December 31$45,655 $43,435 $40,731 $45,655 $43,435 $40,731 

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 ConsolidatedAPS Consolidated
 202020192018202020192018
Tax positions, that if recognized, would decrease our effective tax rate$25,714 $22,813 $19,504 $25,714 $22,813 $19,504 
 
As of the balance sheet date, the tax year ended December 31, 2017 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 2016.

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 ConsolidatedAPS Consolidated
 202020192018202020192018
Unrecognized tax benefit interest expense/(benefit) recognized$266 $459 $(780)$266 $459 $(780)
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 ConsolidatedAPS Consolidated
 202020192018202020192018
Unrecognized tax benefit interest accrued $1,855 $1,589 $1,130 $1,855 $1,589 $1,130 
Additionally, as of December 31, 2020, 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 ConsolidatedAPS Consolidated
 Year Ended December 31,Year Ended December 31,
 202020192018202020192018
Current:   
Federal$11,869 $(13,551)$18,375 $57,299 $(54,697)$88,180 
State1,932 3,195 3,342 99 695 1,877 
Total current13,801 (10,356)21,717 57,398 (54,002)90,057 
Deferred:      
Federal53,398 (14,982)94,721 15,122 29,321 32,436 
State10,974 9,565 17,464 16,244 15,109 22,321 
Total deferred64,372 (5,417)112,185 31,366 44,430 54,757 
Income tax expense/(benefit)$78,173 $(15,773)$133,902 $88,764 $(9,572)$144,814 
The following chart compares pretax income at the 21% statutory federal income tax rate to income tax expense (dollars in thousands):
Pinnacle West ConsolidatedAPS Consolidated
 Year Ended December 31,Year Ended December 31,
 202020192018202020192018
Federal income tax expense at statutory rate$136,127 $113,828 $139,533 $142,020 $120,790 $154,260 
Increases (reductions) in tax expense resulting from:      
State income tax net of federal income tax benefit19,146 18,599 23,115 20,124 19,267 24,531 
State income tax credits net of federal income tax benefit(8,951)(8,519)(6,704)(7,213)(6,781)(5,440)
Nondeductible expenditures associated with ballot initiative— — 7,879 — — — 
Stock compensation34 (2,252)(1,804)183 (1,054)(780)
Excess deferred income taxes — Tax Cuts and Jobs Act(50,543)(124,082)(6,725)(50,543)(124,082)(4,715)
Allowance for equity funds used during construction (see Note 1)(2,747)(2,476)(7,231)(2,747)(2,476)(7,231)
Palo Verde VIE noncontrolling interest (see Note 18)(4,094)(4,094)(4,094)(4,094)(4,094)(4,094)
Investment tax credit amortization(7,510)(6,851)(6,742)(7,510)(6,851)(6,742)
Other(3,289)74 (3,325)(1,456)(4,291)(4,975)
Income tax expense/(benefit)$78,173 $(15,773)$133,902 $88,764 $(9,572)$144,814 
     The components of the net deferred income tax liability were as follows (dollars in thousands):
Pinnacle West ConsolidatedAPS Consolidated
 December 31,December 31,
 2020201920202019
DEFERRED TAX ASSETS  
Risk management activities$4,287 $17,552 $4,287 $17,552 
Regulatory liabilities:   
Excess deferred income taxes — Tax Cuts and Jobs Act319,091 335,877 319,091 335,877 
Asset retirement obligation and removal costs157,470 143,011 157,470 143,011 
Unamortized investment tax credits50,879 52,236 50,879 52,236 
Other postretirement benefits95,778 43,841 95,778 43,841 
Other43,551 52,382 43,551 52,382 
Operating lease liabilities107,853 15,497 107,414 15,497 
Pension liabilities45,853 73,210 40,168 67,976 
Coal reclamation liabilities42,065 40,837 42,065 40,837 
Renewable energy incentives25,355 28,066 25,355 28,066 
Credit and loss carryforwards26,460 54,795 8,034 10,992 
Other78,113 47,605 78,113 55,451 
Total deferred tax assets996,755 904,909 972,205 863,718 
DEFERRED TAX LIABILITIES   
Plant-related(2,489,899)(2,448,458)(2,489,899)(2,448,458)
Risk management activities(1,174)(27)(1,174)(27)
Pension and other postretirement assets(123,462)(21,892)(122,580)(21,458)
Other special use funds(42,927)(44,507)(42,927)(44,507)
Operating lease right-of-use assets(107,853)(15,497)(107,414)(15,497)
Regulatory assets:   
Allowance for equity funds used during construction(41,038)(40,023)(41,038)(40,023)
Deferred fuel and purchased power(47,673)(35,162)(47,673)(35,162)
Pension benefits(116,219)(163,339)(116,219)(163,339)
Retired power plant costs (35,214)(42,228)(35,214)(42,228)
Other(106,227)(82,722)(106,227)(82,722)
Other(20,472)(3,393)(5,513)(3,393)
Total deferred tax liabilities(3,132,158)(2,897,248)(3,115,878)(2,896,814)
Deferred income taxes — net$(2,135,403)$(1,992,339)$(2,143,673)$(2,033,096)
As of December 31, 2020, PNW Consolidated deferred tax assets for credit and loss carryforwards relate to federal general business credits of approximately $35 million, which first begin to expire in 2036 and state credit carryforwards net of federal benefit of $33 million, which first begin to expire in 2023. PNW Consolidated credit and loss carryforwards amount above has been reduced by $42 million of unrecognized tax benefits.
As of December 31, 2020, APS Consolidated deferred tax assets for credit and loss carryforwards relate to state credit carryforwards net of federal benefit of $16 million, which first begin to expire in 2024. APS Consolidated credit and loss carryforwards amount above has been reduced by $8 million of unrecognized tax benefits.
v3.20.4
Lines of Credit and Short-Term Borrowings
12 Months Ended
Dec. 31, 2020
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, 2020 and 2019 (dollars in thousands):
 
December 31, 2020December 31, 2019
Pinnacle WestAPSTotalPinnacle WestAPSTotal
Commitments under Credit Facilities$231,000 $1,000,000 $1,231,000 $250,000 $1,000,000 $1,250,000 
Outstanding Commercial Paper, Term Loan and Revolving Credit Facility Borrowings(169,000)— (169,000)(114,675)— (114,675)
Amount of Credit Facilities Available$62,000 $1,000,000 $1,062,000 $135,325 $1,000,000 $1,135,325 
Weighted-Average Commitment Fees0.125%0.100%0.125%0.100%

Pinnacle West

On May 5, 2020, Pinnacle West refinanced its 364-day $50 million term loan agreement that would have matured on May 7, 2020 with a new 364-day $31 million term loan agreement that matures May 4, 2021. Borrowings under the agreement bear interest at Eurodollar Rate plus 1.40% per annum. At December 31, 2020, Pinnacle West had $19 million in outstanding borrowings under the agreement.

At December 31, 2020, 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, 2020, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding and $150 million of commercial paper borrowings.

APS
 
At December 31, 2020, 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, 2020, APS had no outstanding borrowings under its revolving credit facilities, no letters of credit outstanding or commercial paper borrowings.

See “Financial Assurances” in Note 11 for a discussion of APS’s other outstanding letters of credit.
Debt Provisions
 
On December 17, 2020, 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.)
v3.20.4
Long-Term Debt and Liquidity Matters
12 Months Ended
Dec. 31, 2020
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, 2020 and 2019 (dollars in thousands):
 MaturityInterestDecember 31,
 Dates (a)Rates20202019
APS    
Pollution control bonds:    
Variable2029(b)$35,975 $35,975 
Fixed20244.70%— 115,150 
Total pollution control bonds  35,975 151,125 
Senior unsecured notes2024-2050
2.55%-6.88%
5,830,000 4,875,000 
Term loans(c)— 200,000 
Unamortized discount  (15,900)(12,434)
Unamortized premium  14,781 7,423 
Unamortized debt issuance cost(46,911)(37,981)
Total APS long-term debt  5,817,945 5,183,133 
Less current maturities — 350,000 
Total APS long-term debt less current maturities  5,817,945 4,833,133 
Pinnacle West    
Senior unsecured notes20251.3%500,000 300,000 
Term loan(d)— 150,000 
Unamortized discount(44)(57)
Unamortized debt issuance cost(3,635)(518)
Total Pinnacle West long-term debt496,321 449,425 
Less current maturities— 450,000 
Total Pinnacle West long-term debt less current maturities496,321 (575)
TOTAL LONG-TERM DEBT LESS CURRENT MATURITIES
  $6,314,266 $4,832,558 
(a)    This schedule does not reflect the timing of redemptions that may occur prior to maturities.
(b)    The weighted-average rate for the variable rate pollution control bonds was 0.18% at December 31, 2020 and 1.54% at December 31, 2019.
(c)    The weighted-average interest rate was 2.12% at December 31, 2019. This term loan was repaid on May 26, 2020. See additional details below.
(d)    The weighted-average interest rate was 2.20% at December 31, 2019. This term loan was repaid on June 19, 2020. See additional details below.
The following table shows principal payments due on Pinnacle West’s and APS’s total long-term debt (dollars in thousands):
YearConsolidated
Pinnacle West
Consolidated
APS
2021$— $— 
2022— — 
2023— — 
2024250,000 250,000 
2025800,000 300,000 
Thereafter5,315,975 5,315,975 
Total$6,365,975 $5,865,975 
 
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, 2020
As of
December 31, 2019
 Carrying
Amount
Fair ValueCarrying
Amount
Fair Value
Pinnacle West$496,321 $509,050 $449,425 $450,822 
APS5,817,945 7,103,791 5,183,133 5,743,570 
Total$6,314,266 $7,612,841 $5,632,558 $6,194,392 
 
Credit Facilities and Debt Issuances

Pinnacle West
On June 17, 2020, Pinnacle West issued $500 million of 1.3% unsecured senior notes that mature June 15, 2025. The net proceeds from the sale were used to repay early its $150 million term loan facility set to mature on December 21, 2020, to repay short-term indebtedness consisting of commercial paper and replenish cash incurred or used to fund capital expenditures, to redeem prior to maturity our $300 million, 2.25% senior notes due November 30, 2020, and for general corporate purposes.

On December 23, 2020, Pinnacle West entered into a $150 million term loan facility that matures June 2022. The proceeds were received on January 4, 2021 and used for general corporate purposes. We recognized the term loan facility as long-term debt upon settlement on January 4, 2021.
 
APS

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.    
On May 22, 2020, APS issued $600 million of 3.35% unsecured senior notes that mature May 15, 2050. The net proceeds from the sale were used to repay early its $200 million term loan facility and to repay short-term indebtedness, consisting of commercial paper and revolver borrowings, and to replenish cash used to fund capital expenditures.

On September 11, 2020, APS issued $400 million of 2.65% unsecured senior notes that mature September 15, 2050. The net proceeds from the sale will be used to replenish cash used for previous eligible green expenditures and fund future eligible green expenditures.

On November 19, 2020, APS reopened its $300 million, 2.6% unsecured senior notes that mature on August 15, 2029, and issued an additional $105 million of 2.6% unsecured senior notes. The aggregate balance of $405 million will mature on August 15, 2029. The net proceeds from the sale, together with funds made available from other sources, were used to redeem, prior to maturity, no later than 20 days after the date that the new notes were issued, (i) the $49.4 million outstanding principal amount of 4.7% City of Farmington, New Mexico Pollution Control Revenue Refunding Bonds (Arizona Public Service Company Four Corners Project), 1994 Series A, and (ii) the $65.75 million outstanding principal amount of 4.7% City of Farmington, New Mexico Pollution Control Revenue Refunding Bonds (Arizona Public Service Company Four Corners Project), 1994 Series B.

On December 28, 2020, Pinnacle West contributed $150 million into APS in the form of an equity infusion. APS used this contribution to repay short-term indebtedness.

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, 2020, the ratio was approximately 54% for Pinnacle West and 49% 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 December 17, 2020, the ACC issued a financing order in which, subject to specified parameters and procedures, it approved APS’s long-term debt authorization from $5.9 billion to $7.5 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.)
v3.20.4
Retirement Plans and Other Postretirement Benefits
12 Months Ended
Dec. 31, 2020
Retirement Benefits [Abstract]  
Retirement Plans and Other Postretirement Benefits Retirement Plans and Other Postretirement Benefits
Pinnacle West sponsors a qualified defined benefit and account balance pension plan (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 “HRA”) 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 13 for further discussion of how fair values are determined.)  Due to subjective and complex judgments, which may be required in determining fair values, actual results could differ from the results estimated through the application of these methods.

Under the HRA, included in the other postretirement benefit plan, the Company provides a subsidy to retirees to defray the cost of a Medicare supplemental policy. In prior years, we had been assuming a 4.75% escalation of these benefits; however, actual escalation has been significantly less than this assumption. Accordingly, during 2020 and for future periods, the escalation assumption was reduced to 2.00% (see weighted-average assumption table below). This escalation factor assumption change, among other factors, resulted in an increase in the over-funded status of the other postretirement benefit plan as of December 31, 2020. As a result, on January 4, 2021, we initiated the transfer of approximately $106 million of investment assets from the other postretirement benefit plan into the Active Union Employee Medical Account Trust. The Active Union Employee Medical Account is an existing trust account that holds investments restricted for paying active union employee medical costs (see Note 19). The transfer of other postretirement benefit plan investment assets into the Active Union Employee Medical Account permits access to approximately $106 million of assets for the sole purpose of paying active union employee medical benefits. This transfer of investment assets into the Active Union Employee Medical Account is consistent with the terms of a similar 2018 transaction.
A significant portion of the changes in the actuarial gains and losses of our pension and postretirement plans is attributable to APS and are recoverable in rates.  Accordingly, these changes are recorded as a regulatory asset or regulatory liability (see Note 4).
 
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 PlansOther Benefits Plans
 202020192018202020192018
Service cost-benefits earned during the period
$56,233 $49,902 $56,669 $22,236 $18,369 $21,100 
Interest cost on benefit obligation118,567 136,843 124,689 25,857 29,894 28,147 
Expected return on plan assets(187,443)(171,884)(182,853)(40,077)(38,412)(42,082)
Amortization of:      
Prior service credit— — — (37,575)(37,821)(37,842)
Net actuarial loss34,612 42,584 32,082 — — — 
Net periodic benefit cost/(benefit)$21,969 $57,445 $30,587 $(29,559)$(27,970)$(30,677)
Portion of cost/(benefit) charged to expense$3,386 $30,312 $10,120 $(20,966)$(19,859)$(21,426)
 
The following table shows the plans’ changes in the benefit obligations and funded status (dollars in thousands):
 Pension PlansOther Benefits Plans
 2020201920202019
Change in Benefit Obligation    
Benefit obligation at January 1$3,613,114 $3,190,626 $746,924 $676,771 
Service cost56,233 49,902 22,236 18,369 
Interest cost118,567 136,843 25,857 29,894 
Benefit payments(191,704)(177,882)(31,511)(32,486)
Actuarial (gain) loss306,657 413,625 (139,472)54,376 
Benefit obligation at December 313,902,867 3,613,114 624,034 746,924 
Change in Plan Assets    
Fair value of plan assets at January 13,318,351 2,733,476 837,494 723,677 
Actual return on plan assets642,373 602,030 150,076 144,095 
Employer contributions100,000 150,000 — — 
Benefit payments(174,180)(167,155)(26,405)(30,278)
Fair value of plan assets at December 313,886,544 3,318,351 961,165 837,494 
Funded Status at December 31$(16,323)$(294,763)$337,131 $90,570 

The following table shows information for pension plans with an accumulated obligation in excess of plan assets (dollars in thousands):
As of December 31,
 20202019
Accumulated benefit obligation171,672 169,091 
Fair value of plan assets— — 
 
The Pinnacle West Capital Corporation Retirement Plan is more than 100% funded on an accumulated benefit obligation basis at December 31, 2020 and December 31, 2019, therefore the only pension plan with an accumulated benefit obligation in excess of plan assets in 2020 and 2019 is a non-qualified supplemental excess benefit retirement plan.

The following table shows information for pension plans with a projected benefit obligation in excess of plan assets (dollars in thousands):
As of December 31,
 20202019
Projected benefit obligation182,184 3,613,114 
Fair value of plan assets— 3,318,351 

The Pinnacle West Capital Corporation Retirement Plan is more than 100% funded on a projected benefit obligation basis at December 31, 2020, therefore the only pension plan with a projected benefit obligation in excess of plan assets in 2020 is a non-qualified supplemental excess benefit retirement plan.

The following table shows the amounts recognized on the Consolidated Balance Sheets (dollars in thousands):
 Pension PlansOther Benefits Plans
 2020201920202019
Noncurrent asset$165,861 $— $337,131 $90,570 
Current liability(15,700)(14,578)— — 
Noncurrent liability(166,484)(280,185)— — 
Net amount recognized$(16,323)$(294,763)$337,131 $90,570 
 
The following table shows the details related to accumulated other comprehensive loss as of December 31, 2020 and 2019 (dollars in thousands): 
 Pension PlansOther Benefits Plans
 2020201920202019
Net actuarial loss (gain)$552,301 $735,186 $(237,233)$12,238 
Prior service credit— — (152,337)(189,912)
APS’s portion recorded as a regulatory (asset) liability(469,953)(660,223)387,293 177,209 
Income tax expense (benefit)(20,364)(18,546)1,018 570 
Accumulated other comprehensive loss (gain)$61,984 $56,417 $(1,259)$105 
 
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,
 20202019202020192018
Discount rate – pension plans2.53 %3.30 %3.30 %4.34 %3.65 %
Discount rate – other benefits plans2.63 %3.42 %3.42 %4.39 %3.71 %
Rate of compensation increase4.00 %4.00 %4.00 %4.00 %4.00 %
Expected long-term return on plan assets - pension plansN/AN/A5.75 %6.25 %6.05 %
Expected long-term return on plan assets - other benefit plansN/AN/A4.85 %5.40 %5.40 %
Initial healthcare cost trend rate (pre-65 participants)6.50 %7.00 %7.00 %7.00 %7.00 %
Ultimate healthcare cost trend rate (pre-65 participants)4.75 %4.75 %4.75 %4.75 %4.75 %
Number of years to ultimate trend rate (pre-65 participants)56578
Initial and ultimate healthcare cost trend rate (post-65 participants) (a)2.00 %4.75 %4.75 %4.75 %4.75 %
Interest crediting rate – cash balance pension plans4.50 %4.50 %4.50 %4.50 %4.50 %
 
(a)See discussion above relating to this assumptions impact on benefit obligations and the January 2021 asset transfer to the Active Union Employee Medical Account.

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 2021, we are assuming a 5.30% long-term rate of return for pension assets and 5.05% (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. 

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 may 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 2020, the target and actual allocation for the pension plan at December 31, 2020 are as follows:
Pension Plans
 Target AllocationActual Allocation
Long-term fixed income assets72 %68 %
Return-generating assets28 %32 %
Total100 %100 %

The permissible range is within +/-3% of the target allocation shown in the above table, and also considers the plan’s funded status. At December 31, 2020, the return-seeking assets were slightly outside the target allocation permissible range and were rebalanced to within the target range during January 2021.

The following table presents the additional target allocations, as a percent of total pension plan assets, for the return-generating assets:
Asset ClassTarget Allocation
Equities in US and other developed markets17 %
Equities in emerging markets%
Alternative investments%
Total28 %

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, 2020, 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, 2020:
Other Benefits Plans
Actual Allocation
Long-term fixed income assets55 %
Return-generating assets45 %
Total100 %
See Note 13 for a discussion on the fair value hierarchy and how fair value methodologies are applied.  The plans invest directly in fixed income, U.S. Treasury Futures Contracts, and equity securities, in addition to 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, 2020, 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. Certain partnerships also include funding commitments that may require the plan to contribute up to $50 million to these partnerships; as of December 31, 2020, 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, 2020, by asset category, are as follows (dollars in thousands):
 
 Level 1Level 2Other (a)Total
Pension Plan:   
Cash and cash equivalents$9,911 $— $— $9,911 
Fixed income securities:   
Corporate— 1,684,782 — 1,684,782 
U.S. Treasury794,571 — — 794,571 
Other (b)— 112,224 — 112,224 
Common stock equities (c)331,058 — — 331,058 
Mutual funds (d)262,765 — — 262,765 
Common and collective trusts:
   Equities— — 407,522 407,522 
   Real estate— — 191,595 191,595 
Partnerships— — 22,420 22,420 
Short-term investments and other (e)— — 69,696 69,696 
Total $1,398,305 $1,797,006 $691,233 $3,886,544 
Other Benefits:    
Cash and cash equivalents$1,909 $— $— $1,909 
Fixed income securities:   
Corporate— 221,488 — 221,488 
U.S. Treasury258,102 — — 258,102 
Other (b)— 8,316 — 8,316 
Common stock equities (c)175,605 — — 175,605 
Mutual funds (d)34,310 — — 34,310 
Common and collective trusts:   
   Equities— — 94,674 94,674 
   Real estate— — 19,778 19,778 
Short-term investments and other (e)142,995 — 3,988 146,983 
Total $612,921 $229,804 $118,440 $961,165 
(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, 2019, by asset category, are as follows (dollars in thousands):
 Level 1Level 2Other (a)Total
Pension Plan:   
Cash and cash equivalents$9,370 $— $— $9,370 
Fixed income securities:   
Corporate— 1,541,729 — 1,541,729 
U.S. Treasury406,112 — — 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. Treasury353,650 — — 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 U.S. and international common stock equities.
(e)This category includes plan receivables and payables.

Contributions
 
Future year contribution amounts are dependent on plan asset performance and plan actuarial assumptions.  We made contributions to our pension plan totaling $100 million in 2020, $150 million in 2019, and $50 million in 2018.  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 in 2021 and zero thereafter.  With regard to contributions to our other postretirement benefit plan, we did not make a contribution in 2020 and 2019. We do not expect to make any contributions over the next three years to
our other postretirement benefit plans. The Company was reimbursed $26 million in 2020, $30 million in 2019, and $72 million in 2018 for prior years retiree medical claims from the other postretirement benefit plan trust assets.
 
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):
YearPension PlansOther Benefits Plans
2021$210,119 $31,204 
2022209,593 31,731 
2023215,527 32,196 
2024220,241 31,914 
2025220,787 31,484 
Years 2026-20301,116,848 153,536 
 
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 2020, 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 2020, $11 million for 2019, and $11 million for 2018.
v3.20.4
Leases
12 Months Ended
Dec. 31, 2020
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 2021 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 18 for a discussion of VIEs.)

On June 1, 2020 APS had two separate purchased power lease contracts that commenced. The lease terms end on September 30, 2025 and September 30, 2026, respectively. Both of these leases allow APS the right to the generation capacity from certain natural-gas fueled generators during the months of June through September over the contract term. APS does not operate or maintain these leased assets. APS controls the dispatch of the leased assets during the months of June through September and is required to pay a fixed monthly capacity payment during these periods of use. For these types of leased assets APS has elected to combine both the lease and non-lease payment components and accounts for the entire fixed payment as a lease obligation. These purchased power lease contracts are accounted for as operating leases. The contracts do not contain purchase options or term extension options. In addition to the fixed monthly capacity payment, APS must also pay variable charges based on the actual production volume of the asset. The variable consideration is not included in the measurement of our lease obligation.
The following table provides information related to our lease costs (dollars in thousands):
Year Ended
December 31, 2020
Year Ended
December 31, 2019
Purchased Power Lease ContractsLand, Property & Equipment LeasesTotalPurchased Power Lease ContractsLand, Property & Equipment LeasesTotal
Operating lease cost$68,883 $18,493 $87,376 $42,190 $18,038 $60,228 
Variable lease cost121,359 972 122,331 113,233 782 114,015 
Short-term lease cost— 3,804 3,804 — 4,385 4,385 
Total lease cost$190,242 $23,269 $213,511 $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 expense recognized in the Consolidated Statements of Income was $18 million in 2018, this amount does not include purchased power lease contracts. Operating lease cost for purchased power lease contracts was $47 million in 2018. In addition, contingent rents for purchased power lease contracts was $109 million in 2018. 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, 2020
YearPurchased Power Lease ContractsLand, Property & Equipment LeasesTotal
2021$66,658 $14,455 $81,113 
202268,325 10,849 79,174 
202370,033 8,503 78,536 
202471,784 6,104 77,888 
202573,578 4,400 77,978 
Thereafter36,760 37,314 74,074 
Total lease commitments387,138 81,625 468,763 
Less imputed interest14,375 18,267 32,642 
Total lease liabilities$372,763 $63,358 $436,121 
    
We recognize lease assets and liabilities upon lease commencement. At December 31, 2020, we have certain purchased power lease contracts, that have been executed but have not yet commenced. In January 2021, we also executed additional purchased power lease contracts relating to energy storage. These arrangements have commencement dates beginning in May 2021 with terms ending through December 2042. We expect the total fixed consideration paid for these arrangements, which includes both lease and nonlease payments, will approximate $650 million over the term of the arrangements.
The following tables provide other additional information related to operating lease liabilities (dollars in thousands):
Year Ended
December 31, 2020
Year Ended December 31, 2019
Cash paid for amounts included in the measurement of lease liabilities — operating cash flows:$75,097 $69,075 
Right-of-use operating lease assets obtained in exchange for operating lease liabilities441,653 11,262 

December 31, 2020December 31, 2019
Weighted average remaining lease term6 years13 years
Weighted average discount rate (a)1.69 %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.
v3.20.4
Jointly-Owned Facilities
12 Months Ended
Dec. 31, 2020
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, 2020 (dollars in thousands):

 Percent
Owned
 Plant in
Service
Accumulated
Depreciation
Construction
Work in
Progress
Generating facilities:     
Palo Verde Units 1 and 329.1 %$1,911,339 $1,108,883 $26,623 
Palo Verde Unit 2 (a)16.8 %649,035 379,305 7,268 
Palo Verde Common28.0 %(b)774,054 320,107 41,607 
Palo Verde Sale Leaseback (a)351,050 253,014 — 
Four Corners Generating Station 63.0 %1,621,418 581,436 35,028 
Cholla common facilities (c)50.5 %193,807 109,447 1,206 
Transmission facilities:     
ANPP 500kV System33.5 % (b)131,991 52,626 3,859 
Navajo Southern System26.0 %(b)89,113 33,536 1,215 
Palo Verde — Yuma 500kV System25.3 %(b)23,247 6,681 433 
Four Corners Switchyards61.8 % (b)69,441 17,009 3,145 
Phoenix — Mead System17.1 %(b)39,437 19,072 73 
Palo Verde — Rudd 500kV System50.0 %93,123 28,206 1,921 
Morgan — Pinnacle Peak System64.6 % (b)117,497 20,754 912 
Round Valley System50.0 %531 174 13 
Palo Verde — Morgan System88.9 %(b)257,220 20,943 530 
Hassayampa — North Gila System80.0 %148,067 16,080 — 
Cholla 500kV Switchyard85.7 %7,896 1,850 940 
Saguaro 500kV Switchyard60.0 %21,669 13,229 
Kyrene — Knox System50.0 %578 323 — 
(a)See Note 18.
(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. Cholla Unit 4 was retired on December 24, 2020.
v3.20.4
Commitments and Contingencies
12 Months Ended
Dec. 31, 2020
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 United States Department of Energy (“DOE”) in the United States Court of Federal Claims (“Court of Federal Claims”).  The lawsuit sought to recover damages incurred due to DOE’s breach of the Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste (“Standard Contract”) for failing to accept Palo Verde’s spent nuclear fuel and high level waste from January 1, 2007 through June 30, 2011, as it was required to do pursuant to the terms of the Standard Contract and the Nuclear Waste Policy Act.  On August 18, 2014, APS and DOE entered into a settlement agreement, stipulating to a dismissal of the lawsuit and payment 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. On September 1, 2020, APS and DOE entered into an addendum to the settlement agreement allowing for the recovery of costs incurred through December 31, 2022.

APS has submitted six claims pursuant to the terms of the August 18, 2014 settlement agreement, for six separate time periods during July 1, 2011 through June 30, 2019. The DOE has approved and paid $99.7 million for these claims (APS’s share is $29.0 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 November 2, 2020, APS filed its seventh claim pursuant to the terms of the August 18, 2014 settlement agreement in the amount of $12.2 million (APS’s share is $3.6 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 $13.8 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 $13.3 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 $25.8 million for each retrospective premium assessment declared by NEIL’s Board of Directors due to losses.  In addition, NEIL policies contain rating triggers that would result in APS providing approximately $75.1 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 2021 and 2043 that include required purchase provisions.  APS estimates the contract requirements to be approximately $772 million in 2021; $671 million in 2022; $632 million in 2023; $592 million in 2024; $564 million in 2025; and $5.4 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,
 20212022202320242025Thereafter
Coal take-or-pay commitments (a)$182,569 $183,604 $184,540 $186,804 $177,114 $1,024,854 
 
(a)Total take-or-pay commitments are approximately $1.9 billion.  The total net present value of these commitments is approximately $1.5 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,
 202020192018
Total purchases$189,817 $204,888 $206,093 
 
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 $35 million in 2021; $31 million in 2022; $30 million in 2023; $28 million in 2024; $25 million in 2025; and $105 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 $170 million at December 31, 2020 and $166 million at December 31, 2019. Under our current coal supply agreements, APS expects to make payments for the final mine reclamation as follows:  $16 million in 2021; $17 million in 2022; $18 million in 2023; $19 million in 2024; $20 million in 2025; and $69 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 (“Superfund” or “CERCLA”) 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 during the first or second quarter of 2021. We estimate that our costs related to this investigation and study will be approximately $3 million. We anticipate incurring additional expenditures in the future, but because the overall investigation is not complete and ultimate remediation requirements are not yet finalized, at the present time expenditures related to this matter cannot be reasonably estimated.
 
On August 6, 2013, the Roosevelt Irrigation District (“RID”) filed a lawsuit in Arizona District Court against APS and 24 other defendants, alleging that RID’s groundwater wells were contaminated by the release of hazardous substances from facilities owned or operated by the defendants.  The lawsuit also alleges that, under Superfund laws, the defendants are jointly and severally liable to RID.  The allegations against APS arise out of APS’s current and former ownership of facilities in and around OU3.  As part of a state governmental investigation into groundwater contamination in this area, on January 25, 2015, 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.

Arizona Attorney General Matter

APS received civil investigative demands from the Attorney General seeking information pertaining to the rate plan comparison tool offered to APS customers and other related issues including implementation of rates from the 2017 Settlement Agreement and its Customer Education and Outreach Plan associated with the 2017 Settlement Agreement. APS fully cooperated with the Attorney General’s Office in this matter. On February 22, 2021 APS entered into a consent agreement with the Attorney General as a way to settle the matter. The settlement results in APS paying $24.75 million, $24 million of which is being returned to customers as restitution.
 
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 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. In early 2017, EPA approved a final rule containing a revision to Arizona’s State Implementation Plan (“SIP”) for Cholla that implemented BART requirements for this facility, which did not require the installation of any new pollution control capital improvements. In conjunction with the closure of Cholla Unit 2 in 2015, APS has committed to ceasing coal combustion within Units 1 and 3 by April 2025. PacifiCorp retired Cholla Unit 4 at the end of 2020. (See “Cholla” in Note 4 for information regarding future plans for Cholla and details related to the resulting regulatory asset).
 
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 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 July 29, 2020, EPA took final action on new regulations establishing revised deadlines for initiating the closure of unlined CCR surface impoundments; such disposal units must close as soon as technically feasible, but no later than April 22, 2021.
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 July 29, 2020 final regulation adopted this proposal and now requires explicit EPA approval for facilities to utilize an alternative closure deadline. With respect to the Cholla facility, APS’s application for alternative closure (which would allow the continued disposal of CCR within the facility’s existing unlined CCR surface impoundments until the required date for ceasing coal-fired boiler operations in April 2025) was submitted to EPA on November 30, 2020 and is currently pending. This application will be subject to public comment and, potentially, judicial review.

We cannot at this time predict the outcome of these regulatory proceedings or when the EPA will take final action on those matters that are still pending. 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 $27 million and its share of incremental costs to comply with the CCR rule for Cholla is approximately $16 million. The Navajo Plant disposed of CCR only in a dry landfill storage area. To comply with the CCR rule for the Navajo Plant, APS’s share of incremental costs was 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 have ceased operating and initiated 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-2021. 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 such rules would have had far broader impact on the electric power sector than the ACE regulations. The ACE regulations had been stayed pending judicial review and on January 19, 2021, the U.S. Court of Appeals for the D.C. Circuit vacated the ACE regulations and remanded them back to
EPA to develop new existing power plant carbon regulations consistent with the court’s ruling. That ruling endorsed an expansive view of the federal Clean Air Act consistent with EPA’s 2015 CPP. While the Biden administration has expressed an intent to regulate carbon emissions in this sector more aggressively under the Clean Air Act, we cannot at this time predict the outcome of pending EPA rulemaking proceedings in response to the court’s recent ACE decision.

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.
 
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. Based upon a November 1, 2019 filing by several environmental groups, the EAB again took up review of the Four Corners NPDES Permit. Oral argument on this appeal was held on September 3, 2020 and the EAB denied the environmental group petition on September 30, 2020. On January 22, 2021, the environmental groups filed a petition for review of the EAB’s decision with the U.S. Court of Appeals for the Ninth Circuit. We cannot predict the outcome of these appeal proceedings and, if such appeal is successful, whether that outcome 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 purchased this 7% interest on July 3, 2018 from 4CA. 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. The note is secured by a portion of APS’s payments to be owed to NTEC under the 2016 Coal Supply Agreement. As of December 31, 2020, the note has a remaining balance of $27 million. NTEC continues to make payments in accordance with the terms of the note. Due to its short-remaining term, among other factors, there are no expected credit losses associated with the 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) was 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 of which the prepayment has been fully utilized as of June 2020.

Financial Assurances
 
In the normal course of business, we obtain standby letters of credit and surety bonds from financial institutions and other third parties. These instruments guarantee our own future performance and provide third parties with financial and performance assurance in the event we do not perform. These instruments support commodity contract collateral obligations and other transactions. As of December 31, 2020, standby letters of credit totaled $5.2 million and will expire in 2021. As of December 31, 2020, surety bonds expiring through 2022 totaled $16 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, 2020. 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.) Pinnacle West has not needed to perform under 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, including expected credit losses, 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 are reduced as payments are made under the respective guarantee agreements. The Equity Contribution Guarantees remaining as of December 31, 2020 are immaterial in amount (approximately $3 million) and the PTC Guarantees (approximately $39 million as of December 31, 2020) are currently expected to be terminated ten years following the commercial operation date of the applicable project.
v3.20.4
Asset Retirement Obligations
12 Months Ended
Dec. 31, 2020
Asset Retirement Obligation Disclosure [Abstract]  
Asset Retirement Obligations Asset Retirement Obligations
 
In 2020, APS revised its cost estimates for existing AROs at Cholla relating to updated estimates for the closure of ponds and facilities, and at Four Corners and the Navajo Plant relating to corrective action and water monitoring costs, which resulted in an increase to the ARO of $6 million. Also in 2020, an updated Four Corners decommissioning study was finalized for the updated closure date of 2031, which resulted in an increase to the ARO of $13 million.

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.

The following table shows the change in our asset retirement obligations for 2020 and 2019 (dollars in thousands):

 20202019
Asset retirement obligations at the beginning of year$657,218 $726,545 
Changes attributable to:  
Accretion expense38,652 39,726 
Settlements(9,710)(12,591)
Estimated cash flow revisions18,923 (96,462)
Asset retirement obligations at the end of year$705,083 $657,218 
 
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.
v3.20.4
Fair Value Measurements
12 Months Ended
Dec. 31, 2020
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 — Inputs are 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 may 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 trusts 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. 
 
Investments Held in Nuclear Decommissioning Trusts and Other Special Use Funds
 
The nuclear decommissioning trusts 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 employee medical account. (See Note 19 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 Trusts 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, 2020 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):

Level 1Level 2Level 3OtherTotal
Assets
Risk management activities — derivative instruments:
Commodity contracts$— $9,016 $$(4,271)(a)$4,749 
Nuclear decommissioning trust:
Equity securities29,796 — — (17,828)(b)11,968 
U.S. commingled equity funds— — — 610,055 (c)610,055 
U.S. Treasury debt164,514 — — — 164,514 
Corporate debt— 149,509 — — 149,509 
Mortgage-backed securities— 99,623 — — 99,623 
Municipal bonds— 89,705 — — 89,705 
Other fixed income— 13,061 — — 13,061 
Subtotal nuclear decommissioning trust194,310 351,898 — 592,227 1,138,435 
Other special use funds:
Equity securities37,337 — — 504 (b)37,841 
U.S. Treasury debt203,220 — — — 203,220 
Municipal bonds— 13,448 — — 13,448 
Subtotal other special use funds240,557 13,448 — 504 254,509 
Total assets$434,867 $374,362 $$588,460 $1,397,693 
Liabilities
Risk management activities — derivative instruments:
Commodity contracts$— $(20,498)$(1,107)$2,986 (a)$(18,619)

(a)Represents counterparty netting, margin, and collateral (see Note 16).
(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, 2019 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):
 
Level 1Level 2Level 3OtherTotal
Assets
Risk management activities — derivative instruments:
Commodity contracts$— $551 $33 $(69)(a)$515 
Nuclear decommissioning trust:
Equity securities10,872 — — 2,401 (b)13,273 
U.S. commingled equity funds— — — 518,844 (c)518,844 
U.S. Treasury debt160,607 — — — 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 trust171,479 318,051 — 521,245 1,010,775 
Other special use funds:
Equity securities7,142 — — 474 (b)7,616 
U.S. Treasury debt232,848 — — — 232,848 
Municipal bonds— 4,631 — — 4,631 
Subtotal other special use funds239,990 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 16).
(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, or other characteristics of the product.  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.
 
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 $27.1 million as of December 31, 2020, 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.)
v3.20.4
Earnings Per Share
12 Months Ended
Dec. 31, 2020
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 (in thousands, except per share amounts):
 202020192018
Net income attributable to common shareholders$550,559 $538,320 $511,047 
Weighted average common shares outstanding — basic112,666 112,443 112,129 
Net effect of dilutive securities:   
Contingently issuable performance shares and restricted stock units276 315 421 
Weighted average common shares outstanding — diluted112,942 112,758 112,550 
Earnings per weighted-average common share outstanding
Net income attributable to common shareholders — basic$4.89 $4.79 $4.56 
Net income attributable to common shareholders — diluted$4.87 $4.77 $4.54 
v3.20.4
Stock-Based Compensation
12 Months Ended
Dec. 31, 2020
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, 2020, 1.5 million common shares were available for issuance under the 2012 Plan. During 2020, 2019, and 2018, 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 2020, $18 million in 2019, and $20 million in 2018.  The compensation cost capitalized is immaterial for all years. Income tax benefits related to stock-based compensation arrangements were $4 million in 2020, $7 million in 2019, and $7 million in 2018.

As of December 31, 2020, 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 $22 million in 2020, $21 million in 2019 and $24 million in 2018.
 
The following table is a summary of awards granted and the weighted-average grant date fair value for the three years ended 2020, 2019 and 2018:

Restricted Stock Units, Stock Grants, and Stock Units (a)Performance Shares (b)
 202020192018202020192018
Units granted118,403 109,106 132,997 122,830 142,874 171,708 
Weighted-average grant date fair value$71.70 $89.15 $77.51 $104.74 $92.16 $76.56 
(a)Units granted includes awards that will be cash settled of 45,646 in 2020, 48,972 in 2019, and 66,252 in 2018.
(b)Reflects the target payout level.
 
The following table is a summary of the status of non-vested awards as of December 31, 2020 and changes during the year:

Restricted Stock Units, Stock Grants, and Stock UnitsPerformance Shares
SharesWeighted-Average
Grant Date
Fair Value
Shares (b)Weighted-Average
Grant Date
Fair Value
Nonvested at January 1, 2020242,612 $81.38 306,970 $83.65 
Granted118,403 71.70 122,830 104.74 
Vested(136,893)73.80 (161,906)76.53 
Forfeited (c)(3,565)82.61 (7,890)85.06 
Nonvested at December 31, 2020220,557 (a)77.93 260,004 98.28 
Vested Awards Outstanding at December 31, 202082,921 161,906 
 
(a)Includes 126,996 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 $6 million, $5 million and $4 million in 2020, 2019 and 2018, respectively. This includes cash used to settle restricted stock units of $4 million, $5 million and $5 million in 2020, 2019 and 2018, 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.

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.
v3.20.4
Derivative Accounting
12 Months Ended
Dec. 31, 2020
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 natural gas.  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 13 for a discussion of fair value measurements.)  Derivative instruments may qualify for the normal purchases and normal sales scope exception if they require physical delivery and the quantities represent those transacted in the normal course of business.  Derivative instruments qualifying for the normal purchases and sales scope exception are accounted for under the accrual method of accounting and excluded from our derivative instrument discussion and disclosures below.

For its regulated operations, APS defers for future rate treatment 100% of the unrealized gains and losses on derivatives pursuant to the PSA mechanism that would otherwise be recognized in income.  Realized gains and losses on derivatives are deferred in accordance with the PSA to the extent the amounts are above or below the Base Fuel Rate (see Note 4).  Gains and losses from derivatives in the following tables represent the amounts reflected in income before the effect of PSA deferrals.

The following table shows the outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position):
 
Quantity
CommodityUnit of MeasureDecember 31, 2020December 31, 2019
PowerGWh368 193 
GasBillion cubic feet205 257 
 
Gains and Losses from Derivative Instruments
 
The following table provides information about APS’s gains and losses from derivative instruments in designated cash flow accounting hedging relationships (dollars in thousands):
 
Financial Statement Year Ended
December 31,
Commodity ContractsLocation202020192018
Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a)Fuel and purchased power (b)(763)(1,512)(2,000)
(a)During the years ended December 31, 2020, 2019, and 2018, we had no gains or 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 no amounts will be reclassified from accumulated OCI into income.  For APS, the delivery period for all derivative instruments in designated cash flow accounting hedging relationships have lapsed.
 
The following table provides information about gains and losses from derivative instruments not designated as accounting hedging instruments (dollars in thousands):
Financial Statement Year Ended
December 31,
Commodity ContractsLocation202020192018
Net Loss Recognized in IncomeOperating revenues $— $— $(2,557)
Net Loss Recognized in IncomeFuel and purchased power (a)(3,178)(84,953)(12,951)
Total $(3,178)$(84,953)$(15,508)
(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.  These types of transactions may include non-derivative instruments, derivatives qualifying for scope exceptions, trade receivables and trade payables arising from settled positions, and other forms of non-cash collateral (such as letters of credit).  These types of transactions are excluded from the offsetting tables presented below.
The following tables provide information about the fair value of our risk management activities reported on a gross basis and the impacts of offsetting.  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, 2020:
(dollars in thousands)
Gross 
Recognized 
Derivatives
(a)
Amounts 
Offset
(b)
Net
Recognized
Derivatives
Other
(c)
Amount 
Reported on 
Balance Sheet
Current assets$5,870 $(2,939)$2,931 $— $2,931 
Investments and other assets3,150 (1,332)1,818 — 1,818 
Total assets9,020 (4,271)4,749 — 4,749 
Current liabilities(9,211)2,939 (6,272)(1,285)(7,557)
Deferred credits and other(12,394)1,332 (11,062)— (11,062)
Total liabilities(21,605)4,271 (17,334)(1,285)(18,619)
Total$(12,585)$— $(12,585)$(1,285)$(13,870)
(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 that is not subject to offsetting. Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral posted in excess of the recognized derivative instrument.  Includes cash collateral received from counterparties of $1,285.
 
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.
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, 2020, we have four counterparties for which our exposure represents approximately 62% of Pinnacle West’s $5 million of risk management assets. This exposure relates to master agreements with counterparties and all four are rated as investment grade. Our risk management process assesses and monitors the financial exposure of all counterparties.  Despite the fact that the great majority of our 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 (dollars in thousands):
 December 31, 2020
Aggregate fair value of derivative instruments in a net liability position$21,605 
Cash collateral posted— 
Additional cash collateral in the event credit-risk related contingent features were fully triggered (a)19,510 
(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 $90 million if our debt credit ratings were to fall below investment grade.
v3.20.4
Other Income and Other Expense
12 Months Ended
Dec. 31, 2020
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 2020, 2019 and 2018 (dollars in thousands):
 
 202020192018
Other income:   
Interest income$12,210 $10,377 $8,647 
Investment gains (losses) — net2,358 — — 
Debt return on Four Corners SCR deferral (Note 4)26,121 19,541 16,153 
Debt return on Ocotillo modernization project (Note 4)15,865 20,282 — 
Miscellaneous149 63 96 
Total other income$56,703 $50,263 $24,896 
Other expense:   
Non-operating costs$(12,400)$(10,663)$(10,076)
Investment gains (losses) — net— (1,835)(417)
Miscellaneous(45,376)(a)(5,382)(7,473)
Total other expense$(57,776)$(17,880)$(17,966)
 
(a)Miscellaneous includes donation of approximately $10 million to the APS Foundation and approximately $25.2 million related to the CCT plan (see Note 4).
Other Income and Other Expense - APS
 
The following table provides detail of APS’s other income and other expense for 2020, 2019 and 2018 (dollars in thousands):
 
 202020192018
Other income:   
Interest income$9,621 $6,998 $6,496 
Debt return on Four Corners SCR deferral (Note 4)26,121 19,541 16,153 
Debt return on Ocotillo modernization project (Note 4)15,865 20,282 — 
Miscellaneous148 63 97 
Total other income$51,755 $46,884 $22,746 
Other expense:   
Non-operating costs$(10,659)$(9,612)$(9,462)
Miscellaneous(43,035)(a)(3,378)(5,830)
Total other expense$(53,694)$(12,990)$(15,292)
(a)Miscellaneous includes donations of approximately $10 million to the APS Foundation and approximately $25.2 million related to the CCT plan (see Note 4).
v3.20.4
Palo Verde Sale Leaseback Variable Interest Entities
12 Months Ended
Dec. 31, 2020
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 2021 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 2020, 2019 and 2018. 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 include the following amounts relating to the VIEs (dollars in thousands):
 December 31, 2020December 31, 2019
Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation$98,036 $101,906 
Equity-Noncontrolling interests119,290 122,540 
 
Assets of the VIEs are restricted and may only be used for payment to the noncontrolling interest holders.  These assets are reported on our consolidated financial statements.
 
APS is exposed to losses relating to these VIEs upon the occurrence of certain events that APS does not consider to be reasonably likely to occur.  Under certain circumstances (for example, the 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 $306 million beginning in 2021, and up to $456 million over the lease extension terms.
 
For regulatory ratemaking purposes, the agreements continue to be treated as operating leases and, as a result, we have recorded a regulatory asset relating to the arrangements.
v3.20.4
Investments in Nuclear Decommissioning Trusts and Other Special Use Funds
12 Months Ended
Dec. 31, 2020
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 13 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 — APS established external decommissioning trusts in accordance with NRC regulations to fund the future costs APS expects to incur to decommission Palo Verde.  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 credit losses) 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 credit losses) 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 may be used to pay active union employee medical costs incurred in the current and future periods. In 2020 and 2019, APS was reimbursed $14 million and $15 million, respectively, 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 credit losses) 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. On January 4, 2021, an additional $106 million of investments were transferred from APS other postretirement benefit trust assets into the active union employee medical account (see Note 8).
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, 2020 and December 31, 2019 (dollars in thousands): 
December 31, 2020
 Fair ValueTotal
Unrealized
Gains
Total
Unrealized
Losses
Investment Type:Nuclear Decommissioning TrustsOther Special Use FundsTotal
Equity Securities$639,851 $37,337 $677,188 $421,666 $— 
Available for Sale-Fixed Income Securities516,412 216,668 733,080 (a)46,581 (398)
Other(17,828)504 (17,324)(b)— — 
Total$1,138,435 $254,509 $1,392,944 $468,247 $(398)
(a)As of December 31, 2020, the amortized cost basis of these available-for-sale investments is $687 million.
(b)Represents net pending securities sales and purchases.

December 31, 2019
 Fair ValueTotal
Unrealized
Gains
Total
Unrealized
Losses
Investment Type:Nuclear Decommissioning TrustsOther Special Use FundsTotal
Equity Securities$529,716 $7,142 $536,858 $337,681 $— 
Available for Sale-Fixed Income Securities478,658 237,479 716,137 (a)25,795 (669)
Other2,401 474 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.
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, 2020, 2019 and 2018 (dollars in thousands):
 
 Year Ended December 31,
 Nuclear Decommissioning TrustsOther Special Use FundsTotal
2020
Realized gains$12,194 $176 $12,370 
Realized losses(5,553)(15)(5,568)
Proceeds from the sale of securities (a)675,035 144,484 819,519 
2019
Realized gains11,024 108 11,132 
Realized losses(6,972)— (6,972)
Proceeds from the sale of securities (a)473,806 245,228 719,034 
2018
Realized gains6,679 6,680 
Realized losses(13,552)— (13,552)
Proceeds from the sale of securities (a)554,385 98,648 653,033 
(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, 2020 is as follows (dollars in thousands):
 
 Nuclear Decommissioning TrustsCoal Reclamation Escrow AccountActive Union Medical TrustTotal
Less than one year$19,563 $33,079 $— $52,642 
1 year – 5 years151,537 29,722 142,311 323,570 
5 years – 10 years133,307 2,738 — 136,045 
Greater than 10 years212,005 8,818 — 220,823 
Total$516,412 $74,357 $142,311 $733,080 
v3.20.4
Changes in Accumulated Other Comprehensive Loss
12 Months Ended
Dec. 31, 2020
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, 2020 and 2019 (dollars in thousands): 
 Pension and Other Postretirement Benefits Derivative InstrumentsTotal
Balance at December 31, 2018$(45,997)$(1,711)$(47,708)
OCI (loss) before reclassifications(14,041)— (14,041)
Amounts reclassified from accumulated other comprehensive loss3,516 (a)1,137 (b)4,653 
Balance at December 31, 2019(56,522)(574)(57,096)
OCI (loss) before reclassifications(8,370)(2,089)(10,459)
Amounts reclassified from accumulated other comprehensive loss4,167 (a)592 (b)4,759 
Balance at December 31, 2020$(60,725)$(2,071)$(62,796)
(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 16).
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, 2020 and 2019 (dollars in thousands): 
 Pension and Other Postretirement Benefits Derivative InstrumentsTotal
Balance at December 31, 2018$(25,396)$(1,711)$(27,107)
OCI (loss) before reclassifications(12,572)— (12,572)
Amounts reclassified from accumulated other comprehensive loss3,020 (a)1,137 (b)4,157 
Balance at December 31, 2019(34,948)(574)(35,522)
OCI (loss) before reclassifications(9,568)(18)(9,586)
Amounts reclassified from accumulated other comprehensive loss3,598 (a)592 (b)4,190 
Balance at December 31, 2020$(40,918)$— $(40,918)
(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 16).
v3.20.4
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT
12 Months Ended
Dec. 31, 2020
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,
 202020192018
Operating expenses$7,901 $12,451 $53,844 
Other   
Equity in earnings of subsidiaries566,147 562,946 569,249 
Other expense(4,586)(3,957)(3,202)
Total561,561 558,989 566,047 
Interest expense14,021 15,069 12,074 
Income before income taxes539,639 531,469 500,129 
Income tax benefit(10,920)(6,851)(10,918)
Net income attributable to common shareholders550,559 538,320 511,047 
Other comprehensive income (loss) — attributable to common shareholders(5,700)(9,388)5,846 
Total comprehensive income — attributable to common shareholders$544,859 $528,932 $516,893 
 
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,
 20202019
ASSETS  
Current assets  
Cash and cash equivalents$19 $19 
Accounts receivable123,980 104,640 
Income tax receivable14,719 15,905 
Other current assets298 401 
Total current assets139,016 120,965 
Investments and other assets  
Investments in subsidiaries6,400,339 6,067,957 
Deferred income taxes7,589 40,757 
Other assets52,595 50,139 
Total investments and other assets6,460,523 6,158,853 
Total Assets$6,599,539 $6,279,818 
LIABILITIES AND EQUITY  
Current liabilities  
Accounts payable$5,669 $7,634 
Accrued taxes16,998 8,573 
Common dividends payable93,531 87,982 
Short-term borrowings169,000 114,675 
Current maturities of long-term debt— 450,000 
Operating lease liabilities 90 81 
Other current liabilities15,306 15,126 
Total current liabilities300,594 684,071 
Long-term debt less current maturities (Note 7)496,321 (575)
Pension liabilities17,541 17,942 
Operating lease liabilities1,683 1,780 
Other30,607 23,412 
Total deferred credits and other49,831 43,134 
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
Common stock equity
Common stock2,671,193 2,650,134 
Accumulated other comprehensive loss(62,796)(57,096)
Retained earnings3,025,106 2,837,610 
Total Pinnacle West Shareholders’ equity5,633,503 5,430,648 
Noncontrolling interests119,290 122,540 
Total Equity5,752,793 5,553,188 
Total Liabilities and Equity$6,599,539 $6,279,818 
 
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,
 202020192018
Cash flows from operating activities   
Net income$550,559 $538,320 $511,047 
Adjustments to reconcile net income to net cash provided by operating activities: 
Equity in earnings of subsidiaries — net(566,147)(562,946)(569,249)
Depreciation and amortization76 76 76 
Deferred income taxes33,007 (35,831)49,535 
Accounts receivable(7,903)182 (7,881)
Accounts payable(1,964)(2,129)1,967 
Accrued taxes and income tax receivables — net9,610 16,400 (13,535)
Dividends received from subsidiaries357,500 336,300 316,000 
Other20,163 (1,300)31,807 
Net cash flow provided by operating activities394,901 289,072 319,767 
Cash flows from investing activities   
Investments in subsidiaries(137,881)1,557 (142,796)
Repayments of loans from subsidiaries932 4,190 6,477 
Advances of loans to subsidiaries(7,261)(4,165)(500)
Net cash flow provided by (used for) investing activities(144,210)1,582 (136,819)
Cash flows from financing activities   
Issuance of long-term debt496,950 — 150,000 
Short-term debt borrowings under revolving credit facility211,690 49,000 20,000 
Short-term debt repayments under revolving credit facility(230,690)(65,000)(32,000)
Commercial paper — net73,325 54,275 (7,000)
Dividends paid on common stock(350,577)(329,643)(308,892)
Repayment of long-term debt(450,000)— — 
Common stock equity issuance — net of purchases(1,389)692 (5,055)
Other— — (1)
Net cash flow used for financing activities(250,691)(290,676)(182,948)
Net decrease in cash and cash equivalents— (22)— 
Cash and cash equivalents at beginning of year19 41 41 
Cash and cash equivalents at end of year$19 $19 $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.
v3.20.4
Summary of Significant Accounting Policies (Policies)
12 Months Ended
Dec. 31, 2020
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 18 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
 
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 accounts receivable and accrued unbilled revenues that will ultimately be uncollectible due to credit loss risk. The allowance includes a write-off component that is calculated by applying an estimated write-off factor to retail electric revenues. The write-off factor used to estimate uncollectible accounts is based upon consideration of historical collections experience, the current and forecasted economic environment, changes to our collection policies, and management’s best estimate of future collections success. (See Note 2.)
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, 2020 were as follows:
Fossil plant — 17 years;
Nuclear plant — 20 years;
Other generation — 20 years;
Transmission — 38 years;
Distribution — 34 years; and
General plant — 7 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 6.72% for 2020, 6.98% for 2019, and 7.03% for 2018.  APS compounds AFUDC semi-annually and ceases to accrue AFUDC when construction work is completed and the property is placed in service.

On June 30, 2020, the United States Federal Energy Regulatory Commission (“FERC”) issued an order granting a waiver request related to the existing Allowance for Funds Used During Construction (“AFUDC”) rate calculation beginning March 1, 2020 through February 28, 2021.  The order provides a simplified approach that companies may elect to implement in order to minimize the significant distorted effect on the AFUDC formula resulting from increased short-term debt financing during the COVID-19 pandemic.  APS has adopted this simplified approach to computing the AFUDC composite rate by using a simple average of the actual historical short-term debt balances for 2019, instead of current period short-term debt balances, and has left all other aspects of the AFUDC formula composite rate calculation unchanged. This change impacts the AFUDC composite rate in 2020 but does not impact prior years.  Furthermore, the change in the composite rate calculation does not impact our accounting treatment for these costs. The change did not have a material impact on our financial statements.
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 natural gas.  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, in addition to a non-qualified pension plan.  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 for interim storage, we now accrue a receivable and an offsetting regulatory liability through the settlement period ending December of 2022.
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 accounts and active union employee medical account, are accounted for in accordance with guidance on accounting for investments in debt and equity securities. (See Notes 13 and 19 for more information on these investments.)
Leases
Leases

We determine if an agreement is a lease at contract inception. A lease is defined as a contract, or part of a contract, that conveys the right to control the use of an identified asset for a period of time in exchange for consideration. To control the use of an identified asset an entity must have both a right to obtain substantially all of the benefits from the use of the asset and the right to direct the use of the asset. If we determine an agreement is a lease, and we are the lessee, we recognize a right-of-use lease asset and a lease liability at the lease commencement date. Lease liabilities are recognized based on the present value
of the fixed lease payments over the lease term. To present value lease liabilities we use the implicit rate in the lease if the information is readily available, otherwise we use our incremental borrowing rate determined at lease commencement. Our incremental borrowing rate is based on the rate of interest we would have to borrow on a collateralized basis over a similar term an amount equal to the lease payments in a similar economic environment. When measuring right-of-use assets and lease liabilities we exclude variable lease payments, other than those that depend on an index or rate or are in-substance fixed payments. For short-term leases with terms of 12 months or less, we do not recognize a right-of-use lease asset or lease liability. We recognize operating lease expense using a straight-line pattern over the periods of use.

APS enters into purchased power contracts that may contain leases. This occurs when a purchased power agreement designates a specific power plant, APS obtains substantially all of the economic benefits from the use of the plant and has the right to direct the use of the plant. Lease costs relating to purchased power lease contracts are reported in fuel and purchased power on the Consolidated Statements of Income, and are subject to recovery under the PSA or RES (see Note 4). We also may enter into lease agreements related to vehicles, office space, land, and other equipment. (See Note 9 for information on our lease agreements.)
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 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 and resulted in additional disclosures, these changes did not have a material impact on our financial statements. (See Note 2 for allowance for doubtful accounts related credit loss disclosures.)

ASU 2018-14, Retirement Benefits: Changes to the Disclosure Requirements for Defined Benefit Plans

In August 2018, a new accounting standard was issued that amends certain disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. The amendments remove disclosures that are no longer considered beneficial, clarifies specific disclosure requirements and adds new disclosure requirements relating to defined benefit plans. The new standard is effective for fiscal years ending after December 15, 2020. We adopted and implemented the standard on a retrospective basis in our financial statements for the year ended December 31, 2020. While the adoption of this guidance modified the disclosure requirements relating to defined benefit plans, these changes did not have a material impact on our financial statements. (See Note 8 for Retirement Plans and Other Postretirement Benefits disclosure.)
v3.20.4
Summary of Significant Accounting Policies (Tables)
12 Months Ended
Dec. 31, 2020
Accounting Policies [Abstract]  
Schedule of property, plant and equipment
Pinnacle West’s property, plant and equipment included in the December 31, 2020 and 2019 Consolidated Balance Sheets is composed of the following (dollars in thousands):

Property, Plant and Equipment:20202019
Generation$9,199,012 $8,916,872 
Transmission3,290,477 3,095,907 
Distribution7,107,007 6,690,697 
General plant1,241,389 1,132,816 
Plant in service and held for future use
20,837,885 19,836,292 
Accumulated depreciation and amortization(7,110,310)(6,637,857)
Net
13,727,575 13,198,435 
Construction work in progress937,384 808,133 
Palo Verde sale leaseback, net of accumulated depreciation98,036 101,906 
Intangible assets, net of accumulated amortization282,570 290,564 
Nuclear fuel, net of accumulated amortization113,645 123,500 
Total property, plant and equipment$15,159,210 $14,522,538 
Summary of supplemental cash flow information
The following table summarizes supplemental Pinnacle West cash flow information for each of the last three years (dollars in thousands):
 Year ended December 31,
 202020192018
Cash paid (received) during the period for:   
Income taxes, net of refunds$(3,019)$12,535 $21,173 
Interest, net of amounts capitalized216,951 218,664 208,479 
Significant non-cash investing and financing activities:   
Accrued capital expenditures$113,502 $141,297 $132,620 
Dividends declared but not paid93,531 87,982 82,675 
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,
 202020192018
Cash paid (received) during the period for:   
Income taxes, net of refunds$41,176 $(15,042)$77,942 
Interest, net of amounts capitalized206,328 204,261 196,419 
Significant non-cash investing and financing activities:   
Accrued capital expenditures$113,502 $141,297 $132,620 
Dividends declared but not paid93,500 88,000 82,700 
v3.20.4
Revenue (Tables)
12 Months Ended
Dec. 31, 2020
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,Year Ended December 31,
202020192018
Retail Electric Service
Residential$1,929,178 (a)$1,761,122 $1,867,370 
Non-Residential1,486,098 1,509,514 1,628,891 
Wholesale Energy Sales93,345 121,805 109,198 
Transmission Services for Others65,859 62,460 60,261 
Other Sources12,502 16,308 25,527 
Total Operating Revenues$3,586,982 $3,471,209 $3,691,247 
(a) Residential revenues for the year ended December 31, 2020 reflect a $24 million reduction related to the Arizona Attorney General matter. (See Note 11).
Schedule of Allowance for Doubtful Accounts
The following table provides a rollforward of Pinnacle West’s allowance for doubtful accounts all of which primarily relates to APS (dollars in thousands):
Year Ended December 31, 2020Year Ended December 31, 2019Year Ended December 31, 2018
Allowance for doubtful accounts, balance at beginning of period$8,171 $4,069 $2,513 
Bad debt expense20,633 11,819 10,870 
Actual write-offs(9,022)(7,717)(9,314)
Allowance for doubtful accounts, balance at end of period$19,782 $8,171 $4,069 
v3.20.4
Regulatory Matters (Tables)
12 Months Ended
Dec. 31, 2020
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 2020 and 2019 (dollars in thousands):
 Twelve Months Ended
December 31,
 20202019
Beginning balance$70,137 $37,164 
Deferred fuel and purchased power costs — current period93,651 82,481 
Amounts refunded/(charged) to customers12,047 (49,508)
Ending balance$175,835 $70,137 
Schedule of regulatory assets
The detail of regulatory assets is as follows (dollars in thousands):
SDecember 31, 2020December 31, 2019
 Amortization ThroughCurrentNon-CurrentCurrentNon-Current
Pension (a)$— $469,953 $— $660,223 
Deferred fuel and purchased power (b) (c)2021175,835 — 70,137 — 
Income taxes — AFUDC equity20507,169 158,776 6,800 154,974 
Retired power plant costs203328,181 114,214 28,182 142,503 
Ocotillo deferralN/A— 95,723 — 38,144 
SCR deferralN/A— 81,307 — 52,644 
Deferred property taxes20278,569 49,626 8,569 58,196 
Lost fixed cost recovery (b)202141,807 — 26,067 — 
Deferred compensation2036— 36,195 — 36,464 
Four Corners cost deferral20248,077 24,075 8,077 32,152 
Income taxes — investment tax credit basis adjustment20491,113 24,291 1,098 24,981 
Palo Verde VIEs (Note 18)2046— 21,255 — 20,635 
Coal reclamation20261,068 16,999 1,546 17,688 
Deferred fuel and purchased power — mark-to-market (Note 16)20243,341 9,244 36,887 33,185 
Loss on reacquired debt20381,689 10,877 1,637 12,031 
Mead-Phoenix transmission line — contributions in aid of construction2050332 9,380 332 9,712 
Demand side management (b)2022— 7,268 — — 
Tax expense adjustor mechanism (b)20216,226 — 1,612 — 
Tax expense of Medicare subsidy20241,235 3,704 1,235 4,940 
PSA interest20214,355 — 1,917 — 
TCA balancing account (b)2021— — 6,324 2,885 
OtherVarious2,716 1,100 2,787 2,716 
Total regulatory assets (d) $291,713 $1,133,987 $203,207 $1,304,073 
(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, 2020December 31, 2019
 Amortization ThroughCurrentNon-CurrentCurrentNon-Current
Excess deferred income taxes - ACC — Tax Cuts and Jobs Act (a)2046$41,330 $1,012,583 $59,918 $1,054,053 
Excess deferred income taxes - FERC — Tax Cuts and Jobs Act (a)20587,240 229,147 6,302 237,357 
Asset retirement obligations2057— 506,049 — 418,423 
Other postretirement benefits(d)37,705 349,588 37,575 139,634 
Removal costs(c)52,844 103,008 47,356 136,072 
Income taxes — change in rates20502,839 66,553 2,797 68,265 
Four Corners coal reclamation20385,460 49,435 1,059 51,704 
Spent nuclear fuel20276,768 44,221 6,676 51,019 
Income taxes — deferred investment tax credit20492,231 48,648 2,202 50,034 
Renewable energy standard (b)202139,442 103 39,287 10,300 
Sundance maintenance20312,989 11,508 5,698 11,319 
Property tax deferralN/A— 13,856 — 7,046 
Demand side management (b)202110,819 — 15,024 24,146 
FERC transmission true up20226,598 3,008 1,045 2,004 
TCA balancing account (b)20222,902 4,672 — — 
Tax expense adjustor mechanism (b) (e)20217,089 — 7,018 — 
Active union medical trustN/A— 6,057 — 2,041 
Deferred gains on utility property20222,423 1,544 2,423 4,163 
OtherVarious409 189 532 255 
Total regulatory liabilities $229,088 $2,450,169 $234,912 $2,267,835 

(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.
(e)Pursuant to Decision 77852, the ACC has authorized APS to return to customers up to $7 million of liability recorded to the TEAM balancing account through December 31, 2021. Should new base rates become effective prior to December 31, 2021, any remaining unreturned balance is anticipated to be included in the new base rates.
v3.20.4
Income Taxes (Tables)
12 Months Ended
Dec. 31, 2020
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 ConsolidatedAPS Consolidated
 202020192018202020192018
Total unrecognized tax benefits, January 1$43,435 $40,731 $41,966 $43,435 $40,731 $41,966 
Additions for tax positions of the current year3,418 3,373 3,436 3,418 3,373 3,436 
Additions for tax positions of prior years1,431 1,843 2,696 1,431 1,843 2,696 
Reductions for tax positions of prior years for:      
Changes in judgment(1,965)(2,078)(1,764)(1,965)(2,078)(1,764)
Settlements with taxing authorities— — — — — — 
Lapses of applicable statute of limitations(664)(434)(5,603)(664)(434)(5,603)
Total unrecognized tax benefits, December 31$45,655 $43,435 $40,731 $45,655 $43,435 $40,731 
Summary of unrecognized tax benefits
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 ConsolidatedAPS Consolidated
 202020192018202020192018
Tax positions, that if recognized, would decrease our effective tax rate$25,714 $22,813 $19,504 $25,714 $22,813 $19,504 
The amount of interest expense or benefit recognized related to unrecognized tax benefits are as follows (dollars in thousands):
Pinnacle West ConsolidatedAPS Consolidated
 202020192018202020192018
Unrecognized tax benefit interest expense/(benefit) recognized$266 $459 $(780)$266 $459 $(780)
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 ConsolidatedAPS Consolidated
 202020192018202020192018
Unrecognized tax benefit interest accrued $1,855 $1,589 $1,130 $1,855 $1,589 $1,130 
Components of income tax expense he components of income tax expense are as follows (dollars in thousands):
Pinnacle West ConsolidatedAPS Consolidated
 Year Ended December 31,Year Ended December 31,
 202020192018202020192018
Current:   
Federal$11,869 $(13,551)$18,375 $57,299 $(54,697)$88,180 
State1,932 3,195 3,342 99 695 1,877 
Total current13,801 (10,356)21,717 57,398 (54,002)90,057 
Deferred:      
Federal53,398 (14,982)94,721 15,122 29,321 32,436 
State10,974 9,565 17,464 16,244 15,109 22,321 
Total deferred64,372 (5,417)112,185 31,366 44,430 54,757 
Income tax expense/(benefit)$78,173 $(15,773)$133,902 $88,764 $(9,572)$144,814 
Comparison of pretax income from continuing operations at the federal income tax rate to income tax expense - continuing operations he following chart compares pretax income at the 21% statutory federal income tax rate to income tax expense (dollars in thousands):
Pinnacle West ConsolidatedAPS Consolidated
 Year Ended December 31,Year Ended December 31,
 202020192018202020192018
Federal income tax expense at statutory rate$136,127 $113,828 $139,533 $142,020 $120,790 $154,260 
Increases (reductions) in tax expense resulting from:      
State income tax net of federal income tax benefit19,146 18,599 23,115 20,124 19,267 24,531 
State income tax credits net of federal income tax benefit(8,951)(8,519)(6,704)(7,213)(6,781)(5,440)
Nondeductible expenditures associated with ballot initiative— — 7,879 — — — 
Stock compensation34 (2,252)(1,804)183 (1,054)(780)
Excess deferred income taxes — Tax Cuts and Jobs Act(50,543)(124,082)(6,725)(50,543)(124,082)(4,715)
Allowance for equity funds used during construction (see Note 1)(2,747)(2,476)(7,231)(2,747)(2,476)(7,231)
Palo Verde VIE noncontrolling interest (see Note 18)(4,094)(4,094)(4,094)(4,094)(4,094)(4,094)
Investment tax credit amortization(7,510)(6,851)(6,742)(7,510)(6,851)(6,742)
Other(3,289)74 (3,325)(1,456)(4,291)(4,975)
Income tax expense/(benefit)$78,173 $(15,773)$133,902 $88,764 $(9,572)$144,814 
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 ConsolidatedAPS Consolidated
 December 31,December 31,
 2020201920202019
DEFERRED TAX ASSETS  
Risk management activities$4,287 $17,552 $4,287 $17,552 
Regulatory liabilities:   
Excess deferred income taxes — Tax Cuts and Jobs Act319,091 335,877 319,091 335,877 
Asset retirement obligation and removal costs157,470 143,011 157,470 143,011 
Unamortized investment tax credits50,879 52,236 50,879 52,236 
Other postretirement benefits95,778 43,841 95,778 43,841 
Other43,551 52,382 43,551 52,382 
Operating lease liabilities107,853 15,497 107,414 15,497 
Pension liabilities45,853 73,210 40,168 67,976 
Coal reclamation liabilities42,065 40,837 42,065 40,837 
Renewable energy incentives25,355 28,066 25,355 28,066 
Credit and loss carryforwards26,460 54,795 8,034 10,992 
Other78,113 47,605 78,113 55,451 
Total deferred tax assets996,755 904,909 972,205 863,718 
DEFERRED TAX LIABILITIES   
Plant-related(2,489,899)(2,448,458)(2,489,899)(2,448,458)
Risk management activities(1,174)(27)(1,174)(27)
Pension and other postretirement assets(123,462)(21,892)(122,580)(21,458)
Other special use funds(42,927)(44,507)(42,927)(44,507)
Operating lease right-of-use assets(107,853)(15,497)(107,414)(15,497)
Regulatory assets:   
Allowance for equity funds used during construction(41,038)(40,023)(41,038)(40,023)
Deferred fuel and purchased power(47,673)(35,162)(47,673)(35,162)
Pension benefits(116,219)(163,339)(116,219)(163,339)
Retired power plant costs (35,214)(42,228)(35,214)(42,228)
Other(106,227)(82,722)(106,227)(82,722)
Other(20,472)(3,393)(5,513)(3,393)
Total deferred tax liabilities(3,132,158)(2,897,248)(3,115,878)(2,896,814)
Deferred income taxes — net$(2,135,403)$(1,992,339)$(2,143,673)$(2,033,096)
v3.20.4
Lines of Credit and Short-Term Borrowings (Tables)
12 Months Ended
Dec. 31, 2020
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, 2020 and 2019 (dollars in thousands):
 
December 31, 2020December 31, 2019
Pinnacle WestAPSTotalPinnacle WestAPSTotal
Commitments under Credit Facilities$231,000 $1,000,000 $1,231,000 $250,000 $1,000,000 $1,250,000 
Outstanding Commercial Paper, Term Loan and Revolving Credit Facility Borrowings(169,000)— (169,000)(114,675)— (114,675)
Amount of Credit Facilities Available$62,000 $1,000,000 $1,062,000 $135,325 $1,000,000 $1,135,325 
Weighted-Average Commitment Fees0.125%0.100%0.125%0.100%
v3.20.4
Long-Term Debt and Liquidity Matters (Tables)
12 Months Ended
Dec. 31, 2020
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, 2020 and 2019 (dollars in thousands):
 MaturityInterestDecember 31,
 Dates (a)Rates20202019
APS    
Pollution control bonds:    
Variable2029(b)$35,975 $35,975 
Fixed20244.70%— 115,150 
Total pollution control bonds  35,975 151,125 
Senior unsecured notes2024-2050
2.55%-6.88%
5,830,000 4,875,000 
Term loans(c)— 200,000 
Unamortized discount  (15,900)(12,434)
Unamortized premium  14,781 7,423 
Unamortized debt issuance cost(46,911)(37,981)
Total APS long-term debt  5,817,945 5,183,133 
Less current maturities — 350,000 
Total APS long-term debt less current maturities  5,817,945 4,833,133 
Pinnacle West    
Senior unsecured notes20251.3%500,000 300,000 
Term loan(d)— 150,000 
Unamortized discount(44)(57)
Unamortized debt issuance cost(3,635)(518)
Total Pinnacle West long-term debt496,321 449,425 
Less current maturities— 450,000 
Total Pinnacle West long-term debt less current maturities496,321 (575)
TOTAL LONG-TERM DEBT LESS CURRENT MATURITIES
  $6,314,266 $4,832,558 
(a)    This schedule does not reflect the timing of redemptions that may occur prior to maturities.
(b)    The weighted-average rate for the variable rate pollution control bonds was 0.18% at December 31, 2020 and 1.54% at December 31, 2019.
(c)    The weighted-average interest rate was 2.12% at December 31, 2019. This term loan was repaid on May 26, 2020. See additional details below.
(d)    The weighted-average interest rate was 2.20% at December 31, 2019. This term loan was repaid on June 19, 2020. See additional details below.
Principal payments due on Pinnacle West's and APS's total long-term debt
The following table shows principal payments due on Pinnacle West’s and APS’s total long-term debt (dollars in thousands):
YearConsolidated
Pinnacle West
Consolidated
APS
2021$— $— 
2022— — 
2023— — 
2024250,000 250,000 
2025800,000 300,000 
Thereafter5,315,975 5,315,975 
Total$6,365,975 $5,865,975 
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, 2020
As of
December 31, 2019
 Carrying
Amount
Fair ValueCarrying
Amount
Fair Value
Pinnacle West$496,321 $509,050 $449,425 $450,822 
APS5,817,945 7,103,791 5,183,133 5,743,570 
Total$6,314,266 $7,612,841 $5,632,558 $6,194,392 
v3.20.4
Retirement Plans and Other Postretirement Benefits (Tables)
12 Months Ended
Dec. 31, 2020
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 PlansOther Benefits Plans
 202020192018202020192018
Service cost-benefits earned during the period
$56,233 $49,902 $56,669 $22,236 $18,369 $21,100 
Interest cost on benefit obligation118,567 136,843 124,689 25,857 29,894 28,147 
Expected return on plan assets(187,443)(171,884)(182,853)(40,077)(38,412)(42,082)
Amortization of:      
Prior service credit— — — (37,575)(37,821)(37,842)
Net actuarial loss34,612 42,584 32,082 — — — 
Net periodic benefit cost/(benefit)$21,969 $57,445 $30,587 $(29,559)$(27,970)$(30,677)
Portion of cost/(benefit) charged to expense$3,386 $30,312 $10,120 $(20,966)$(19,859)$(21,426)
Schedule of changes in the benefit obligations and funded status
The following table shows the plans’ changes in the benefit obligations and funded status (dollars in thousands):
 Pension PlansOther Benefits Plans
 2020201920202019
Change in Benefit Obligation    
Benefit obligation at January 1$3,613,114 $3,190,626 $746,924 $676,771 
Service cost56,233 49,902 22,236 18,369 
Interest cost118,567 136,843 25,857 29,894 
Benefit payments(191,704)(177,882)(31,511)(32,486)
Actuarial (gain) loss306,657 413,625 (139,472)54,376 
Benefit obligation at December 313,902,867 3,613,114 624,034 746,924 
Change in Plan Assets    
Fair value of plan assets at January 13,318,351 2,733,476 837,494 723,677 
Actual return on plan assets642,373 602,030 150,076 144,095 
Employer contributions100,000 150,000 — — 
Benefit payments(174,180)(167,155)(26,405)(30,278)
Fair value of plan assets at December 313,886,544 3,318,351 961,165 837,494 
Funded Status at December 31$(16,323)$(294,763)$337,131 $90,570 
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 information for pension plans with an accumulated obligation in excess of plan assets (dollars in thousands):
As of December 31,
 20202019
Accumulated benefit obligation171,672 169,091 
Fair value of plan assets— — 
 
The Pinnacle West Capital Corporation Retirement Plan is more than 100% funded on an accumulated benefit obligation basis at December 31, 2020 and December 31, 2019, therefore the only pension plan with an accumulated benefit obligation in excess of plan assets in 2020 and 2019 is a non-qualified supplemental excess benefit retirement plan.

The following table shows information for pension plans with a projected benefit obligation in excess of plan assets (dollars in thousands):
As of December 31,
 20202019
Projected benefit obligation182,184 3,613,114 
Fair value of plan assets— 3,318,351 
Schedule of amounts recognized on the Consolidated Balance Sheets
The following table shows the amounts recognized on the Consolidated Balance Sheets (dollars in thousands):
 Pension PlansOther Benefits Plans
 2020201920202019
Noncurrent asset$165,861 $— $337,131 $90,570 
Current liability(15,700)(14,578)— — 
Noncurrent liability(166,484)(280,185)— — 
Net amount recognized$(16,323)$(294,763)$337,131 $90,570 
Schedule of accumulated other comprehensive loss
The following table shows the details related to accumulated other comprehensive loss as of December 31, 2020 and 2019 (dollars in thousands): 
 Pension PlansOther Benefits Plans
 2020201920202019
Net actuarial loss (gain)$552,301 $735,186 $(237,233)$12,238 
Prior service credit— — (152,337)(189,912)
APS’s portion recorded as a regulatory (asset) liability(469,953)(660,223)387,293 177,209 
Income tax expense (benefit)(20,364)(18,546)1,018 570 
Accumulated other comprehensive loss (gain)$61,984 $56,417 $(1,259)$105 
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,
 20202019202020192018
Discount rate – pension plans2.53 %3.30 %3.30 %4.34 %3.65 %
Discount rate – other benefits plans2.63 %3.42 %3.42 %4.39 %3.71 %
Rate of compensation increase4.00 %4.00 %4.00 %4.00 %4.00 %
Expected long-term return on plan assets - pension plansN/AN/A5.75 %6.25 %6.05 %
Expected long-term return on plan assets - other benefit plansN/AN/A4.85 %5.40 %5.40 %
Initial healthcare cost trend rate (pre-65 participants)6.50 %7.00 %7.00 %7.00 %7.00 %
Ultimate healthcare cost trend rate (pre-65 participants)4.75 %4.75 %4.75 %4.75 %4.75 %
Number of years to ultimate trend rate (pre-65 participants)56578
Initial and ultimate healthcare cost trend rate (post-65 participants) (a)2.00 %4.75 %4.75 %4.75 %4.75 %
Interest crediting rate – cash balance pension plans4.50 %4.50 %4.50 %4.50 %4.50 %
 
(a)See discussion above relating to this assumptions impact on benefit obligations and the January 2021 asset transfer to the Active Union Employee Medical Account.
Schedule of fair value of pension plan and other postretirement benefit plan assets, by asset category
Based on the IPS, and given the pension plan’s funded status at year-end 2020, the target and actual allocation for the pension plan at December 31, 2020 are as follows:
Pension Plans
 Target AllocationActual Allocation
Long-term fixed income assets72 %68 %
Return-generating assets28 %32 %
Total100 %100 %

The permissible range is within +/-3% of the target allocation shown in the above table, and also considers the plan’s funded status. At December 31, 2020, the return-seeking assets were slightly outside the target allocation permissible range and were rebalanced to within the target range during January 2021.

The following table presents the additional target allocations, as a percent of total pension plan assets, for the return-generating assets:
Asset ClassTarget Allocation
Equities in US and other developed markets17 %
Equities in emerging markets%
Alternative investments%
Total28 %
The following table presents the actual allocations of the investment for the other postretirement benefit plan at December 31, 2020:
Other Benefits Plans
Actual Allocation
Long-term fixed income assets55 %
Return-generating assets45 %
Total100 %
The fair value of Pinnacle West’s pension plan and other postretirement benefit plan assets at December 31, 2020, by asset category, are as follows (dollars in thousands):
 
 Level 1Level 2Other (a)Total
Pension Plan:   
Cash and cash equivalents$9,911 $— $— $9,911 
Fixed income securities:   
Corporate— 1,684,782 — 1,684,782 
U.S. Treasury794,571 — — 794,571 
Other (b)— 112,224 — 112,224 
Common stock equities (c)331,058 — — 331,058 
Mutual funds (d)262,765 — — 262,765 
Common and collective trusts:
   Equities— — 407,522 407,522 
   Real estate— — 191,595 191,595 
Partnerships— — 22,420 22,420 
Short-term investments and other (e)— — 69,696 69,696 
Total $1,398,305 $1,797,006 $691,233 $3,886,544 
Other Benefits:    
Cash and cash equivalents$1,909 $— $— $1,909 
Fixed income securities:   
Corporate— 221,488 — 221,488 
U.S. Treasury258,102 — — 258,102 
Other (b)— 8,316 — 8,316 
Common stock equities (c)175,605 — — 175,605 
Mutual funds (d)34,310 — — 34,310 
Common and collective trusts:   
   Equities— — 94,674 94,674 
   Real estate— — 19,778 19,778 
Short-term investments and other (e)142,995 — 3,988 146,983 
Total $612,921 $229,804 $118,440 $961,165 
(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, 2019, by asset category, are as follows (dollars in thousands):
 Level 1Level 2Other (a)Total
Pension Plan:   
Cash and cash equivalents$9,370 $— $— $9,370 
Fixed income securities:   
Corporate— 1,541,729 — 1,541,729 
U.S. Treasury406,112 — — 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. Treasury353,650 — — 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 U.S. and international common stock equities.
(e)This category includes plan receivables and payables.
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):
YearPension PlansOther Benefits Plans
2021$210,119 $31,204 
2022209,593 31,731 
2023215,527 32,196 
2024220,241 31,914 
2025220,787 31,484 
Years 2026-20301,116,848 153,536 
v3.20.4
Leases (Tables)
12 Months Ended
Dec. 31, 2020
Leases [Abstract]  
Schedule of lease costs
The following table provides information related to our lease costs (dollars in thousands):
Year Ended
December 31, 2020
Year Ended
December 31, 2019
Purchased Power Lease ContractsLand, Property & Equipment LeasesTotalPurchased Power Lease ContractsLand, Property & Equipment LeasesTotal
Operating lease cost$68,883 $18,493 $87,376 $42,190 $18,038 $60,228 
Variable lease cost121,359 972 122,331 113,233 782 114,015 
Short-term lease cost— 3,804 3,804 — 4,385 4,385 
Total lease cost$190,242 $23,269 $213,511 $155,423 $23,205 $178,628 
The following tables provide other additional information related to operating lease liabilities (dollars in thousands):
Year Ended
December 31, 2020
Year Ended December 31, 2019
Cash paid for amounts included in the measurement of lease liabilities — operating cash flows:$75,097 $69,075 
Right-of-use operating lease assets obtained in exchange for operating lease liabilities441,653 11,262 

December 31, 2020December 31, 2019
Weighted average remaining lease term6 years13 years
Weighted average discount rate (a)1.69 %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.
Schedule of maturities of operating lease liabilities
The following table provides information related to the maturity of our operating lease liabilities (dollars in thousands):
December 31, 2020
YearPurchased Power Lease ContractsLand, Property & Equipment LeasesTotal
2021$66,658 $14,455 $81,113 
202268,325 10,849 79,174 
202370,033 8,503 78,536 
202471,784 6,104 77,888 
202573,578 4,400 77,978 
Thereafter36,760 37,314 74,074 
Total lease commitments387,138 81,625 468,763 
Less imputed interest14,375 18,267 32,642 
Total lease liabilities$372,763 $63,358 $436,121 
v3.20.4
Jointly-Owned Facilities (Tables)
12 Months Ended
Dec. 31, 2020
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, 2020 (dollars in thousands):
 Percent
Owned
 Plant in
Service
Accumulated
Depreciation
Construction
Work in
Progress
Generating facilities:     
Palo Verde Units 1 and 329.1 %$1,911,339 $1,108,883 $26,623 
Palo Verde Unit 2 (a)16.8 %649,035 379,305 7,268 
Palo Verde Common28.0 %(b)774,054 320,107 41,607 
Palo Verde Sale Leaseback (a)351,050 253,014 — 
Four Corners Generating Station 63.0 %1,621,418 581,436 35,028 
Cholla common facilities (c)50.5 %193,807 109,447 1,206 
Transmission facilities:     
ANPP 500kV System33.5 % (b)131,991 52,626 3,859 
Navajo Southern System26.0 %(b)89,113 33,536 1,215 
Palo Verde — Yuma 500kV System25.3 %(b)23,247 6,681 433 
Four Corners Switchyards61.8 % (b)69,441 17,009 3,145 
Phoenix — Mead System17.1 %(b)39,437 19,072 73 
Palo Verde — Rudd 500kV System50.0 %93,123 28,206 1,921 
Morgan — Pinnacle Peak System64.6 % (b)117,497 20,754 912 
Round Valley System50.0 %531 174 13 
Palo Verde — Morgan System88.9 %(b)257,220 20,943 530 
Hassayampa — North Gila System80.0 %148,067 16,080 — 
Cholla 500kV Switchyard85.7 %7,896 1,850 940 
Saguaro 500kV Switchyard60.0 %21,669 13,229 
Kyrene — Knox System50.0 %578 323 — 
(a)See Note 18.
(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. Cholla Unit 4 was retired on December 24, 2020.
v3.20.4
Commitments and Contingencies (Tables)
12 Months Ended
Dec. 31, 2020
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,
 20212022202320242025Thereafter
Coal take-or-pay commitments (a)$182,569 $183,604 $184,540 $186,804 $177,114 $1,024,854 
 
(a)Total take-or-pay commitments are approximately $1.9 billion.  The total net present value of these commitments is approximately $1.5 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,
 202020192018
Total purchases$189,817 $204,888 $206,093 
v3.20.4
Asset Retirement Obligations (Tables)
12 Months Ended
Dec. 31, 2020
Asset Retirement Obligation Disclosure [Abstract]  
Change in asset retirement obligations
The following table shows the change in our asset retirement obligations for 2020 and 2019 (dollars in thousands):

 20202019
Asset retirement obligations at the beginning of year$657,218 $726,545 
Changes attributable to:  
Accretion expense38,652 39,726 
Settlements(9,710)(12,591)
Estimated cash flow revisions18,923 (96,462)
Asset retirement obligations at the end of year$705,083 $657,218 
v3.20.4
Fair Value Measurements (Tables)
12 Months Ended
Dec. 31, 2020
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, 2020 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):

Level 1Level 2Level 3OtherTotal
Assets
Risk management activities — derivative instruments:
Commodity contracts$— $9,016 $$(4,271)(a)$4,749 
Nuclear decommissioning trust:
Equity securities29,796 — — (17,828)(b)11,968 
U.S. commingled equity funds— — — 610,055 (c)610,055 
U.S. Treasury debt164,514 — — — 164,514 
Corporate debt— 149,509 — — 149,509 
Mortgage-backed securities— 99,623 — — 99,623 
Municipal bonds— 89,705 — — 89,705 
Other fixed income— 13,061 — — 13,061 
Subtotal nuclear decommissioning trust194,310 351,898 — 592,227 1,138,435 
Other special use funds:
Equity securities37,337 — — 504 (b)37,841 
U.S. Treasury debt203,220 — — — 203,220 
Municipal bonds— 13,448 — — 13,448 
Subtotal other special use funds240,557 13,448 — 504 254,509 
Total assets$434,867 $374,362 $$588,460 $1,397,693 
Liabilities
Risk management activities — derivative instruments:
Commodity contracts$— $(20,498)$(1,107)$2,986 (a)$(18,619)

(a)Represents counterparty netting, margin, and collateral (see Note 16).
(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, 2019 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):
 
Level 1Level 2Level 3OtherTotal
Assets
Risk management activities — derivative instruments:
Commodity contracts$— $551 $33 $(69)(a)$515 
Nuclear decommissioning trust:
Equity securities10,872 — — 2,401 (b)13,273 
U.S. commingled equity funds— — — 518,844 (c)518,844 
U.S. Treasury debt160,607 — — — 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 trust171,479 318,051 — 521,245 1,010,775 
Other special use funds:
Equity securities7,142 — — 474 (b)7,616 
U.S. Treasury debt232,848 — — — 232,848 
Municipal bonds— 4,631 — — 4,631 
Subtotal other special use funds239,990 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 16).
(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.
v3.20.4
Earnings Per Share (Tables)
12 Months Ended
Dec. 31, 2020
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 (in thousands, except per share amounts):
 202020192018
Net income attributable to common shareholders$550,559 $538,320 $511,047 
Weighted average common shares outstanding — basic112,666 112,443 112,129 
Net effect of dilutive securities:   
Contingently issuable performance shares and restricted stock units276 315 421 
Weighted average common shares outstanding — diluted112,942 112,758 112,550 
Earnings per weighted-average common share outstanding
Net income attributable to common shareholders — basic$4.89 $4.79 $4.56 
Net income attributable to common shareholders — diluted$4.87 $4.77 $4.54 
v3.20.4
Stock-Based Compensation (Tables)
12 Months Ended
Dec. 31, 2020
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 2020, 2019 and 2018:

Restricted Stock Units, Stock Grants, and Stock Units (a)Performance Shares (b)
 202020192018202020192018
Units granted118,403 109,106 132,997 122,830 142,874 171,708 
Weighted-average grant date fair value$71.70 $89.15 $77.51 $104.74 $92.16 $76.56 
(a)Units granted includes awards that will be cash settled of 45,646 in 2020, 48,972 in 2019, and 66,252 in 2018.
(b)Reflects the target payout level.
The following table is a summary of the status of non-vested awards as of December 31, 2020 and changes during the year:

Restricted Stock Units, Stock Grants, and Stock UnitsPerformance Shares
SharesWeighted-Average
Grant Date
Fair Value
Shares (b)Weighted-Average
Grant Date
Fair Value
Nonvested at January 1, 2020242,612 $81.38 306,970 $83.65 
Granted118,403 71.70 122,830 104.74 
Vested(136,893)73.80 (161,906)76.53 
Forfeited (c)(3,565)82.61 (7,890)85.06 
Nonvested at December 31, 2020220,557 (a)77.93 260,004 98.28 
Vested Awards Outstanding at December 31, 202082,921 161,906 
 
(a)Includes 126,996 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 2020, 2019 and 2018:

Restricted Stock Units, Stock Grants, and Stock Units (a)Performance Shares (b)
 202020192018202020192018
Units granted118,403 109,106 132,997 122,830 142,874 171,708 
Weighted-average grant date fair value$71.70 $89.15 $77.51 $104.74 $92.16 $76.56 
(a)Units granted includes awards that will be cash settled of 45,646 in 2020, 48,972 in 2019, and 66,252 in 2018.
(b)Reflects the target payout level.
The following table is a summary of the status of non-vested awards as of December 31, 2020 and changes during the year:

Restricted Stock Units, Stock Grants, and Stock UnitsPerformance Shares
SharesWeighted-Average
Grant Date
Fair Value
Shares (b)Weighted-Average
Grant Date
Fair Value
Nonvested at January 1, 2020242,612 $81.38 306,970 $83.65 
Granted118,403 71.70 122,830 104.74 
Vested(136,893)73.80 (161,906)76.53 
Forfeited (c)(3,565)82.61 (7,890)85.06 
Nonvested at December 31, 2020220,557 (a)77.93 260,004 98.28 
Vested Awards Outstanding at December 31, 202082,921 161,906 
 
(a)Includes 126,996 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.
v3.20.4
Derivative Accounting (Tables)
12 Months Ended
Dec. 31, 2020
Derivative Instruments and Hedging Activities Disclosure [Abstract]  
Outstanding gross notional amount of derivatives, which represents both purchases and sales (does not reflect net position)
The following table shows the outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position):
 
Quantity
CommodityUnit of MeasureDecember 31, 2020December 31, 2019
PowerGWh368 193 
GasBillion cubic feet205 257 
Gains and losses from derivative instruments in designated cash flow accounting hedges relationships
The following table provides information about APS’s gains and losses from derivative instruments in designated cash flow accounting hedging relationships (dollars in thousands):
 
Financial Statement Year Ended
December 31,
Commodity ContractsLocation202020192018
Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a)Fuel and purchased power (b)(763)(1,512)(2,000)
(a)During the years ended December 31, 2020, 2019, and 2018, we had no gains or 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 (dollars in thousands):
Financial Statement Year Ended
December 31,
Commodity ContractsLocation202020192018
Net Loss Recognized in IncomeOperating revenues $— $— $(2,557)
Net Loss Recognized in IncomeFuel and purchased power (a)(3,178)(84,953)(12,951)
Total $(3,178)$(84,953)$(15,508)
(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.  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, 2020:
(dollars in thousands)
Gross 
Recognized 
Derivatives
(a)
Amounts 
Offset
(b)
Net
Recognized
Derivatives
Other
(c)
Amount 
Reported on 
Balance Sheet
Current assets$5,870 $(2,939)$2,931 $— $2,931 
Investments and other assets3,150 (1,332)1,818 — 1,818 
Total assets9,020 (4,271)4,749 — 4,749 
Current liabilities(9,211)2,939 (6,272)(1,285)(7,557)
Deferred credits and other(12,394)1,332 (11,062)— (11,062)
Total liabilities(21,605)4,271 (17,334)(1,285)(18,619)
Total$(12,585)$— $(12,585)$(1,285)$(13,870)
(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 that is not subject to offsetting. Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral posted in excess of the recognized derivative instrument.  Includes cash collateral received from counterparties of $1,285.
 
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.
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.  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, 2020:
(dollars in thousands)
Gross 
Recognized 
Derivatives
(a)
Amounts 
Offset
(b)
Net
Recognized
Derivatives
Other
(c)
Amount 
Reported on 
Balance Sheet
Current assets$5,870 $(2,939)$2,931 $— $2,931 
Investments and other assets3,150 (1,332)1,818 — 1,818 
Total assets9,020 (4,271)4,749 — 4,749 
Current liabilities(9,211)2,939 (6,272)(1,285)(7,557)
Deferred credits and other(12,394)1,332 (11,062)— (11,062)
Total liabilities(21,605)4,271 (17,334)(1,285)(18,619)
Total$(12,585)$— $(12,585)$(1,285)$(13,870)
(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 that is not subject to offsetting. Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral posted in excess of the recognized derivative instrument.  Includes cash collateral received from counterparties of $1,285.
 
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.
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 (dollars in thousands):
 December 31, 2020
Aggregate fair value of derivative instruments in a net liability position$21,605 
Cash collateral posted— 
Additional cash collateral in the event credit-risk related contingent features were fully triggered (a)19,510 
(a)This amount is after counterparty netting and includes those contracts which qualify for scope exceptions, which are excluded from the derivative details above.
v3.20.4
Other Income and Other Expense (Tables)
12 Months Ended
Dec. 31, 2020
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 2020, 2019 and 2018 (dollars in thousands):
 
 202020192018
Other income:   
Interest income$12,210 $10,377 $8,647 
Investment gains (losses) — net2,358 — — 
Debt return on Four Corners SCR deferral (Note 4)26,121 19,541 16,153 
Debt return on Ocotillo modernization project (Note 4)15,865 20,282 — 
Miscellaneous149 63 96 
Total other income$56,703 $50,263 $24,896 
Other expense:   
Non-operating costs$(12,400)$(10,663)$(10,076)
Investment gains (losses) — net— (1,835)(417)
Miscellaneous(45,376)(a)(5,382)(7,473)
Total other expense$(57,776)$(17,880)$(17,966)
 
(a)Miscellaneous includes donation of approximately $10 million to the APS Foundation and approximately $25.2 million related to the CCT plan (see Note 4).
The following table provides detail of APS’s other income and other expense for 2020, 2019 and 2018 (dollars in thousands):
 
 202020192018
Other income:   
Interest income$9,621 $6,998 $6,496 
Debt return on Four Corners SCR deferral (Note 4)26,121 19,541 16,153 
Debt return on Ocotillo modernization project (Note 4)15,865 20,282 — 
Miscellaneous148 63 97 
Total other income$51,755 $46,884 $22,746 
Other expense:   
Non-operating costs$(10,659)$(9,612)$(9,462)
Miscellaneous(43,035)(a)(3,378)(5,830)
Total other expense$(53,694)$(12,990)$(15,292)
(a)Miscellaneous includes donations of approximately $10 million to the APS Foundation and approximately $25.2 million related to the CCT plan (see Note 4).
v3.20.4
Palo Verde Sale Leaseback Variable Interest Entities (Tables)
12 Months Ended
Dec. 31, 2020
Variable Interest Entities [Abstract]  
Amounts relating to the VIEs included in Consolidated Balance Sheets
Our Consolidated Balance Sheets include the following amounts relating to the VIEs (dollars in thousands):
 December 31, 2020December 31, 2019
Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation$98,036 $101,906 
Equity-Noncontrolling interests119,290 122,540 
v3.20.4
Investments in Nuclear Decommissioning Trusts and Other Special Use Funds (Tables)
12 Months Ended
Dec. 31, 2020
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, 2020 and December 31, 2019 (dollars in thousands): 
December 31, 2020
 Fair ValueTotal
Unrealized
Gains
Total
Unrealized
Losses
Investment Type:Nuclear Decommissioning TrustsOther Special Use FundsTotal
Equity Securities$639,851 $37,337 $677,188 $421,666 $— 
Available for Sale-Fixed Income Securities516,412 216,668 733,080 (a)46,581 (398)
Other(17,828)504 (17,324)(b)— — 
Total$1,138,435 $254,509 $1,392,944 $468,247 $(398)
(a)As of December 31, 2020, the amortized cost basis of these available-for-sale investments is $687 million.
(b)Represents net pending securities sales and purchases.

December 31, 2019
 Fair ValueTotal
Unrealized
Gains
Total
Unrealized
Losses
Investment Type:Nuclear Decommissioning TrustsOther Special Use FundsTotal
Equity Securities$529,716 $7,142 $536,858 $337,681 $— 
Available for Sale-Fixed Income Securities478,658 237,479 716,137 (a)25,795 (669)
Other2,401 474 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.
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, 2020, 2019 and 2018 (dollars in thousands):
 
 Year Ended December 31,
 Nuclear Decommissioning TrustsOther Special Use FundsTotal
2020
Realized gains$12,194 $176 $12,370 
Realized losses(5,553)(15)(5,568)
Proceeds from the sale of securities (a)675,035 144,484 819,519 
2019
Realized gains11,024 108 11,132 
Realized losses(6,972)— (6,972)
Proceeds from the sale of securities (a)473,806 245,228 719,034 
2018
Realized gains6,679 6,680 
Realized losses(13,552)— (13,552)
Proceeds from the sale of securities (a)554,385 98,648 653,033 
(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, 2020 is as follows (dollars in thousands):
 
 Nuclear Decommissioning TrustsCoal Reclamation Escrow AccountActive Union Medical TrustTotal
Less than one year$19,563 $33,079 $— $52,642 
1 year – 5 years151,537 29,722 142,311 323,570 
5 years – 10 years133,307 2,738 — 136,045 
Greater than 10 years212,005 8,818 — 220,823 
Total$516,412 $74,357 $142,311 $733,080 
v3.20.4
Changes in Accumulated Other Comprehensive Loss (Tables)
12 Months Ended
Dec. 31, 2020
Comprehensive Income (Loss), Net of Tax, Attributable to Parent [Abstract]  
Schedule of changes in accumulated other comprehensive loss including reclassification adjustments, by component
The following table shows the changes in Pinnacle West’s consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the years ended December 31, 2020 and 2019 (dollars in thousands): 
 Pension and Other Postretirement Benefits Derivative InstrumentsTotal
Balance at December 31, 2018$(45,997)$(1,711)$(47,708)
OCI (loss) before reclassifications(14,041)— (14,041)
Amounts reclassified from accumulated other comprehensive loss3,516 (a)1,137 (b)4,653 
Balance at December 31, 2019(56,522)(574)(57,096)
OCI (loss) before reclassifications(8,370)(2,089)(10,459)
Amounts reclassified from accumulated other comprehensive loss4,167 (a)592 (b)4,759 
Balance at December 31, 2020$(60,725)$(2,071)$(62,796)
(a)These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost (see Note 8).
(b)These amounts represent realized gains and losses and are included in the computation of fuel and purchased power costs and are subject to the PSA (see Note 16).
The following table shows the changes in APS’s consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the years ended December 31, 2020 and 2019 (dollars in thousands): 
 Pension and Other Postretirement Benefits Derivative InstrumentsTotal
Balance at December 31, 2018$(25,396)$(1,711)$(27,107)
OCI (loss) before reclassifications(12,572)— (12,572)
Amounts reclassified from accumulated other comprehensive loss3,020 (a)1,137 (b)4,157 
Balance at December 31, 2019(34,948)(574)(35,522)
OCI (loss) before reclassifications(9,568)(18)(9,586)
Amounts reclassified from accumulated other comprehensive loss3,598 (a)592 (b)4,190 
Balance at December 31, 2020$(40,918)$— $(40,918)
(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 16).
v3.20.4
Summary of Significant Accounting Policies - Additional Information (Details)
$ / shares in Units, $ in Millions
1 Months Ended 12 Months Ended 36 Months Ended
May 31, 2014
$ / kWh
Dec. 31, 2020
USD ($)
$ / shares
shares
Dec. 31, 2019
USD ($)
Dec. 31, 2018
USD ($)
Dec. 31, 2020
USD ($)
$ / shares
shares
Approximate remaining average useful lives of utility property          
Depreciation   $ 553 $ 522 $ 486  
Depreciation rates (as a percent)   2.84% 2.81% 2.81%  
Allowance for Funds Used During Construction          
Composite rate used to calculate AFUDC (as a percent)   6.72% 6.98% 7.03%  
Income Taxes          
Percent likelihood largest tax benefit amount is realized (greater than)   50.00%      
Intangible Assets          
Amortization expense   $ 70 $ 66 $ 68  
Estimated amortization expense on existing intangible assets over the next five years          
2021   68     $ 68
2022   56     56
2023   48     48
2024   33     33
2025   $ 25     $ 25
Remaining amortization period for intangible assets   7 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)         32.43%
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   20 years      
Other Generation          
Approximate remaining average useful lives of utility property          
Average useful life   20 years      
Transmission          
Approximate remaining average useful lives of utility property          
Average useful life   38 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   7 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%
v3.20.4
Summary of Significant Accounting Policies - Summary of Property, Plant and Equipment (Details) - USD ($)
$ in Thousands
Dec. 31, 2020
Dec. 31, 2019
Utility Plant and Depreciation [Line Items]    
Net $ 13,727,575 $ 13,198,435
Construction work in progress 937,384 808,133
Intangible assets, net of accumulated amortization 282,570 290,564
Nuclear fuel, net of accumulated amortization 113,645 123,500
Total property, plant and equipment 15,159,210 14,522,538
Electric Service    
Utility Plant and Depreciation [Line Items]    
Generation 9,199,012 8,916,872
Transmission 3,290,477 3,095,907
Distribution 7,107,007 6,690,697
General plant 1,241,389 1,132,816
Plant in service and held for future use 20,837,885 19,836,292
Accumulated depreciation and amortization (7,110,310) (6,637,857)
Net 13,727,575 13,198,435
Construction work in progress 937,384 808,133
Intangible assets, net of accumulated amortization 282,570 290,564
Nuclear fuel, net of accumulated amortization 113,645 123,500
Total property, plant and equipment 15,159,210 14,522,538
Electric Service | Variable Interest Entity    
Utility Plant and Depreciation [Line Items]    
Total property, plant and equipment $ 98,036 $ 101,906
v3.20.4
Summary of Significant Accounting Policies - Supplemental Cash Flow Information (Details) - USD ($)
$ in Thousands
12 Months Ended
Dec. 31, 2020
Dec. 31, 2019
Dec. 31, 2018
Cash and Cash Equivalents [Line Items]      
Income taxes, net of refunds $ (3,019) $ 12,535 $ 21,173
Interest, net of amounts capitalized 216,951 218,664 208,479
Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]      
Accrued capital expenditures 113,502 141,297 132,620
Dividends declared but not paid 93,531 87,982 82,675
Sale of 4CA 7% interest in Four Corners $ 0 0 68,907
4CA | El Paso's Interest in Four Corners      
Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]      
Ownership interest acquired (as a percent) 7.00%    
ARIZONA PUBLIC SERVICE COMPANY      
Cash and Cash Equivalents [Line Items]      
Income taxes, net of refunds $ 41,176 (15,042) 77,942
Interest, net of amounts capitalized 206,328 204,261 196,419
Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]      
Accrued capital expenditures 113,502 141,297 132,620
Dividends declared but not paid $ 93,500 $ 88,000 $ 82,700
v3.20.4
Revenue - Sources of Revenue (Details) - USD ($)
$ in Thousands
12 Months Ended
Dec. 31, 2020
Dec. 31, 2019
Dec. 31, 2018
Disaggregation of Revenue [Line Items]      
Total Operating Revenues $ 3,586,982 $ 3,471,209 $ 3,691,247
Retail Electric Service | Retail residential      
Disaggregation of Revenue [Line Items]      
Total Operating Revenues 1,929,178 1,761,122 1,867,370
Retail Electric Service | Retail non-residential      
Disaggregation of Revenue [Line Items]      
Total Operating Revenues 1,486,098 1,509,514 1,628,891
Retail Electric Service | Wholesale      
Disaggregation of Revenue [Line Items]      
Total Operating Revenues 93,345 121,805 109,198
Transmission Services for Others      
Disaggregation of Revenue [Line Items]      
Total Operating Revenues 65,859 62,460 60,261
Other Sources      
Disaggregation of Revenue [Line Items]      
Total Operating Revenues $ 12,502 $ 16,308 $ 25,527
v3.20.4
Revenue - Additional Information (Details) - USD ($)
$ in Thousands
12 Months Ended
Dec. 31, 2020
Dec. 31, 2019
Dec. 31, 2018
Disaggregation of Revenue [Line Items]      
Operating revenues $ 3,586,982 $ 3,471,209 $ 3,691,247
Regulatory cost recovery revenue 54,000 56,000 47,000
Electric and Transmission Service      
Disaggregation of Revenue [Line Items]      
Operating revenues 3,533,000 3,415,000 3,644,000
Retail Electric Service | Retail residential      
Disaggregation of Revenue [Line Items]      
Operating revenues 1,929,178 $ 1,761,122 $ 1,867,370
Retail Electric Service | Arizona Attorney General Settlement | Retail residential      
Disaggregation of Revenue [Line Items]      
Operating revenues $ (24,000)    
v3.20.4
Revenue - Allowance for Doubtful Accounts (Details) - USD ($)
$ in Thousands
12 Months Ended
Dec. 31, 2020
Dec. 31, 2019
Dec. 31, 2018
Dec. 31, 2020
Accounts Receivable, Allowance for Credit Loss [Roll Forward]        
Allowance for doubtful accounts, balance at beginning of period $ 8,171 $ 4,069 $ 2,513  
Bad debt expense 20,633 11,819 10,870  
Actual write-offs (9,022) (7,717) (9,314)  
Allowance for doubtful accounts, balance at end of period $ 8,171 $ 4,069 $ 2,513 $ 19,782
v3.20.4
Regulatory Matters - Regulatory Matters - COVID-19 (Details) - ARIZONA PUBLIC SERVICE COMPANY - USD ($)
12 Months Ended
Jan. 21, 2021
Dec. 31, 2020
Dec. 31, 2020
May 05, 2020
Public Utilities, General Disclosures [Line Items]        
Demand side management funds       $ 36,000,000
Customer credits   $ 43,000,000 $ 43,000,000  
Customer credits, additional funds   7,000,000 7,000,000  
Voluntary funds   15,000,000 15,000,000  
Customer COVID assistance   12,400,000 12,400,000  
Non-customer funds   8,800,000 8,800,000  
Bill credits for limited income customers   $ 3,600,000 3,600,000  
Threshold percentage for deferral of potential recovery   50.00%    
Threshold for deferral of potential recovery   $ 2,500,000 2,500,000  
Customer support fund, bill credit   100 100  
Expanded credit for limited income customers   300 300  
Customer assistance, small customers, bill credit   1,000 1,000  
Additional bill credit for delinquent limited income customers   250 250  
Customer support fund, non-profits and community organizations   $ 2,700,000 2,700,000  
Damage from Fire, Explosion or Other Hazard        
Public Utilities, General Disclosures [Line Items]        
Negative impact on operating results     $ 23,000,000  
Damage from Fire, Explosion or Other Hazard | Subsequent Event        
Public Utilities, General Disclosures [Line Items]        
Customer support fund, payment period 8 months      
Past due balance threshold qualifying for payment extension $ 75      
v3.20.4
Regulatory Matters - Retail Rate Case Filing (Details)
Nov. 06, 2020
USD ($)
Oct. 31, 2019
USD ($)
$ / kWh
GW
Jun. 30, 2019
USD ($)
Aug. 13, 2018
USD ($)
Jan. 08, 2018
USD ($)
Mar. 27, 2017
USD ($)
$ / kWh
Dec. 31, 2020
USD ($)
Oct. 02, 2020
USD ($)
ACC                
Public Utilities, General Disclosures [Line Items]                
Increase (decrease) in revenue $ (169,000,000)             $ (89,700,000)
Average percentage annual customer bill increase (5.14%)             (2.70%)
Recommended return on equity, percentage 10.00%             9.40%
Alternative, percentage               0.30%
Increment of fair value rate, percentage 0.80%             0.00%
Residential Utility Consumer Office                
Public Utilities, General Disclosures [Line Items]                
Increase (decrease) in revenue               $ 20,800,000
Average percentage annual customer bill increase               0.63%
Recommended return on equity, percentage               8.74%
Increment of fair value rate, percentage               0.00%
ACC | ARIZONA PUBLIC SERVICE COMPANY                
Public Utilities, General Disclosures [Line Items]                
Requested rate increase for tax act   $ 184,000,000   $ (86,500,000) $ (119,100,000)      
Retail Rate Case Filing with Arizona Corporation Commission | ACC | ARIZONA PUBLIC SERVICE COMPANY                
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%    
Rate matter, cost base rate     $ 8,870,000,000          
Base fuel rate (in dollars per kWh) | $ / kWh   0.030168            
Rate matter, funding limited income crisis bill program   $ 1,250,000            
Commercial customers, market pricing, threshold | GW   200            
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    
AZ Sun II Program | Retail Rate Case Filing with Arizona Corporation Commission | ACC | ARIZONA PUBLIC SERVICE COMPANY                
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    
Coal Community Transition Plan | ACC                
Public Utilities, General Disclosures [Line Items]                
Amount funded by customers $ 100,000,000              
Amount funded by customers, term 10 years              
Amount funded by shareholders $ 25,000,000           $ 25,200,000  
Coal Community Transition Plan | ACC | Navajo Nation, Economic Development Organization                
Public Utilities, General Disclosures [Line Items]                
Amount funded by shareholders, term 5 years              
Amount funded by shareholders $ 1,250,000              
Coal Community Transition Plan | ACC | Navajo Nation, Electrification Projects                
Public Utilities, General Disclosures [Line Items]                
Amount funded by customers 10,000,000              
Amount funded by shareholders 10,000,000           $ 10,000,000  
Coal Community Transition Plan | ACC | Navajo Nation, Transmission Revenue Sharing                
Public Utilities, General Disclosures [Line Items]                
Amount funded by shareholders 2,500,000              
Coal Community Transition Plan | ACC | Navajo County Communities, Cholla Power Plant Closure                
Public Utilities, General Disclosures [Line Items]                
Amount funded by customers $ 12,000,000              
Amount funded by customers, term 5 years              
Coal Community Transition Plan | ACC | Navajo Nation, Generation Station                
Public Utilities, General Disclosures [Line Items]                
Amount funded by customers $ 3,700,000              
Minimum | ACC | ARIZONA PUBLIC SERVICE COMPANY                
Public Utilities, General Disclosures [Line Items]                
Regulatory impact, operating results   $ 69,000,000            
Minimum | Retail Rate Case Filing with Arizona Corporation Commission | ACC | ARIZONA PUBLIC SERVICE COMPANY                
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 | ACC | ARIZONA PUBLIC SERVICE COMPANY                
Public Utilities, General Disclosures [Line Items]                
Environmental surcharge cap rate (in dollars per kWh) | $ / kWh           0.00050    
v3.20.4
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%
v3.20.4
Regulatory Matters - Additional Information (Details)
12 Months Ended
Oct. 01, 2021
$ / kWh
Feb. 22, 2021
USD ($)
Feb. 15, 2021
USD ($)
Feb. 01, 2021
USD ($)
$ / kWh
Aug. 20, 2020
USD ($)
Customer
Jun. 01, 2020
USD ($)
May 01, 2020
$ / kWh
Feb. 14, 2020
USD ($)
Feb. 01, 2020
$ / 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. 15, 2018
USD ($)
Feb. 01, 2018
$ / kWh
Jan. 08, 2018
USD ($)
Nov. 20, 2017
USD ($)
Dec. 20, 2016
$ / kWh
Dec. 31, 2020
USD ($)
program
MW
Dec. 31, 2017
$ / kWh
Jul. 01, 2020
USD ($)
May 15, 2020
USD ($)
May 05, 2020
USD ($)
Dec. 31, 2019
USD ($)
Jul. 01, 2019
USD ($)
Mar. 15, 2019
agreement
Dec. 31, 2018
USD ($)
Jun. 29, 2018
USD ($)
Nov. 14, 2017
USD ($)
Sep. 01, 2017
USD ($)
Regulatory Matters [Line Items]                                                                          
Number of customers | Customer         3,800         13,000                                                      
Inconvenience payment         $ 25         $ 25                                                      
ARIZONA PUBLIC SERVICE COMPANY                                                                          
Regulatory Matters [Line Items]                                                                          
Demand side management funds                                                           $ 36,000,000              
Customer credits                                                   $ 43,000,000                      
Customer credits, additional funds                                                   7,000,000                      
ARIZONA PUBLIC SERVICE COMPANY | Damage from Fire, Explosion or Other Hazard                                                                          
Regulatory Matters [Line Items]                                                                          
Pre-tax income                                                   $ (23,000,000)                      
ARIZONA PUBLIC SERVICE COMPANY | Lost Fixed Cost Recovery Mechanism                                                                          
Regulatory Matters [Line Items]                                                                          
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               $ 26,600,000               $ 36,200,000         $ 60,700,000                                
Decrease in amount of adjustment representing prorated sales losses               $ 9,600,000               $ 24,500,000                                          
ARIZONA PUBLIC SERVICE COMPANY | ACC                                                                          
Regulatory Matters [Line Items]                                                                          
Program term                                                   18 years                      
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                                                  
Number of public utility programs | program                                                   2                      
Solar power capacity | MW                                                   80                      
ARIZONA PUBLIC SERVICE COMPANY | ACC | Arizona Renewable Energy Standard and Tariff 2018                                                                          
Regulatory Matters [Line Items]                                                                          
Amount of proposed budget                                                       $ 84,700,000       $ 86,300,000     $ 89,900,000    
Request to meet revenue requirements                                                       $ 4,500,000                  
ARIZONA PUBLIC SERVICE COMPANY | ACC | Demand Side Management Adjustor Charge 2018                                                                          
Regulatory Matters [Line Items]                                                                          
Amount of proposed budget                                                                       $ 52,600,000 $ 52,600,000
ARIZONA PUBLIC SERVICE COMPANY | ACC | Power Supply Adjustor (PSA)                                                                          
Regulatory Matters [Line Items]                                                                          
PSA rate (in dollars per kWh) | $ / kWh                 (0.000456)               0.001658         0.004555                              
Forward component of PSA rate (in dollars per kWh) | $ / kWh                 (0.002086)               0.000536                                        
Historical component of PSA rate (in dollars per kWh) | $ / kWh                 0.001630               0.001122                                        
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             0.094             0.105           0.116                                  
ARIZONA PUBLIC SERVICE COMPANY | ACC | Arizona Renewable Energy Standard and Tariff                                                                          
Regulatory Matters [Line Items]                                                                          
Plan term                                                   5 years                      
ARIZONA PUBLIC SERVICE COMPANY | ACC | Demand Side Management Adjustor Charge 2019                                                                          
Regulatory Matters [Line Items]                                                                          
Amount of proposed budget                                                                   $ 34,100,000      
ARIZONA PUBLIC SERVICE COMPANY | ACC | Demand Side Management Adjustor Charge 2020                                                                          
Regulatory Matters [Line Items]                                                                          
Amount of proposed budget                                                         $ 51,900,000   $ 51,900,000            
ARIZONA PUBLIC SERVICE COMPANY | ACC | Demand Side Management Adjustor Charge 2021                                                                          
Regulatory Matters [Line Items]                                                                          
Amount of proposed budget                                                   $ 63,700,000                      
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           $ (6,100,000)             $ 25,800,000           $ (22,700,000)                                    
Rate matters, increase (decrease) in cost recovery, retail customer rates           $ 10,900,000             $ 4,700,000           $ (26,900,000)                                    
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)               (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 | 2017 Settlement Agreement and its Customer Education and Outreach Plan                                                                          
Regulatory Matters [Line Items]                                                                          
Settlement amount   $ 24,750,000                                                                      
Settlement amount returned to customers   $ 24,000,000                                                                      
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     $ 38,500,000                                                                    
Decrease in amount of adjustment representing prorated sales losses     $ 11,800,000                                                                    
Subsequent Event | ARIZONA PUBLIC SERVICE COMPANY | FERC | Environmental Improvement Surcharge                                                                          
Regulatory Matters [Line Items]                                                                          
Rate matters, increase (decrease) in cost recovery       $ 10,300,000                                                                  
Rate matters, increase (decrease) in cost recovery, excess of annual amount       $ 1,500,000                                                                  
Forecast | ARIZONA PUBLIC SERVICE COMPANY | ACC | Power Supply Adjustor (PSA)                                                                          
Regulatory Matters [Line Items]                                                                          
PSA rate (in dollars per kWh) | $ / kWh       0.003544                                                                  
Forward component of PSA rate (in dollars per kWh) | $ / kWh       0.003434                                                                  
Historical component of PSA rate (in dollars per kWh) | $ / kWh       0.000110                                                                  
Forecast | ARIZONA PUBLIC SERVICE COMPANY | ACC | Net Metering                                                                          
Regulatory Matters [Line Items]                                                                          
Request second-year energy price for exported energy | $ / kWh 0.105                                                                        
Forecast | 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       0.004                                                                  
v3.20.4
Regulatory Matters - Deferred Fuel and Purchased Power Regulatory Asset (Details) - USD ($)
$ in Thousands
12 Months Ended
Dec. 31, 2020
Dec. 31, 2019
Dec. 31, 2018
Change in regulatory asset      
Deferred fuel and purchased power costs — current period $ 93,651 $ 82,481 $ 78,277
Amounts refunded/(charged) to customers 12,047 (49,508) (116,750)
ARIZONA PUBLIC SERVICE COMPANY      
Change in regulatory asset      
Deferred fuel and purchased power costs — current period 93,651 82,481 78,277
Amounts refunded/(charged) to customers 12,047 (49,508) (116,750)
ACC | ARIZONA PUBLIC SERVICE COMPANY | Power Supply Adjustor (PSA)      
Change in regulatory asset      
Beginning balance 70,137 37,164  
Deferred fuel and purchased power costs — current period 93,651 82,481  
Amounts refunded/(charged) to customers 12,047 (49,508)  
Ending balance $ 175,835 $ 70,137 $ 37,164
v3.20.4
Regulatory Matters - Four Corners, Cholla and Navajo Plant (Details) - ARIZONA PUBLIC SERVICE COMPANY - USD ($)
$ in Millions
1 Months Ended
Sep. 30, 2018
Apr. 30, 2018
Dec. 31, 2020
Retired power plant costs      
Acquisition      
Regulatory asset, net book value     $ 57.0
Navajo plant      
Acquisition      
Regulatory asset, net book value     72.0
Navajo plant, coal reclamation regulatory asset      
Acquisition      
Regulatory asset, net book value     $ 18.0
Four Corners Units 4 and 5 | SCE      
Acquisition      
Settlement agreement, ACC approved rate adjustment, annualized customer impact $ 58.5 $ 67.5  
v3.20.4
Regulatory Matters - Schedule of Regulatory Assets (Details) - USD ($)
$ in Thousands
Dec. 31, 2020
Dec. 31, 2019
Detail of regulatory assets    
Regulatory assets, current $ 291,713 $ 203,207
Regulatory assets, non-current 1,133,987 1,304,073
Pension    
Detail of regulatory assets    
Regulatory assets, current 0 0
Regulatory assets, non-current 469,953 660,223
Deferred fuel and purchased power    
Detail of regulatory assets    
Regulatory assets, current 175,835 70,137
Regulatory assets, non-current 0 0
Income taxes — AFUDC equity    
Detail of regulatory assets    
Regulatory assets, current 7,169 6,800
Regulatory assets, non-current 158,776 154,974
Retired power plant costs    
Detail of regulatory assets    
Regulatory assets, current 28,181 28,182
Regulatory assets, non-current 114,214 142,503
Ocotillo deferral    
Detail of regulatory assets    
Regulatory assets, current 0 0
Regulatory assets, non-current 95,723 38,144
SCR deferral    
Detail of regulatory assets    
Regulatory assets, current 0 0
Regulatory assets, non-current 81,307 52,644
Deferred property taxes    
Detail of regulatory assets    
Regulatory assets, current 8,569 8,569
Regulatory assets, non-current 49,626 58,196
Lost fixed cost recovery    
Detail of regulatory assets    
Regulatory assets, current 41,807 26,067
Regulatory assets, non-current 0 0
Deferred compensation    
Detail of regulatory assets    
Regulatory assets, current 0 0
Regulatory assets, non-current 36,195 36,464
Four Corners cost deferral    
Detail of regulatory assets    
Regulatory assets, current 8,077 8,077
Regulatory assets, non-current 24,075 32,152
Income taxes — investment tax credit basis adjustment    
Detail of regulatory assets    
Regulatory assets, current 1,113 1,098
Regulatory assets, non-current 24,291 24,981
Palo Verde VIE    
Detail of regulatory assets    
Regulatory assets, current 0 0
Regulatory assets, non-current 21,255 20,635
Coal reclamation    
Detail of regulatory assets    
Regulatory assets, current 1,068 1,546
Regulatory assets, non-current 16,999 17,688
Deferred fuel and purchased power - mark-to-market    
Detail of regulatory assets    
Regulatory assets, current 3,341 36,887
Regulatory assets, non-current 9,244 33,185
Loss on reacquired debt    
Detail of regulatory assets    
Regulatory assets, current 1,689 1,637
Regulatory assets, non-current 10,877 12,031
Mead-Phoenix transmission line — contributions in aid of construction    
Detail of regulatory assets    
Regulatory assets, current 332 332
Regulatory assets, non-current 9,380 9,712
Demand side management    
Detail of regulatory assets    
Regulatory assets, current 0 0
Regulatory assets, non-current 7,268 0
Tax expense adjustor mechanism    
Detail of regulatory assets    
Regulatory assets, current 6,226 1,612
Regulatory assets, non-current 0 0
Tax expense of Medicare subsidy    
Detail of regulatory assets    
Regulatory assets, current 1,235 1,235
Regulatory assets, non-current 3,704 4,940
PSA interest    
Detail of regulatory assets    
Regulatory assets, current 4,355 1,917
Regulatory assets, non-current 0 0
TCA balancing account    
Detail of regulatory assets    
Regulatory assets, current 0 6,324
Regulatory assets, non-current 0 2,885
Other    
Detail of regulatory assets    
Regulatory assets, current 2,716 2,787
Regulatory assets, non-current $ 1,100 $ 2,716
v3.20.4
Regulatory Matters - Schedule of Regulatory Liabilities (Details) - USD ($)
$ in Thousands
Dec. 31, 2021
Dec. 31, 2020
Dec. 31, 2019
Detail of regulatory liabilities      
Regulatory liabilities, current   $ 229,088 $ 234,912
Regulatory liabilities, non-current   2,450,169 2,267,835
Asset retirement obligations      
Detail of regulatory liabilities      
Regulatory liabilities, current   0 0
Regulatory liabilities, non-current   506,049 418,423
Other postretirement benefits      
Detail of regulatory liabilities      
Regulatory liabilities, current   37,705 37,575
Regulatory liabilities, non-current   349,588 139,634
Removal costs      
Detail of regulatory liabilities      
Regulatory liabilities, current   52,844 47,356
Regulatory liabilities, non-current   103,008 136,072
Income taxes — change in rates      
Detail of regulatory liabilities      
Regulatory liabilities, current   2,839 2,797
Regulatory liabilities, non-current   66,553 68,265
Four Corners coal reclamation      
Detail of regulatory liabilities      
Regulatory liabilities, current   5,460 1,059
Regulatory liabilities, non-current   49,435 51,704
Spent nuclear fuel      
Detail of regulatory liabilities      
Regulatory liabilities, current   6,768 6,676
Regulatory liabilities, non-current   44,221 51,019
Income taxes — deferred investment tax credit      
Detail of regulatory liabilities      
Regulatory liabilities, current   2,231 2,202
Regulatory liabilities, non-current   48,648 50,034
Renewable energy program      
Detail of regulatory liabilities      
Regulatory liabilities, current   39,442 39,287
Regulatory liabilities, non-current   103 10,300
Sundance maintenance      
Detail of regulatory liabilities      
Regulatory liabilities, current   2,989 5,698
Regulatory liabilities, non-current   11,508 11,319
Deferred property taxes      
Detail of regulatory liabilities      
Regulatory liabilities, current   0 0
Regulatory liabilities, non-current   13,856 7,046
Demand side management      
Detail of regulatory liabilities      
Regulatory liabilities, current   10,819 15,024
Regulatory liabilities, non-current   0 24,146
FERC transmission true up      
Detail of regulatory liabilities      
Regulatory liabilities, current   6,598 1,045
Regulatory liabilities, non-current   3,008 2,004
TCA balancing account      
Detail of regulatory liabilities      
Regulatory liabilities, current   2,902 0
Regulatory liabilities, non-current   4,672 0
Tax expense adjustor mechanism      
Detail of regulatory liabilities      
Regulatory liabilities, current   7,089 7,018
Regulatory liabilities, non-current   0 0
Tax expense adjustor mechanism | Forecast      
Detail of regulatory liabilities      
Regulatory liabilities, current $ 7,000    
Active union medical trust      
Detail of regulatory liabilities      
Regulatory liabilities, current   0 0
Regulatory liabilities, non-current   6,057 2,041
Deferred gains on utility property      
Detail of regulatory liabilities      
Regulatory liabilities, current   2,423 2,423
Regulatory liabilities, non-current   1,544 4,163
Other      
Detail of regulatory liabilities      
Regulatory liabilities, current   409 532
Regulatory liabilities, non-current   189 255
ACC | Excess deferred income taxes - ACC - Tax Cuts and Jobs Act      
Detail of regulatory liabilities      
Regulatory liabilities, current   41,330 59,918
Regulatory liabilities, non-current   1,012,583 1,054,053
FERC | Excess deferred income taxes - ACC - Tax Cuts and Jobs Act      
Detail of regulatory liabilities      
Regulatory liabilities, current   7,240 6,302
Regulatory liabilities, non-current   $ 229,147 $ 237,357
v3.20.4
Income Taxes - Additional Information (Details) - USD ($)
12 Months Ended
Dec. 31, 2020
Dec. 31, 2019
Dec. 31, 2017
Income Taxes      
Reduction in net deferred income tax liabilities     $ 1,140,000,000
Income tax benefit $ 31,000,000 $ 62,000,000  
Amortization period 28 years 6 months    
Income tax expense benefit attributable to non controlling interests $ 0    
Interest expense to be received on the underpayment of income taxes 1,000,000    
Increase (decrease) in deferred income taxes due to regulation adoption 42,000,000    
ARIZONA PUBLIC SERVICE COMPANY      
Income Taxes      
Increase (decrease) in deferred income taxes due to regulation adoption 8,000,000    
Federal      
Income Taxes      
Income tax benefit 14,000,000 57,000,000  
General business tax credit carryforwards 35,000,000    
State      
Income Taxes      
State credit carryforwards net of federal benefit $ 33,000,000 $ 16,000,000  
v3.20.4
Income Taxes - Reconciliation of Unrecognized Tax Benefits (Details) - USD ($)
$ in Thousands
12 Months Ended
Dec. 31, 2020
Dec. 31, 2019
Dec. 31, 2018
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 $ 43,435 $ 40,731 $ 41,966
Additions for tax positions of the current year 3,418 3,373 3,436
Additions for tax positions of prior years 1,431 1,843 2,696
Reductions for tax positions of prior years for:      
Changes in judgment (1,965) (2,078) (1,764)
Settlements with taxing authorities 0 0 0
Lapses of applicable statute of limitations (664) (434) (5,603)
Total unrecognized tax benefits, end of the year 45,655 43,435 40,731
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 43,435 40,731 41,966
Additions for tax positions of the current year 3,418 3,373 3,436
Additions for tax positions of prior years 1,431 1,843 2,696
Reductions for tax positions of prior years for:      
Changes in judgment (1,965) (2,078) (1,764)
Settlements with taxing authorities 0 0 0
Lapses of applicable statute of limitations (664) (434) (5,603)
Total unrecognized tax benefits, end of the year $ 45,655 $ 43,435 $ 40,731
v3.20.4
Income Taxes - Summary of Unrecognized Tax Benefits (Details) - USD ($)
$ in Thousands
12 Months Ended
Dec. 31, 2020
Dec. 31, 2019
Dec. 31, 2018
Income Tax [Line Items]      
Tax positions, that if recognized, would decrease our effective tax rate $ 25,714 $ 22,813 $ 19,504
Unrecognized tax benefit interest expense/(benefit) recognized 266 459 (780)
Unrecognized tax benefit interest accrued 1,855 1,589 1,130
ARIZONA PUBLIC SERVICE COMPANY      
Income Tax [Line Items]      
Tax positions, that if recognized, would decrease our effective tax rate 25,714 22,813 19,504
Unrecognized tax benefit interest expense/(benefit) recognized 266 459 (780)
Unrecognized tax benefit interest accrued $ 1,855 $ 1,589 $ 1,130
v3.20.4
Income Taxes - Components of Income Tax Expense (Details) - USD ($)
$ in Thousands
12 Months Ended
Dec. 31, 2020
Dec. 31, 2019
Dec. 31, 2018
Current:      
Federal $ 11,869 $ (13,551) $ 18,375
State 1,932 3,195 3,342
Total current 13,801 (10,356) 21,717
Deferred:      
Federal 53,398 (14,982) 94,721
State 10,974 9,565 17,464
Total deferred 64,372 (5,417) 112,185
Income tax expense/(benefit) 78,173 (15,773) 133,902
ARIZONA PUBLIC SERVICE COMPANY      
Current:      
Federal 57,299 (54,697) 88,180
State 99 695 1,877
Total current 57,398 (54,002) 90,057
Deferred:      
Federal 15,122 29,321 32,436
State 16,244 15,109 22,321
Total deferred 31,366 44,430 54,757
Income tax expense/(benefit) $ 88,764 $ (9,572) $ 144,814
v3.20.4
Income Taxes - Effective Tax Rate Reconciliation (Details) - USD ($)
$ in Thousands
12 Months Ended
Dec. 31, 2020
Dec. 31, 2019
Dec. 31, 2018
Income Tax Reconciliation Increases Reductions in Tax Expense [Abstract]      
Federal income tax expense at statutory rate $ 136,127 $ 113,828 $ 139,533
State income tax net of federal income tax benefit 19,146 18,599 23,115
State income tax credits net of federal income tax benefit (8,951) (8,519) (6,704)
Nondeductible expenditures associated with ballot initiative 0 0 7,879
Stock compensation 34 (2,252) (1,804)
Excess deferred income taxes — Tax Cuts and Jobs Act (50,543) (124,082) (6,725)
Allowance for equity funds used during construction (see Note 1) (2,747) (2,476) (7,231)
Palo Verde VIE noncontrolling interest (see Note 18) (4,094) (4,094) (4,094)
Investment tax credit amortization (7,510) (6,851) (6,742)
Other (3,289) 74 (3,325)
Income tax expense/(benefit) 78,173 (15,773) 133,902
ARIZONA PUBLIC SERVICE COMPANY      
Income Tax Reconciliation Increases Reductions in Tax Expense [Abstract]      
Federal income tax expense at statutory rate 142,020 120,790 154,260
State income tax net of federal income tax benefit 20,124 19,267 24,531
State income tax credits net of federal income tax benefit (7,213) (6,781) (5,440)
Nondeductible expenditures associated with ballot initiative 0 0 0
Stock compensation 183 (1,054) (780)
Excess deferred income taxes — Tax Cuts and Jobs Act (50,543) (124,082) (4,715)
Allowance for equity funds used during construction (see Note 1) (2,747) (2,476) (7,231)
Palo Verde VIE noncontrolling interest (see Note 18) (4,094) (4,094) (4,094)
Investment tax credit amortization (7,510) (6,851) (6,742)
Other (1,456) (4,291) (4,975)
Income tax expense/(benefit) $ 88,764 $ (9,572) $ 144,814
v3.20.4
Income Taxes - Components of Deferred Income Tax Liability (Details) - USD ($)
$ in Thousands
Dec. 31, 2020
Dec. 31, 2019
DEFERRED TAX ASSETS    
Risk management activities $ 4,287 $ 17,552
Regulatory liabilities:    
Excess deferred income taxes — Tax Cuts and Jobs Act 319,091 335,877
Asset retirement obligation and removal costs 157,470 143,011
Unamortized investment tax credits 50,879 52,236
Other postretirement liabilities 95,778 43,841
Other 43,551 52,382
Operating lease liabilities 107,853 15,497
Pension liabilities 45,853 73,210
Coal reclamation liabilities 42,065 40,837
Renewable energy incentives 25,355 28,066
Credit and loss carryforwards 26,460 54,795
Other 78,113 47,605
Total deferred tax assets 996,755 904,909
DEFERRED TAX LIABILITIES    
Plant-related (2,489,899) (2,448,458)
Risk management activities (1,174) (27)
Pension and other postretirement assets (123,462) (21,892)
Other special use funds (42,927) (44,507)
Operating lease right-of-use assets (107,853) (15,497)
Regulatory assets:    
Allowance for equity funds used during construction (41,038) (40,023)
Deferred fuel and purchased power (47,673) (35,162)
Pension benefits (116,219) (163,339)
Retired power plant costs (35,214) (42,228)
Other (106,227) (82,722)
Other (20,472) (3,393)
Total deferred tax liabilities (3,132,158) (2,897,248)
Deferred income taxes — net (2,135,403) (1,992,339)
ARIZONA PUBLIC SERVICE COMPANY    
DEFERRED TAX ASSETS    
Risk management activities 4,287 17,552
Regulatory liabilities:    
Excess deferred income taxes — Tax Cuts and Jobs Act 319,091 335,877
Asset retirement obligation and removal costs 157,470 143,011
Unamortized investment tax credits 50,879 52,236
Other postretirement liabilities 95,778 43,841
Other 43,551 52,382
Operating lease liabilities 107,414 15,497
Pension liabilities 40,168 67,976
Coal reclamation liabilities 42,065 40,837
Renewable energy incentives 25,355 28,066
Credit and loss carryforwards 8,034 10,992
Other 78,113 55,451
Total deferred tax assets 972,205 863,718
DEFERRED TAX LIABILITIES    
Plant-related (2,489,899) (2,448,458)
Risk management activities (1,174) (27)
Pension and other postretirement assets (122,580) (21,458)
Other special use funds (42,927) (44,507)
Operating lease right-of-use assets (107,414) (15,497)
Regulatory assets:    
Allowance for equity funds used during construction (41,038) (40,023)
Deferred fuel and purchased power (47,673) (35,162)
Pension benefits (116,219) (163,339)
Retired power plant costs (35,214) (42,228)
Other (106,227) (82,722)
Other (5,513) (3,393)
Total deferred tax liabilities (3,115,878) (2,896,814)
Deferred income taxes — net $ (2,143,673) $ (2,033,096)
v3.20.4
Lines of Credit and Short-Term Borrowings - Schedule of Credit Facilities (Details) - USD ($)
$ in Thousands
12 Months Ended
Dec. 31, 2020
Dec. 31, 2019
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 $ 1,231,000 $ 1,250,000
Outstanding Commercial Paper, Term Loan and Revolving Credit Facility Borrowings (169,000) (114,675)
Amount of Credit Facilities Available 1,062,000 1,135,325
Revolving credit facility | Pinnacle West    
Lines of Credit and Short-Term Borrowings    
Commitments under Credit Facilities 231,000 250,000
Outstanding Commercial Paper, Term Loan and Revolving Credit Facility Borrowings (169,000) (114,675)
Amount of Credit Facilities Available 62,000 135,325
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, Term Loan and Revolving Credit Facility Borrowings 0 0
Amount of Credit Facilities Available $ 1,000,000 $ 1,000,000
v3.20.4
Lines of Credit and Short-Term Borrowings - Additional Information (Details)
12 Months Ended
Dec. 31, 2020
USD ($)
Facility
Dec. 23, 2020
USD ($)
Dec. 17, 2020
USD ($)
May 05, 2020
USD ($)
May 04, 2020
USD ($)
Dec. 31, 2019
USD ($)
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            
Lines of Credit and Short-Term Borrowings            
Notes issued   $ 150,000,000        
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  
Notes issued       $ 31,000,000    
Long-term line of credit $ 19,000,000          
Revolving credit facility            
Lines of Credit and Short-Term Borrowings            
Long-term line of credit 169,000,000         $ 114,675,000
Amount committed 1,231,000,000         1,250,000,000
Revolving credit facility | Pinnacle West            
Lines of Credit and Short-Term Borrowings            
Long-term line of credit 169,000,000         114,675,000
Amount committed 231,000,000         250,000,000
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          
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 5,200,000          
Letter of credit | ARIZONA PUBLIC SERVICE COMPANY | Revolving Credit Facility Maturing in 2022 and 2023            
Lines of Credit and Short-Term Borrowings            
Outstanding letters of credit 0          
Commercial paper | Pinnacle West | Revolving credit facility maturing July 2023            
Lines of Credit and Short-Term Borrowings            
Commercial paper 150,000,000          
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 1.40%          
v3.20.4
Long-Term Debt and Liquidity Matters - Components of Long-Term Debt (Details) - USD ($)
$ in Thousands
Dec. 31, 2020
Jun. 17, 2020
Jun. 16, 2020
May 22, 2020
Dec. 31, 2019
Long-Term Debt and Liquidity Matters [Line Items]          
Total long-term debt $ 6,314,266       $ 5,632,558
TOTAL LONG-TERM DEBT LESS CURRENT MATURITIES 6,314,266       4,832,558
Pinnacle West          
Long-Term Debt and Liquidity Matters [Line Items]          
Gross long-term debt 6,365,975        
Unamortized discount (44)       (57)
Unamortized debt issue costs (3,635)       (518)
Total long-term debt 496,321       449,425
Less current maturities 0       450,000
Total long-term debt less current maturities 496,321       (575)
TOTAL LONG-TERM DEBT LESS CURRENT MATURITIES 496,321       (575)
ARIZONA PUBLIC SERVICE COMPANY          
Long-Term Debt and Liquidity Matters [Line Items]          
Gross long-term debt 5,865,975        
Unamortized discount (15,900)       (12,434)
Unamortized premium 14,781       7,423
Unamortized debt issue costs (46,911)       (37,981)
Total long-term debt 5,817,945       5,183,133
Less current maturities 0       350,000
Total long-term debt less current maturities 5,817,945       4,833,133
TOTAL LONG-TERM DEBT LESS CURRENT MATURITIES 5,817,945       4,833,133
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) 0.18%       1.54%
Pollution Control Bonds - Fixed | ARIZONA PUBLIC SERVICE COMPANY          
Long-Term Debt and Liquidity Matters [Line Items]          
Gross long-term debt $ 0       $ 115,150
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 $ 35,975       151,125
Senior unsecured notes          
Long-Term Debt and Liquidity Matters [Line Items]          
Interest rate (as a percent)   1.30% 2.25%    
Senior unsecured notes | ARIZONA PUBLIC SERVICE COMPANY          
Long-Term Debt and Liquidity Matters [Line Items]          
Gross long-term debt $ 5,830,000       4,875,000
Senior unsecured notes | ARIZONA PUBLIC SERVICE COMPANY | Minimum          
Long-Term Debt and Liquidity Matters [Line Items]          
Interest rate (as a percent) 2.55%     3.35%  
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 $ 500,000       300,000
Interest rate (as a percent) 1.30%        
Term loan | Term loans | ARIZONA PUBLIC SERVICE COMPANY          
Long-Term Debt and Liquidity Matters [Line Items]          
Term loans $ 0       200,000
Term loan | Term Loan Facility Maturing 2020 | Pinnacle West          
Long-Term Debt and Liquidity Matters [Line Items]          
Term loans $ 0       $ 150,000
Weighted-average interest rate (as a percent)         2.20%
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%
v3.20.4
Long-Term Debt and Liquidity Matters - Additional Information (Details) - USD ($)
12 Months Ended
Nov. 19, 2020
Jun. 17, 2020
May 22, 2020
Jan. 15, 2020
Dec. 31, 2020
Dec. 31, 2019
Dec. 31, 2018
Dec. 23, 2020
Dec. 17, 2020
Dec. 16, 2020
Nov. 18, 2020
Sep. 11, 2020
Jun. 16, 2020
May 05, 2020
Long-Term Debt and Liquidity Matters [Line Items]                            
Repayment of long-term debt         $ 915,150,000 $ 600,000,000 $ 182,000,000              
Issuance of long-term debt         $ 1,596,672,000 1,092,188,000 445,245,000              
Maximum                            
Debt Provisions                            
Ratio of consolidated debt to consolidated capitalization (as a percent)         65.00%                  
Term loan                            
Long-Term Debt and Liquidity Matters [Line Items]                            
Notes issued               $ 150,000,000            
Repayment of long-term debt   $ 150,000,000                        
Pinnacle West                            
Long-Term Debt and Liquidity Matters [Line Items]                            
Repayment of long-term debt         $ 450,000,000 0 0              
Issuance of long-term debt         $ 496,950,000 0 150,000,000              
Debt Provisions                            
Actual ratio of consolidated debt to total consolidated capitalization required to be maintained as per the debt covenant (as a percent)         54.00%                  
Pinnacle West | Term loan                            
Long-Term Debt and Liquidity Matters [Line Items]                            
Notes issued                           $ 31,000,000
ARIZONA PUBLIC SERVICE COMPANY                            
Long-Term Debt and Liquidity Matters [Line Items]                            
Repayment of long-term debt         $ 465,150,000 600,000,000 182,000,000              
Issuance of long-term debt         $ 1,099,722,000 $ 1,092,188,000 295,245,000              
Debt Provisions                            
Actual ratio of consolidated debt to total consolidated capitalization required to be maintained as per the debt covenant (as a percent)         49.00%                  
Equity infusion from Pinnacle West         $ 150,000,000   $ 150,000,000              
ARIZONA PUBLIC SERVICE COMPANY | ACC                            
Debt Provisions                            
Long term debt authorization                 $ 7,500,000,000 $ 5,900,000,000        
ARIZONA PUBLIC SERVICE COMPANY | Term loan                            
Long-Term Debt and Liquidity Matters [Line Items]                            
Repayment of long-term debt     $ 200,000,000                      
ARIZONA PUBLIC SERVICE COMPANY | Senior notes                            
Long-Term Debt and Liquidity Matters [Line Items]                            
Interest rate (as a percent)       2.20%                    
Extinguishment of debt       $ 150,000,000                    
Senior unsecured notes | Pinnacle West                            
Long-Term Debt and Liquidity Matters [Line Items]                            
Interest rate (as a percent)         1.30%                  
Senior unsecured notes                            
Long-Term Debt and Liquidity Matters [Line Items]                            
Interest rate (as a percent)   1.30%                     2.25%  
Senior unsecured notes | Senior notes                            
Long-Term Debt and Liquidity Matters [Line Items]                            
Notes issued   $ 500,000,000                     $ 300,000,000  
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)     3.35%   2.55%                  
Senior unsecured notes | ARIZONA PUBLIC SERVICE COMPANY | Senior notes                            
Long-Term Debt and Liquidity Matters [Line Items]                            
Notes issued $ 405,000,000     $ 250,000,000             $ 300,000,000 $ 400,000,000    
Interest rate (as a percent) 2.60%                     2.65%    
Extinguishment of debt     $ 600,000,000                      
Issuance of long-term debt $ 105,000,000                          
City of Farmington, New Mexico Pollution Control Revenue Refunding Bond | ARIZONA PUBLIC SERVICE COMPANY                            
Long-Term Debt and Liquidity Matters [Line Items]                            
Interest rate (as a percent)         4.70%                  
Repayment of long-term debt 49,400,000                          
City of Farmington, New Mexico Pollution Control Revenue Refunding Bond, 1994 Series B | ARIZONA PUBLIC SERVICE COMPANY                            
Long-Term Debt and Liquidity Matters [Line Items]                            
Interest rate (as a percent)         4.70%                  
Repayment of long-term debt $ 65,750,000                          
v3.20.4
Long-Term Debt and Liquidity Matters - Future Principal Payments (Details)
$ in Thousands
Dec. 31, 2020
USD ($)
Pinnacle West  
Principal payments due on long-term debt  
2021 $ 0
2022 0
2023 0
2024 250,000
2025 800,000
Thereafter 5,315,975
Total 6,365,975
ARIZONA PUBLIC SERVICE COMPANY  
Principal payments due on long-term debt  
2021 0
2022 0
2023 0
2024 250,000
2025 300,000
Thereafter 5,315,975
Total $ 5,865,975
v3.20.4
Long-Term Debt and Liquidity Matters - Fair Value of Long-Term Debt (Details) - USD ($)
$ in Thousands
Dec. 31, 2020
Dec. 31, 2019
Estimated fair value of long-term debt, including current maturities    
Carrying Amount $ 6,314,266 $ 5,632,558
Fair Value 7,612,841 6,194,392
Pinnacle West    
Estimated fair value of long-term debt, including current maturities    
Carrying Amount 496,321 449,425
Fair Value 509,050 450,822
ARIZONA PUBLIC SERVICE COMPANY    
Estimated fair value of long-term debt, including current maturities    
Carrying Amount 5,817,945 5,183,133
Fair Value $ 7,103,791 $ 5,743,570
v3.20.4
Retirement Plans and Other Postretirement Benefits - Additional Information (Details) - USD ($)
12 Months Ended
Jan. 04, 2021
Dec. 31, 2020
Dec. 31, 2019
Dec. 31, 2018
Defined Benefit Plan Disclosure [Line Items]        
Initial pre-65 ultimate health care cost trend rate (as a percent)   4.75% 4.75%  
Initial post-65 healthcare cost trend rate (as a percent)   2.00% 4.75%  
Funded percentage (more than)   100.00%    
Partnership funding commitments, contribution amount (up to)   $ 50,000,000    
Partnership funding commitments, funded amount   38,000,000    
Minimum contributions under MAP-21        
Voluntary employer contributions over next three years (up to)   $ 100,000,000    
Subsequent Event        
Defined Benefit Plan Disclosure [Line Items]        
Transfer to active union medical account $ (106,000,000)      
Pension Benefits        
Defined Benefit Plan Disclosure [Line Items]        
Expected long-term return on plan assets for next fiscal year (as a percent)   5.30%    
Contributions        
Employer contributions   $ 100,000,000 $ 150,000,000 $ 50,000,000
Minimum contributions under MAP-21        
Minimum contributions under MAP-21   $ 0    
Pension Benefits | Subsequent Event        
Defined Benefit Plan Disclosure [Line Items]        
Transfer to active union medical account (106,000,000)      
Other Benefits        
Defined Benefit Plan Disclosure [Line Items]        
Expected long-term return on plan assets for next fiscal year (as a percent)   5.05%    
Contributions        
Employer contributions   $ 0 0  
Minimum contributions under MAP-21        
Retiree medical cost reimbursement   26,000,000 30,000,000 72,000,000
Other Benefits | Subsequent Event        
Defined Benefit Plan Disclosure [Line Items]        
Transfer to active union medical account $ 106,000,000      
Pinnacle West        
Minimum contributions under MAP-21        
Expenses recorded for the defined contribution savings plan   $ 11,000,000 $ 11,000,000 $ 11,000,000
ARIZONA PUBLIC SERVICE COMPANY        
Minimum contributions under MAP-21        
APS's employees share of total cost of the plans (as a percent)   99.00%    
v3.20.4
Retirement Plans and Other Postretirement Benefits - Net Periodic Benefit Costs and Portion including Portion Charged to Expense (Details) - USD ($)
$ in Thousands
12 Months Ended
Dec. 31, 2020
Dec. 31, 2019
Dec. 31, 2018
Net periodic benefit costs and the portion of these costs charged to expense      
Portion of cost/(benefit) charged to expense $ (56,341) $ (22,989) $ (49,791)
Pension Benefits      
Net periodic benefit costs and the portion of these costs charged to expense      
Service cost-benefits earned during the period 56,233 49,902 56,669
Interest cost on benefit obligation 118,567 136,843 124,689
Expected return on plan assets (187,443) (171,884) (182,853)
Prior service credit 0 0 0
Net actuarial loss 34,612 42,584 32,082
Net periodic benefit cost/(benefit) 21,969 57,445 30,587
Portion of cost/(benefit) charged to expense 3,386 30,312 10,120
Other Benefits      
Net periodic benefit costs and the portion of these costs charged to expense      
Service cost-benefits earned during the period 22,236 18,369 21,100
Interest cost on benefit obligation 25,857 29,894 28,147
Expected return on plan assets (40,077) (38,412) (42,082)
Prior service credit (37,575) (37,821) (37,842)
Net actuarial loss 0 0 0
Net periodic benefit cost/(benefit) (29,559) (27,970) (30,677)
Portion of cost/(benefit) charged to expense $ (20,966) $ (19,859) $ (21,426)
v3.20.4
Retirement Plans and Other Postretirement Benefits - Changes Benefit Obligations and Funded Status (Details) - USD ($)
$ in Thousands
12 Months Ended
Dec. 31, 2020
Dec. 31, 2019
Dec. 31, 2018
Pension Benefits      
Change in Benefit Obligation      
Benefit obligation at the beginning of the period $ 3,613,114 $ 3,190,626  
Service cost 56,233 49,902 $ 56,669
Interest cost 118,567 136,843 124,689
Benefit payments (191,704) (177,882)  
Actuarial (gain) loss 306,657 413,625  
Benefit obligation at the end of the period 3,902,867 3,613,114 3,190,626
Change in Plan Assets      
Balance at the beginning of the period 3,318,351 2,733,476  
Actual return on plan assets 642,373 602,030  
Employer contributions 100,000 150,000 50,000
Benefit payments (174,180) (167,155)  
Balance at the end of the period 3,886,544 3,318,351 2,733,476
Funded Status at the end of the period (16,323) (294,763)  
Other Benefits      
Change in Benefit Obligation      
Benefit obligation at the beginning of the period 746,924 676,771  
Service cost 22,236 18,369 21,100
Interest cost 25,857 29,894 28,147
Benefit payments (31,511) (32,486)  
Actuarial (gain) loss (139,472) 54,376  
Benefit obligation at the end of the period 624,034 746,924 676,771
Change in Plan Assets      
Balance at the beginning of the period 837,494 723,677  
Actual return on plan assets 150,076 144,095  
Employer contributions 0 0  
Benefit payments (26,405) (30,278)  
Balance at the end of the period 961,165 837,494 $ 723,677
Funded Status at the end of the period $ 337,131 $ 90,570  
v3.20.4
Retirement Plans and Other Postretirement Benefits - Projected Benefit Obligation for Pension Plans (Details) - Pension Benefits - USD ($)
$ in Thousands
Dec. 31, 2020
Dec. 31, 2019
Projected benefit obligation and the accumulated benefit obligation for pension plans with an accumulated obligation in excess of plan assets    
Accumulated benefit obligation $ 171,672 $ 169,091
Fair value of plan assets 0 0
Projected benefit obligation 182,184 3,613,114
Fair value of plan assets $ 0 $ 3,318,351
v3.20.4
Retirement Plans and Other Postretirement Benefits - Amounts Recognized on the Consolidated Balance Sheets (Details) - USD ($)
$ in Thousands
Dec. 31, 2020
Dec. 31, 2019
Amounts recognized on the Consolidated Balance Sheets    
Noncurrent asset $ 502,992 $ 90,570
Pension Benefits    
Amounts recognized on the Consolidated Balance Sheets    
Noncurrent asset 165,861 0
Current liability (15,700) (14,578)
Noncurrent liability (166,484) (280,185)
Net amount recognized (16,323) (294,763)
Other Benefits    
Amounts recognized on the Consolidated Balance Sheets    
Noncurrent asset 337,131 90,570
Current liability 0 0
Noncurrent liability 0 0
Net amount recognized $ 337,131 $ 90,570
v3.20.4
Retirement Plans and Other Postretirement Benefits - Impact to Accumulated Other Comprehensive Loss (Details) - USD ($)
$ in Thousands
Dec. 31, 2020
Dec. 31, 2019
Pension Benefits    
Details related to accumulated other comprehensive loss    
Net actuarial loss (gain) $ 552,301 $ 735,186
Prior service credit 0 0
APS’s portion recorded as a regulatory (asset) liability (469,953) (660,223)
Income tax expense (benefit) (20,364) (18,546)
Accumulated other comprehensive loss (gain) 61,984 56,417
Other Benefits    
Details related to accumulated other comprehensive loss    
Net actuarial loss (gain) (237,233) 12,238
Prior service credit (152,337) (189,912)
APS’s portion recorded as a regulatory (asset) liability 387,293 177,209
Income tax expense (benefit) 1,018 570
Accumulated other comprehensive loss (gain) $ (1,259) $ 105
v3.20.4
Retirement Plans and Other Postretirement Benefits - Weighted-Average Assumptions for Pensions and Other Benefits (Details)
12 Months Ended
Dec. 31, 2020
Dec. 31, 2019
Dec. 31, 2018
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) 6.50% 7.00%  
Initial pre-65 ultimate health care cost trend rate (as a percent) 4.75% 4.75%  
Number of years to ultimate trend rate (pre-65 participants) 5 years 6 years  
Initial post-65 healthcare cost trend rate (as a percent) 2.00% 4.75%  
Interest crediting rate – cash balance pension plans 4.50% 4.50%  
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 pre-65 ultimate healthcare cost trend rate (as a percent) 4.75% 4.75% 4.75%
Number of years to ultimate trend rate (pre-65 participants) 5 years 7 years 8 years
Initial post-65 health care cost trend rate (as a percent) 4.75% 4.75% 4.75%
Interest crediting rate – cash balance pension plans 4.50% 4.50% 4.50%
Pension Benefits      
Weighted-average assumptions used to determine benefit obligations      
Discount rate (as a percent) 2.53% 3.30%  
Weighted-average assumptions used to determine net periodic benefit costs      
Discount rate (as a percent) 3.30% 4.34% 3.65%
Rate of compensation increase (as a percent) 4.00% 4.00% 4.00%
Expected long-term return on plan assets (as a percent) 5.75% 6.25% 6.05%
Other Benefits      
Weighted-average assumptions used to determine benefit obligations      
Discount rate (as a percent) 2.63% 3.42%  
Weighted-average assumptions used to determine net periodic benefit costs      
Discount rate (as a percent) 3.42% 4.39% 3.71%
Expected long-term return on plan assets (as a percent) 4.85% 5.40% 5.40%
v3.20.4
Retirement Plans and Other Postretirement Benefits - Asset Allocation (Details)
Dec. 31, 2020
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 72.00%
Actual Allocation 68.00%
Pension Benefits | Return-generating assets  
Defined Benefit Plan Disclosure [Line Items]  
Target Allocation 28.00%
Actual Allocation 32.00%
Target Allocation 28.00%
Pension Benefits | Equities in US and other developed markets  
Defined Benefit Plan Disclosure [Line Items]  
Target Allocation 17.00%
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 5.00%
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 55.00%
Other Benefits | Return-generating assets  
Defined Benefit Plan Disclosure [Line Items]  
Actual Allocation 45.00%
v3.20.4
Retirement Plans and Other Postretirement Benefits - Fair Value of Pinnacle West's Pension Plan (Details) - USD ($)
$ in Thousands
Dec. 31, 2020
Dec. 31, 2019
Dec. 31, 2018
Pension Benefits      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Other $ 691,233 $ 832,143  
Fair value of plan assets 3,886,544 3,318,351 $ 2,733,476
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 1,398,305 852,239  
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 1,797,006 1,633,969  
Other Benefits      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Other 118,440 107,473  
Fair value of plan assets 961,165 837,494 $ 723,677
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 612,921 519,382  
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 229,804 210,639  
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 9,911 9,370  
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 9,911 9,370  
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 1,909 2,184  
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 1,909 2,184  
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 1,684,782 1,541,729  
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 1,684,782 1,541,729  
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 221,488 202,640  
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 221,488 202,640  
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 794,571 406,112  
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 794,571 406,112  
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 258,102 353,650  
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 258,102 353,650  
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 112,224 92,240  
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 112,224 92,240  
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 8,316 7,999  
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 8,316 7,999  
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 331,058 250,829  
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 331,058 250,829  
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 175,605 146,316  
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 175,605 146,316  
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 262,765 185,928  
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 262,765 185,928  
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 34,310 14,351  
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 34,310 14,351  
Equities | Pension Benefits      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Other 407,522 392,403  
Fair value of plan assets 407,522 392,403  
Equities | Other Benefits      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Other 94,674 83,648  
Fair value of plan assets 94,674 83,648  
Real estate | Pension Benefits      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Other 191,595 171,645  
Fair value of plan assets 191,595 171,645  
Real estate | Other Benefits      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Other 19,778 19,806  
Fair value of plan assets 19,778 19,806  
Fixed income | Pension Benefits      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Other   98,065  
Fair value of plan assets   98,065  
Partnerships | Pension Benefits      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Other 22,420 103,796  
Fair value of plan assets 22,420 103,796  
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 69,696 66,234  
Fair value of plan assets 69,696 66,234  
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 3,988 4,019  
Fair value of plan assets 146,983 6,900  
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 142,995 2,881  
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  
v3.20.4
Retirement Plans and Other Postretirement Benefits - Estimated Future Benefit Payments (Details)
$ in Thousands
Dec. 31, 2020
USD ($)
Pension Benefits  
Estimated Future Benefit Payments  
2021 $ 210,119
2022 209,593
2023 215,527
2024 220,241
2025 220,787
Years 2026-2030 1,116,848
Other Benefits  
Estimated Future Benefit Payments  
2021 31,204
2022 31,731
2023 32,196
2024 31,914
2025 31,484
Years 2026-2030 $ 153,536
v3.20.4
Leases - Additional information (Details)
$ in Thousands
12 Months Ended
Dec. 31, 2018
USD ($)
Dec. 31, 2020
USD ($)
Counterparty
Jun. 01, 2020
Lease
Dec. 31, 2019
USD ($)
Operating Leased Assets [Line Items]        
Number of lease agreements, sell and lease back | Counterparty   3    
Number of lease agreements | Lease     2  
Operating lease right-of-use assets   $ 505,064   $ 145,813
Operating lease, liability   436,121    
Prepaid lease costs reclassified as other deferred debits   34,983   33,400
Deferred lease costs   187,448   $ 168,323
Operating lease, expense $ 18,000      
Lease not yet commenced   650,000    
Purchased Power Lease Contracts        
Operating Leased Assets [Line Items]        
Operating lease, liability   $ 372,763    
Operating lease, expense 47,000      
Contingent rentals $ 109,000      
v3.20.4
Leases - Lease costs (Details) - USD ($)
$ in Thousands
12 Months Ended
Dec. 31, 2020
Dec. 31, 2019
Operating Leased Assets [Line Items]    
Operating lease cost $ 87,376 $ 60,228
Variable lease cost 122,331 114,015
Short-term lease cost 3,804 4,385
Total lease cost 213,511 178,628
Purchased Power Lease Contracts    
Operating Leased Assets [Line Items]    
Operating lease cost 68,883 42,190
Variable lease cost 121,359 113,233
Short-term lease cost 0 0
Total lease cost 190,242 155,423
Land, Property & Equipment Leases    
Operating Leased Assets [Line Items]    
Operating lease cost 18,493 18,038
Variable lease cost 972 782
Short-term lease cost 3,804 4,385
Total lease cost $ 23,269 $ 23,205
v3.20.4
Leases - Maturity of our operating lease liabilities (Details)
$ in Thousands
Dec. 31, 2020
USD ($)
Lessee, Lease, Description [Line Items]  
2021 $ 81,113
2022 79,174
2023 78,536
2024 77,888
2025 77,978
Thereafter 74,074
Total lease commitments 468,763
Less imputed interest 32,642
Total lease liabilities 436,121
Purchased Power Lease Contracts  
Lessee, Lease, Description [Line Items]  
2021 66,658
2022 68,325
2023 70,033
2024 71,784
2025 73,578
Thereafter 36,760
Total lease commitments 387,138
Less imputed interest 14,375
Total lease liabilities 372,763
Land, Property & Equipment Leases  
Lessee, Lease, Description [Line Items]  
2021 14,455
2022 10,849
2023 8,503
2024 6,104
2025 4,400
Thereafter 37,314
Total lease commitments 81,625
Less imputed interest 18,267
Total lease liabilities $ 63,358
v3.20.4
Leases - Other additional information related to operating lease liabilities (Details) - USD ($)
$ in Thousands
12 Months Ended
Dec. 31, 2020
Dec. 31, 2019
Leases [Abstract]    
Cash paid for amounts included in the measurement of lease liabilities - operating cash flows $ 75,097 $ 69,075
Right-of-use operating lease assets obtained in exchange for operating lease liabilities $ 441,653 $ 11,262
Weighted average remaining lease term 6 years 13 years
Weighted average discount rate 1.69% 3.71%
v3.20.4
Jointly-Owned Facilities (Details) - ARIZONA PUBLIC SERVICE COMPANY
$ in Thousands
Dec. 31, 2020
USD ($)
Palo Verde Units 1 and 3  
Interests in jointly-owned facilities  
Percent owned 29.10%
Plant in service $ 1,911,339
Accumulated depreciation 1,108,883
Construction work in progress $ 26,623
Palo Verde Unit 2  
Interests in jointly-owned facilities  
Percent owned 16.80%
Plant in service $ 649,035
Accumulated depreciation 379,305
Construction work in progress $ 7,268
Palo Verde Common  
Interests in jointly-owned facilities  
Percent owned 28.00%
Plant in service $ 774,054
Accumulated depreciation 320,107
Construction work in progress 41,607
Palo Verde Sale Leaseback  
Interests in jointly-owned facilities  
Plant in service 351,050
Accumulated depreciation 253,014
Construction work in progress $ 0
Four Corners Generating Station  
Interests in jointly-owned facilities  
Percent owned 63.00%
Plant in service $ 1,621,418
Accumulated depreciation 581,436
Construction work in progress $ 35,028
Cholla Common Facilities  
Interests in jointly-owned facilities  
Percent owned 50.50%
Plant in service $ 193,807
Accumulated depreciation 109,447
Construction work in progress $ 1,206
ANPP 500kV System  
Interests in jointly-owned facilities  
Percent owned 33.50%
Plant in service $ 131,991
Accumulated depreciation 52,626
Construction work in progress $ 3,859
Navajo Southern System  
Interests in jointly-owned facilities  
Percent owned 26.00%
Plant in service $ 89,113
Accumulated depreciation 33,536
Construction work in progress $ 1,215
Palo Verde — Yuma 500kV System  
Interests in jointly-owned facilities  
Percent owned 25.30%
Plant in service $ 23,247
Accumulated depreciation 6,681
Construction work in progress $ 433
Four Corners Switchyards  
Interests in jointly-owned facilities  
Percent owned 61.80%
Plant in service $ 69,441
Accumulated depreciation 17,009
Construction work in progress $ 3,145
Phoenix — Mead System  
Interests in jointly-owned facilities  
Percent owned 17.10%
Plant in service $ 39,437
Accumulated depreciation 19,072
Construction work in progress $ 73
Palo Verde — Rudd 500kV System  
Interests in jointly-owned facilities  
Percent owned 50.00%
Plant in service $ 93,123
Accumulated depreciation 28,206
Construction work in progress $ 1,921
Morgan — Pinnacle Peak System  
Interests in jointly-owned facilities  
Percent owned 64.60%
Plant in service $ 117,497
Accumulated depreciation 20,754
Construction work in progress $ 912
Round Valley System  
Interests in jointly-owned facilities  
Percent owned 50.00%
Plant in service $ 531
Accumulated depreciation 174
Construction work in progress $ 13
Palo Verde — Morgan System  
Interests in jointly-owned facilities  
Percent owned 88.90%
Plant in service $ 257,220
Accumulated depreciation 20,943
Construction work in progress $ 530
Hassayampa — North Gila System  
Interests in jointly-owned facilities  
Percent owned 80.00%
Plant in service $ 148,067
Accumulated depreciation 16,080
Construction work in progress $ 0
Cholla 500kV Switchyard  
Interests in jointly-owned facilities  
Percent owned 85.70%
Plant in service $ 7,896
Accumulated depreciation 1,850
Construction work in progress $ 940
Saguaro 500kV Switchyard  
Interests in jointly-owned facilities  
Percent owned 60.00%
Plant in service $ 21,669
Accumulated depreciation 13,229
Construction work in progress $ 2
Kyrene — Knox System  
Interests in jointly-owned facilities  
Percent owned 50.00%
Plant in service $ 578
Accumulated depreciation 323
Construction work in progress $ 0
v3.20.4
Commitments and Contingencies - Palo Verde Nuclear Generating Station and Contractual Obligations (Details)
12 Months Ended 84 Months Ended
Nov. 02, 2020
USD ($)
claim
Dec. 31, 2020
USD ($)
Trust
Dec. 31, 2019
USD ($)
Dec. 31, 2018
USD ($)
Jun. 30, 2018
USD ($)
time_period
claim
Dec. 31, 1986
Trust
Fuel and Purchased Power Commitments and Purchase Obligations [Abstract]            
Total take-or-pay commitments   $ 170,097,000 $ 165,695,000      
ARIZONA PUBLIC SERVICE COMPANY            
Palo Verde Nuclear Generating Station [Abstract]            
Maximum insurance against public liability per occurrence for a nuclear incident   13,800,000,000        
Maximum available nuclear liability insurance   450,000,000        
Remaining nuclear liability insurance through mandatory industry wide retrospective assessment program   13,300,000,000        
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   $ 25,800,000        
Period to provide collateral assurance based on rating triggers   20 days        
Collateral assurance based on rating triggers   $ 75,100,000        
Fuel and Purchased Power Commitments and Purchase Obligations [Abstract]            
2021   772,000,000        
2022   671,000,000        
2023   632,000,000        
2024   592,000,000        
2025   564,000,000        
Thereafter   5,400,000,000        
Total take-or-pay commitments   170,097,000 165,695,000      
ARIZONA PUBLIC SERVICE COMPANY | Coal take-or-pay commitments            
Fuel and Purchased Power Commitments and Purchase Obligations [Abstract]            
2021   182,569,000        
2022   183,604,000        
2023   184,540,000        
2024   186,804,000        
2025   177,114,000        
Thereafter   1,024,854,000        
Total take-or-pay commitments   1,900,000,000        
Present value of commitments   1,500,000,000        
Total purchases   189,817,000 204,888,000 $ 206,093,000    
ARIZONA PUBLIC SERVICE COMPANY | Renewable energy credits            
Fuel and Purchased Power Commitments and Purchase Obligations [Abstract]            
2021   35,000,000        
2022   31,000,000        
2023   30,000,000        
2024   28,000,000        
2025   25,000,000        
Thereafter   105,000,000        
ARIZONA PUBLIC SERVICE COMPANY | Coal Mine Reclamation Obligations            
Fuel and Purchased Power Commitments and Purchase Obligations [Abstract]            
2021   16,000,000        
2022   17,000,000        
2023   18,000,000        
2024   19,000,000        
2025   20,000,000        
Thereafter   69,000,000        
ARIZONA PUBLIC SERVICE COMPANY | Coal Mine Reclamation Balance Sheet Obligations            
Fuel and Purchased Power Commitments and Purchase Obligations [Abstract]            
Total take-or-pay commitments   $ 170,000,000 $ 166,000,000      
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 $ 12,200,000       $ 99,700,000  
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]            
Gain contingency, new claims filed, number | claim 7       6  
Gain contingency, number of separate time periods | time_period         6  
Settlement amount, awarded to company $ 3,600,000       $ 29,000,000.0  
v3.20.4
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, 2020
USD ($)
Commitments and Contingencies [Line Items]        
Costs related to investigation and study under Superfund site | $       $ 3
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      
v3.20.4
Commitments and Contingencies - Environmental Matters and Financial Assurances (Details) - USD ($)
$ in Thousands
12 Months Ended
Feb. 22, 2021
Jul. 03, 2018
Jul. 06, 2016
Dec. 31, 2020
Financial Assurances        
Equity contribution guarantees       $ 3,000
Production tax credit guarantees       39,000
2017 Settlement Agreement and its Customer Education and Outreach Plan | ARIZONA PUBLIC SERVICE COMPANY | Subsequent Event        
Arizona Attorney General [Abstract]        
Settlement amount $ 24,750      
Settlement amount returned to customers $ 24,000      
Letter of credit | ARIZONA PUBLIC SERVICE COMPANY        
Financial Assurances        
Outstanding letters of credit       5,200
Four Corners | NTEC        
Environmental Matters        
Option to purchase, ownership interest (as a percent)   7.00% 7.00%  
Payment received for coal supply agreement   $ 70,000    
Four Corners | 4CA        
Environmental Matters        
Percentage share cost of control     7.00%  
Remaining balance of notes       27,000
Four Corners | Coal Supply Agreement Arbitration | NTEC        
Environmental Matters        
Option to purchase, ownership interest (as a percent)     7.00%  
Four Corners | Coal Supply Agreement Arbitration | 4CA        
Environmental Matters        
Asset purchase agreement       $ 10,000
Regional Haze Rules | Four Corners Units 4 and 5 | ARIZONA PUBLIC SERVICE COMPANY        
Environmental Matters        
Percentage share cost of control       63.00%
Expected environmental cost       $ 400,000
Regional Haze Rules | Four Corners Units 4 and 5 | Four Corners | ARIZONA PUBLIC SERVICE COMPANY        
Environmental Matters        
Additional expected environment cost       $ 45,000
Regional Haze Rules | Four Corners Units 4 and 5 | Natural Gas Tolling Letter of Credit | ARIZONA PUBLIC SERVICE COMPANY        
Environmental Matters        
Additional percentage share of cost of control       7.00%
Coal Combustion Waste | Four Corners | ARIZONA PUBLIC SERVICE COMPANY        
Environmental Matters        
Additional expected environment cost       $ 27,000
Coal Combustion Waste | Navajo Generating Station | ARIZONA PUBLIC SERVICE COMPANY        
Environmental Matters        
Additional expected environment cost       1,000
Coal Combustion Waste | Minimum | Cholla | ARIZONA PUBLIC SERVICE COMPANY        
Environmental Matters        
Additional expected environment cost       16,000
Coal Combustion Waste | Minimum | Cholla and Four Corners | ARIZONA PUBLIC SERVICE COMPANY        
Environmental Matters        
Additional expected environment cost       10,000
Coal Combustion Waste | Maximum | Cholla and Four Corners | ARIZONA PUBLIC SERVICE COMPANY        
Environmental Matters        
Additional expected environment cost       15,000
Surety Bonds Expiring in 2020 | ARIZONA PUBLIC SERVICE COMPANY        
Financial Assurances        
Surety bonds expiring, amount       $ 16,000
v3.20.4
Asset Retirement Obligations (Details) - ARIZONA PUBLIC SERVICE COMPANY - USD ($)
$ in Thousands
12 Months Ended
Dec. 31, 2020
Dec. 31, 2019
Change in asset retirement obligations    
Asset retirement obligations at the beginning of year $ 657,218 $ 726,545
Changes attributable to:    
Accretion expense 38,652 39,726
Settlements (9,710) (12,591)
Estimated cash flow revisions 18,923 (96,462)
Asset retirement obligations at the end of year 705,083 657,218
Four Corners Units 4 and 5    
Asset Retirement Obligations    
Increase (decrease) in asset retirement obligation 13,000  
Navajo Generating Station    
Asset Retirement Obligations    
Increase (decrease) in asset retirement obligation $ 6,000 (8,000)
Palo Verde Nuclear Generating Station    
Asset Retirement Obligations    
Increase (decrease) in asset retirement obligation   (89,000)
Decrease in regulatory asset   80,000
Decrease in regulatory liability   $ 9,000
v3.20.4
Fair Value Measurements - Fair Value of Assets and Liabilities (Details) - USD ($)
$ in Thousands
Dec. 31, 2020
Dec. 31, 2019
Assets    
Commodity contracts, assets $ 4,749 $ 515
Commodity contracts, liabilities (4,271) (69)
Nuclear decommissioning trust 1,138,435 1,010,775
Nuclear decommissioning trust, other 592,227 521,245
Other special use fund 254,509 245,095
Other special use funds, other 504 474
Total assets 1,397,693 1,256,385
Total assets, other 588,460 521,650
Liabilities    
Gross derivative liability, other 2,986  
Gross derivative liability, other   (711)
Amount reported on balance sheet (18,619) (72,132)
Equity securities    
Assets    
Nuclear decommissioning trust 11,968 13,273
Nuclear decommissioning trust, other (17,828) 2,401
Other special use fund 37,841 7,616
Other special use funds, other 504 474
U.S. commingled equity funds    
Assets    
Nuclear decommissioning trust 610,055 518,844
U.S. Treasury debt    
Assets    
Nuclear decommissioning trust 164,514 160,607
Other special use fund 203,220 232,848
Corporate debt    
Assets    
Nuclear decommissioning trust 149,509 115,869
Mortgage-backed securities    
Assets    
Nuclear decommissioning trust 99,623 118,795
Municipal bonds    
Assets    
Nuclear decommissioning trust 89,705 73,040
Other special use fund 13,448 4,631
Other fixed income    
Assets    
Nuclear decommissioning trust 13,061 10,347
Level 1    
Assets    
Commodity contracts, assets 0 0
Nuclear decommissioning trust 194,310 171,479
Other special use fund 240,557 239,990
Total assets 434,867 411,469
Liabilities    
Gross derivative liability 0 0
Level 1 | Equity securities    
Assets    
Nuclear decommissioning trust 29,796 10,872
Other special use fund 37,337 7,142
Level 1 | U.S. commingled equity funds    
Assets    
Nuclear decommissioning trust 0 0
Level 1 | U.S. Treasury debt    
Assets    
Nuclear decommissioning trust 164,514 160,607
Other special use fund 203,220 232,848
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    
Commodity contracts, assets 9,016 551
Nuclear decommissioning trust 351,898 318,051
Other special use fund 13,448 4,631
Total assets 374,362 323,233
Liabilities    
Gross derivative liability (20,498) (67,992)
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 149,509 115,869
Level 2 | Mortgage-backed securities    
Assets    
Nuclear decommissioning trust 99,623 118,795
Level 2 | Municipal bonds    
Assets    
Nuclear decommissioning trust 89,705 73,040
Other special use fund 13,448 4,631
Level 2 | Other fixed income    
Assets    
Nuclear decommissioning trust 13,061 10,347
Level 3    
Assets    
Commodity contracts, assets 4 33
Nuclear decommissioning trust 0 0
Other special use fund 0 0
Total assets 4 33
Liabilities    
Gross derivative liability (1,107) (3,429)
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 $ 610,055 $ 518,844
v3.20.4
Fair Value Measurements - Additional Information (Details) - USD ($)
Dec. 31, 2020
Nov. 06, 2020
Fair Value Disclosures [Abstract]    
Stated interest rate for notes receivable 3.90%  
Financing receivable $ 27,100,000  
Coal Community Transition Plan | ACC    
Fair Value Disclosure, Asset and Liability, Not Measured at Fair Value [Line Items]    
Amount funded by shareholders $ 25,200,000 $ 25,000,000
v3.20.4
Earnings Per Share (Details) - USD ($)
$ / shares in Units, shares in Thousands, $ in Thousands
12 Months Ended
Dec. 31, 2020
Dec. 31, 2019
Dec. 31, 2018
Earnings Per Share [Abstract]      
Net income attributable to common shareholders $ 550,559 $ 538,320 $ 511,047
Weighted Average common shares outstanding — basic (in shares) 112,666 112,443 112,129
Net effect of dilutive securities:      
Contingently issuable performance shares and restricted stock units (in shares) 276 315 421
Weighted average common shares outstanding — diluted (in shares) 112,942 112,758 112,550
Earnings per weighted-average common share outstanding      
Net income attributable to common shareholders - basic (in dollars per share) $ 4.89 $ 4.79 $ 4.56
Net Income attributable to common shareholders - diluted (in dollars per share) $ 4.87 $ 4.77 $ 4.54
v3.20.4
Stock-Based Compensation - Additional Information (Details)
shares in Millions, $ in Millions
12 Months Ended
Dec. 31, 2020
USD ($)
performance_criteria
shares
Dec. 31, 2019
USD ($)
Dec. 31, 2018
USD ($)
Stock-Based Compensation      
Compensation cost that has been charged against income $ 18 $ 18 $ 20
Total income tax benefit recognized 4 7 7
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 $ 22 21 24
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 $ 6 5 4
Cash flow effect, cash used to settle awards $ 4 $ 5 $ 5
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%    
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%    
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) | shares 4.6    
Common shares available for issuance (in shares) | shares 1.5    
v3.20.4
Stock-Based Compensation - Summary of Restricted Stock, Stock Grants, Stock Units and Performance Shares (Details) - $ / shares
12 Months Ended
Dec. 31, 2020
Dec. 31, 2019
Dec. 31, 2018
Restricted Stock Units, Stock Grants, and Stock Units      
Stocks granted and the weighted average fair value      
Units granted (in shares) 118,403 109,106 132,997
Grant date fair value (in dollars per share) $ 71.70 $ 89.15 $ 77.51
Number of granted awards to be settled in cash (in shares) 45,646 48,972 66,252
Performance Shares      
Stocks granted and the weighted average fair value      
Units granted (in shares) 122,830 142,874 171,708
Grant date fair value (in dollars per share) $ 104.74 $ 92.16 $ 76.56
v3.20.4
Stock-Based Compensation - Status of Nonvested Restricted Stock, Stock Grants, Stock Units and Performance Shares (Details) - $ / shares
12 Months Ended
Dec. 31, 2020
Dec. 31, 2019
Dec. 31, 2018
Restricted Stock Units, Stock Grants, and Stock Units      
Nonvested shares      
Balance at the beginning of the period (in shares) 242,612    
Granted (in shares) 118,403    
Vested (in shares) (136,893)    
Forfeited (in shares) (3,565)    
Balance at the end of the period (in shares) 220,557 242,612  
Weighted-Average Grant-Date Fair Value      
Balance at the beginning of the period (in dollars per share) $ 81.38    
Granted (in dollars per share) 71.70 $ 89.15 $ 77.51
Vested (in dollars per share) 73.80    
Forfeited (in dollars per share) 82.61    
Balance at the end of the period (in dollars per share) $ 77.93 $ 81.38  
Vested awards outstanding at end of year (in shares) 82,921    
Vested awards outstanding at end of year (in dollars per share)    
Number of nonvested awards to be settled in cash (in shares) 126,996    
Performance Shares      
Nonvested shares      
Balance at the beginning of the period (in shares) 306,970    
Granted (in shares) 122,830    
Vested (in shares) (161,906)    
Forfeited (in shares) (7,890)    
Balance at the end of the period (in shares) 260,004 306,970  
Weighted-Average Grant-Date Fair Value      
Balance at the beginning of the period (in dollars per share) $ 83.65    
Granted (in dollars per share) 104.74 $ 92.16 $ 76.56
Vested (in dollars per share) 76.53    
Forfeited (in dollars per share) 85.06    
Balance at the end of the period (in dollars per share) $ 98.28 $ 83.65  
Vested awards outstanding at end of year (in shares) 161,906    
Vested awards outstanding at end of year (in dollars per share)    
v3.20.4
Derivative Accounting - Additional Information (Details)
12 Months Ended
Dec. 31, 2020
USD ($)
Derivative [Line Items]  
Amounts reclassified from accumulated other comprehensive income $ 0
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]  
Aggregate fair value of derivative instruments in a net liability position $ 21,605,000
Additional collateral to counterparties for energy related non-derivative instrument contracts $ 90,000,000
Risk Management Assets | Credit Concentration Risk  
Derivative [Line Items]  
Concentration risk, percentage 62.00%
Aggregate fair value of derivative instruments in a net liability position $ 5,000,000
v3.20.4
Derivative Accounting - Outstanding Gross Notional Amounts Outstanding (Details) - Commodity Contracts
MWh in Thousands
12 Months Ended
Dec. 31, 2020
MWh
Bcf
Dec. 31, 2019
MWh
Bcf
Outstanding gross notional amount of derivatives    
Power (in MWh) | MWh 368 193
Gas (in bcf) | Bcf 205 257
v3.20.4
Derivative Accounting - Gains and Losses from Derivative Instruments (Details) - Commodity Contracts - USD ($)
12 Months Ended
Dec. 31, 2020
Dec. 31, 2019
Dec. 31, 2018
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 Loss Recognized in Income (3,178,000) (84,953,000) (15,508,000)
Revenue | Not Designated as Hedging Instruments      
Derivative Instruments Not Designated as Cash Flows Hedges      
Net Loss Recognized in Income 0 0 (2,557,000)
Fuel and purchased power | Designated as Hedging Instruments      
Derivative Instruments in Designated Cash Flows Hedges      
Loss reclassified from accumulated other comprehensive income into income (effective portion realized) (763,000) (1,512,000) (2,000,000)
Fuel and purchased power | Not Designated as Hedging Instruments      
Derivative Instruments Not Designated as Cash Flows Hedges      
Net Loss Recognized in Income $ (3,178,000) $ (84,953,000) $ (12,951,000)
v3.20.4
Derivative Accounting - Derivative Instruments in the Balance Sheet (Details) - USD ($)
Dec. 31, 2020
Dec. 31, 2019
Assets    
Gross Recognized Derivatives $ 4,749,000 $ 515,000
Liabilities    
Amount Reported on Balance Sheet (18,619,000) (72,132,000)
Commodity Contracts    
Assets    
Gross Recognized Derivatives 9,020,000  
Amounts Offset (4,271,000)  
Net Recognized Derivatives 4,749,000  
Other 0 405,000
Amount Reported on Balance Sheet 4,749,000  
Liabilities    
Gross Recognized Derivatives (21,605,000) (71,421,000)
Amounts Offset 4,271,000 474,000
Net Recognized Derivatives (17,334,000) (70,947,000)
Other (1,285,000) (1,185,000)
Amount Reported on Balance Sheet (18,619,000) (72,132,000)
Assets and Liabilities    
Gross Recognized Derivatives (12,585,000) (70,837,000)
Amounts Offset 0 0
Net Recognized Derivatives (12,585,000) (70,837,000)
Other (1,285,000) (780,000)
Amount Reported on Balance Sheet (13,870,000) (71,617,000)
Commodity Contracts | Current Assets    
Assets    
Gross Recognized Derivatives 5,870,000 584,000
Amounts Offset (2,939,000) (474,000)
Net Recognized Derivatives 2,931,000 110,000
Other 0 405,000
Amount Reported on Balance Sheet 2,931,000 515,000
Commodity Contracts | Investments and Other Assets    
Assets    
Gross Recognized Derivatives 3,150,000  
Amounts Offset (1,332,000)  
Net Recognized Derivatives 1,818,000  
Other 0  
Amount Reported on Balance Sheet 1,818,000  
Commodity Contracts | Current Liabilities    
Liabilities    
Gross Recognized Derivatives (9,211,000) (38,235,000)
Amounts Offset 2,939,000 474,000
Net Recognized Derivatives (6,272,000) (37,761,000)
Other (1,285,000) (1,185,000)
Amount Reported on Balance Sheet (7,557,000) (38,946,000)
Commodity Contracts | Deferred Credits and Other    
Liabilities    
Gross Recognized Derivatives (12,394,000) (33,186,000)
Amounts Offset 1,332,000 0
Net Recognized Derivatives (11,062,000) (33,186,000)
Other 0 0
Amount Reported on Balance Sheet $ (11,062,000) $ (33,186,000)
v3.20.4
Derivative Accounting - Credit Risk and Related Contingent Features (Details) - Commodity Contracts
$ in Thousands
Dec. 31, 2020
USD ($)
Credit Risk and Credit-Related Contingent Features  
Aggregate fair value of derivative instruments in a net liability position $ 21,605
Cash collateral posted 0
Additional cash collateral in the event credit-risk related contingent features were fully triggered $ 19,510
v3.20.4
Other Income and Other Expense (Details) - USD ($)
12 Months Ended
Dec. 31, 2020
Dec. 31, 2019
Dec. 31, 2018
Nov. 06, 2020
Other income:        
Interest income $ 12,210,000 $ 10,377,000 $ 8,647,000  
Investment gains (losses) — net 2,358,000 0 0  
Miscellaneous 149,000 63,000 96,000  
Total other income 56,703,000 50,263,000 24,896,000  
Other expense:        
Non-operating costs (12,400,000) (10,663,000) (10,076,000)  
Investment gains (losses) — net 0 (1,835,000) (417,000)  
Miscellaneous (45,376,000) (5,382,000) (7,473,000)  
Total other expense (57,776,000) (17,880,000) (17,966,000)  
ARIZONA PUBLIC SERVICE COMPANY        
Other income:        
Interest income 9,621,000 6,998,000 6,496,000  
Miscellaneous 148,000 63,000 97,000  
Total other income 51,755,000 46,884,000 22,746,000  
Other expense:        
Non-operating costs (10,659,000) (9,612,000) (9,462,000)  
Miscellaneous (43,035,000) (3,378,000) (5,830,000)  
Total other expense (53,694,000) (12,990,000) (15,292,000)  
ACC | Coal Community Transition Plan        
Other expense:        
Amount funded by shareholders 25,200,000     $ 25,000,000
ACC | Navajo Nation, Electrification Projects | Coal Community Transition Plan        
Other expense:        
Amount funded by shareholders 10,000,000     $ 10,000,000
SCR deferral        
Other income:        
Debt return on Four Corners SCR 26,121,000 19,541,000 16,153,000  
SCR deferral | ARIZONA PUBLIC SERVICE COMPANY        
Other income:        
Debt return on Four Corners SCR 26,121,000 19,541,000 16,153,000  
Octotillo deferral        
Other income:        
Debt return on Four Corners SCR 15,865,000 20,282,000 0  
Octotillo deferral | ARIZONA PUBLIC SERVICE COMPANY        
Other income:        
Debt return on Four Corners SCR $ 15,865,000 $ 20,282,000 $ 0  
v3.20.4
Palo Verde Sale Leaseback Variable Interest Entities (Details)
$ in Thousands
12 Months Ended
Dec. 31, 2020
USD ($)
Trust
Lease
Dec. 31, 2019
USD ($)
Dec. 31, 2018
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 | Variable Interest Entity        
Palo Verde Sale Leaseback Variable Interest Entities        
Increase in net income due to consolidation of Palo Verde Sale Leaseback Trusts     $ 19,000  
Initial loss exposure to the VIEs noncontrolling equity participants during lease extension period 306,000      
Maximum loss exposure to the VIE's noncontrolling equity participants during lease extension period $ 456,000      
Period Through 2023 | ARIZONA PUBLIC SERVICE COMPANY | Variable Interest Entity        
Palo Verde Sale Leaseback Variable Interest Entities        
Number of leases under which assets are retained | Lease 1      
Period Through 2033 | ARIZONA PUBLIC SERVICE COMPANY | Variable Interest Entity        
Palo Verde Sale Leaseback Variable Interest Entities        
Number of leases under which assets are retained | Lease 2      
Period 2021 through 2023 | ARIZONA PUBLIC SERVICE COMPANY | Variable Interest Entity        
Palo Verde Sale Leaseback Variable Interest Entities        
Annual lease payments $ 23,000      
Period 2024 through 2033 | ARIZONA PUBLIC SERVICE COMPANY | Variable Interest Entity        
Palo Verde Sale Leaseback Variable Interest Entities        
Annual lease payments $ 16,000      
Maximum | Period 2024 through 2033 | ARIZONA PUBLIC SERVICE COMPANY | Variable Interest Entity        
Palo Verde Sale Leaseback Variable Interest Entities        
Lease period 2 years      
v3.20.4
Palo Verde Sale Leaseback Variable Interest Entities - Schedule of VIEs (Details) - USD ($)
$ in Thousands
Dec. 31, 2020
Dec. 31, 2019
Palo Verde Sale Leaseback Variable Interest Entities    
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation $ 15,159,210 $ 14,522,538
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets    
Equity — Noncontrolling interests 119,290 122,540
ARIZONA PUBLIC SERVICE COMPANY    
Palo Verde Sale Leaseback Variable Interest Entities    
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation 15,158,846 14,522,156
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets    
Equity — Noncontrolling interests 119,290 122,540
Palo Verde VIE | ARIZONA PUBLIC SERVICE COMPANY    
Palo Verde Sale Leaseback Variable Interest Entities    
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation 98,036 101,906
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets    
Equity — Noncontrolling interests $ 119,290 $ 122,540
v3.20.4
Investments in Nuclear Decommissioning Trusts and Other Special Use Funds (Details) - USD ($)
$ in Thousands
3 Months Ended 12 Months Ended
Jan. 04, 2021
Dec. 31, 2020
Dec. 31, 2020
Dec. 31, 2019
Dec. 31, 2018
Subsequent Event          
Fair value of fixed income securities, summarized by contractual maturities          
Transfer to active union medical account $ 106,000        
ARIZONA PUBLIC SERVICE COMPANY          
Nuclear decommissioning trust fund assets          
Fair Value   $ 1,392,944 $ 1,392,944 $ 1,255,870  
Total Unrealized Gains   468,247 468,247 363,476  
Total Unrealized Losses   (398) (398) (669)  
Amortized cost   687,000 687,000 691,000  
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds          
Realized gains     12,370 11,132 $ 6,680
Realized losses     (5,568) (6,972) (13,552)
Proceeds from the sale of securities     819,519 719,034 653,033
Fair value of fixed income securities, summarized by contractual maturities          
Employee medical claims amount   14,000   15,000  
ARIZONA PUBLIC SERVICE COMPANY | Equity securities          
Nuclear decommissioning trust fund assets          
Equity Securities   677,188 677,188 536,858  
Total Unrealized Gains   421,666 421,666 337,681  
Total Unrealized Losses   0 0 0  
ARIZONA PUBLIC SERVICE COMPANY | Fixed income securities          
Nuclear decommissioning trust fund assets          
Fair Value   733,080 733,080 716,137  
Total Unrealized Gains   46,581 46,581 25,795  
Total Unrealized Losses   (398) (398) (669)  
Fair value of fixed income securities, summarized by contractual maturities          
Less than one year   52,642 52,642    
1 year - 5 years   323,570 323,570    
5 years - 10 years   136,045 136,045    
Greater than 10 years   220,823 220,823    
Total   733,080 733,080    
ARIZONA PUBLIC SERVICE COMPANY | Other Receivables from Broker-Dealers and Clearing          
Nuclear decommissioning trust fund assets          
Other   (17,324) (17,324) 2,875  
Total Unrealized Gains   0 0 0  
Total Unrealized Losses   0 0 0  
Nuclear Decommissioning Trusts | ARIZONA PUBLIC SERVICE COMPANY          
Nuclear decommissioning trust fund assets          
Fair Value   1,138,435 1,138,435 1,010,775  
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds          
Realized gains     12,194 11,024 6,679
Realized losses     (5,553) (6,972) (13,552)
Proceeds from the sale of securities     675,035 473,806 554,385
Nuclear Decommissioning Trusts | ARIZONA PUBLIC SERVICE COMPANY | Equity securities          
Nuclear decommissioning trust fund assets          
Equity Securities   639,851 639,851 529,716  
Nuclear Decommissioning Trusts | ARIZONA PUBLIC SERVICE COMPANY | Fixed income securities          
Nuclear decommissioning trust fund assets          
Fair Value   516,412 516,412 478,658  
Fair value of fixed income securities, summarized by contractual maturities          
Less than one year   19,563 19,563    
1 year - 5 years   151,537 151,537    
5 years - 10 years   133,307 133,307    
Greater than 10 years   212,005 212,005    
Total   516,412 516,412    
Nuclear Decommissioning Trusts | ARIZONA PUBLIC SERVICE COMPANY | Other Receivables from Broker-Dealers and Clearing          
Nuclear decommissioning trust fund assets          
Other   (17,828) (17,828) 2,401  
Coal Reclamation Escrow Account | ARIZONA PUBLIC SERVICE COMPANY | Fixed income securities          
Fair value of fixed income securities, summarized by contractual maturities          
Less than one year   33,079 33,079    
1 year - 5 years   29,722 29,722    
5 years - 10 years   2,738 2,738    
Greater than 10 years   8,818 8,818    
Total   74,357 74,357    
Active union medical trust | ARIZONA PUBLIC SERVICE COMPANY | Fixed income securities          
Fair value of fixed income securities, summarized by contractual maturities          
Less than one year   0 0    
1 year - 5 years   142,311 142,311    
5 years - 10 years   0 0    
Greater than 10 years   0 0    
Total   142,311 142,311    
Other Special Use Funds | ARIZONA PUBLIC SERVICE COMPANY          
Nuclear decommissioning trust fund assets          
Fair Value   254,509 254,509 245,095  
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds          
Realized gains     176 108 1
Realized losses     (15) 0 0
Proceeds from the sale of securities     144,484 245,228 $ 98,648
Other Special Use Funds | ARIZONA PUBLIC SERVICE COMPANY | Equity securities          
Nuclear decommissioning trust fund assets          
Equity Securities   37,337 37,337 7,142  
Other Special Use Funds | ARIZONA PUBLIC SERVICE COMPANY | Fixed income securities          
Nuclear decommissioning trust fund assets          
Fair Value   216,668 216,668 237,479  
Other Special Use Funds | ARIZONA PUBLIC SERVICE COMPANY | Other Receivables from Broker-Dealers and Clearing          
Nuclear decommissioning trust fund assets          
Other   $ 504 $ 504 $ 474  
v3.20.4
Changes in Accumulated Other Comprehensive Loss (Details) - USD ($)
$ in Thousands
12 Months Ended
Dec. 31, 2020
Dec. 31, 2019
Changes in accumulated other comprehensive income (loss) by component    
Beginning balance $ 5,553,188 $ 5,348,705
Ending balance 5,752,793 5,553,188
Pension and Other Postretirement Benefits    
Changes in accumulated other comprehensive income (loss) by component    
Beginning balance (56,522) (45,997)
OCI (loss) before reclassifications (8,370) (14,041)
Amounts reclassified from accumulated other comprehensive loss 4,167 3,516
Ending balance (60,725) (56,522)
Derivative Instruments    
Changes in accumulated other comprehensive income (loss) by component    
Beginning balance (574) (1,711)
OCI (loss) before reclassifications (2,089) 0
Amounts reclassified from accumulated other comprehensive loss 592 1,137
Ending balance (2,071) (574)
Accumulated Other Comprehensive Income (Loss)    
Changes in accumulated other comprehensive income (loss) by component    
Beginning balance (57,096) (47,708)
OCI (loss) before reclassifications (10,459) (14,041)
Amounts reclassified from accumulated other comprehensive loss 4,759 4,653
Ending balance (62,796) (57,096)
ARIZONA PUBLIC SERVICE COMPANY    
Changes in accumulated other comprehensive income (loss) by component    
Beginning balance 5,998,803 5,786,797
Ending balance 6,345,185 5,998,803
ARIZONA PUBLIC SERVICE COMPANY | Pension and Other Postretirement Benefits    
Changes in accumulated other comprehensive income (loss) by component    
Beginning balance (34,948) (25,396)
OCI (loss) before reclassifications (9,568) (12,572)
Amounts reclassified from accumulated other comprehensive loss 3,598 3,020
Ending balance (40,918) (34,948)
ARIZONA PUBLIC SERVICE COMPANY | Derivative Instruments    
Changes in accumulated other comprehensive income (loss) by component    
Beginning balance (574) (1,711)
OCI (loss) before reclassifications (18) 0
Amounts reclassified from accumulated other comprehensive loss 592 1,137
Ending balance 0 (574)
ARIZONA PUBLIC SERVICE COMPANY | Accumulated Other Comprehensive Income (Loss)    
Changes in accumulated other comprehensive income (loss) by component    
Beginning balance (35,522) (27,107)
OCI (loss) before reclassifications (9,586) (12,572)
Amounts reclassified from accumulated other comprehensive loss 4,190 4,157
Ending balance $ (40,918) $ (35,522)
v3.20.4
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT - Comprehensive Income (Details) - USD ($)
$ in Thousands
12 Months Ended
Dec. 31, 2020
Dec. 31, 2019
Dec. 31, 2018
CONDENSED FINANCIAL STATEMENTS      
Operating expenses $ 2,798,830 $ 2,799,249 $ 2,917,560
Other      
Total 89,044 86,803 109,040
Interest expense 247,501 235,251 243,465
Income tax benefit 78,173 (15,773) 133,902
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS 550,559 538,320 511,047
Other comprehensive income (loss) — attributable to common shareholders (5,700) (9,388) 5,846
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS 544,859 528,932 516,893
Pinnacle West      
CONDENSED FINANCIAL STATEMENTS      
Operating expenses 7,901 12,451 53,844
Other      
Equity in earnings of subsidiaries 566,147 562,946 569,249
Other expense (4,586) (3,957) (3,202)
Total 561,561 558,989 566,047
Interest expense 14,021 15,069 12,074
Income before income taxes 539,639 531,469 500,129
Income tax benefit (10,920) (6,851) (10,918)
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS 550,559 538,320 511,047
Other comprehensive income (loss) — attributable to common shareholders (5,700) (9,388) 5,846
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS $ 544,859 $ 528,932 $ 516,893
v3.20.4
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT - Balance Sheets (Details) - USD ($)
$ in Thousands
Dec. 31, 2020
Dec. 31, 2019
Dec. 31, 2018
Dec. 31, 2017
Current assets        
Cash and cash equivalents $ 59,968 $ 10,283    
Accounts receivable 313,576 266,426    
Income tax receivable 6,792 21,727    
Other current assets 76,627 61,958    
Total current assets 1,198,319 1,030,030    
Investments and other assets        
Other assets 92,922 96,953    
Total investments and other assets 1,485,866 1,352,823    
Total Assets 20,020,421 18,479,247    
Current liabilities        
Accounts payable 318,585 346,448    
Accrued taxes 159,551 144,899    
Common dividends payable 93,531 87,982    
Short-term borrowings 169,000 114,675    
Current maturities of long-term debt 0 800,000    
Operating lease liabilities 74,785 12,713    
Other current liabilities 187,448 168,323    
Total current liabilities 1,360,433 2,078,365    
Deferred credits and other        
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 7) 6,314,266 4,832,558    
Operating lease liabilities 361,336 51,872    
Other 190,643 159,844    
Total deferred credits and other 6,592,929 6,015,136    
COMMITMENTS AND CONTINGENCIES (SEE NOTES)    
Common stock equity        
Common stock 2,677,482 2,659,561    
Accumulated other comprehensive loss (62,796) (57,096)    
Retained earnings 3,025,106 2,837,610    
Total shareholders’ equity 5,633,503 5,430,648    
Noncontrolling interests (Note 18) 119,290 122,540    
Total equity 5,752,793 5,553,188 $ 5,348,705 $ 5,135,730
Total Liabilities and Equity 20,020,421 18,479,247    
Pinnacle West        
Current assets        
Cash and cash equivalents 19 19    
Accounts receivable 123,980 104,640    
Income tax receivable 14,719 15,905    
Other current assets 298 401    
Total current assets 139,016 120,965    
Investments and other assets        
Investments in subsidiaries 6,400,339 6,067,957    
Deferred income taxes 7,589 40,757    
Other assets 52,595 50,139    
Total investments and other assets 6,460,523 6,158,853    
Total Assets 6,599,539 6,279,818    
Current liabilities        
Accounts payable 5,669 7,634    
Accrued taxes 16,998 8,573    
Common dividends payable 93,531 87,982    
Short-term borrowings 169,000 114,675    
Current maturities of long-term debt 0 450,000    
Operating lease liabilities 90 81    
Other current liabilities 15,306 15,126    
Total current liabilities 300,594 684,071    
Deferred credits and other        
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 7) 496,321 (575)    
Pension liabilities 17,541 17,942    
Operating lease liabilities 1,683 1,780    
Other 30,607 23,412    
Total deferred credits and other 49,831 43,134    
COMMITMENTS AND CONTINGENCIES (SEE NOTES)    
Common stock equity        
Common stock 2,671,193 2,650,134    
Accumulated other comprehensive loss (62,796) (57,096)    
Retained earnings 3,025,106 2,837,610    
Total shareholders’ equity 5,633,503 5,430,648    
Noncontrolling interests (Note 18) 119,290 122,540    
Total equity 5,752,793 5,553,188    
Total Liabilities and Equity $ 6,599,539 $ 6,279,818    
v3.20.4
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT - Cash Flows (Details) - USD ($)
$ in Thousands
12 Months Ended
Dec. 31, 2020
Dec. 31, 2019
Dec. 31, 2018
Cash Flows from Operating Activities      
Net income $ 570,052 $ 557,813 $ 530,540
Adjustments to reconcile net income to net cash provided by operating activities:      
Depreciation and amortization 686,253 664,140 650,955
Deferred income taxes 69,469 (1,479) 117,355
Accounts receivable (18,191) (12,789) 37,530
Accounts payable (6,059) 50,641 (14,602)
Net cash flow provided by operating activities 966,365 956,726 1,277,144
Cash flows from investing activities      
Net cash flow used for investing activities (1,277,818) (1,130,977) (1,192,824)
Cash flows from financing activities      
Issuance of long-term debt 1,596,672 1,092,188 445,245
Short-term debt borrowings under revolving credit facility 751,690 49,000 45,000
Short-term debt repayments under revolving credit facility (770,690) (65,000) (57,000)
Dividends paid on common stock (350,577) (329,643) (308,892)
Repayment of long-term debt (915,150) (600,000) (182,000)
Common stock equity issuance and purchases — net (1,389) 692 (5,055)
Net cash flow provided by (used for) financing activities 361,138 178,768 (92,446)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 49,685 4,517 (8,126)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 10,283 5,766 13,892
CASH AND CASH EQUIVALENTS AT END OF YEAR 59,968 10,283 5,766
Pinnacle West      
Cash Flows from Operating Activities      
Net income 550,559 538,320 511,047
Adjustments to reconcile net income to net cash provided by operating activities:      
Equity in earnings of subsidiaries - net (566,147) (562,946) (569,249)
Depreciation and amortization 76 76 76
Deferred income taxes 33,007 (35,831) 49,535
Accounts receivable (7,903) 182 (7,881)
Accounts payable (1,964) (2,129) 1,967
Accrued taxes and income tax receivable - net 9,610 16,400 (13,535)
Dividends received from subsidiaries 357,500 336,300 316,000
Other 20,163 (1,300) 31,807
Net cash flow provided by operating activities 394,901 289,072 319,767
Cash flows from investing activities      
Investments in subsidiaries (137,881) 1,557 (142,796)
Repayments of loans from subsidiaries 932 4,190 6,477
Advances of loans to subsidiaries (7,261) (4,165) (500)
Net cash flow used for investing activities (144,210) 1,582 (136,819)
Cash flows from financing activities      
Issuance of long-term debt 496,950 0 150,000
Short-term debt borrowings under revolving credit facility 211,690 49,000 20,000
Short-term debt repayments under revolving credit facility (230,690) (65,000) (32,000)
Commercial paper — net 73,325 54,275 (7,000)
Dividends paid on common stock (350,577) (329,643) (308,892)
Repayment of long-term debt (450,000) 0 0
Common stock equity issuance and purchases — net (1,389) 692 (5,055)
Other 0 0 (1)
Net cash flow provided by (used for) financing activities (250,691) (290,676) (182,948)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 0 (22) 0
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 19 41 41
CASH AND CASH EQUIVALENTS AT END OF YEAR $ 19 $ 19 $ 41