PINNACLE WEST CAPITAL CORP, 10-K filed on 2/25/2022
Annual Report
v3.22.0.1
Cover Page - USD ($)
 12 Months Ended
Dec. 31, 2021
Feb. 17, 2022
Jun. 30, 2021
Entity Information [Line Items]      
Document Type 10-K    
Document Annual Report true    
Document Period End Date Dec. 31, 2021    
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 Incorporation, State or Country Code AZ    
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     $ 9,024,891,205
Entity Common Stock, Shares Outstanding   112,931,929  
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 18, 2022 are incorporated by reference into Part III hereof.    
Entity Central Index Key 0000764622    
Amendment Flag false    
Document Fiscal Year Focus 2021    
Document Fiscal Period Focus FY    
Arizona Public Service Company      
Entity Information [Line Items]      
Document Type 10-K    
Document Period End Date Dec. 31, 2021    
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 Incorporation, State or Country Code AZ    
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 2021    
Document Fiscal Period Focus FY    
v3.22.0.1
Audit Information
 12 Months Ended
Dec. 31, 2021
Auditor [Line Items]  
Auditor Name Deloitte & Touche LLP
Auditor Location Phoenix, Arizona
Auditor Firm ID 34
Arizona Public Service Company  
Auditor [Line Items]  
Auditor Name Deloitte & Touche LLP
Auditor Location Phoenix, Arizona
Auditor Firm ID 34
v3.22.0.1
CONSOLIDATED STATEMENTS OF INCOME - USD ($)
shares in Thousands, $ in Thousands
 12 Months Ended
Dec. 31, 2021
Dec. 31, 2020
Dec. 31, 2019
Income Statement [Abstract]      
OPERATING REVENUES (Note 2) $ 3,803,835 $ 3,586,982 $ 3,471,209
OPERATING EXPENSES      
Fuel and purchased power 1,152,551 993,419 1,042,237
Operations and maintenance 954,067 958,910 941,616
Depreciation and amortization 650,875 614,378 590,929
Taxes other than income taxes 234,639 224,835 218,579
Other expenses 6,393 7,288 5,888
Total 2,998,525 2,798,830 2,799,249
OPERATING INCOME 805,310 788,152 671,960
OTHER INCOME (DEDUCTIONS)      
Allowance for equity funds used during construction (Note 1) 41,737 33,776 31,431
Pension and other postretirement non-service credits — net (Note 8) 112,541 56,341 22,989
Other income (Note 17) 45,100 56,703 50,263
Other expense (Note 17) (25,396) (57,776) (17,880)
Total 173,982 89,044 86,803
INTEREST EXPENSE      
Interest charges 254,314 247,501 235,251
Allowance for borrowed funds used during construction (Note 1) (21,052) (18,530) (18,528)
Total 233,262 228,971 216,723
INCOME BEFORE INCOME TAXES 746,030 648,225 542,040
INCOME TAXES (Note 5) 110,086 78,173 (15,773)
NET INCOME 635,944 570,052 557,813
Less: Net income attributable to noncontrolling interests (Note 18) 17,224 19,493 19,493
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS $ 618,720 $ 550,559 $ 538,320
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — BASIC (in shares) 112,910 112,666 112,443
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — DILUTED (in shares) 113,192 112,942 112,758
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING      
Net income attributable to common shareholders - basic (in dollars per share) $ 5.48 $ 4.89 $ 4.79
Net income attributable to common shareholders — diluted (in dollars per share) $ 5.47 $ 4.87 $ 4.77
v3.22.0.1
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2021
Dec. 31, 2020
Dec. 31, 2019
Statement of Comprehensive Income [Abstract]      
NET INCOME $ 635,944 $ 570,052 $ 557,813
Derivative instruments:      
Net unrealized loss, net of tax benefit (expense) 1,077 (2,089) 0
Reclassification of net realized gain, net of tax expense 18 592 1,137
Pension and other postretirement benefits activity, net of tax benefit (expense) 6,840 (4,203) (10,525)
Total other comprehensive income (loss) 7,935 (5,700) (9,388)
COMPREHENSIVE INCOME 643,879 564,352 548,425
Less: Comprehensive income attributable to noncontrolling interests 17,224 19,493 19,493
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS $ 626,655 $ 544,859 $ 528,932
v3.22.0.1
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2021
Dec. 31, 2020
Dec. 31, 2019
Statement of Comprehensive Income [Abstract]      
Net unrealized loss, tax benefit (expense) $ (378) $ 662 $ 0
Reclassification of net realized gain, tax benefit (expense) 18 (171) (375)
Pension and other postretirement benefits activity, tax benefit (expense) $ (2,256) $ 1,371 $ 3,452
v3.22.0.1
CONSOLIDATED BALANCE SHEETS - USD ($)
$ in Thousands
Dec. 31, 2021
Dec. 31, 2020
CURRENT ASSETS    
Cash and cash equivalents $ 9,969 $ 59,968
Customer and other receivables 391,923 313,576
Accrued unbilled revenues 133,980 132,197
Allowance for doubtful accounts (Note 2) (25,354) (19,782)
Materials and supplies (at average cost) 349,135 314,745
Fossil fuel (at average cost) 18,032 19,552
Income tax receivable (Note 5) 7,514 6,792
Assets from risk management activities (Note 16) 63,481 2,931
Deferred fuel and purchased power regulatory asset (Note 4) 388,148 175,835
Other regulatory assets (Note 4) 130,376 115,878
Other current assets 83,896 76,627
Total current assets 1,551,100 1,198,319
INVESTMENTS AND OTHER ASSETS    
Nuclear decommissioning trust (Notes 13 and 19) 1,294,757 1,138,435
Other special use funds (Notes 13 and 19) 358,410 254,509
Assets from risk management activities (Note 16) 46,908 1,818
Other assets 97,884 91,104
Total investments and other assets 1,797,959 1,485,866
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 7 and 10)    
Plant in service and held for future use 21,688,661 20,837,885
Accumulated depreciation and amortization (7,504,603) (7,110,310)
Net 14,184,058 13,727,575
Construction work in progress 1,329,478 937,384
Palo Verde sale leaseback, net of accumulated depreciation 94,166 98,036
Intangible assets, net of accumulated amortization 273,693 282,570
Nuclear fuel, net of accumulated amortization 106,039 113,645
Total property, plant and equipment 15,987,434 15,159,210
DEFERRED DEBITS    
Regulatory assets (Notes 1, 4 and 5) 1,192,987 1,133,987
Operating lease right-of-use assets (Note 9) 890,057 505,064
Assets for pension and other postretirement benefits (Note 8) 545,723 502,992
Other 37,962 34,983
Total deferred debits 2,666,729 2,177,026
Total Assets 22,003,222 20,020,421
CURRENT LIABILITIES    
Accounts payable 393,083 318,585
Accrued taxes 168,645 159,551
Accrued interest 57,332 56,962
Common dividends payable 95,988 93,531
Short-term borrowings (Note 6) 292,000 169,000
Current maturities of long-term debt (Note 7) 150,000 0
Customer deposits 42,293 48,340
Liabilities from risk management activities (Note 16) 4,373 7,557
Liabilities for asset retirements (Note 12) 4,473 15,586
Operating lease liabilities (Note 9) 100,443 74,785
Regulatory liabilities (Note 4) 296,271 229,088
Other current liabilities 151,968 187,448
Total current liabilities 1,756,869 1,360,433
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 7) 6,913,735 6,314,266
DEFERRED CREDITS AND OTHER    
Deferred income taxes (Note 5) 2,311,862 2,135,403
Regulatory liabilities (Notes 1, 4, 5 and 8) 2,499,213 2,450,169
Liabilities for asset retirements (Note 12) 762,909 689,497
Liabilities for pension benefits (Note 8) 152,865 166,484
Liabilities from risk management activities (Note 16) 0 11,062
Customer advances 257,151 221,032
Coal mine reclamation 174,616 170,097
Deferred investment tax credit 186,570 191,372
Unrecognized tax benefits (Note 5) 4,657 5,834
Operating lease liabilities (Note 9) 728,401 361,336
Other 232,914 190,643
Total deferred credits and other 7,311,158 6,592,929
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
EQUITY    
Common stock, no par value; authorized 150,000,000 shares, 113,014,528 and 112,760,051 issued at respective dates 2,702,743 2,677,482
Treasury stock at cost; 87,608 shares at end of 2021 and 72,006 shares at end of 2020 (6,401) (6,289)
Total common stock 2,696,342 2,671,193
Retained earnings 3,264,719 3,025,106
Accumulated other comprehensive loss (54,861) (62,796)
Total shareholders’ equity 5,906,200 5,633,503
Noncontrolling interests (Note 18) 115,260 119,290
Total equity 6,021,460 5,752,793
Total Liabilities and Equity $ 22,003,222 $ 20,020,421
v3.22.0.1
CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($)
$ in Thousands
Dec. 31, 2021
Dec. 31, 2020
PROPERTY, PLANT AND EQUIPMENT    
Accumulated depreciation of Palo Verde sale leaseback $ 256,884 $ 253,014
Accumulated amortization on intangible assets 737,694 698,500
Accumulated amortization on nuclear fuel $ 133,122 $ 137,207
EQUITY    
Common stock, authorized shares (in shares) 150,000,000 150,000,000
Common stock, issued shares (in shares) 113,014,528 112,760,051
Treasury stock at cost, shares (in shares) 87,608 72,006
v3.22.0.1
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2021
Dec. 31, 2020
Dec. 31, 2019
CASH FLOWS FROM OPERATING ACTIVITIES      
Net income $ 635,944 $ 570,052 $ 557,813
Adjustments to reconcile net income to net cash provided by operating activities:      
Depreciation and amortization including nuclear fuel 719,141 686,253 664,140
Deferred fuel and purchased power (256,871) (93,651) (82,481)
Deferred fuel and purchased power amortization 44,557 (12,047) 49,508
Allowance for equity funds used during construction (41,737) (33,776) (31,431)
Deferred income taxes 117,471 69,469 (1,479)
Deferred investment tax credit (4,802) (5,096) (3,938)
Stock compensation 18,460 18,292 18,376
Changes in current assets and liabilities:      
Customer and other receivables (72,559) (18,191) (12,789)
Accrued unbilled revenues (1,783) (4,032) 9,005
Materials, supplies and fossil fuel (32,870) 11,623 (51,826)
Income tax receivable (722) 14,935 (21,727)
Other current assets (22,720) (30,640) (3,507)
Accounts payable 20,267 (6,059) 50,641
Accrued taxes 9,094 14,652 (9,920)
Other current liabilities (52,086) 22,520 (84,651)
Change in margin and collateral accounts — assets (50) 404 (247)
Change in margin and collateral accounts — liabilities 350 100 (125)
Change in unrecognized tax benefits (568) 2,220 2,704
Change in long-term regulatory liabilities 57,549 13,017 124,221
Change in other long-term assets (246,473) (67,453) (82,895)
Change in other long-term liabilities (29,578) (186,227) (132,666)
Net cash provided by operating activities 860,014 966,365 956,726
CASH FLOWS FROM INVESTING ACTIVITIES      
Capital expenditures (1,473,475) (1,326,584) (1,191,447)
Contributions in aid of construction 105,654 62,503 70,693
Allowance for borrowed funds used during construction (21,052) (18,530) (18,528)
Proceeds from nuclear decommissioning trust sales and other special use funds 1,720,966 819,518 719,034
Investment in nuclear decommissioning trust and other special use funds (1,725,480) (822,608) (722,181)
Other 6,458 7,883 11,452
Net cash used for investing activities (1,386,929) (1,277,818) (1,130,977)
CASH FLOWS FROM FINANCING ACTIVITIES      
Issuance of long-term debt 746,999 1,596,672 1,092,188
Repayment of long-term debt 0 (915,150) (600,000)
Short-term borrowings and (repayments) — net 142,000 73,325 54,275
Short-term debt borrowings under revolving credit facility 0 751,690 49,000
Short-term debt repayments under revolving credit facility (19,000) (770,690) (65,000)
Dividends paid on common stock (369,478) (350,577) (329,643)
Common stock equity issuance and purchases — net (2,350) (1,389) 692
Distributions to noncontrolling interests (21,255) (22,743) (22,744)
Net cash provided by financing activities 476,916 361,138 178,768
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (49,999) 49,685 4,517
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 59,968 10,283 5,766
CASH AND CASH EQUIVALENTS AT END OF YEAR $ 9,969 $ 59,968 $ 10,283
v3.22.0.1
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY - USD ($)
$ in Thousands
Total
Common Stock
Treasury Stock
Retained Earnings
Accumulated Other Comprehensive Income (Loss)
Noncontrolling Interests
Beginning balance (in shares) at Dec. 31, 2018   112,159,896 58,135      
Beginning balance at Dec. 31, 2018 $ 5,348,705 $ 2,634,265 $ (4,825) $ 2,641,183 $ (47,708) $ 125,790
Increase (Decrease) in Shareholders' Equity            
Net income 557,813     538,320   19,493
Other comprehensive income (loss) (9,388)       (9,388)  
Dividends on common stock (341,893)     (341,893)    
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)
Ending balance (in shares) at Dec. 31, 2019   112,540,126 103,546      
Ending balance at Dec. 31, 2019 5,553,188 $ 2,659,561 $ (9,427) 2,837,610 (57,096) 122,540
Increase (Decrease) in Shareholders' Equity            
Net income 570,052     550,559   19,493
Other comprehensive income (loss) (5,700)       (5,700)  
Dividends on common stock (363,063)     (363,063)    
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      
Capital activities by noncontrolling interests $ (22,743)         (22,743)
Ending balance (in shares) at Dec. 31, 2020 112,760,051 112,760,051 72,006      
Ending balance at Dec. 31, 2020 $ 5,752,793 $ 2,677,482 $ (6,289) 3,025,106 (62,796) 119,290
Increase (Decrease) in Shareholders' Equity            
Net income 635,944     618,720   17,224
Other comprehensive income (loss) 7,935       7,935  
Dividends on common stock (379,108)     (379,108)    
Issuance of common stock (in shares)   254,477        
Issuance of common stock 25,261 $ 25,261        
Purchase of treasury stock (in shares) [1]     (68,892)      
Purchase of treasury stock [1] (4,655)   $ (4,655)      
Reissuance of treasury stock for stock-based compensation and other (in shares)     53,290      
Reissuance of treasury stock for stock-based compensation and other 4,543   $ 4,543      
Capital activities by noncontrolling interests (21,255)         (21,255)
Other $ 2     1   1
Ending balance (in shares) at Dec. 31, 2021 113,014,528 113,014,528 87,608      
Ending balance at Dec. 31, 2021 $ 6,021,460 $ 2,702,743 $ (6,401) $ 3,264,719 $ (54,861) $ 115,260
[1] Primarily represents shares of common stock withheld from certain stock awards for tax purposes.
v3.22.0.1
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Parenthetical) - $ / shares
 12 Months Ended
Dec. 31, 2021
Dec. 31, 2020
Dec. 31, 2019
Statement of Stockholders' Equity [Abstract]      
Dividends declared per common share (in dollars per share) $ 3.36 $ 3.23 $ 3.04
v3.22.0.1
CONSOLIDATED STATEMENTS OF INCOME - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2021
Dec. 31, 2020
Dec. 31, 2019
OPERATING REVENUES (Note 2) $ 3,803,835 $ 3,586,982 $ 3,471,209
OPERATING EXPENSES      
Fuel and purchased power 1,152,551 993,419 1,042,237
Operations and maintenance 954,067 958,910 941,616
Depreciation and amortization 650,875 614,378 590,929
Taxes other than income taxes 234,639 224,835 218,579
Other expenses 6,393 7,288 5,888
Total 2,998,525 2,798,830 2,799,249
OPERATING INCOME 805,310 788,152 671,960
OTHER INCOME (DEDUCTIONS)      
Allowance for equity funds used during construction (Note 1) 41,737 33,776 31,431
Pension and other postretirement non-service credits — net (Note 8) 112,541 56,341 22,989
Other income (Note 17) 45,100 56,703 50,263
Other expense (Note 17) (25,396) (57,776) (17,880)
Total 173,982 89,044 86,803
INTEREST EXPENSE      
Interest charges 254,314 247,501 235,251
Allowance for borrowed funds used during construction (Note 1) (21,052) (18,530) (18,528)
Total 233,262 228,971 216,723
INCOME BEFORE INCOME TAXES 746,030 648,225 542,040
INCOME TAXES (Note 5) 110,086 78,173 (15,773)
NET INCOME 635,944 570,052 557,813
Less: Net income attributable to noncontrolling interests (Note 18) 17,224 19,493 19,493
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS 618,720 550,559 538,320
Arizona Public Service Company      
OPERATING REVENUES (Note 2) 3,803,835 3,586,982 3,471,209
OPERATING EXPENSES      
Fuel and purchased power 1,152,551 993,419 1,042,237
Operations and maintenance 940,588 945,181 926,716
Depreciation and amortization 650,773 614,293 590,844
Taxes other than income taxes 234,569 224,790 218,540
Other expenses 6,393 7,288 5,888
Total 2,984,874 2,784,971 2,784,225
OPERATING INCOME 818,961 802,011 686,984
OTHER INCOME (DEDUCTIONS)      
Allowance for equity funds used during construction (Note 1) 41,737 33,776 31,431
Pension and other postretirement non-service credits — net (Note 8) 112,742 57,359 24,529
Other income (Note 17) 43,053 51,755 46,884
Other expense (Note 17) (18,897) (53,694) (12,990)
Total 178,635 89,196 89,854
INTEREST EXPENSE      
Interest charges 243,592 233,452 220,174
Allowance for borrowed funds used during construction (Note 1) (21,052) (18,530) (18,528)
Total 222,540 214,922 201,646
INCOME BEFORE INCOME TAXES 775,056 676,285 575,192
INCOME TAXES (Note 5) 125,553 88,764 (9,572)
NET INCOME 649,503 587,521 584,764
Less: Net income attributable to noncontrolling interests (Note 18) 17,224 19,493 19,493
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS $ 632,279 $ 568,028 $ 565,271
v3.22.0.1
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2021
Dec. 31, 2020
Dec. 31, 2019
NET INCOME $ 635,944 $ 570,052 $ 557,813
Derivative instruments:      
Net unrealized loss, net of tax benefit (expense) 1,077 (2,089) 0
Reclassification of net realized gain, net of tax expense 18 592 1,137
Pension and other postretirement benefits activity, net of tax benefit (expense) 6,840 (4,203) (10,525)
Total other comprehensive income (loss) 7,935 (5,700) (9,388)
COMPREHENSIVE INCOME 643,879 564,352 548,425
Less: Comprehensive income attributable to noncontrolling interests 17,224 19,493 19,493
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS 626,655 544,859 528,932
Arizona Public Service Company      
NET INCOME 649,503 587,521 584,764
Derivative instruments:      
Net unrealized loss, net of tax benefit (expense) (18) (18) 0
Reclassification of net realized gain, net of tax expense 18 592 1,137
Pension and other postretirement benefits activity, net of tax benefit (expense) 6,038 (5,970) (9,552)
Total other comprehensive income (loss) 6,038 (5,396) (8,415)
COMPREHENSIVE INCOME 655,541 582,125 576,349
Less: Comprehensive income attributable to noncontrolling interests 17,224 19,493 19,493
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS $ 638,317 $ 562,632 $ 556,856
v3.22.0.1
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2021
Dec. 31, 2020
Dec. 31, 2019
Net unrealized loss, tax benefit (expense) $ (378) $ 662 $ 0
Reclassification of net realized gain, tax benefit (expense) 18 (171) (375)
Pension and other postretirement benefits activity, tax benefit (expense) (2,256) 1,371 3,452
Arizona Public Service Company      
Net unrealized loss, tax benefit (expense) 18 18 0
Reclassification of net realized gain, tax benefit (expense) 18 (171) (375)
Pension and other postretirement benefits activity, tax benefit (expense) $ (1,990) $ 1,955 $ 3,136
v3.22.0.1
CONSOLIDATED BALANCE SHEETS - USD ($)
$ in Thousands
Dec. 31, 2021
Dec. 31, 2020
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 7 and 10)    
Plant in service and held for future use $ 21,688,661 $ 20,837,885
Accumulated depreciation and amortization (7,504,603) (7,110,310)
Net 14,184,058 13,727,575
Construction work in progress 1,329,478 937,384
Palo Verde sale leaseback, net of accumulated depreciation 94,166 98,036
Intangible assets, net of accumulated amortization 273,693 282,570
Nuclear fuel, net of accumulated amortization 106,039 113,645
Total property, plant and equipment 15,987,434 15,159,210
INVESTMENTS AND OTHER ASSETS    
Nuclear decommissioning trust (Notes 13 and 19) 1,294,757 1,138,435
Other special use funds (Notes 13 and 19) 358,410 254,509
Assets from risk management activities (Note 16) 46,908 1,818
Other assets 97,884 91,104
Total investments and other assets 1,797,959 1,485,866
CURRENT ASSETS    
Cash and cash equivalents 9,969 59,968
Customer and other receivables 391,923 313,576
Accrued unbilled revenues 133,980 132,197
Allowance for doubtful accounts (Note 2) (25,354) (19,782)
Materials and supplies (at average cost) 349,135 314,745
Fossil fuel (at average cost) 18,032 19,552
Income tax receivable (Note 5) 7,514 6,792
Assets from risk management activities (Note 16) 63,481 2,931
Deferred fuel and purchased power regulatory asset (Note 4) 388,148 175,835
Other regulatory assets (Note 4) 130,376 115,878
Other current assets 83,896 76,627
Total current assets 1,551,100 1,198,319
DEFERRED DEBITS    
Regulatory assets (Notes 1, 4 and 5) 1,192,987 1,133,987
Operating lease right-of-use assets (Note 9) 890,057 505,064
Assets for pension and other postretirement benefits (Note 8) 545,723 502,992
Other 37,962 34,983
Total deferred debits 2,666,729 2,177,026
Total Assets 22,003,222 20,020,421
EQUITY    
Retained earnings 3,264,719 3,025,106
Accumulated other comprehensive loss (54,861) (62,796)
Total shareholders’ equity 5,906,200 5,633,503
Noncontrolling interests (Note 18) 115,260 119,290
Total equity 6,021,460 5,752,793
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 7) 6,913,735 6,314,266
CURRENT LIABILITIES    
Short-term borrowings (Note 6) 292,000 169,000
Accounts payable 393,083 318,585
Accrued taxes 168,645 159,551
Accrued interest 57,332 56,962
Common dividends payable 95,988 93,531
Customer deposits 42,293 48,340
Liabilities from risk management activities (Note 16) 4,373 7,557
Liabilities for asset retirements (Note 12) 4,473 15,586
Operating lease liabilities (Note 9) 100,443 74,785
Regulatory liabilities (Note 4) 296,271 229,088
Other current liabilities 151,968 187,448
Total current liabilities 1,756,869 1,360,433
DEFERRED CREDITS AND OTHER    
Deferred income taxes (Note 5) 2,311,862 2,135,403
Regulatory liabilities (Notes 1, 4, 5 and 8) 2,499,213 2,450,169
Liabilities for asset retirements (Note 12) 762,909 689,497
Liabilities for pension benefits (Note 8) 152,865 166,484
Liabilities from risk management activities (Note 16) 0 11,062
Customer advances 257,151 221,032
Coal mine reclamation 174,616 170,097
Deferred investment tax credit 186,570 191,372
Unrecognized tax benefits (Note 5) 4,657 5,834
Operating lease liabilities (Note 9) 728,401 361,336
Other 232,914 190,643
Total deferred credits and other 7,311,158 6,592,929
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
Total Liabilities and Equity 22,003,222 20,020,421
Arizona Public Service Company    
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 7 and 10)    
Plant in service and held for future use 21,685,200 20,834,424
Accumulated depreciation and amortization (7,501,317) (7,107,058)
Net 14,183,883 13,727,366
Construction work in progress 1,327,721 937,384
Palo Verde sale leaseback, net of accumulated depreciation 94,166 98,036
Intangible assets, net of accumulated amortization 273,537 282,415
Nuclear fuel, net of accumulated amortization 106,039 113,645
Total property, plant and equipment 15,985,346 15,158,846
INVESTMENTS AND OTHER ASSETS    
Nuclear decommissioning trust (Notes 13 and 19) 1,294,757 1,138,435
Other special use funds (Notes 13 and 19) 358,410 254,509
Assets from risk management activities (Note 16) 46,908 1,818
Other assets 42,440 44,192
Total investments and other assets 1,742,515 1,438,954
CURRENT ASSETS    
Cash and cash equivalents 9,374 57,310
Customer and other receivables 390,533 312,644
Accrued unbilled revenues 133,980 132,197
Allowance for doubtful accounts (Note 2) (25,354) (19,782)
Materials and supplies (at average cost) 349,135 314,745
Fossil fuel (at average cost) 18,032 19,552
Income tax receivable (Note 5) 10,756 0
Assets from risk management activities (Note 16) 63,481 2,931
Deferred fuel and purchased power regulatory asset (Note 4) 388,148 175,835
Other regulatory assets (Note 4) 130,376 115,878
Other current assets 57,729 47,593
Total current assets 1,526,190 1,158,903
DEFERRED DEBITS    
Regulatory assets (Notes 1, 4 and 5) 1,192,987 1,133,987
Operating lease right-of-use assets (Note 9) 888,207 503,475
Assets for pension and other postretirement benefits (Note 8) 537,092 495,673
Other 37,319 34,413
Total deferred debits 2,655,605 2,167,548
Total Assets 21,909,656 19,924,251
EQUITY    
Common stock 178,162 178,162
Additional paid-in capital 3,021,696 2,871,696
Retained earnings 3,470,235 3,216,955
Accumulated other comprehensive loss (34,880) (40,918)
Total shareholders’ equity 6,635,213 6,225,895
Noncontrolling interests (Note 18) 115,260 119,290
Total equity 6,750,473 6,345,185
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 7) 6,266,693 5,817,945
Total capitalization 13,017,166 12,163,130
CURRENT LIABILITIES    
Short-term borrowings (Note 6) 278,700 0
Accounts payable 389,365 311,699
Accrued taxes 152,012 148,970
Accrued interest 56,622 56,322
Common dividends payable 96,000 93,500
Customer deposits 42,293 48,340
Liabilities from risk management activities (Note 16) 4,373 7,557
Liabilities for asset retirements (Note 12) 4,473 15,586
Operating lease liabilities (Note 9) 100,199 74,695
Regulatory liabilities (Note 4) 296,271 229,088
Other current liabilities 145,286 190,420
Total current liabilities 1,565,594 1,176,177
DEFERRED CREDITS AND OTHER    
Deferred income taxes (Note 5) 2,331,701 2,143,673
Regulatory liabilities (Notes 1, 4, 5 and 8) 2,499,213 2,450,169
Liabilities for asset retirements (Note 12) 762,909 689,497
Liabilities for pension benefits (Note 8) 138,328 148,943
Liabilities from risk management activities (Note 16) 0 11,062
Customer advances 257,151 221,032
Coal mine reclamation 174,616 170,097
Deferred investment tax credit 186,570 191,372
Unrecognized tax benefits (Note 5) 37,423 39,410
Operating lease liabilities (Note 9) 726,572 359,653
Other 212,413 160,036
Total deferred credits and other 7,326,896 6,584,944
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
Total Liabilities and Equity $ 21,909,656 $ 19,924,251
v3.22.0.1
CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($)
$ in Thousands
Dec. 31, 2021
Dec. 31, 2020
PROPERTY, PLANT AND EQUIPMENT    
Accumulated depreciation of Palo Verde sale leaseback $ 256,884 $ 253,014
Accumulated amortization on intangible assets 737,694 698,500
Accumulated amortization on nuclear fuel $ 133,122 $ 137,207
EQUITY    
Common stock, authorized shares (in shares) 150,000,000 150,000,000
Common stock, issued shares (in shares) 113,014,528 112,760,051
Treasury stock at cost, shares (in shares) 87,608 72,006
Arizona Public Service Company    
PROPERTY, PLANT AND EQUIPMENT    
Accumulated depreciation of Palo Verde sale leaseback $ 256,884 $ 253,014
Accumulated amortization on intangible assets 736,560 697,366
Accumulated amortization on nuclear fuel $ 133,122 $ 137,207
v3.22.0.1
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2021
Dec. 31, 2020
Dec. 31, 2019
CASH FLOWS FROM OPERATING ACTIVITIES      
Net income $ 635,944 $ 570,052 $ 557,813
Adjustments to reconcile net income to net cash provided by operating activities:      
Depreciation and amortization including nuclear fuel 719,141 686,253 664,140
Deferred fuel and purchased power (256,871) (93,651) (82,481)
Deferred fuel and purchased power amortization 44,557 (12,047) 49,508
Allowance for equity funds used during construction (41,737) (33,776) (31,431)
Deferred income taxes 117,471 69,469 (1,479)
Deferred investment tax credit (4,802) (5,096) (3,938)
Changes in current assets and liabilities:      
Customer and other receivables (72,559) (18,191) (12,789)
Accrued unbilled revenues (1,783) (4,032) 9,005
Materials, supplies and fossil fuel (32,870) 11,623 (51,826)
Income tax receivable (722) 14,935 (21,727)
Other current assets (22,720) (30,640) (3,507)
Accounts payable 20,267 (6,059) 50,641
Accrued taxes 9,094 14,652 (9,920)
Other current liabilities (52,086) 22,520 (84,651)
Change in margin and collateral accounts — assets (50) 404 (247)
Change in margin and collateral accounts — liabilities 350 100 (125)
Change in unrecognized tax benefits (568) 2,220 2,704
Change in long-term regulatory liabilities 57,549 13,017 124,221
Change in other long-term assets (246,473) (67,453) (82,895)
Change in other long-term liabilities (29,578) (186,227) (132,666)
Net cash provided by operating activities 860,014 966,365 956,726
CASH FLOWS FROM INVESTING ACTIVITIES      
Capital expenditures (1,473,475) (1,326,584) (1,191,447)
Contributions in aid of construction 105,654 62,503 70,693
Allowance for borrowed funds used during construction (21,052) (18,530) (18,528)
Proceeds from nuclear decommissioning trust sales and other special use funds 1,720,966 819,518 719,034
Investment in nuclear decommissioning trust and other special use funds (1,725,480) (822,608) (722,181)
Other 6,458 7,883 11,452
Net cash used for investing activities (1,386,929) (1,277,818) (1,130,977)
CASH FLOWS FROM FINANCING ACTIVITIES      
Issuance of long-term debt 746,999 1,596,672 1,092,188
Repayment of long-term debt 0 (915,150) (600,000)
Short-term borrowings and (repayments) — net 142,000 73,325 54,275
Short-term debt borrowings under revolving credit facility 0 751,690 49,000
Short-term debt repayments under revolving credit facility (19,000) (770,690) (65,000)
Dividends paid on common stock (369,478) (350,577) (329,643)
Noncontrolling interests (21,255) (22,743) (22,744)
Net cash provided by financing activities 476,916 361,138 178,768
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (49,999) 49,685 4,517
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 59,968 10,283 5,766
CASH AND CASH EQUIVALENTS AT END OF YEAR 9,969 59,968 10,283
Arizona Public Service Company      
CASH FLOWS FROM OPERATING ACTIVITIES      
Net income 649,503 587,521 584,764
Adjustments to reconcile net income to net cash provided by operating activities:      
Depreciation and amortization including nuclear fuel 719,039 686,168 664,055
Deferred fuel and purchased power (256,871) (93,651) (82,481)
Deferred fuel and purchased power amortization 44,557 (12,047) 49,508
Allowance for equity funds used during construction (41,737) (33,776) (31,431)
Deferred income taxes 128,852 36,462 48,367
Deferred investment tax credit (4,802) (5,096) (3,938)
Changes in current assets and liabilities:      
Customer and other receivables (72,101) (28,206) (12,075)
Accrued unbilled revenues (1,783) (4,032) 9,005
Materials, supplies and fossil fuel (32,870) 11,623 (51,826)
Income tax receivable (10,756) 7,313 (7,313)
Other current assets (25,587) (24,669) (1,461)
Accounts payable 23,510 (4,503) 53,258
Accrued taxes 3,042 12,642 (40,029)
Other current liabilities (61,647) 29,587 (82,138)
Change in margin and collateral accounts — assets (50) 404 (247)
Change in margin and collateral accounts — liabilities 350 100 (125)
Change in unrecognized tax benefits (568) 2,220 2,704
Change in long-term regulatory liabilities 57,549 13,017 124,221
Change in other long-term assets (231,804) (65,139) (85,725)
Change in other long-term liabilities (20,272) (186,871) (129,682)
Net cash provided by operating activities 865,554 929,067 1,007,411
CASH FLOWS FROM INVESTING ACTIVITIES      
Capital expenditures (1,471,795) (1,326,584) (1,191,447)
Contributions in aid of construction 105,654 62,503 70,693
Allowance for borrowed funds used during construction (21,052) (18,530) (18,528)
Proceeds from nuclear decommissioning trust sales and other special use funds 1,720,966 819,518 719,034
Investment in nuclear decommissioning trust and other special use funds (1,725,480) (822,608) (722,181)
Other 273 (554) 6,336
Net cash used for investing activities (1,391,434) (1,286,255) (1,136,093)
CASH FLOWS FROM FINANCING ACTIVITIES      
Issuance of long-term debt 446,999 1,099,722 1,092,188
Repayment of long-term debt 0 (465,150) (600,000)
Short-term borrowings and (repayments) — net 278,700 0 0
Short-term debt borrowings under revolving credit facility 0 540,000 0
Short-term debt repayments under revolving credit facility 0 (540,000) 0
Dividends paid on common stock (376,500) (357,500) (336,300)
Equity infusion from Pinnacle West 150,000 150,000 0
Noncontrolling interests (21,255) (22,743) (22,744)
Net cash provided by financing activities 477,944 404,329 133,144
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (47,936) 47,141 4,462
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 57,310 10,169 5,707
CASH AND CASH EQUIVALENTS AT END OF YEAR $ 9,374 $ 57,310 $ 10,169
v3.22.0.1
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY - USD ($)
$ in Thousands
Total
Common 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, 2018   112,159,896         71,264,947        
Beginning balance at Dec. 31, 2018 $ 5,348,705 $ 2,634,265 $ 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                      
Equity infusion from Pinnacle West           150,000          
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)    
Capital activities by noncontrolling interests (22,743)       (22,743) (22,743)         (22,743)
Ending balance (in shares) at Dec. 31, 2019   112,540,126         71,264,947        
Ending balance at Dec. 31, 2019 5,553,188 $ 2,659,561 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                      
Equity infusion from Pinnacle West           150,000   150,000      
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)    
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         71,264,947        
Ending balance at Dec. 31, 2020 $ 5,752,793 $ 2,677,482 3,025,106 (62,796) 119,290 6,345,185 $ 178,162 2,871,696 3,216,955 (40,918) 119,290
Increase (Decrease) in Shareholders' Equity                      
Equity infusion from Pinnacle West           150,000   150,000      
Net income 635,944   618,720   17,224 649,503     632,279   17,224
Other comprehensive income (loss) 7,935     7,935   6,038       6,038  
Dividends on common stock (379,108)   (379,108)     (379,000)     (379,000)    
Capital activities by noncontrolling interests (21,255)       (21,255) (21,255)         (21,255)
Other $ 2   1   1 2     1   1
Ending balance (in shares) at Dec. 31, 2021 113,014,528 113,014,528         71,264,947        
Ending balance at Dec. 31, 2021 $ 6,021,460 $ 2,702,743 $ 3,264,719 $ (54,861) $ 115,260 $ 6,750,473 $ 178,162 $ 3,021,696 $ 3,470,235 $ (34,880) $ 115,260
v3.22.0.1
Summary of Significant Accounting Policies
 12 Months Ended
Dec. 31, 2021
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 Variable Interest Entities (each a “VIE”) 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. We have determined that Pinnacle West is the primary beneficiary of a captive insurance protected cell VIE. As of December 31, 2021, the captive cell's activities are insignificant to our consolidated financial statements.
 
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 the 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
•AFUDC.

Pinnacle West’s property, plant and equipment included in the December 31, 2021, and 2020 Consolidated Balance Sheets is composed of the following (dollars in thousands):

Property, Plant and Equipment:20212020
Generation$9,480,572 $9,199,012 
Transmission3,402,016 3,290,477 
Distribution7,520,016 7,107,007 
General plant1,286,057 1,241,389 
Plant in service and held for future use
21,688,661 20,837,885 
Accumulated depreciation and amortization(7,504,603)(7,110,310)
Net
14,184,058 13,727,575 
Construction work in progress1,329,478 937,384 
Palo Verde sale leaseback, net of accumulated depreciation94,166 98,036 
Intangible assets, net of accumulated amortization273,693 282,570 
Nuclear fuel, net of accumulated amortization106,039 113,645 
Total property, plant and equipment$15,987,434 $15,159,210 

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 AROs.  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, 2021, were as follows:
•Steam generation — 12 years;
•Nuclear plant — 25 years;
•Other generation — 19 years;
•Transmission — 37 years;
•Distribution — 33 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 $575 million in 2021, $553 million in 2020, and $522 million in 2019. For the years 2019 through 2021, the depreciation rates ranged from a low of 1.37% to a high of 12.15%.  The weighted-average depreciation rate was 2.87% in 2021, 2.84% in 2020, and 2.81% in 2019.

Asset Retirement Obligations

APS has AROs for its Palo Verde nuclear facilities and certain other generation assets.  The Palo Verde ARO 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 AROs 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 AROs 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 ARO 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 6.75% for 2021, 6.72% for 2020, and 6.98% for 2019.  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, FERC issued an order granting a waiver request related to the existing AFUDC rate calculation beginning March 1, 2020, through February 28, 2021. On February 23, 2021, this waiver was extended until September 30, 2021. On September 21, 2021, it was further extended until March 21, 2022.  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 and 2021 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,
 202120202019
Cash paid (received) during the period for:   
Income taxes, net of refunds$229 $(3,019)$12,535 
Interest, net of amounts capitalized227,584 216,951 218,664 
Significant non-cash investing and financing activities:   
Accrued capital expenditures$167,733 $113,502 $141,297 
Dividends declared but not paid95,988 93,531 87,982 

The following table summarizes supplemental APS cash flow information for each of the last three years (dollars in thousands):
 Year ended December 31,
 202120202019
Cash paid (received) during the period for:   
Income taxes, net of refunds$19,783 $41,176 $(15,042)
Interest, net of amounts capitalized217,749 206,328 204,261 
Significant non-cash investing and financing activities:   
Accrued capital expenditures$167,657 $113,502 $141,297 
Dividends declared but not paid96,000 93,500 88,000 
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 $80 million in 2021, $70 million in 2020, and $66 million in 2019.  Estimated amortization expense on existing intangible assets over the next five years is $75 million in 2022, $63 million in 2023, $44 million in 2024, $33 million in 2025, and $27 million in 2026.  At December 31, 2021, the weighted-average remaining amortization period for intangible assets was 6 years.
 
Investments
 
El Dorado holds investments in both debt and equity securities.  Investments in debt securities are generally accounted for as held-to-maturity and investments in equity securities are accounted for using either the equity method (if significant influence) or the measurement alternative for investments without readily determinable fair values (if less than 20% ownership and no significant influence).

BCE 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. Purchased power lease contracts may also include energy storage facilities. 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, 2021, 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.
v3.22.0.1
Revenue
 12 Months Ended
Dec. 31, 2021
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,
202120202019
Retail Electric Service
Residential$1,913,324 $1,929,178 (a)$1,761,122 
Non-Residential1,586,940 1,486,098 1,509,514 
Wholesale Energy Sales187,640 93,345 121,805 
Transmission Services for Others99,285 65,859 62,460 
Other Sources16,646 12,502 16,308 
Total Operating Revenues$3,803,835 $3,586,982 $3,471,209 

(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 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 21 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, 2021, 2020 and 2019 were $3,760 million, $3,533 million. and $3,415 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, 2021, 2020 and 2019, our revenues that do not qualify as revenue from contracts with customers were $44 million, $54 million and $56 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, 2021, and 2020.

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. 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. During this time, our disconnection policies were also impacted by the Summer Disconnection Moratorium. These circumstances and the on-going COVID-19 pandemic continue to impact our allowance for doubtful accounts including our write-off factor. We continue to monitor the impacts of COVID-19, our disconnection policies, summer moratorium, 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 (dollars in thousands):
Year Ended December 31, 2021Year Ended December 31, 2020Year Ended December 31, 2019
Allowance for doubtful accounts, balance at beginning of period$19,782 $8,171 $4,069 
Bad debt expense22,251 20,633 11,819 
Actual write-offs(16,679)(9,022)(7,717)
Allowance for doubtful accounts, balance at end of period$25,354 $19,782 $8,171 
v3.22.0.1
New Accounting Standards
 12 Months Ended
Dec. 31, 2021
Accounting Standards Update and Change in Accounting Principle [Abstract]  
New Accounting Standards New Accounting Standards
 
ASU 2021-05, Leases: Certain Leases with Variable Lease Payments
In July 2021, a new accounting standard was issued that amends the lease accounting guidance. The amended guidance will require lessors to account for certain lease transactions, that contain variable lease payments, as operating leases. The amendments are intended to eliminate the recognition of any day-one loss associated with certain sales-type and direct-financing lease transactions. The changes do not impact lessee accounting. The standard may be adopted using either a prospective or modified retrospective approach. We adopted this standard on January 1, 2022, using a prospective approach. The adoption of this standard did not impact our financial statements.
v3.22.0.1
Regulatory Matters
 12 Months Ended
Dec. 31, 2021
Regulated Operations [Abstract]  
Regulatory Matters Regulatory Matters
COVID-19 Pandemic

During 2020 and 2021, APS implemented several programs and initiatives to help our customers deal with the economic and other impacts of the COVID-19 pandemic, including but not limited to the following:

•Suspension of Disconnections; Waiver of Late Payment Fees. APS voluntarily suspended disconnections of customers for nonpayment beginning March 13, 2020, until December 31, 2020. The suspension of disconnection of customers for nonpayment ended on January 1, 2021, and customers with past due balances of $75 or greater as of that date were automatically placed on eight-month payment arrangements. APS voluntarily began waiving late payment fees of its customers on March 13, 2020 and is continuing to waive late payment fees. APS has experienced and is continuing to experience an increase in bad debt expense associated with the COVID-19 pandemic, the Summer Disconnection Moratorium (defined below) and the related write-offs of customer delinquent accounts.

•COVID-19 Emergency Relief Package. 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. APS refunded
approximately $43 million to customers. The additional $7 million over the ACC-approved amount was the result of the kWh credit being based on historic consumption, which was different than actual consumption during the refund period.

•COVID Customer Support Fund. In 2020, APS 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 (i) approximately $8.8 million in funds that are not recoverable through rates, and (ii) an additional $3.6 million in bill credits for limited income customers 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 bill credits being deferred for potential future recovery in rates. Included in the COVID Customer Support Fund were programs that assisted customers with a delinquency of two or more months, providing 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. APS has 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.

•Deferral of PSA Rate Increase. In February 2021, APS delayed the annual reset of the PSA, with 50% of the PSA rate increase taking effect in April 2021 and the remaining 50% taking effect in November 2021. See below for discussion of the PSA.

2019 Retail Rate Case

APS filed an application with the ACC on October 31, 2019 (the “2019 Rate Case”) seeking an increase in annual 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 was the subject of a separate proceeding. See “Four Corners 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 12 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.

On October 2, 2020, the ACC Staff, the Residential Utility Consumer Office (“RUCO”) and other intervenors filed their initial written testimony with the ACC. The ACC Staff recommended, among other things, (i) a $89.7 million revenue increase, (ii) an average annual customer bill increase of 2.7%, (iii) a 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) the recovery of the deferral and rate base effects of the construction and operating costs of the Four Corners SCR project and (vi) the recovery of the rate base effects of the construction and ongoing consideration of the deferral of the Ocotillo modernization project. RUCO recommended, among other things, (i) a $20.8 million revenue decrease, (ii) an average annual customer bill decrease of 0.63%, (iii) a return on equity of 8.74%, (iv) a 0% return on the increment of fair value rate base, (v) the 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) the 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 customer 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, 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 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 Plant, 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. In 2021, APS committed an additional $900,000 to be paid to the Hopi Tribe related to APS’s ownership interests in the Navajo Plant, and this amount was recognized in our December 31, 2021 financials.

On December 4, 2020, the ACC Staff and intervenors filed surrebuttal testimony. The ACC Staff reduced its recommended rate increase to $59.8 million, or an average annual customer bill increase of 1.82%. In RUCO’s surrebuttal, the recommended revenue decrease changed to $50.1 million, or an average annual customer bill decrease of 1.52%. The hearing concluded on March 3, 2021 and the post-hearing briefing concluded on April 30, 2021.

On August 2, 2021, the Administrative Law Judge issued a Recommended Opinion and Order in the 2019 Rate Case (the “2019 Rate Case ROO”) and issued corrections on September 10 and September 20, 2021. The 2019 Rate Case ROO recommended, among other things, (i) a $111 million decrease in annual revenue requirements, (ii) a return on equity of 9.16%, (iii) a 0.30% return on the increment of fair value rate base greater than original cost, with total fair value rate of return further adjusted to include a 0.03% reduction to return on equity resulting in an effective fair value rate of return of 4.95%, (iv) the nonrecovery of the deferral and rate base effects of the operating costs and construction of the Four Corners SCR project (see “Four Corners SCR Cost Recovery” below for additional information), (v) the recovery of the deferral and rate base effects of the operating costs and construction of the Ocotillo modernization project, which includes a reduction in the return on the deferral, (vi) a 15% disallowance of annual amortization of Navajo Plant regulatory asset recovery, (vii) the denial of the request to defer, until APS’s next general rate case, the increase or decrease in its Arizona property taxes attributable to tax rate changes, and (viii) a collaborative process to review and recommend revisions to APS’s adjustment mechanisms within 12 months after the date of the decision. The 2019 Rate Case ROO also recommended that the CCT plan include the following components: (i) $50 million that will be paid over 10 years to the Navajo Nation, (ii) $5 million that will be paid over five years to the Navajo County Communities surrounding Cholla Power Plant, and (iii) $1.675 million that will be paid to the Hopi Tribe related to APS’s ownership interests in the Navajo Plant. These amounts would be recoverable from APS’s customers through the RES adjustment mechanism. APS filed exceptions on September 13, 2021, regarding the disallowance of the SCR cost deferrals and plant investments that was recommended in the 2019 Rate Case ROO, among other issues.
On October 6, 2021 and October 27, 2021, the ACC voted on various amendments to the 2019 Rate Case ROO that would result in, among other things, (i) a return on equity of 8.70%, (ii) the recovery of the deferral and rate base effects of the operating costs and construction of the Four Corners SCR project, with the exception of $215.5 million (see “Four Corners SCR Cost Recovery” below), (iii) that the CCT plan include the following components: (a) a payment of $1 million to the Hopi Tribe within 60 days of the 2019 Rate Case decision, (b) a payment of $10 million over three years to the Navajo Nation, (c) a payment of $0.5 million to the Navajo County communities within 60 days of the 2019 Rate Case decision, (d) up to $1.25 million for electrification of homes and businesses on the Hopi reservation and (e) up to $1.25 million for the electrification of homes and businesses on the Navajo Nation reservation. These payments and expenditures are attributable to the future closures of Four Corners and Cholla, along with the prior closure of the Navajo Plant and all ordered payments and expenditures would be recoverable through rates, and (iv) a change in the residential on-peak time-of-use period from 3 p.m. to 8 p.m. to 4 p.m. to 7 p.m. Monday through Friday, excluding holidays. The 2019 Rate Case ROO, as amended, results in a total annual revenue decrease for APS of $4.8 million, excluding temporary CCT payments and expenditures. On November 2, 2021, the ACC approved the 2019 Rate Case ROO, as amended. On November 24, 2021, APS filed an application for rehearing of the 2019 Rate Case with the ACC and the application was deemed denied on December 15, 2021, as the ACC did not act upon it. On December 17, 2021, APS filed its Notice of Direct Appeal at the Arizona Court of Appeals and a Petition for Special Action with the Arizona Supreme Court, requesting review of the disallowance of $215 million of Four Corners SCR plant investments and deferrals (see “Four Corners SCR Cost Recovery” below for additional information) and the 20 basis point penalty reduction to the return on equity. On February 8, 2022, the Arizona Supreme Court declined to accept jurisdiction on APS’s Petition for Special Action. APS cannot predict the outcome of this proceeding.

Consistent with the 2019 Rate Case decision, APS implemented the new rates effective as of December 1, 2021. On December 3, 2021, ACC Staff notified the ACC of a discrepancy between the written decision, which approved the change in time-of-use on-peak hours to 4 p.m. to 7 p.m., but did not explicitly approve the 10 months contemplated in APS’s verbal testimony to implement the new time-of-use hours. On December 16, 2021, the ACC ordered APS to complete the implementation of the time-of-use peak period by April 1, 2022. On January 12, 2022, the ACC voted to extend the deadline until September 1, 2022, to complete the implementation of the new on-peak hours for residential customers. In addition, the ACC ordered extensive compliance and reporting obligations and will be continuing to explore whether penalties or rebates would be owed to certain customers. APS cannot predict the outcome of this matter.

APS expects to file an application with the ACC for its next general retail rate case by mid-year 2022 but is continuing to evaluate the timing of such filing.

Information Technology ACC Investigation

On December 16, 2021, the ACC opened an investigation into various matters related to APS’s Information Technology department, including information about technology projects, costs, vendor management leadership and decision making. APS is cooperating with the investigation. The ACC Staff has been directed to report to the ACC on the investigation in April 2022. APS cannot predict the outcome of this matter.
2016 Retail Rate Case Filing
 
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 RUCO, 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.

Other key provisions of the 2017 Settlement 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 to 7 p.m. to 3 p.m. to 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.

On August 15, 2017, the ACC approved the 2017 Settlement Agreement without material modifications and 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”). The new rates went into effect on August 19, 2017.
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.

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 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 RES residential distributed energy requirement for 2020. On September 23, 2020, the ACC approved the 2020 RES Implementation Plan, including APS’s requested waiver of the residential distributed energy requirements for 2020. 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 RES residential distributed energy requirement for 2021. In the 2021 RES Implementation Plan, APS requested $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. On June 7, 2021, the ACC approved the 2021 RES Implementation Plan, including APS’s requested waiver of the residential distributed energy requirements for 2021. As part of the approval, the ACC approved the requested budget and authorized APS to collect $68.3 million through the Renewable Energy Adjustment Charge to support APS’s RES programs.

In June 2021, the ACC adopted a clean energy rules package which would require APS to meet certain clean energy standards and technology procurement mandates, obtain approval for its action plan included in its IRP, and seek cost recovery in a rate process. Since the adopted clean energy rules differed
substantially from the original Recommended Order and Opinion, supplemental rulemaking procedures were required before the rules could become effective. On January 26, 2022, the ACC reversed its prior decision and declined to send the final draft energy rules through the rulemaking process. Instead, the ACC opened a new docket to consider all-source requests for proposals (“RFP”) requirements and the IRP process. See “Energy Modernization Plan” below for more information.

On July 1, 2021, APS filed its 2022 RES Implementation Plan and proposed a budget of approximately $93.1 million. APS filed an amended 2022 RES Implementation Plan on December 9, 2021, with a proposed budget of $100.5 million. This budget includes funding for programs to comply with the decision in the 2019 Rate Case, including the ACC authorizing spending $20 million to $30 million in capital costs for the APS Solar Communities program each year for a period of three years from the effective date of the 2019 Rate Case decision. APS’s budget proposal supports existing approved projects and commitments and requests a permanent waiver of the RES residential and non-residential distributed energy requirements for 2022. The ACC has not yet ruled on the 2022 RES Implementation Plan.

Demand Side Management Adjustor Charge. The ACC EES requires APS to submit a Demand Side Management Implementation Plan (“DSM Plan”) annually for review and approval by 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 DSM 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. APS has refunded approximately $43 million to customers. The additional $7 million over the ACC-approved amount was the result of the kWh credit being based on historic consumption which was different than actual consumption during the refund period. The difference was recorded to the DSM balancing account and was included in the 2021 DSM Implementation Plan, as described below.

On December 31, 2020, APS filed its 2021 DSM Plan, which requested a budget of $63.7 million and continued 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. On April 6, 2021, APS filed an amended 2021 DSM Plan that proposed an additional performance incentive for customers participating in the residential energy storage pilot program approved in the 2020 RES Implementation Plan. On July 13, 2021, the ACC approved the amended 2021 DSM Plan.

On April 20, 2021, APS filed a request to extend the June 1, 2021 deadline to file its 2022 DSM Plan until 120 days after the ACC has taken action on APS’s amended 2021 DSM Plan. The ACC approved the request, granting an extension until 120 days after the ACC action on the 2021 DSM Plan, or December 31, 2021, whichever is later. On December 17, 2021, APS filed its 2022 DSM Plan which requested a budget of $78.4 million and represents an increase of approximately $14 million in DSM spending above 2021.

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 2021 and 2020 (dollars in thousands):
 Twelve Months Ended
December 31,
 20212020
Beginning balance$175,835 $70,137 
Deferred fuel and purchased power costs — current period256,871 93,651 
Amounts refunded/(charged) to customers(44,558)12,047 
Ending balance$388,148 $175,835 

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, which 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, which 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, which is the maximum permitted under the Plan of Administration for the PSA. This left $215.9 million of fuel and purchased power costs above this annual cap which will be reflected in future year resets of the PSA. 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 due to concerns of the impact on customers during COVID-19. In March 2021, the ACC voted to implement the 2021 PSA rate on a staggered basis, with 50% of the PSA rate increase taking effect in April 2021 and the remaining 50% taking effect in November 2021. The PSA rate implemented on April 1, 2021 was $0.001544 per kWh, which consisted of a forward component of $(0.004444) per kWh and a historical component of $0.005988 per kWh. On November 1, 2021, the remaining increase was implemented to a PSA rate of $0.003544 per kWh, which consisted of a forward component of $(0.004444) per kWh and a historical component of $0.007988 per kWh. As part of this approval, the ACC ordered ACC Staff to conduct a fuel and purchased power procurement audit, which is currently underway, to better understand the factors that contributed to the increase in fuel costs. APS cannot predict the outcome of this audit.

On November 30, 2021, APS filed its PSA rate for the PSA year beginning February 1, 2022. That rate was $0.007544 per kWh, which consisted of a forward component of $(0.004842) per kWh and a historical component of $0.012386 per kWh. The 2022 PSA rate is a $0.004 per kWh increase compared to the 2021 PSA year, which is the maximum permitted under the Plan of Administration for the PSA. These rates went into effect as filed on February 1, 2022. At the time of the compliance filing, the amount remaining over the annual cap was approximately $365 million of fuel and purchased power costs which will be reflected in future year resets of the PSA.
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 but did not rule on the prudency. On October 28, 2021, APS filed an application requesting approval to recover costs related to three additional energy storage projects through the PSA once the systems are in service. On December 16, 2021, the ACC approved this application but did not rule on the prudency. APS cannot predict the outcome of this matter.

Environmental Improvement Surcharge (“EIS”). The EIS permits APS to recover the capital carrying costs (rate of return, depreciation, and taxes) plus incremental operations and maintenance expenses associated with environmental improvements made outside of a test year to comply with environmental standards set by federal, state, tribal, or local laws and regulations.  A filing is made on or before February 1 each year for qualified environmental improvements since the prior rate case test 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, 2022 application requested an increase in the charge to $11.4 million, or $1.1 million over the prior-period charge, and it will become effective with the first billing cycle in April 2022 absent the ACC taking action.

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.  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 with 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. The resolution of proposed adjustments can result in significant volatility in the revenues to be collected.

On March 17, 2020, APS made a filing to make 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. APS amended its March 17, 2020 filing on April 28, 2020, September 29, 2021, and October 27, 2021. In January 2022, FERC approved APS’s modifications to its annual transmission formula.
Effective June 1, 2019, APS’s annual wholesale transmission revenue requirement for all users of its transmission system increased by approximately $25.8 million for the 12-month period beginning June 1, 2019, in accordance with the FERC-approved formula. Of this amount, wholesale customer rates increased by $21.1 million and retail customer rates would have increased by approximately $4.7 million. However, since changes in Retail Transmission Charges are reflected through the TCA after consideration of transmission recovery in retail base rates and the ACC approved TCA balancing account, the retail revenue requirement increased by a total of $4.9 million, resulting in a decrease to residential rates and an increase to commercial rates. 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 revenue requirement for all users of its transmission system decreased by approximately $6.1 million for the 12-month period beginning June 1, 2020, in accordance with the FERC-approved formula. Of this net amount, wholesale customer rates increased by $4.8 million and retail customer rates would have decreased by approximately $10.9 million. However, since changes in Retail Transmission Charges are reflected through the TCA after consideration of transmission recovery in retail base rates and the ACC approved balancing account, the retail revenue requirement decreased by a total of $7.4 million, resulting in reductions to both residential and commercial rates. An adjustment to APS’s retail rates to recover FERC approved transmission charges went into effect automatically on June 1, 2020.

Effective June 1, 2021, APS’s annual wholesale transmission revenue requirement for all users of its transmission system increased by approximately $4 million for the 12-month period beginning June 1, 2021, in accordance with the FERC-approved formula. Of this net amount, wholesale customer rates decreased by approximately $3.2 million and retail customer rates would have increased by approximately $7.2 million. However, since changes in Retail Transmission Charges are reflected through the TCA after consideration of transmission recovery in retail base rates and the ACC approved balancing account, the retail revenue requirement decreased by $28.4 million, resulting in reductions to both residential and commercial rates. An adjustment to APS’s retail rates to recover FERC-approved transmission charges went into effect automatically on June 1, 2021.

Lost Fixed Cost Recovery Mechanism. The LFCR mechanism permits APS to recover on an after-the-fact basis a portion of its fixed costs that would otherwise have been collected by APS in the kWh sales lost due to APS energy efficiency programs and to DG such as rooftop solar arrays.  The fixed costs recoverable by the LFCR mechanism were 2.5 cents for both lost residential and non-residential kWh as set forth in the 2017 Settlement Agreement. The fixed costs recoverable by the LFCR mechanism are currently 2.56 cents for lost residential and 2.68 cents non-residential kWh as set forth in the 2019 Rate Case decision. 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, 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). On April 13, 2021, the ACC voted not to approve the requested $11.8 million increase to the annual LFCR adjustment, thus the previously approved rates continue to remain intact. The $11.8 million will continue to be maintained in the LFCR regulatory asset balancing account and will be included in APS’s next LFCR application filing in accordance with the compliance requirements.

As a result of the 2019 Rate Case decision, APS’s annual LFCR adjustor rate will be dependent on an annual earnings test filing, which will compare APS’s previous year’s rate of return with the related authorized rate of return. If the actual rate of return is higher than the authorized rate of return, the LFCR rate for the subsequent year is set at zero. APS determined that the changes to the LFCR mechanism as a result of the 2019 Rate Case decision did not materially impact its results of operations and financial statements for the year ended December 31, 2021.

On February 15, 2022, APS filed its 2022 annual LFCR adjustment, requesting that effective May 1, 2022, the annual LFCR recovery amount be increased to $59.1 million (a $32.5 million increase from previous levels). The ACC’s final determination of APS’s 2022 annual LFCR adjustment filing and related earnings test may materially impact the timing and amounts of future LFCR revenue recognition. See Note 2 for a discussion of alternative revenue program accounting treatment related to certain regulatory cost recovery mechanisms and see the Regulatory Assets and Liabilities table below. APS cannot predict the outcome or timing of the ACC’s consideration and final determination of its 2022 annual LFCR adjustment filing.

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 August 13, 2018, APS filed a request with the ACC that addressed the return of $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 the 2019 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 the 2019 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.

As part of the 2019 Rate Case decision, the TEAM rates were reset to zero beginning December 31, 2021 and all impacts of the Tax Act were removed from the TEAM and incorporated into APS’s base rates. The TEAM was retained to address potential changes in tax law that may be enacted prior to a decision in APS’s next rate case.

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.

In accordance with the 2017 Rate Case Decision, APS filed its request for an 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. In accordance with this decision, the RCP export energy price of 9.4 cents per kWh became effective on October 1, 2021.
See “2016 Retail Rate Case Filing” 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.

After various proceedings between September 2016 and March 2020, at which time Burns’ appeal of a prior dismissal by the trial court was pending before the Arizona Court of Appeals, 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. On March 4, 2021, the Court of Appeals found Burns’ motion to be moot because the Court of Appeals had issued an opinion deciding the matter that same day.

In its March 4, 2021, opinion, the Court of Appeals affirmed the trial court’s dismissal of Burns’ complaint, concluding that Burns could not overturn the ACC’s 4-1 vote refusing to enforce his subpoenas. On May 15, 2021, Burns filed a petition for review with the Arizona Supreme Court asking for reversal of the Court of Appeals opinion and the trial court’s judgment. APS and the ACC filed responses to Burns’ petition on July 14, 2021, requesting that the petition be denied. The Arizona Supreme Court granted Burns' petition and oral argument is scheduled for March 8, 2022. Pinnacle West and APS cannot predict the outcome of this matter.

Energy Modernization Plan

On January 30, 2018, the initial Energy Modernization Plan was proposed, 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. On April 25, 2019, the ACC Staff issued an initial set of draft energy rules and subsequent drafts were filed by ACC Staff in July 2019, February 2020, and 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 power was defined as a clean energy resource. The proposed rules also required 50% of retail energy served be renewable by the end of 2035. A new EES was not included in the proposed rules. These rules would have required 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, these rules would have changed the IRP planning horizon from 15 years to 10 years.
The ACC discussed the final draft energy rules at several different meetings in 2020 and 2021. On November 13, 2020, the ACC approved a final draft energy rules package. On April 19, 2021, the Administrative Law Judge issued a Recommended Order and Opinion on the final energy rules. In June 2021, the ACC adopted clean energy rules based on a series of ACC amendments. The adopted rules included a final standard of 100% clean energy by 2070 and the following interim standards for carbon reduction from baseline carbon emissions level: 50% reduction by December 31, 2032; 65% reduction by December 31, 2040; 80% reduction by December 31, 2050, and 95% reduction by December 31, 2060. Since the adopted clean energy rules differed substantially from the original Recommended Order and Opinion, supplemental rulemaking procedures were required before the rules could become effective. On January 26, 2022, the ACC reversed its prior decision and declined to send the final draft energy rules through the rulemaking process. Instead, the ACC opened a new docket to consider all-source RFP requirements and the IRP process. 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. 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 IRPs 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. In February 2022, the ACC acknowledged APS’s IRP. The ACC also approved certain amendments to the IRP process, including, setting an EES of 1.3% of retail sales annually (averaged over a three-year period) and a demand-side resource capacity of 35% of 2020 peak demand by 2030 and authorizing future rate base treatment of qualifying demand-side resources as proposed in future rate cases. 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 PPAs with qualified facilities, each for 80 MW solar facilities. In March 2021, the ACC approved these agreements.

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.

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.

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 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 and ACC proposed draft amendments to the customer service disconnections rules. On April 14, 2021, the ACC voted to send to the formal rulemaking process a draft rules package governing customer disconnections that allows utilities to choose between a temperature threshold (above 95 degrees and below 32 degrees) or calendar method (June 1 – October 15) for disconnection moratoriums. On November 2, 2021, the ACC approved the final rules, and on November 23, 2021, the rules were submitted to the Arizona Office of the Attorney General for final review and approval. Although the rules are not yet final, APS intends to employ the calendar method for its disconnection moratorium. This is consistent with APS’s existing disconnection moratorium processes since 2019.

Retail Electric Competition Rules

On November 17, 2018, the ACC voted to re-examine the facilitation of a deregulated retail electric market in Arizona. 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. 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. 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 continues to discuss matters related to retail electric competition, including the potential for additional buy-through programs or other pilot programs. At the same time, the Arizona legislature is considering a bill that would nullify, if approved, a 20-year-old electric deregulation law that has been in place since 1998. The bill has several procedural steps in the legislative process before becoming law. 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.

On August 4, 2021, Green Mountain Energy filed an application seeking a certificate of convenience and necessity to allow it to provide competitive electric generation service in Arizona. Green Mountain Energy has requested that the ACC grant it the ability to provide competitive service in APS’s and Tucson Electric Power Company’s certificated service territories and proposes to deliver a 100% renewable energy product to residential and general service customers in those service territories. APS opposes Green Mountain Energy’s application and intends to intervene to contest it. On November 3, 2021, the ACC submitted questions to the Arizona Attorney General requesting legal opinions related to a number of issues surrounding retail electric competition and the ACC’s ability to issue competitive certificates convenience and necessity. On November 26, 2021, the Administrative Law Judge issued a procedural order indicating it would not be appropriate to set a schedule until the Attorney General has provided his insights on the applicable law.
On October 28, 2021, an ACC Commissioner docketed a letter directing ACC Staff and interested stakeholders to design a 200-300 MW pilot program that would allow residential and small commercial customers of APS to elect a competitive electricity supplier. The letter also states that similar programs should be designed for other Arizona regulated electric utilities. APS cannot predict the outcome of these future activities.

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. In February 2020, APS launched a new online rate comparison tool. 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 whether additional inquiries or actions may be taken by the ACC.

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 resulted in APS paying $24.75 million, approximately $24 million of which has been 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.  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. The ACC did not issue a decision on this matter.  APS included the costs for the SCR project in the retail rate base in its 2019 Rate Case filing with the ACC.

On November 2, 2021, the 2019 Rate Case decision was approved by the ACC allowing approximately $194 million of SCR related plant investments and cost deferrals in rate base and to recover, depreciate and amortize in rates based on an end-of-life assumption of July 2031. The decision also included a partial and combined disallowance of $215.5 million on the SCR investments and deferrals. APS believes the SCR plant investments and related SCR cost deferrals were prudently incurred, and on December 17, 2021, APS filed its Notice of Direct Appeal at the Arizona Court of Appeals requesting review of the $215.5 million disallowance. Based on the partial recovery of these investments and cost deferrals in current rates and the uncertainty of the outcome of the legal appeals process, APS has not recorded an impairment or write-off relating to the SCR plant investments or deferrals as of December 31, 2021. If the 2019 Rate Case decision to disallow $215.5 million of the SCRs is ultimately upheld, APS will be required to record a charge to its results of operations, net of tax, of approximately $154.4 million. We cannot predict the outcome of the legal challenges nor the timing of when this matter will be resolved. See above for further discussion on the 2019 Rate Case decision.

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 and the unit ceased operation in December 2020. APS has committed to end the use of coal at its remaining Cholla units by 2025.

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 ($41.8 million as of December 31, 2021), 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. In accordance with the 2019 Rate Case decision, the regulatory asset is being amortized through 2033.

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. 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.

APS has been recovering a return on and of the net book value of its interest in the Navajo plant in base rates over its previously estimated life through 2026. Pursuant to the 2019 Rate Case decision described above, APS will be allowed continued recovery of the book value of its remaining investment in the Navajo plant ($62.2 million as of December 31, 2021), in addition to a return on the net book value, with the exception of 15% of the annual amortization expense in rates. In addition, APS will be allowed recovery of other costs related to retirement and closure, including the Navajo coal reclamation regulatory asset ($16.8 million as of December 31, 2021). The disallowed recovery of 15% of the annual amortization does not have a material impact on APS financial statements.
Regulatory Assets and Liabilities
The detail of regulatory assets is as follows (dollars in thousands):
SDecember 31, 2021December 31, 2020
 Amortization ThroughCurrentNon-CurrentCurrentNon-Current
Pension (a)$— $509,751 $— $469,953 
Deferred fuel and purchased power (b) (c)2022388,148 — 175,835 — 
Income taxes — AFUDC equity20517,625 164,768 7,169 158,776 
Ocotillo deferral (e)20319,507 138,143 — 95,723 
Retired power plant costs203315,160 99,681 28,181 114,214 
SCR deferral (e) (f)20318,147 97,624 — 81,307 
Lost fixed cost recovery (b)202263,889 — 41,807 — 
Deferred property taxes20278,569 41,057 8,569 49,626 
Deferred compensation2036— 33,997 — 36,195 
Income taxes — investment tax credit basis adjustment20561,129 23,639 1,113 24,291 
Four Corners cost deferral20248,077 15,998 8,077 24,075 
Palo Verde VIEs (Note 18)2046— 21,094 — 21,255 
Coal reclamation20262,978 13,862 1,068 16,999 
Loss on reacquired debt20381,648 9,372 1,689 10,877 
Mead-Phoenix transmission line — contributions in aid of construction2050332 9,048 332 9,380 
Tax expense adjustor mechanism (b)2031656 5,845 6,226 — 
TCA balancing account (b)2023170 3,663 — — 
Tax expense of Medicare subsidy20241,235 2,469 1,235 3,704 
Demand side management (b)2022919 — — 7,268 
PSA interest2022335 — 4,355 — 
Deferred fuel and purchased power — mark-to-market (Note 16)2024— — 3,341 9,244 
OtherVarious— 2,976 2,716 1,100 
Total regulatory assets (d) $518,524 $1,192,987 $291,713 $1,133,987 
(a)This asset represents the future recovery of pension benefit obligations and expense 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.  As a result of the 2019 Rate Case Decision, the amount authorized for inclusion in rate base was determined using an averaging methodology, which resulted in a reduced return in retail rates. 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.”
(e)Balance includes amounts for future regulatory consideration and amortization period determination.
(f)See “Four Corners SCR Cost Recovery” discussion above.
The detail of regulatory liabilities is as follows (dollars in thousands):
 December 31, 2021December 31, 2020
 Amortization ThroughCurrentNon-CurrentCurrentNon-Current
Excess deferred income taxes - ACC — Tax Cuts and Jobs Act (a)2046$40,903 $971,545 $41,330 $1,012,583 
Excess deferred income taxes - FERC — Tax Cuts and Jobs Act (a)20587,239 221,877 7,240 229,147 
Asset retirement obligations2057— 614,683 — 506,049 
Other postretirement benefits(d)37,789 337,027 37,705 349,588 
Removal costs(c)69,476 50,104 52,844 103,008 
Deferred fuel and purchased power — mark-to-market (Note 17)202460,693 46,908 — — 
Income taxes — change in rates20512,876 64,802 2,839 66,553 
Four Corners coal reclamation20382,316 53,076 5,460 49,435 
Spent nuclear fuel20276,701 38,581 6,768 44,221 
Income taxes — deferred investment tax credit20562,264 47,337 2,231 48,648 
Renewable energy standard (b)202238,453 187 39,442 103 
FERC transmission true up (b)202321,379 12,924 6,598 3,008 
Property tax deferral (e)20244,671 15,521 — 13,856 
Sundance maintenance2031— 13,797 2,989 11,508 
Demand side management (b)2022— 5,417 10,819 — 
Tax expense adjustor mechanism (b) (e)N/A— 4,835 7,089 — 
Deferred gains on utility property20221,301 551 2,423 1,544 
TCA balancing account (b)2022— — 2,902 4,672 
Active union medical trustN/A— — — 6,057 
OtherVarious210 41 409 189 
Total regulatory liabilities $296,271 $2,499,213 $229,088 $2,450,169 

(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)Balance includes amounts for future regulatory consideration and amortization period determination.
v3.22.0.1
Income Taxes
 12 Months Ended
Dec. 31, 2021
Income Tax Disclosure [Abstract]  
Income Taxes Income Taxes
 
Certain assets and liabilities are reported differently for income tax purposes than they are for financial statement purposes.  The tax effect of these differences is recorded as deferred taxes.  We calculate deferred taxes using currently enacted income tax rates.    

APS has recorded regulatory assets and regulatory liabilities related to income taxes on its Consolidated Balance Sheets in accordance with accounting guidance for regulated operations.  The regulatory assets are for certain temporary differences, primarily the allowance for equity funds used during construction, investment tax credit (“ITC”) basis adjustment and tax expense of Medicare subsidy.  The regulatory liabilities primarily relate to the change in income tax rates and deferred taxes resulting from ITCs.
    
The Tax Act reduced the corporate tax rate to 21% effective January 1, 2018. As a result of this rate reduction, the Company recognized a $1.14 billion reduction in its net deferred income tax liabilities as of December 31, 2017. In accordance with accounting for regulated companies, the effect of this rate reduction was substantially offset by a net regulatory liability.

Federal income tax laws require the amortization of a majority of the balance over the remaining regulatory life of the related property. As a result of the modifications made to the annual transmission formula rate during the second quarter of 2018, the Company began amortization of FERC jurisdictional net excess deferred tax liabilities in 2018. On March 13, 2019, the ACC approved the Company’s proposal to amortize non-depreciation related net excess deferred tax liabilities subject to its jurisdiction over a twelve-month period. As a result, the Company began amortization in March 2019. The Company recorded $14 million of income tax benefit related to the amortization of these non-depreciation related net excess deferred tax liabilities as of March 31, 2020, with these non-depreciation related net excess deferred tax liabilities being fully amortized as of March 31, 2020. 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 of income tax benefit related to amortization of these depreciation related net excess deferred tax liabilities for the periods ending December 31, 2021, and December 31, 2020. See Note 4 for more details.

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
 202120202019202120202019
Total unrecognized tax benefits, January 1$45,655 $43,435 $40,731 $45,655 $43,435 $40,731 
Additions for tax positions of the current year3,305 3,418 3,373 3,305 3,418 3,373 
Additions for tax positions of prior years1,449 1,431 1,843 1,449 1,431 1,843 
Reductions for tax positions of prior years for:      
Changes in judgment(2,659)(1,965)(2,078)(2,659)(1,965)(2,078)
Settlements with taxing authorities— — — — — — 
Lapses of applicable statute of limitations(2,664)(664)(434)(2,664)(664)(434)
Total unrecognized tax benefits, December 31$45,086 $45,655 $43,435 $45,086 $45,655 $43,435 

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
 202120202019202120202019
Tax positions, that if recognized, would decrease our effective tax rate$26,300 $25,714 $22,813 $26,300 $25,714 $22,813 

As of the balance sheet date, the tax year ended December 31, 2018, 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 2017.

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
 202120202019202120202019
Unrecognized tax benefit interest expense/(benefit) recognized$(535)$266 $459 $(535)$266 $459 

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
 202120202019202120202019
Unrecognized tax benefit interest accrued $1,320 $1,855 $1,589 $1,320 $1,855 $1,589 
Additionally, as of December 31, 2021, we have recognized less than $1 million of interest expense to be paid on the underpayment of income taxes for certain adjustments that we have filed, or will file, with the IRS.
The components of income tax expense are as follows (dollars in thousands):
Pinnacle West ConsolidatedAPS Consolidated
 Year Ended December 31,Year Ended December 31,
 202120202019202120202019
Current:   
Federal$(5,041)$11,869 $(13,551)$1,514 $57,299 $(54,697)
State2,458 1,932 3,195 (11)99 695 
Total current(2,583)13,801 (10,356)1,503 57,398 (54,002)
Deferred:      
Federal95,327 53,398 (14,982)101,175 15,122 29,321 
State17,342 10,974 9,565 22,875 16,244 15,109 
Total deferred112,669 64,372 (5,417)124,050 31,366 44,430 
Income tax expense/(benefit)$110,086 $78,173 $(15,773)$125,553 $88,764 $(9,572)

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,
 202120202019202120202019
Federal income tax expense at statutory rate$156,666 $136,127 $113,828 $162,762 $142,020 $120,790 
Increases (reductions) in tax expense resulting from:      
State income tax net of federal income tax benefit22,656 19,146 18,599 23,339 20,124 19,267 
State income tax credits net of federal income tax benefit(7,015)(8,951)(8,519)(5,277)(7,213)(6,781)
Net operating loss carryback tax benefit(5,915)— — — — — 
Excess deferred income taxes — Tax Cuts and Jobs Act(36,558)(50,543)(124,082)(36,558)(50,543)(124,082)
Allowance for equity funds used during construction (see Note 1)(4,180)(2,747)(2,476)(4,180)(2,747)(2,476)
Palo Verde VIE noncontrolling interest (see Note 18)(3,617)(4,094)(4,094)(3,617)(4,094)(4,094)
Investment tax credit amortization(7,620)(7,510)(6,851)(7,620)(7,510)(6,851)
Other(4,331)(3,255)(2,178)(3,296)(1,273)(5,345)
Income tax expense/(benefit)$110,086 $78,173 $(15,773)$125,553 $88,764 $(9,572)
     The components of the net deferred income tax liability were as follows (dollars in thousands):
Pinnacle West ConsolidatedAPS Consolidated
 December 31,December 31,
 2021202020212020
DEFERRED TAX ASSETS  
Risk management activities$677 $4,287 $677 $4,287 
Regulatory liabilities:   
Excess deferred income taxes — Tax Cuts and Jobs Act306,915 319,091 306,915 319,091 
Asset retirement obligation and removal costs174,952 157,470 174,952 157,470 
Unamortized investment tax credits49,601 50,879 49,601 50,879 
Other postretirement benefits92,654 95,778 92,654 95,778 
Other65,815 43,551 65,815 43,551 
Operating lease liabilities204,890 107,853 204,378 107,414 
Pension liabilities42,136 45,853 37,814 40,168 
Coal reclamation liabilities43,165 42,065 43,165 42,065 
Renewable energy incentives22,646 25,355 22,646 25,355 
Credit and loss carryforwards57,077 26,460 18,902 8,034 
Other74,184 78,113 74,184 78,113 
Total deferred tax assets1,134,712 996,755 1,091,703 972,205 
DEFERRED TAX LIABILITIES   
Plant-related(2,570,613)(2,489,899)(2,570,613)(2,489,899)
Risk management activities(27,276)(1,174)(27,276)(1,174)
Pension and other postretirement assets(133,624)(123,462)(132,769)(122,580)
Other special use funds(64,610)(42,927)(64,610)(42,927)
Operating lease right-of-use assets(204,890)(107,853)(204,378)(107,414)
Regulatory assets:   
Allowance for equity funds used during construction(42,616)(41,038)(42,616)(41,038)
Deferred fuel and purchased power(96,033)(47,673)(96,033)(47,673)
Pension benefits(126,010)(116,219)(126,010)(116,219)
Retired power plant costs (28,389)(35,214)(28,389)(35,214)
Other(123,902)(106,227)(123,902)(106,227)
Other(28,611)(20,472)(6,808)(5,513)
Total deferred tax liabilities(3,446,574)(3,132,158)(3,423,404)(3,115,878)
Deferred income taxes — net$(2,311,862)$(2,135,403)$(2,331,701)$(2,143,673)
As of December 31, 2021, PNW Consolidated deferred tax assets for credit and loss carryforwards relate to federal general business credits of approximately $51 million, which first begin to expire in 2036, state credit carryforwards net of federal benefit of $42 million, which first begin to expire in 2023, and Arizona net operating loss net of federal benefit of $6 million, which will expire in 2041. PNW Consolidated credit and loss carryforwards amount above has been reduced by $42 million of unrecognized tax benefits.
As of December 31, 2021, APS Consolidated deferred tax assets for credit and loss carryforwards relate to state credit carryforwards net of federal benefit of $24 million, which first begin to expire in 2024 and Arizona net operating loss net of federal benefit of $4 million, which will expire in 2041. APS
Consolidated credit and loss carryforwards amount above has been reduced by $9 million of unrecognized tax benefits.
v3.22.0.1
Lines of Credit and Short-Term Borrowings
 12 Months Ended
Dec. 31, 2021
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 (dollars in thousands):
 
December 31, 2021December 31, 2020
Pinnacle WestAPSTotalPinnacle WestAPSTotal
Commitments under Credit Facilities$200,000 $1,000,000 $1,200,000 $231,000 $1,000,000 $1,231,000 
Outstanding Commercial Paper, Term Loan and Revolving Credit Facility Borrowings(13,300)(278,700)(292,000)(169,000)— (169,000)
Amount of Credit Facilities Available$186,700 $721,300 $908,000 $62,000 $1,000,000 $1,062,000 
Commitment Fees0.175%0.125%0.125%0.100%

Pinnacle West

On May 5, 2020, Pinnacle West refinanced its 364-day $50 million term loan agreement with a new 364-day $31 million term loan facility that would have matured May 4, 2021. Borrowings under the facility bore interest at Eurodollar Rate plus 1.40% per annum. Pinnacle West repaid this facility on April 27, 2021.

On May 28, 2021, Pinnacle West replaced its $200 million revolving credit facility that would have matured on July 11, 2023, with a new $200 million revolving credit facility that matures on May 28, 2026. 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 and the agreement includes a sustainability-linked pricing metric which permits an interest rate reduction or increase by meeting or missing targets related to specific environmental and employee health and safety sustainability objectives. The facility is available to support Pinnacle West’s general corporate purposes, including support for Pinnacle West's $200 million commercial paper program, for bank borrowings or for issuances of letters of credits. At December 31, 2021, Pinnacle West had no outstanding borrowings under its revolving credit facility, no letters of credit outstanding under the credit facility and $13 million of commercial paper borrowings.

APS
 
On May 28, 2021, APS replaced its two $500 million revolving credit facilities that would have matured on June 29, 2022 and July 11, 2023, respectively, with two new $500 million revolving credit facilities that total $1 billion and that mature on May 28, 2026.  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 and the agreements include a sustainability-linked pricing metric which permits an interest rate reduction or increase by meeting or missing targets related to specific environmental and employee health and safety sustainability objectives. These facilities are available to support APS’s general corporate purposes, including support for APS’s $750 million commercial paper program, for bank borrowings or for issuances of letters of credit.  At December 31, 2021, APS had no outstanding borrowings under its revolving credit facilities, no letters of credit outstanding under the credit facilities and $279 million of outstanding commercial paper borrowings.

See “Financial Assurances” in Note 11 for a discussion of 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.
v3.22.0.1
Long-Term Debt and Liquidity Matters
 12 Months Ended
Dec. 31, 2021
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 (dollars in thousands):
 MaturityInterestDecember 31,
 Dates (a)Rates20212020
APS    
Pollution control bonds:    
Variable2029(b)$35,975 $35,975 
Total pollution control bonds  35,975 35,975 
Senior unsecured notes2024-2050
2.20%-6.88%
6,280,000 5,830,000 
Unamortized discount  (14,995)(15,900)
Unamortized premium  13,575 14,781 
Unamortized debt issuance cost(47,862)(46,911)
Total APS long-term debt  6,266,693 5,817,945 
Less current maturities — — 
Total APS long-term debt less current maturities  6,266,693 5,817,945 
Pinnacle West    
Senior unsecured notes20251.3%500,000 500,000 
Term loans2022-2024(c)300,000 — 
Unamortized discount(34)(44)
Unamortized debt issuance cost(2,924)(3,635)
Total Pinnacle West long-term debt797,042 496,321 
Less current maturities150,000 — 
Total Pinnacle West long-term debt less current maturities647,042 496,321 
TOTAL LONG-TERM DEBT LESS CURRENT MATURITIES
$6,913,735 $6,314,266 
(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 0.22% at December 31, 2021, and 0.18% at December 31, 2020.
(c)    The weighted-average interest rate was 0.81% at December 31, 2021. 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
2022$150,000 $— 
2023— — 
2024400,000 250,000 
2025800,000 300,000 
2026250,000 250,000 
Thereafter5,515,975 5,515,975 
Total$7,115,975 $6,315,975 
 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, 2021		As of
December 31, 2020
 Carrying
Amount		Fair ValueCarrying
Amount		Fair Value
Pinnacle West$797,042 $792,735 $496,321 $509,050 
APS6,266,693 6,933,619 5,817,945 7,103,791 
Total$7,063,735 $7,726,354 $6,314,266 $7,612,841 
 
Credit Facilities and Debt Issuances

Pinnacle West

On December 21, 2021, Pinnacle West entered into a $450 million term loan facility that matures December 20, 2024. On December 21, 2021, $150 million of the proceeds were received and recognized as long-term debt on the Consolidated Balance Sheets. On January 6, 2022, the remaining $300 million of proceeds was received and recognized on that date as long-term debt on the Consolidated Balance Sheets. The proceeds were used for general corporate purposes.

On December 23, 2020, Pinnacle West entered into a $150 million term loan facility that matures June 30, 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. On January 6, 2022, Pinnacle West repaid this term loan facility early.
 
APS

On August 16, 2021, APS issued $450 million of 2.2% unsecured senior notes that mature December 15, 2031. The net proceeds from the sale were used to repay short-term indebtedness consisting of commercial paper, replenish cash used to fund capital expenditures, and for general corporate purposes.

On December 21, 2021, Pinnacle West contributed $150 million into APS in the form of an equity infusion. APS used this contribution to repay short-term indebtedness.

On January 6, 2022, 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.

BCE

On February 11, 2022, a special purpose subsidiary of BCE entered into a credit agreement to finance capital expenditures and related costs for a microgrid project in California under development by the subsidiary. The credit facilities consist of an approximately $33 million equity bridge loan facility, an
approximately $42 million non-recourse construction to term loan facility, and an approximately $5 million letter of credit. In connection with the credit agreement, Pinnacle West has guaranteed the full amount of the equity bridge loan. On February 11, 2022, $12 million was drawn from the equity bridge loan.
 
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, 2021, the ratio was approximately 56% for Pinnacle West and 50% 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.
v3.22.0.1
Retirement Plans and Other Postretirement Benefits
 12 Months Ended
Dec. 31, 2021
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. Prior to 2020, 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. Our retail rates provide for the inclusion of annual benefit costs, which allows for recovery or return of this regulatory asset/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
 202120202019202120202019
Service cost-benefits earned during the period$61,236 $56,233 $49,902 $17,796 $22,236 $18,369 
Non-service costs (credits):
Interest cost on benefit obligation98,566 118,567 136,843 16,513 25,857 29,894 
Expected return on plan assets(202,628)(187,443)(171,884)(41,444)(40,077)(38,412)
Amortization of:      
Prior service credit— — — (37,705)(37,575)(37,821)
Net actuarial (gain)/loss15,948 34,612 42,584 (10,093)— — 
Net periodic benefit cost/(benefit)$(26,878)$21,969 $57,445 $(54,933)$(29,559)$(27,970)
Portion of cost/(benefit) charged to expense$(32,743)$3,386 $30,312 $(38,657)$(20,966)$(19,859)
 
The following table shows the plans’ changes in the benefit obligations and funded status (dollars in thousands):
 Pension PlansOther Benefits Plans
 2021202020212020
Change in Benefit Obligation    
Benefit obligation at January 1$3,902,867 $3,613,114 $624,034 $746,924 
Service cost61,236 56,233 17,796 22,236 
Interest cost98,566 118,567 16,513 25,857 
Benefit payments(207,928)(191,704)(31,280)(31,511)
Actuarial (gain) loss(137,917)306,657 (35,222)(139,472)
Benefit obligation at December 313,716,824 3,902,867 591,841 624,034 
Change in Plan Assets    
Fair value of plan assets at January 13,886,544 3,318,351 961,165 837,494 
Actual return on plan assets18,169 642,373 41,432 150,076 
Employer contributions100,000 100,000 — — 
Benefit payments(192,672)(174,180)(24,310)(26,405)
Transfer to active union medical account— — (105,852)— 
Fair value of plan assets at December 313,812,041 3,886,544 872,435 961,165 
Funded Status at December 31$95,217 $(16,323)$280,594 $337,131 

The following table shows information for pension plans with an accumulated obligation in excess of plan assets (dollars in thousands):
As of December 31,
 20212020
Accumulated benefit obligation161,086 171,672 
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, 2021, and December 31, 2020, therefore the only pension plan with an accumulated benefit obligation in excess of plan assets in 2021 and 2020 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,
 20212020
Projected benefit obligation169,912 182,184 
Fair value of plan assets— — 

The Pinnacle West Capital Corporation Retirement Plan is more than 100% funded on a projected benefit obligation basis at December 31, 2021, and December 31, 2020, therefore the only pension plan with a projected benefit obligation in excess of plan assets in 2021 and 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
 2021202020212020
Noncurrent asset$265,129 $165,861 $280,594 $337,131 
Current liability(17,047)(15,700)— — 
Noncurrent liability(152,865)(166,484)— — 
Net amount recognized (funded status)$95,217 $(16,323)$280,594 $337,131 
 
The following table shows the details related to accumulated other comprehensive loss (gain) as of December 31, 2021, and 2020 (dollars in thousands): 
 Pension PlansOther Benefits Plans
 2021202020212020
Net actuarial loss (gain)$582,895 $552,301 $(262,352)$(237,233)
Prior service credit— — (114,632)(152,337)
APS’s portion recorded as a regulatory (asset) liability(509,751)(469,953)374,816 387,293 
Income tax expense (benefit)(18,081)(20,364)990 1,018 
Accumulated other comprehensive loss (gain)$55,063 $61,984 $(1,178)$(1,259)
 
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,
 20212020202120202019
Discount rate – pension plans2.92 %2.53 %2.53 %3.30 %4.34 %
Discount rate – other benefits plans2.98 %2.63 %2.63 %3.42 %4.39 %
Rate of compensation increase4.00 %4.00 %4.00 %4.00 %4.00 %
Expected long-term return on plan assets - pension plansN/AN/A5.30 %5.75 %6.25 %
Expected long-term return on plan assets - other benefit plansN/AN/A4.90 %4.85 %5.40 %
Initial healthcare cost trend rate (pre-65 participants)6.00 %6.50 %6.50 %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)45457
Initial and ultimate healthcare cost trend rate (post-65 participants) (a)2.00 %2.00 %2.00 %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 2022, we are assuming a 5.00% long-term rate of return for pension assets and 5.50% (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 2021, the target and actual allocation for the pension plan at December 31, 2021, are as follows:
 Target AllocationActual Allocation
Long-term fixed income assets80 %79 %
Return-generating assets20 %21 %
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.

The following table presents the additional target allocations, as a percent of total pension plan assets, for the return-generating assets:
Target Allocation
Equities in US and other developed markets12 %
Equities in emerging markets4 %
Alternative investments4 %
Total20 %

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, 2021, 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, 2021:
Actual Allocation
Long-term fixed income assets63 %
Return-generating assets37 %
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, 2021, 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, 2021, 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, 2021, by asset category, are as follows (dollars in thousands):
 
 Level 1Level 2Other (a)Total
Pension Plan:   
Cash and cash equivalents$821 $— $— $821 
Fixed income securities:   
Corporate— 1,765,623 — 1,765,623 
U.S. Treasury1,008,211 — — 1,008,211 
Other (b)— 165,496 — 165,496 
Common stock equities (c)209,063 — — 209,063 
Mutual funds (d)132,656 — — 132,656 
Common and collective trusts:
Equities— — 255,141 255,141 
Real estate— — 173,197 173,197 
Partnerships— — 15,730 15,730 
Short-term investments and other (e)— — 86,103 86,103 
Total$1,350,751 $1,931,119 $530,171 $3,812,041 
Other Benefits:    
Cash and cash equivalents$121 $— $— $121 
Fixed income securities:   
Corporate— 244,572 — 244,572 
U.S. Treasury287,057 — — 287,057 
Other (b)— 9,330 — 9,330 
Common stock equities (c)176,024 — — 176,024 
Mutual funds (d)26,262 — — 26,262 
Common and collective trusts:   
Equities— — 96,547 96,547 
Real estate— — 23,851 23,851 
Short-term investments and other (e)2,517 — 6,154 8,671 
Total$491,981 $253,902 $126,552 $872,435 
(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 and asset backed securities.
(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, 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 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 2021, $100 million in 2020, and $150 million in 2019.  The minimum required contributions for the pension plan are zero for the next three years and we do not expect to make any voluntary contributions in 2022, 2023 or 2024.  With regard to contributions to our other postretirement benefit plan, we did not make a contribution in 2021 or 2020 and do not expect to make any contributions in 2022, 2023 or 2024. The Company was reimbursed
$24 million in 2021, $26 million in 2020, and $30 million in 2019 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
2022$220,549 $31,244 
2023219,132 31,658 
2024221,724 31,486 
2025222,356 30,988 
2026221,709 30,780 
Years 2027-20311,121,557 151,194 
 
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 2021, 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 $12 million for 2021, $11 million for 2020, and $11 million for 2019.
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Leases
 12 Months Ended
Dec. 31, 2021
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 2022 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 May 1, 2021, APS had a new purchased power lease contract that commenced, with a lease term expiring on October 31, 2027. On December 31, 2021, APS modified an existing purchased power lease contract that had commenced in June 2020. The lease modification extends the expiration of this
lease from September 30, 2025, to October 31, 2031, among other changes. These purchased power lease agreements allow APS the right to the generation capacity from certain natural-gas fueled generators during certain months of each year throughout the term of the arrangements. As APS only has rights to use the assets during certain periods of each year the leases have non-consecutive periods of use. APS does not operate or maintain these leased assets. APS controls the dispatch of these leased assets and is required to pay fixed monthly capacity payments during the 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):
For the Year Ended
December 31,
202120202019
Operating Lease Cost - Purchased Power Lease Contracts$105,762 $68,883 42,190 
Operating Lease Cost - Land, Property, and Other Equipment18,498 18,493 18,038 
Total Operating Lease Cost124,260 87,376 60,228 
Variable lease cost (a)118,969 122,331 114,015 
Short-term lease cost3,872 3,804 4,385 
Total lease cost$247,101 $213,511 $178,628 

(a)     Primarily relates to purchased power lease contracts.

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 generation 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.
The following table provides information related to the maturity of our operating lease liabilities (dollars in thousands):
December 31, 2021
YearPurchased Power Lease ContractsLand, Property & Equipment LeasesTotal
2022$103,752 $13,051 $116,803 
2023106,151 10,758 116,909 
2024104,315 8,073 112,388 
2025106,582 6,034 112,616 
2026120,016 4,803 124,819 
Thereafter299,594 35,289 334,883 
Total lease commitments840,410 78,008 918,418 
Less imputed interest72,249 17,325 89,574 
Total lease liabilities$768,161 $60,683 $828,844 
    
We recognize lease assets and liabilities upon lease commencement. At December 31, 2021, we have various lease arrangements that have been executed but have not yet commenced. These arrangements primarily relate to energy storage assets, with expected lease commencement dates ranging from June 2022 through June 2024, with lease terms expiring through May 2044. We expect the total fixed consideration paid for these arrangements, which includes both lease and nonlease payments, will approximate $1.3 billion 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, 2021		Year Ended December 31, 2020Year Ended December 31, 2019
Cash paid for amounts included in the measurement of lease liabilities — operating cash flows:$116,661 $75,097 $69,075 
Right-of-use operating lease assets obtained in exchange for operating lease liabilities500,582 441,653 11,262 

December 31, 2021December 31, 2020
Weighted average remaining lease term8 years6 years
Weighted average discount rate (a)2.13 %1.69 %
(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.
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Jointly-Owned Facilities
 12 Months Ended
Dec. 31, 2021
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, 2021 (dollars in thousands):

 Percent
Owned		 Plant in
Service		Accumulated
Depreciation		Construction
Work in
Progress
Generating facilities:     
Palo Verde Units 1 and 329.1 %$1,932,629 $1,113,905 $28,288 
Palo Verde Unit 2 (a)16.8 %657,102 384,193 14,084 
Palo Verde Common28.0 %(b)792,849 334,804 43,690 
Palo Verde Sale Leaseback (a)351,050 256,884 — 
Four Corners Generating Station 63.0 %1,686,702 608,247 21,515 
Cholla Common Facilities (c)50.5 %208,709 121,877 1,608 
Transmission facilities:     
ANPP 500kV System33.5 %(b)133,289 53,708 115 
Navajo Southern System26.8 %(b)89,895 35,144 1,535 
Palo Verde — Yuma 500kV System25.8 %(b)23,650 7,188 716 
Four Corners Switchyards60.1 %(b)73,133 18,637 258 
Phoenix — Mead System17.1 %(b)39,523 20,150 — 
Palo Verde — Rudd 500kV System50.0 %96,376 29,426 — 
Morgan — Pinnacle Peak System64.7 %(b)119,814 23,575 138 
Round Valley System50.0 %535 180 — 
Palo Verde — Morgan System87.8 %(b)259,180 27,995 268 
Hassayampa — North Gila System80.0 %148,039 19,317 — 
Cholla 500kV Switchyard85.7 %8,287 2,163 5 
Saguaro 500kV Switchyard60.0 %21,655 13,471 — 
Kyrene — Knox System50.0 %578 328 — 
(a)See Note 18.
(b)Weighted-average of interests.
(c)PacifiCorp owns Cholla Unit 4 (see Note 4 for additional information), and APS operated the unit for PacifiCorp.  Cholla Unit 4 was retired on December 24, 2020. The common facilities at Cholla are jointly-owned.
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Commitments and Contingencies
 12 Months Ended
Dec. 31, 2021
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 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, 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, which required DOE to pay the Palo Verde owners for certain specified costs incurred by Palo Verde during the period January 1, 2007, through June 30, 2011. 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 seven claims pursuant to the terms of the August 18, 2014, settlement agreement, for seven separate time periods during July 1, 2011, through June 30, 2020. DOE has approved and paid $111.8 million for these claims (APS’s share is $32.5 million). The amounts recovered were primarily recorded as adjustments to a regulatory liability and had no impact on reported net income. In accordance with the 2017 Rate Case Decision, this regulatory liability is being refunded to customers. See Note 4. On November 1, 2021, APS filed its eighth 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). In February 2022, the DOE approved this claim.

Nuclear Insurance
 
Public liability for incidents at nuclear power plants is governed by the Price-Anderson Nuclear Industries Indemnity Act (“Price-Anderson Act”), which limits the liability of nuclear reactor owners to the amount of insurance available from both commercial sources and an industry-wide retrospective payment plan.  In accordance with the Price-Anderson Act, the Palo Verde participants are insured against public liability for a nuclear incident up to approximately $13.5 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.  The remaining balance of approximately $13.1 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 $22.4 million for each retrospective premium assessment declared by NEIL’s Board of Directors due to losses.  Additionally, at the sole discretion of the NEIL Board of Directors, APS would be liable to provide approximately $63.3 million in deposit premium within 20 days of request as assurance to satisfy any site obligation of retrospective premium assessment.  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 2022 and 2043 that include required purchase provisions.  APS estimates the contract requirements to be approximately $1 billion in 2022; $765 million in 2023; $703 million in 2024; $686 million in 2025; $687 million in 2026; and $6.9 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,
 20222023202420252026Thereafter
Coal take-or-pay commitments (a)$202,917 $201,826 $203,638 $194,192 $195,121 $925,644 
 
(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):
 
 Years Ended December 31,
 202120202019
Total purchases$219,958 $189,817 $204,888 
 
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 $32 million in 2022; $30 million in 2023; $29 million in 2024; $26 million in 2025; $22 million in 2026; and $87 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 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 $175 million at December 31, 2021, and $170 million at December 31, 2020. Under our current coal supply agreements, APS expects to make payments for the final mine reclamation as follows: $17 million in 2022; $18 million in 2023; $19 million in 2024; $20 million in 2025; $21 million in 2026; and $48 million thereafter. These funds are held in an escrow account and will be distributed to certain coal providers under the terms of the applicable coal supply agreements.  Any amendments to current coal supply agreements may change the timing of the contribution or cost of final reclamation. The annual payments to the escrow account and final distribution to certain coal providers may be subject to adjustments based on escrow earnings.

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, 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 2022. APS's estimated costs related to this investigation and study is approximately $3 million. APS anticipates incurring additional expenditures in the future, but because the overall investigation is not complete and ultimate remediation requirements are not yet finalized, at the present time expenditures related to this matter cannot be reasonably estimated.
 
On August 6, 2013, the Roosevelt Irrigation District (“RID”) filed a lawsuit in Arizona District Court against APS and 24 other defendants, alleging that RID’s groundwater wells were contaminated by the release of hazardous substances from facilities owned or operated by the defendants.  The lawsuit also alleges that, under Superfund laws, the defendants are jointly and severally liable to RID.  The allegations against APS arise out of APS’s current and former ownership of facilities in and around OU3.  As part of a
state governmental investigation into groundwater contamination in this area, on January 25, 2015, the 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 resulted in APS paying $24.75 million, approximately $24 million of which was returned to customers as restitution.

Four Corners SCR Cost Recovery

As part of APS’s 2019 Rate Case, APS included recovery of the deferral and rate base effects of the Four Corners SCR project. On November 2, 2021, the 2019 Rate Case decision was approved by the ACC allowing approximately $194 million of SCR related plant investments and cost deferrals in rate base and to recover, depreciate and amortize in rates based on an end-of-life assumption of July 2031. The decision also included a partial and combined disallowance of $215.5 million on the SCR investments and deferrals. APS believes the SCR plant investments and related SCR cost deferrals were prudently incurred, and on December 17, 2021, APS filed its Notice of Direct Appeal at the Arizona Court of Appeals requesting review of the $215.5 million disallowance. Based on the partial recovery of these investments and cost deferrals in current rates and the uncertainty of the outcome of the legal appeals process, APS has not recorded an impairment or write-off relating to the SCR plant investments or deferrals as of December 31, 2021. If the 2019 Rate Case decision to disallow $215.5 million of the SCRs is ultimately upheld, APS will be required to record a charge to its results of operations, net of tax, of approximately
$154.4 million. We cannot predict the outcome of the legal challenges nor the timing of when this matter will be resolved. See Note 4 for additional information regarding the Four Corners SCR cost recovery.
 
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 GHGs, 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.

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. 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 “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 by April 11, 2021, at the latest. All APS disposal units subject to these closure requirements were closed as of April 11, 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. On January 11, 2022, EPA began issuing proposed decisions pursuant to this provision of the federal CCR regulations and we anticipate receiving a proposed decision with respect to the Cholla facility in 2022.

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 $30 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 April 11, 2021, at the latest (except for those disposal units subject to alternative closure). APS completed the assessments of corrective measures on June 14, 2019; however, additional investigations and engineering analyses that will support the remedy selection are still underway. In addition, APS will also solicit input from the public and host public hearings 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. 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. Nonetheless, on October 29, 2021, the U.S. Supreme Court announced that it was accepting judicial review of the January D.C. Circuit decision vacating the ACE regulations. 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 or ongoing litigation related to the scope of EPA’s authority under the Clean Air Act to regulate carbon emissions from existing power plants.

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

The latest NPDES permit for Four Corners was issued on September 30, 2019. Based upon a November 1, 2019, filing by several environmental groups, the Environmental Appeals Board (“EAB”) took up review of the Four Corners NPDES Permit. 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. The September 2019 permit remains in effect pending this appeal. As of November 11, 2021, the parties to this lawsuit, including APS, reached a tentative agreement to settle this matter. Review of this agreement, including public commenting, is currently pending with EPA. Notwithstanding this tentative agreement, we cannot predict the outcome of these appeal proceedings, including further settlement discussions, and, if settlement efforts fail and the appeal is eventually 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, 2021, the note has a remaining balance of approximately $9.2 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.

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, 2021, standby letters of credit totaled approximately $5 million and will expire in 2022. As of December 31, 2021, surety bonds expiring through 2023 totaled approximately $14 million. The underlying liabilities insured by these instruments are reflected on our balance sheets, where applicable. Therefore, no additional liability is reflected for the letters of credit and surety bonds themselves.
 
We enter into agreements that include indemnification provisions relating to liabilities arising from or related to certain of our agreements.  Most significantly, APS has agreed to indemnify the equity participants and other parties in the Palo Verde sale leaseback transactions with respect to certain tax matters.  Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnification provisions cannot be reasonably estimated.  Based on historical experience and evaluation of the specific indemnities, we do not believe that any material loss related to such indemnification provisions is likely.
 
Pinnacle West has issued parental guarantees and has provided indemnification under certain surety bonds for APS which were not material at December 31, 2021. 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 wind farm in Missouri and Nobles 2 wind farm in Minnesota, 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, 2021, are immaterial in amount (approximately $2 million) and the PTC Guarantees (approximately $37 million as of December 31, 2021) are currently expected to be terminated 10 years following the commercial operation date of the applicable project.
In connection with the credit agreement entered into by a special purpose subsidiary of BCE on February 11, 2022, Pinnacle West has guaranteed the full amount of the equity bridge loan under the credit facility. See Note 7 for additional details.
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Asset Retirement Obligations
 12 Months Ended
Dec. 31, 2021
Asset Retirement Obligation Disclosure [Abstract]  
Asset Retirement Obligations Asset Retirement Obligations
 
In 2021, APS revised its cost estimates for existing AROs at Cholla related to updated estimates for the closure of ponds and facilities, which resulted in an increase to the ARO of approximately $28 million. See additional details in Notes 4 and 11.

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.

The following table shows the change in our AROs (dollars in thousands):

 20212020
Asset retirement obligations at the beginning of year$705,083 $657,218 
Changes attributable to:  
Accretion expense38,437 38,652 
Settlements(4,111)(9,710)
Estimated cash flow revisions27,973 18,923 
Asset retirement obligations at the end of year$767,382 $705,083 
 
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.
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Fair Value Measurements
 12 Months Ended
Dec. 31, 2021
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 trusts’ 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, 2021, 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$— $115,079 $— $(4,690)(a)$110,389 
Nuclear decommissioning trust:
Equity securities45,264 — — (27,782)(b)17,482 
U.S. commingled equity funds— — — 595,048 (c)595,048 
U.S. Treasury debt240,745 — — — 240,745 
Corporate debt— 203,454 — — 203,454 
Mortgage-backed securities— 155,574 — — 155,574 
Municipal bonds— 72,189 — — 72,189 
Other fixed income— 10,265 — — 10,265 
Subtotal nuclear decommissioning trust286,009 441,482 — 567,266 1,294,757 
Other special use funds:
Equity securities47,570 — — 936 (b)48,506 
U.S. Treasury debt298,170 — — — 298,170 
Municipal bonds— 11,734 — — 11,734 
Subtotal other special use funds345,740 11,734 — 936 358,410 
Total assets$631,749 $568,295 $— $563,512 $1,763,556 
Liabilities
Risk management activities — derivative instruments:
Commodity contracts$— $(4,740)$(2,738)$3,105 (a)$(4,373)

(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, 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 $(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 $4 $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.
 
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 $9 million as of December 31, 2021, 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.
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Earnings Per Share
 12 Months Ended
Dec. 31, 2021
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):
 202120202019
Net income attributable to common shareholders$618,720 $550,559 $538,320 
Weighted average common shares outstanding — basic112,910 112,666 112,443 
Net effect of dilutive securities:   
Contingently issuable performance shares and restricted stock units282 276 315 
Weighted average common shares outstanding — diluted113,192 112,942 112,758 
Earnings per weighted-average common share outstanding
Net income attributable to common shareholders — basic$5.48 $4.89 $4.79 
Net income attributable to common shareholders — diluted$5.47 $4.87 $4.77 
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Stock-Based Compensation
 12 Months Ended
Dec. 31, 2021
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 2021 Long-Term Incentive Plan (“2021 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 2021 Plan authorizes up to 1.5 million common shares to be available for grant.  As of December 31, 2021, 1.2 million common shares were available for issuance under the 2021 Plan. During 2021, 2020, and 2019, the Company granted awards in the form of restricted stock units, stock units, stock grants, and performance shares. Awards granted from 2012 to May 2021 were issued under the 2012 Long-Term Incentive Plan (“2012 Plan”), and awards granted from 2007 to 2011 were issued under the 2007 Long-Term Incentive Plan (“2007 Plan”). No new awards may be granted under the 2012 or 2007 Plans.
Stock-Based Compensation Expense and Activity
 
Compensation cost included in net income for stock-based compensation plans was $18 million in 2021, $18 million in 2020, and $18 million in 2019.  The compensation cost capitalized is immaterial for all years. Income tax benefits related to stock-based compensation arrangements were $3 million in 2021, $4 million in 2020, and $7 million in 2019.

As of December 31, 2021, there were approximately $11 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 2021, $22 million in 2020 and $21 million in 2019.
 
The following table is a summary of awards granted and the weighted-average grant date fair value for each of the last three years:

Restricted Stock Units, Stock Grants, and Stock Units (a)Performance Shares (b)
 202120202019202120202019
Units granted152,345 118,403 109,106 161,840 122,830 142,874 
Weighted-average grant date fair value$76.72 $71.70 $89.15 $82.42 $104.74 $92.16 
(a)Units granted includes awards that will be cash settled of 51,074 in 2021, 45,646 in 2020, and 48,972 in 2019.
(b)Reflects the target payout level.
 
The following table is a summary of the status of non-vested awards as of December 31, 2021, 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, 2021220,557 $77.93 260,004 $98.28 
Granted152,345 76.72 161,840 82.42 
Vested(115,099)80.50 (136,070)92.16 
Forfeited (c)(4,647)80.11 (5,092)95.07 
Nonvested at December 31, 2021253,156 (a)79.37 280,682 92.16 
Vested Awards Outstanding at December 31, 202188,706 136,070 
(a)Includes 118,538 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 $4 million, $6 million, and $5 million in 2021, 2020 and 2019, respectively. This includes cash used to settle restricted stock units of $3 million, $4 million, and $5 million in 2021, 2020 and 2019, 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 typically 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.
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Derivative Accounting
 12 Months Ended
Dec. 31, 2021
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, 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, 2021December 31, 2020
PowerGWh— 368 
GasBillion cubic feet155 205 
 
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 ContractsLocation202120202019
Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a)Fuel and purchased power (b)$— $(763)$(1,512)
(a)During the years ended December 31, 2021, 2020, and 2019, 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 ContractsLocation202120202019
Net Gain (Loss) Recognized in IncomeFuel and purchased power (a)$216,847 $(3,178)$(84,953)
(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, 2021:
 (dollars in thousands) 		Gross 
Recognized 
Derivatives
 (a)		Amounts 
Offset
(b)		Net
 Recognized
 Derivatives		Other
 (c)		Amounts 
Reported on 
Balance Sheets
Current assets$66,777 $(3,346)$63,431 $50 $63,481 
Investments and other assets48,302 (1,394)46,908 — 46,908 
Total assets115,079 (4,740)110,339 50 110,389 
Current liabilities(6,084)3,346 (2,738)(1,635)(4,373)
Deferred credits and other(1,394)1,394 — — — 
Total liabilities(7,478)4,740 (2,738)(1,635)(4,373)
Total$107,601 $— $107,601 $(1,585)$106,016 
(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 $1,635 and cash margin provided to counterparties of $50.

As of December 31, 2020:
 (dollars in thousands) 		Gross
 Recognized
 Derivatives
 (a)		Amounts
Offset 
(b)		Net
 Recognized
 Derivatives		Other
 (c)		Amounts
 Reported on
 Balance Sheets
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 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 $1,285.
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, 2021, we have three counterparties for which our exposure represents approximately 38% of Pinnacle West’s $110 million of risk management assets. This exposure relates to master agreements with counterparties and all three 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, 2021
Aggregate fair value of derivative instruments in a net liability position$7,478 
Cash collateral posted— 
Additional cash collateral in the event credit-risk related contingent features were fully triggered (a)2,658 
(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 $88 million if our debt credit ratings were to fall below investment grade.
v3.22.0.1
Other Income and Other Expense
 12 Months Ended
Dec. 31, 2021
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 2021, 2020 and 2019 (dollars in thousands):
 
 202120202019
Other income:   
Interest income$6,726 $12,210 $10,377 
Investment gains (losses) — net— 2,358 — 
Debt return on Four Corners SCR deferral (Note 4)14,955 15,865 19,541 
Debt return on Ocotillo modernization project (Note 4)23,366 26,121 20,282 
Miscellaneous53 149 63 
Total other income$45,100 $56,703 $50,263 
Other expense:   
Non-operating costs$(13,008)$(12,400)$(10,663)
Investment gains (losses) — net(1,367)— (1,835)
Miscellaneous(11,021)(45,376)(a)(5,382)
Total other expense$(25,396)$(57,776)$(17,880)
(a)The 2020 miscellaneous amount includes donations 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 2021, 2020 and 2019 (dollars in thousands):
 
 202120202019
Other income:   
Interest income$4,692 $9,621 $6,998 
Debt return on Four Corners SCR deferral (Note 4)14,955 15,865 19,541 
Debt return on Ocotillo modernization project (Note 4)23,366 26,121 20,282 
Miscellaneous40 148 63 
Total other income$43,053 $51,755 $46,884 
Other expense:   
Non-operating costs$(10,080)$(10,659)$(9,612)
Miscellaneous(8,817)(43,035)(a)(3,378)
Total other expense$(18,897)$(53,694)$(12,990)
(a)The 2020 miscellaneous amount includes donations of approximately $10 million to the APS Foundation and approximately $25.2 million related to the CCT plan. See Note 4.
v3.22.0.1
Palo Verde Sale Leaseback Variable Interest Entities
 12 Months Ended
Dec. 31, 2021
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.  Prior to April 1, 2021, the lease terms allowed APS the right to retain the assets through 2023 under one lease and 2033 under the other two leases. On April 1, 2021, APS executed an amended lease agreement with one of the VIE lessor trust entities relating to the lease agreement with the term ending in 2023. The amendment extends the lease term for this lease through 2033 and changes the lease payment. As a result of this amendment, APS will now retain the assets through 2033 under all three lease agreements. APS will be required to make payments relating to the three leases in total of approximately $21 million annually for the period 2022 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 $17 million for 2021, and $19 million for 2020 and 2019. 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, 2021December 31, 2020
Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation$94,166 $98,036 
Equity-Noncontrolling interests115,260 119,290 
 
Assets of the VIEs are restricted and may only be used for payment to the noncontrolling interest holders.  These assets are reported on our consolidated financial statements.
 
APS is exposed to losses relating to these VIEs upon the occurrence of certain events that APS does not consider 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 $315 million beginning in 2022, and up to $501 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.
v3.22.0.1
Investments in Nuclear Decommissioning Trusts and Other Special Use Funds
 12 Months Ended
Dec. 31, 2021
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 Account, 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 mine 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 2021 and 2020, APS was reimbursed $15 million and $14 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 table 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 trusts and other special use fund assets (dollars in thousands): 
December 31, 2021
 Fair ValueTotal
Unrealized
Gains		Total
Unrealized
Losses
Investment Type:Nuclear Decommissioning TrustsOther Special Use FundsTotal
Equity securities$640,312 $47,570 $687,882 $451,387 $— 
Available for sale-fixed income securities682,227 309,904 992,131 (a)24,283 (4,063)
Other(27,782)936 (26,846)(b)— — 
Total$1,294,757 $358,410 $1,653,167 $475,670 $(4,063)
(a)As of December 31, 2021, the amortized cost basis of these available-for-sale investments is $972 million.
(b)Represents net pending securities sales and purchases.

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.
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 (dollars in thousands):
 
 Year Ended December 31,
 Nuclear Decommissioning TrustsOther Special Use FundsTotal
2021
Realized gains$134,610 $49 $134,659 
Realized losses(8,431)(7)(8,438)
Proceeds from the sale of securities (a)1,457,305 263,661 1,720,966 
2020
Realized gains12,194 176 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 
(a)Proceeds are reinvested in the nuclear decommissioning trusts and other special use funds, excluding amounts reimbursed to the Company for active union employee medical claims from the active union employee medical account.
    
Fixed Income Securities Contractual Maturities

The fair value of APS’s fixed income securities, summarized by contractual maturities, at December 31, 2021, is as follows (dollars in thousands):
 
 Nuclear Decommissioning TrustsCoal Reclamation Escrow AccountActive Union Employee Medical AccountTotal
Less than one year$31,070 $36,852 $40,870 $108,792 
1 year – 5 years195,975 41,931 158,235 396,141 
5 years – 10 years155,202 1,775 21,846 178,823 
Greater than 10 years299,980 8,395 — 308,375 
Total$682,227 $88,953 $220,951 $992,131 
v3.22.0.1
Changes in Accumulated Other Comprehensive Loss
 12 Months Ended
Dec. 31, 2021
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 (dollars in thousands): 
 Pension and Other Postretirement Benefits Derivative InstrumentsTotal
Balance at December 31, 2019$(56,522)$(574)$(57,096)
OCI (loss) before reclassifications(8,370)(2,089)(10,459)
Amounts reclassified from accumulated other comprehensive loss4,167 (a)592 (b)4,759 
Balance at December 31, 2020(60,725)(2,071)(62,796)
OCI (loss) before reclassifications2,439 1,077 3,516 
Amounts reclassified from accumulated other comprehensive loss4,401 (a)18 (b)4,419 
Balance at December 31, 2021$(53,885)$(976)$(54,861)
(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 (dollars in thousands): 
 Pension and Other Postretirement Benefits Derivative InstrumentsTotal
Balance at December 31, 2019$(34,948)$(574)$(35,522)
OCI (loss) before reclassifications(9,568)(18)(9,586)
Amounts reclassified from accumulated other comprehensive loss3,598 (a)592 (b)4,190 
Balance at December 31, 2020(40,918)— (40,918)
OCI (loss) before reclassifications2,043 (18)2,025 
Amounts reclassified from accumulated other comprehensive loss3,995 (a)18 (b)4,013 
Balance at December 31, 2021$(34,880)$— $(34,880)
(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.
v3.22.0.1
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT
 12 Months Ended
Dec. 31, 2021
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,
 202120202019
Operating expenses$10,245 $7,901 $12,451 
Other   
Equity in earnings of subsidiaries628,916 566,147 562,946 
Other expense(4,919)(4,586)(3,957)
Total623,997 561,561 558,989 
Interest expense10,672 14,021 15,069 
Income before income taxes603,080 539,639 531,469 
Income tax benefit(15,640)(10,920)(6,851)
Net income attributable to common shareholders618,720 550,559 538,320 
Other comprehensive income (loss) — attributable to common shareholders7,935 (5,700)(9,388)
Total comprehensive income — attributable to common shareholders$626,655 $544,859 $528,932 
 
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,
 20212020
ASSETS  
Current assets  
Cash and cash equivalents$594 $19 
Accounts receivable125,457 123,980 
Income tax receivable1,498 14,719 
Other current assets13 298 
Total current assets127,562 139,016 
Investments and other assets  
Investments in subsidiaries6,797,528 6,400,339 
Deferred income taxes19,520 7,589 
Other assets57,608 52,595 
Total investments and other assets6,874,656 6,460,523 
Total Assets$7,002,218 $6,599,539 
LIABILITIES AND EQUITY  
Current liabilities  
Accounts payable$3,071 $5,669 
Accrued taxes19,855 16,998 
Common dividends payable95,988 93,531 
Short-term borrowings13,300 169,000 
Current maturities of long-term debt150,000 — 
Operating lease liabilities 107 90 
Other current liabilities14,684 15,306 
Total current liabilities297,005 300,594 
Long-term debt less current maturities (Note 7)647,139 496,321 
Pension liabilities14,537 17,541 
Operating lease liabilities1,576 1,683 
Other20,501 30,607 
Total deferred credits and other36,614 49,831 
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
Common stock equity
Common stock2,696,342 2,671,193 
Accumulated other comprehensive loss(54,861)(62,796)
Retained earnings3,264,719 3,025,106 
Total Pinnacle West Shareholders’ equity5,906,200 5,633,503 
Noncontrolling interests115,260 119,290 
Total Equity6,021,460 5,752,793 
Total Liabilities and Equity$7,002,218 $6,599,539 
 
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,
 202120202019
Cash flows from operating activities   
Net income$618,720 $550,559 $538,320 
Adjustments to reconcile net income to net cash provided by operating activities: 
Equity in earnings of subsidiaries — net(628,916)(566,147)(562,946)
Depreciation and amortization93 76 76 
Deferred income taxes(11,381)33,007 (35,831)
Accounts receivable8,897 (7,903)182 
Accounts payable(2,598)(1,964)(2,129)
Accrued taxes and income tax receivables — net16,079 9,610 16,400 
Dividends received from subsidiaries376,500 357,500 336,300 
Other4,214 20,163 (1,300)
Net cash flow provided by operating activities381,608 394,901 289,072 
Cash flows from investing activities   
Investments in subsidiaries(145,266)(137,881)1,557 
Repayments of loans from subsidiaries4,017 932 4,190 
Advances of loans to subsidiaries(12,256)(7,261)(4,165)
Net cash flow provided by (used for) investing activities(153,505)(144,210)1,582 
Cash flows from financing activities   
Issuance of long-term debt300,000 496,950 — 
Short-term debt borrowings under revolving credit facility— 211,690 49,000 
Short-term debt repayments under revolving credit facility(19,000)(230,690)(65,000)
Short-term borrowings and (repayments) — net(136,700)73,325 54,275 
Dividends paid on common stock(369,478)(350,577)(329,643)
Repayment of long-term debt— (450,000)— 
Common stock equity issuance and purchases — net(2,350)(1,389)692 
Net cash flow used for financing activities(227,528)(250,691)(290,676)
Net decrease in cash and cash equivalents575 — (22)
Cash and cash equivalents at beginning of year19 19 41 
Cash and cash equivalents at end of year$594 $19 $19 
     
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 on a stand-alone basis as a holding company. Investments in subsidiaries are accounted for using the equity method.
v3.22.0.1
Summary of Significant Accounting Policies (Policies)
 12 Months Ended
Dec. 31, 2021
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 Variable Interest Entities (each a “VIE”) 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. We have determined that Pinnacle West is the primary beneficiary of a captive insurance protected cell VIE. As of December 31, 2021, the captive cell's activities are insignificant to our consolidated financial statements.
 
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 the 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
•AFUDC.
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 AROs.  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, 2021, were as follows:
•Steam generation — 12 years;
•Nuclear plant — 25 years;
•Other generation — 19 years;
•Transmission — 37 years;
•Distribution — 33 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 AROs for its Palo Verde nuclear facilities and certain other generation assets.  The Palo Verde ARO 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 AROs 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 AROs 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 ARO 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 6.75% for 2021, 6.72% for 2020, and 6.98% for 2019.  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, FERC issued an order granting a waiver request related to the existing AFUDC rate calculation beginning March 1, 2020, through February 28, 2021. On February 23, 2021, this waiver was extended until September 30, 2021. On September 21, 2021, it was further extended until March 21, 2022.  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 and 2021 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).

BCE 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. Purchased power lease contracts may also include energy storage facilities. 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
 
ASU 2021-05, Leases: Certain Leases with Variable Lease Payments
In July 2021, a new accounting standard was issued that amends the lease accounting guidance. The amended guidance will require lessors to account for certain lease transactions, that contain variable lease payments, as operating leases. The amendments are intended to eliminate the recognition of any day-one loss associated with certain sales-type and direct-financing lease transactions. The changes do not impact lessee accounting. The standard may be adopted using either a prospective or modified retrospective approach. We adopted this standard on January 1, 2022, using a prospective approach. The adoption of this standard did not impact our financial statements.
v3.22.0.1
Summary of Significant Accounting Policies (Tables)
 12 Months Ended
Dec. 31, 2021
Accounting Policies [Abstract]  
Schedule of property, plant and equipment
Pinnacle West’s property, plant and equipment included in the December 31, 2021, and 2020 Consolidated Balance Sheets is composed of the following (dollars in thousands):

Property, Plant and Equipment:20212020
Generation$9,480,572 $9,199,012 
Transmission3,402,016 3,290,477 
Distribution7,520,016 7,107,007 
General plant1,286,057 1,241,389 
Plant in service and held for future use
21,688,661 20,837,885 
Accumulated depreciation and amortization(7,504,603)(7,110,310)
Net
14,184,058 13,727,575 
Construction work in progress1,329,478 937,384 
Palo Verde sale leaseback, net of accumulated depreciation94,166 98,036 
Intangible assets, net of accumulated amortization273,693 282,570 
Nuclear fuel, net of accumulated amortization106,039 113,645 
Total property, plant and equipment$15,987,434 $15,159,210 
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,
 202120202019
Cash paid (received) during the period for:   
Income taxes, net of refunds$229 $(3,019)$12,535 
Interest, net of amounts capitalized227,584 216,951 218,664 
Significant non-cash investing and financing activities:   
Accrued capital expenditures$167,733 $113,502 $141,297 
Dividends declared but not paid95,988 93,531 87,982 

The following table summarizes supplemental APS cash flow information for each of the last three years (dollars in thousands):
 Year ended December 31,
 202120202019
Cash paid (received) during the period for:   
Income taxes, net of refunds$19,783 $41,176 $(15,042)
Interest, net of amounts capitalized217,749 206,328 204,261 
Significant non-cash investing and financing activities:   
Accrued capital expenditures$167,657 $113,502 $141,297 
Dividends declared but not paid96,000 93,500 88,000 
v3.22.0.1
Revenue (Tables)
 12 Months Ended
Dec. 31, 2021
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,
202120202019
Retail Electric Service
Residential$1,913,324 $1,929,178 (a)$1,761,122 
Non-Residential1,586,940 1,486,098 1,509,514 
Wholesale Energy Sales187,640 93,345 121,805 
Transmission Services for Others99,285 65,859 62,460 
Other Sources16,646 12,502 16,308 
Total Operating Revenues$3,803,835 $3,586,982 $3,471,209 
(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 (dollars in thousands):
Year Ended December 31, 2021Year Ended December 31, 2020Year Ended December 31, 2019
Allowance for doubtful accounts, balance at beginning of period$19,782 $8,171 $4,069 
Bad debt expense22,251 20,633 11,819 
Actual write-offs(16,679)(9,022)(7,717)
Allowance for doubtful accounts, balance at end of period$25,354 $19,782 $8,171 
v3.22.0.1
Regulatory Matters (Tables)
 12 Months Ended
Dec. 31, 2021
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 2021 and 2020 (dollars in thousands):
 Twelve Months Ended
December 31,
 20212020
Beginning balance$175,835 $70,137 
Deferred fuel and purchased power costs — current period256,871 93,651 
Amounts refunded/(charged) to customers(44,558)12,047 
Ending balance$388,148 $175,835 
Schedule of regulatory assets
The detail of regulatory assets is as follows (dollars in thousands):
SDecember 31, 2021December 31, 2020
 Amortization ThroughCurrentNon-CurrentCurrentNon-Current
Pension (a)$— $509,751 $— $469,953 
Deferred fuel and purchased power (b) (c)2022388,148 — 175,835 — 
Income taxes — AFUDC equity20517,625 164,768 7,169 158,776 
Ocotillo deferral (e)20319,507 138,143 — 95,723 
Retired power plant costs203315,160 99,681 28,181 114,214 
SCR deferral (e) (f)20318,147 97,624 — 81,307 
Lost fixed cost recovery (b)202263,889 — 41,807 — 
Deferred property taxes20278,569 41,057 8,569 49,626 
Deferred compensation2036— 33,997 — 36,195 
Income taxes — investment tax credit basis adjustment20561,129 23,639 1,113 24,291 
Four Corners cost deferral20248,077 15,998 8,077 24,075 
Palo Verde VIEs (Note 18)2046— 21,094 — 21,255 
Coal reclamation20262,978 13,862 1,068 16,999 
Loss on reacquired debt20381,648 9,372 1,689 10,877 
Mead-Phoenix transmission line — contributions in aid of construction2050332 9,048 332 9,380 
Tax expense adjustor mechanism (b)2031656 5,845 6,226 — 
TCA balancing account (b)2023170 3,663 — — 
Tax expense of Medicare subsidy20241,235 2,469 1,235 3,704 
Demand side management (b)2022919 — — 7,268 
PSA interest2022335 — 4,355 — 
Deferred fuel and purchased power — mark-to-market (Note 16)2024— — 3,341 9,244 
OtherVarious— 2,976 2,716 1,100 
Total regulatory assets (d) $518,524 $1,192,987 $291,713 $1,133,987 
(a)This asset represents the future recovery of pension benefit obligations and expense 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.  As a result of the 2019 Rate Case Decision, the amount authorized for inclusion in rate base was determined using an averaging methodology, which resulted in a reduced return in retail rates. 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.”
(e)Balance includes amounts for future regulatory consideration and amortization period determination.
(f)See “Four Corners SCR Cost Recovery” discussion above.
Schedule of regulatory liabilities
The detail of regulatory liabilities is as follows (dollars in thousands):
 December 31, 2021December 31, 2020
 Amortization ThroughCurrentNon-CurrentCurrentNon-Current
Excess deferred income taxes - ACC — Tax Cuts and Jobs Act (a)2046$40,903 $971,545 $41,330 $1,012,583 
Excess deferred income taxes - FERC — Tax Cuts and Jobs Act (a)20587,239 221,877 7,240 229,147 
Asset retirement obligations2057— 614,683 — 506,049 
Other postretirement benefits(d)37,789 337,027 37,705 349,588 
Removal costs(c)69,476 50,104 52,844 103,008 
Deferred fuel and purchased power — mark-to-market (Note 17)202460,693 46,908 — — 
Income taxes — change in rates20512,876 64,802 2,839 66,553 
Four Corners coal reclamation20382,316 53,076 5,460 49,435 
Spent nuclear fuel20276,701 38,581 6,768 44,221 
Income taxes — deferred investment tax credit20562,264 47,337 2,231 48,648 
Renewable energy standard (b)202238,453 187 39,442 103 
FERC transmission true up (b)202321,379 12,924 6,598 3,008 
Property tax deferral (e)20244,671 15,521 — 13,856 
Sundance maintenance2031— 13,797 2,989 11,508 
Demand side management (b)2022— 5,417 10,819 — 
Tax expense adjustor mechanism (b) (e)N/A— 4,835 7,089 — 
Deferred gains on utility property20221,301 551 2,423 1,544 
TCA balancing account (b)2022— — 2,902 4,672 
Active union medical trustN/A— — — 6,057 
OtherVarious210 41 409 189 
Total regulatory liabilities $296,271 $2,499,213 $229,088 $2,450,169 

(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)Balance includes amounts for future regulatory consideration and amortization period determination.
v3.22.0.1
Income Taxes (Tables)
 12 Months Ended
Dec. 31, 2021
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
 202120202019202120202019
Total unrecognized tax benefits, January 1$45,655 $43,435 $40,731 $45,655 $43,435 $40,731 
Additions for tax positions of the current year3,305 3,418 3,373 3,305 3,418 3,373 
Additions for tax positions of prior years1,449 1,431 1,843 1,449 1,431 1,843 
Reductions for tax positions of prior years for:      
Changes in judgment(2,659)(1,965)(2,078)(2,659)(1,965)(2,078)
Settlements with taxing authorities— — — — — — 
Lapses of applicable statute of limitations(2,664)(664)(434)(2,664)(664)(434)
Total unrecognized tax benefits, December 31$45,086 $45,655 $43,435 $45,086 $45,655 $43,435 
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
 202120202019202120202019
Tax positions, that if recognized, would decrease our effective tax rate$26,300 $25,714 $22,813 $26,300 $25,714 $22,813 
The amount of interest expense or benefit recognized related to unrecognized tax benefits are as follows (dollars in thousands):
Pinnacle West ConsolidatedAPS Consolidated
 202120202019202120202019
Unrecognized tax benefit interest expense/(benefit) recognized$(535)$266 $459 $(535)$266 $459 

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
 202120202019202120202019
Unrecognized tax benefit interest accrued $1,320 $1,855 $1,589 $1,320 $1,855 $1,589 
Components of income tax expense The components of income tax expense are as follows (dollars in thousands):
Pinnacle West ConsolidatedAPS Consolidated
 Year Ended December 31,Year Ended December 31,
 202120202019202120202019
Current:   
Federal$(5,041)$11,869 $(13,551)$1,514 $57,299 $(54,697)
State2,458 1,932 3,195 (11)99 695 
Total current(2,583)13,801 (10,356)1,503 57,398 (54,002)
Deferred:      
Federal95,327 53,398 (14,982)101,175 15,122 29,321 
State17,342 10,974 9,565 22,875 16,244 15,109 
Total deferred112,669 64,372 (5,417)124,050 31,366 44,430 
Income tax expense/(benefit)$110,086 $78,173 $(15,773)$125,553 $88,764 $(9,572)
Comparison of pretax income from continuing operations at the federal income tax rate to income tax expense - continuing operations The following chart compares pretax income at the 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,
 202120202019202120202019
Federal income tax expense at statutory rate$156,666 $136,127 $113,828 $162,762 $142,020 $120,790 
Increases (reductions) in tax expense resulting from:      
State income tax net of federal income tax benefit22,656 19,146 18,599 23,339 20,124 19,267 
State income tax credits net of federal income tax benefit(7,015)(8,951)(8,519)(5,277)(7,213)(6,781)
Net operating loss carryback tax benefit(5,915)— — — — — 
Excess deferred income taxes — Tax Cuts and Jobs Act(36,558)(50,543)(124,082)(36,558)(50,543)(124,082)
Allowance for equity funds used during construction (see Note 1)(4,180)(2,747)(2,476)(4,180)(2,747)(2,476)
Palo Verde VIE noncontrolling interest (see Note 18)(3,617)(4,094)(4,094)(3,617)(4,094)(4,094)
Investment tax credit amortization(7,620)(7,510)(6,851)(7,620)(7,510)(6,851)
Other(4,331)(3,255)(2,178)(3,296)(1,273)(5,345)
Income tax expense/(benefit)$110,086 $78,173 $(15,773)$125,553 $88,764 $(9,572)
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,
 2021202020212020
DEFERRED TAX ASSETS  
Risk management activities$677 $4,287 $677 $4,287 
Regulatory liabilities:   
Excess deferred income taxes — Tax Cuts and Jobs Act306,915 319,091 306,915 319,091 
Asset retirement obligation and removal costs174,952 157,470 174,952 157,470 
Unamortized investment tax credits49,601 50,879 49,601 50,879 
Other postretirement benefits92,654 95,778 92,654 95,778 
Other65,815 43,551 65,815 43,551 
Operating lease liabilities204,890 107,853 204,378 107,414 
Pension liabilities42,136 45,853 37,814 40,168 
Coal reclamation liabilities43,165 42,065 43,165 42,065 
Renewable energy incentives22,646 25,355 22,646 25,355 
Credit and loss carryforwards57,077 26,460 18,902 8,034 
Other74,184 78,113 74,184 78,113 
Total deferred tax assets1,134,712 996,755 1,091,703 972,205 
DEFERRED TAX LIABILITIES   
Plant-related(2,570,613)(2,489,899)(2,570,613)(2,489,899)
Risk management activities(27,276)(1,174)(27,276)(1,174)
Pension and other postretirement assets(133,624)(123,462)(132,769)(122,580)
Other special use funds(64,610)(42,927)(64,610)(42,927)
Operating lease right-of-use assets(204,890)(107,853)(204,378)(107,414)
Regulatory assets:   
Allowance for equity funds used during construction(42,616)(41,038)(42,616)(41,038)
Deferred fuel and purchased power(96,033)(47,673)(96,033)(47,673)
Pension benefits(126,010)(116,219)(126,010)(116,219)
Retired power plant costs (28,389)(35,214)(28,389)(35,214)
Other(123,902)(106,227)(123,902)(106,227)
Other(28,611)(20,472)(6,808)(5,513)
Total deferred tax liabilities(3,446,574)(3,132,158)(3,423,404)(3,115,878)
Deferred income taxes — net$(2,311,862)$(2,135,403)$(2,331,701)$(2,143,673)
v3.22.0.1
Lines of Credit and Short-Term Borrowings (Tables)
 12 Months Ended
Dec. 31, 2021
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 (dollars in thousands):
 
December 31, 2021December 31, 2020
Pinnacle WestAPSTotalPinnacle WestAPSTotal
Commitments under Credit Facilities$200,000 $1,000,000 $1,200,000 $231,000 $1,000,000 $1,231,000 
Outstanding Commercial Paper, Term Loan and Revolving Credit Facility Borrowings(13,300)(278,700)(292,000)(169,000)— (169,000)
Amount of Credit Facilities Available$186,700 $721,300 $908,000 $62,000 $1,000,000 $1,062,000 
Commitment Fees0.175%0.125%0.125%0.100%
v3.22.0.1
Long-Term Debt and Liquidity Matters (Tables)
 12 Months Ended
Dec. 31, 2021
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 (dollars in thousands):
 MaturityInterestDecember 31,
 Dates (a)Rates20212020
APS    
Pollution control bonds:    
Variable2029(b)$35,975 $35,975 
Total pollution control bonds  35,975 35,975 
Senior unsecured notes2024-2050
2.20%-6.88%
6,280,000 5,830,000 
Unamortized discount  (14,995)(15,900)
Unamortized premium  13,575 14,781 
Unamortized debt issuance cost(47,862)(46,911)
Total APS long-term debt  6,266,693 5,817,945 
Less current maturities — — 
Total APS long-term debt less current maturities  6,266,693 5,817,945 
Pinnacle West    
Senior unsecured notes20251.3%500,000 500,000 
Term loans2022-2024(c)300,000 — 
Unamortized discount(34)(44)
Unamortized debt issuance cost(2,924)(3,635)
Total Pinnacle West long-term debt797,042 496,321 
Less current maturities150,000 — 
Total Pinnacle West long-term debt less current maturities647,042 496,321 
TOTAL LONG-TERM DEBT LESS CURRENT MATURITIES
$6,913,735 $6,314,266 
(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 0.22% at December 31, 2021, and 0.18% at December 31, 2020.
(c)    The weighted-average interest rate was 0.81% at December 31, 2021. 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
2022$150,000 $— 
2023— — 
2024400,000 250,000 
2025800,000 300,000 
2026250,000 250,000 
Thereafter5,515,975 5,515,975 
Total$7,115,975 $6,315,975 
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, 2021		As of
December 31, 2020
 Carrying
Amount		Fair ValueCarrying
Amount		Fair Value
Pinnacle West$797,042 $792,735 $496,321 $509,050 
APS6,266,693 6,933,619 5,817,945 7,103,791 
Total$7,063,735 $7,726,354 $6,314,266 $7,612,841 
v3.22.0.1
Retirement Plans and Other Postretirement Benefits (Tables)
 12 Months Ended
Dec. 31, 2021
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
 202120202019202120202019
Service cost-benefits earned during the period$61,236 $56,233 $49,902 $17,796 $22,236 $18,369 
Non-service costs (credits):
Interest cost on benefit obligation98,566 118,567 136,843 16,513 25,857 29,894 
Expected return on plan assets(202,628)(187,443)(171,884)(41,444)(40,077)(38,412)
Amortization of:      
Prior service credit— — — (37,705)(37,575)(37,821)
Net actuarial (gain)/loss15,948 34,612 42,584 (10,093)— — 
Net periodic benefit cost/(benefit)$(26,878)$21,969 $57,445 $(54,933)$(29,559)$(27,970)
Portion of cost/(benefit) charged to expense$(32,743)$3,386 $30,312 $(38,657)$(20,966)$(19,859)
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
 2021202020212020
Change in Benefit Obligation    
Benefit obligation at January 1$3,902,867 $3,613,114 $624,034 $746,924 
Service cost61,236 56,233 17,796 22,236 
Interest cost98,566 118,567 16,513 25,857 
Benefit payments(207,928)(191,704)(31,280)(31,511)
Actuarial (gain) loss(137,917)306,657 (35,222)(139,472)
Benefit obligation at December 313,716,824 3,902,867 591,841 624,034 
Change in Plan Assets    
Fair value of plan assets at January 13,886,544 3,318,351 961,165 837,494 
Actual return on plan assets18,169 642,373 41,432 150,076 
Employer contributions100,000 100,000 — — 
Benefit payments(192,672)(174,180)(24,310)(26,405)
Transfer to active union medical account— — (105,852)— 
Fair value of plan assets at December 313,812,041 3,886,544 872,435 961,165 
Funded Status at December 31$95,217 $(16,323)$280,594 $337,131 
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,
 20212020
Accumulated benefit obligation161,086 171,672 
Fair value of plan assets— — 
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,
 20212020
Projected benefit obligation169,912 182,184 
Fair value of plan assets— — 
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
 2021202020212020
Noncurrent asset$265,129 $165,861 $280,594 $337,131 
Current liability(17,047)(15,700)— — 
Noncurrent liability(152,865)(166,484)— — 
Net amount recognized (funded status)$95,217 $(16,323)$280,594 $337,131 
Schedule of accumulated other comprehensive loss
The following table shows the details related to accumulated other comprehensive loss (gain) as of December 31, 2021, and 2020 (dollars in thousands): 
 Pension PlansOther Benefits Plans
 2021202020212020
Net actuarial loss (gain)$582,895 $552,301 $(262,352)$(237,233)
Prior service credit— — (114,632)(152,337)
APS’s portion recorded as a regulatory (asset) liability(509,751)(469,953)374,816 387,293 
Income tax expense (benefit)(18,081)(20,364)990 1,018 
Accumulated other comprehensive loss (gain)$55,063 $61,984 $(1,178)$(1,259)
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,
 20212020202120202019
Discount rate – pension plans2.92 %2.53 %2.53 %3.30 %4.34 %
Discount rate – other benefits plans2.98 %2.63 %2.63 %3.42 %4.39 %
Rate of compensation increase4.00 %4.00 %4.00 %4.00 %4.00 %
Expected long-term return on plan assets - pension plansN/AN/A5.30 %5.75 %6.25 %
Expected long-term return on plan assets - other benefit plansN/AN/A4.90 %4.85 %5.40 %
Initial healthcare cost trend rate (pre-65 participants)6.00 %6.50 %6.50 %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)45457
Initial and ultimate healthcare cost trend rate (post-65 participants) (a)2.00 %2.00 %2.00 %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 2021, the target and actual allocation for the pension plan at December 31, 2021, are as follows:
 Target AllocationActual Allocation
Long-term fixed income assets80 %79 %
Return-generating assets20 %21 %
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.

The following table presents the additional target allocations, as a percent of total pension plan assets, for the return-generating assets:
Target Allocation
Equities in US and other developed markets12 %
Equities in emerging markets4 %
Alternative investments4 %
Total20 %
The following table presents the actual allocations of the investment for the other postretirement benefit plan at December 31, 2021:
Actual Allocation
Long-term fixed income assets63 %
Return-generating assets37 %
Total100 %
The fair value of Pinnacle West’s pension plan and other postretirement benefit plan assets at December 31, 2021, by asset category, are as follows (dollars in thousands):
 
 Level 1Level 2Other (a)Total
Pension Plan:   
Cash and cash equivalents$821 $— $— $821 
Fixed income securities:   
Corporate— 1,765,623 — 1,765,623 
U.S. Treasury1,008,211 — — 1,008,211 
Other (b)— 165,496 — 165,496 
Common stock equities (c)209,063 — — 209,063 
Mutual funds (d)132,656 — — 132,656 
Common and collective trusts:
Equities— — 255,141 255,141 
Real estate— — 173,197 173,197 
Partnerships— — 15,730 15,730 
Short-term investments and other (e)— — 86,103 86,103 
Total$1,350,751 $1,931,119 $530,171 $3,812,041 
Other Benefits:    
Cash and cash equivalents$121 $— $— $121 
Fixed income securities:   
Corporate— 244,572 — 244,572 
U.S. Treasury287,057 — — 287,057 
Other (b)— 9,330 — 9,330 
Common stock equities (c)176,024 — — 176,024 
Mutual funds (d)26,262 — — 26,262 
Common and collective trusts:   
Equities— — 96,547 96,547 
Real estate— — 23,851 23,851 
Short-term investments and other (e)2,517 — 6,154 8,671 
Total$491,981 $253,902 $126,552 $872,435 
(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 and asset backed securities.
(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, 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 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
2022$220,549 $31,244 
2023219,132 31,658 
2024221,724 31,486 
2025222,356 30,988 
2026221,709 30,780 
Years 2027-20311,121,557 151,194 
v3.22.0.1
Leases (Tables)
 12 Months Ended
Dec. 31, 2021
Leases [Abstract]  
Schedule of lease costs
The following table provides information related to our lease costs (dollars in thousands):
For the Year Ended
December 31,
202120202019
Operating Lease Cost - Purchased Power Lease Contracts$105,762 $68,883 42,190 
Operating Lease Cost - Land, Property, and Other Equipment18,498 18,493 18,038 
Total Operating Lease Cost124,260 87,376 60,228 
Variable lease cost (a)118,969 122,331 114,015 
Short-term lease cost3,872 3,804 4,385 
Total lease cost$247,101 $213,511 $178,628 

(a)     Primarily relates to purchased power lease contracts.
The following tables provide other additional information related to operating lease liabilities (dollars in thousands):
Year Ended
December 31, 2021		Year Ended December 31, 2020Year Ended December 31, 2019
Cash paid for amounts included in the measurement of lease liabilities — operating cash flows:$116,661 $75,097 $69,075 
Right-of-use operating lease assets obtained in exchange for operating lease liabilities500,582 441,653 11,262 

December 31, 2021December 31, 2020
Weighted average remaining lease term8 years6 years
Weighted average discount rate (a)2.13 %1.69 %
(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, 2021
YearPurchased Power Lease ContractsLand, Property & Equipment LeasesTotal
2022$103,752 $13,051 $116,803 
2023106,151 10,758 116,909 
2024104,315 8,073 112,388 
2025106,582 6,034 112,616 
2026120,016 4,803 124,819 
Thereafter299,594 35,289 334,883 
Total lease commitments840,410 78,008 918,418 
Less imputed interest72,249 17,325 89,574 
Total lease liabilities$768,161 $60,683 $828,844 
v3.22.0.1
Jointly-Owned Facilities (Tables)
 12 Months Ended
Dec. 31, 2021
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, 2021 (dollars in thousands):
 Percent
Owned		 Plant in
Service		Accumulated
Depreciation		Construction
Work in
Progress
Generating facilities:     
Palo Verde Units 1 and 329.1 %$1,932,629 $1,113,905 $28,288 
Palo Verde Unit 2 (a)16.8 %657,102 384,193 14,084 
Palo Verde Common28.0 %(b)792,849 334,804 43,690 
Palo Verde Sale Leaseback (a)351,050 256,884 — 
Four Corners Generating Station 63.0 %1,686,702 608,247 21,515 
Cholla Common Facilities (c)50.5 %208,709 121,877 1,608 
Transmission facilities:     
ANPP 500kV System33.5 %(b)133,289 53,708 115 
Navajo Southern System26.8 %(b)89,895 35,144 1,535 
Palo Verde — Yuma 500kV System25.8 %(b)23,650 7,188 716 
Four Corners Switchyards60.1 %(b)73,133 18,637 258 
Phoenix — Mead System17.1 %(b)39,523 20,150 — 
Palo Verde — Rudd 500kV System50.0 %96,376 29,426 — 
Morgan — Pinnacle Peak System64.7 %(b)119,814 23,575 138 
Round Valley System50.0 %535 180 — 
Palo Verde — Morgan System87.8 %(b)259,180 27,995 268 
Hassayampa — North Gila System80.0 %148,039 19,317 — 
Cholla 500kV Switchyard85.7 %8,287 2,163 5 
Saguaro 500kV Switchyard60.0 %21,655 13,471 — 
Kyrene — Knox System50.0 %578 328 — 
(a)See Note 18.
(b)Weighted-average of interests.
(c)PacifiCorp owns Cholla Unit 4 (see Note 4 for additional information), and APS operated the unit for PacifiCorp.  Cholla Unit 4 was retired on December 24, 2020. The common facilities at Cholla are jointly-owned.
v3.22.0.1
Commitments and Contingencies (Tables)
 12 Months Ended
Dec. 31, 2021
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,
 20222023202420252026Thereafter
Coal take-or-pay commitments (a)$202,917 $201,826 $203,638 $194,192 $195,121 $925,644 
 
(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):
 
 Years Ended December 31,
 202120202019
Total purchases$219,958 $189,817 $204,888 
v3.22.0.1
Asset Retirement Obligations (Tables)
 12 Months Ended
Dec. 31, 2021
Asset Retirement Obligation Disclosure [Abstract]  
Change in asset retirement obligations
The following table shows the change in our AROs (dollars in thousands):

 20212020
Asset retirement obligations at the beginning of year$705,083 $657,218 
Changes attributable to:  
Accretion expense38,437 38,652 
Settlements(4,111)(9,710)
Estimated cash flow revisions27,973 18,923 
Asset retirement obligations at the end of year$767,382 $705,083 
v3.22.0.1
Fair Value Measurements (Tables)
 12 Months Ended
Dec. 31, 2021
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, 2021, 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$— $115,079 $— $(4,690)(a)$110,389 
Nuclear decommissioning trust:
Equity securities45,264 — — (27,782)(b)17,482 
U.S. commingled equity funds— — — 595,048 (c)595,048 
U.S. Treasury debt240,745 — — — 240,745 
Corporate debt— 203,454 — — 203,454 
Mortgage-backed securities— 155,574 — — 155,574 
Municipal bonds— 72,189 — — 72,189 
Other fixed income— 10,265 — — 10,265 
Subtotal nuclear decommissioning trust286,009 441,482 — 567,266 1,294,757 
Other special use funds:
Equity securities47,570 — — 936 (b)48,506 
U.S. Treasury debt298,170 — — — 298,170 
Municipal bonds— 11,734 — — 11,734 
Subtotal other special use funds345,740 11,734 — 936 358,410 
Total assets$631,749 $568,295 $— $563,512 $1,763,556 
Liabilities
Risk management activities — derivative instruments:
Commodity contracts$— $(4,740)$(2,738)$3,105 (a)$(4,373)

(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, 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 $(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 $4 $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.
v3.22.0.1
Earnings Per Share (Tables)
 12 Months Ended
Dec. 31, 2021
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):
 202120202019
Net income attributable to common shareholders$618,720 $550,559 $538,320 
Weighted average common shares outstanding — basic112,910 112,666 112,443 
Net effect of dilutive securities:   
Contingently issuable performance shares and restricted stock units282 276 315 
Weighted average common shares outstanding — diluted113,192 112,942 112,758 
Earnings per weighted-average common share outstanding
Net income attributable to common shareholders — basic$5.48 $4.89 $4.79 
Net income attributable to common shareholders — diluted$5.47 $4.87 $4.77 
v3.22.0.1
Stock-Based Compensation (Tables)
 12 Months Ended
Dec. 31, 2021
Share-based Payment Arrangement [Abstract]  
Summary of restricted stock units, stock grants and stock units
The following table is a summary of awards granted and the weighted-average grant date fair value for each of the last three years:

Restricted Stock Units, Stock Grants, and Stock Units (a)Performance Shares (b)
 202120202019202120202019
Units granted152,345 118,403 109,106 161,840 122,830 142,874 
Weighted-average grant date fair value$76.72 $71.70 $89.15 $82.42 $104.74 $92.16 
(a)Units granted includes awards that will be cash settled of 51,074 in 2021, 45,646 in 2020, and 48,972 in 2019.
(b)Reflects the target payout level.
The following table is a summary of the status of non-vested awards as of December 31, 2021, 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, 2021220,557 $77.93 260,004 $98.28 
Granted152,345 76.72 161,840 82.42 
Vested(115,099)80.50 (136,070)92.16 
Forfeited (c)(4,647)80.11 (5,092)95.07 
Nonvested at December 31, 2021253,156 (a)79.37 280,682 92.16 
Vested Awards Outstanding at December 31, 202188,706 136,070 
(a)Includes 118,538 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 each of the last three years:

Restricted Stock Units, Stock Grants, and Stock Units (a)Performance Shares (b)
 202120202019202120202019
Units granted152,345 118,403 109,106 161,840 122,830 142,874 
Weighted-average grant date fair value$76.72 $71.70 $89.15 $82.42 $104.74 $92.16 
(a)Units granted includes awards that will be cash settled of 51,074 in 2021, 45,646 in 2020, and 48,972 in 2019.
(b)Reflects the target payout level.
The following table is a summary of the status of non-vested awards as of December 31, 2021, 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, 2021220,557 $77.93 260,004 $98.28 
Granted152,345 76.72 161,840 82.42 
Vested(115,099)80.50 (136,070)92.16 
Forfeited (c)(4,647)80.11 (5,092)95.07 
Nonvested at December 31, 2021253,156 (a)79.37 280,682 92.16 
Vested Awards Outstanding at December 31, 202188,706 136,070 
(a)Includes 118,538 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.
v3.22.0.1
Derivative Accounting (Tables)
 12 Months Ended
Dec. 31, 2021
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, 2021December 31, 2020
PowerGWh— 368 
GasBillion cubic feet155 205 
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 ContractsLocation202120202019
Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a)Fuel and purchased power (b)$— $(763)$(1,512)
(a)During the years ended December 31, 2021, 2020, and 2019, 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 ContractsLocation202120202019
Net Gain (Loss) Recognized in IncomeFuel and purchased power (a)$216,847 $(3,178)$(84,953)
(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, 2021:
 (dollars in thousands) 		Gross 
Recognized 
Derivatives
 (a)		Amounts 
Offset
(b)		Net
 Recognized
 Derivatives		Other
 (c)		Amounts 
Reported on 
Balance Sheets
Current assets$66,777 $(3,346)$63,431 $50 $63,481 
Investments and other assets48,302 (1,394)46,908 — 46,908 
Total assets115,079 (4,740)110,339 50 110,389 
Current liabilities(6,084)3,346 (2,738)(1,635)(4,373)
Deferred credits and other(1,394)1,394 — — — 
Total liabilities(7,478)4,740 (2,738)(1,635)(4,373)
Total$107,601 $— $107,601 $(1,585)$106,016 
(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 $1,635 and cash margin provided to counterparties of $50.

As of December 31, 2020:
 (dollars in thousands) 		Gross
 Recognized
 Derivatives
 (a)		Amounts
Offset 
(b)		Net
 Recognized
 Derivatives		Other
 (c)		Amounts
 Reported on
 Balance Sheets
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 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 $1,285.
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, 2021:
 (dollars in thousands) 		Gross 
Recognized 
Derivatives
 (a)		Amounts 
Offset
(b)		Net
 Recognized
 Derivatives		Other
 (c)		Amounts 
Reported on 
Balance Sheets
Current assets$66,777 $(3,346)$63,431 $50 $63,481 
Investments and other assets48,302 (1,394)46,908 — 46,908 
Total assets115,079 (4,740)110,339 50 110,389 
Current liabilities(6,084)3,346 (2,738)(1,635)(4,373)
Deferred credits and other(1,394)1,394 — — — 
Total liabilities(7,478)4,740 (2,738)(1,635)(4,373)
Total$107,601 $— $107,601 $(1,585)$106,016 
(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 $1,635 and cash margin provided to counterparties of $50.

As of December 31, 2020:
 (dollars in thousands) 		Gross
 Recognized
 Derivatives
 (a)		Amounts
Offset 
(b)		Net
 Recognized
 Derivatives		Other
 (c)		Amounts
 Reported on
 Balance Sheets
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 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 $1,285.
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, 2021
Aggregate fair value of derivative instruments in a net liability position$7,478 
Cash collateral posted— 
Additional cash collateral in the event credit-risk related contingent features were fully triggered (a)2,658 
(a)This amount is after counterparty netting and includes those contracts which qualify for scope exceptions, which are excluded from the derivative details above.
v3.22.0.1
Other Income and Other Expense (Tables)
 12 Months Ended
Dec. 31, 2021
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 2021, 2020 and 2019 (dollars in thousands):
 
 202120202019
Other income:   
Interest income$6,726 $12,210 $10,377 
Investment gains (losses) — net— 2,358 — 
Debt return on Four Corners SCR deferral (Note 4)14,955 15,865 19,541 
Debt return on Ocotillo modernization project (Note 4)23,366 26,121 20,282 
Miscellaneous53 149 63 
Total other income$45,100 $56,703 $50,263 
Other expense:   
Non-operating costs$(13,008)$(12,400)$(10,663)
Investment gains (losses) — net(1,367)— (1,835)
Miscellaneous(11,021)(45,376)(a)(5,382)
Total other expense$(25,396)$(57,776)$(17,880)
(a)The 2020 miscellaneous amount includes donations 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 2021, 2020 and 2019 (dollars in thousands):
 
 202120202019
Other income:   
Interest income$4,692 $9,621 $6,998 
Debt return on Four Corners SCR deferral (Note 4)14,955 15,865 19,541 
Debt return on Ocotillo modernization project (Note 4)23,366 26,121 20,282 
Miscellaneous40 148 63 
Total other income$43,053 $51,755 $46,884 
Other expense:   
Non-operating costs$(10,080)$(10,659)$(9,612)
Miscellaneous(8,817)(43,035)(a)(3,378)
Total other expense$(18,897)$(53,694)$(12,990)
(a)The 2020 miscellaneous amount includes donations of approximately $10 million to the APS Foundation and approximately $25.2 million related to the CCT plan. See Note 4.
v3.22.0.1
Palo Verde Sale Leaseback Variable Interest Entities (Tables)
 12 Months Ended
Dec. 31, 2021
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, 2021December 31, 2020
Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation$94,166 $98,036 
Equity-Noncontrolling interests115,260 119,290 
v3.22.0.1
Investments in Nuclear Decommissioning Trusts and Other Special Use Funds (Tables)
 12 Months Ended
Dec. 31, 2021
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 trusts and other special use fund assets (dollars in thousands): 
December 31, 2021
 Fair ValueTotal
Unrealized
Gains		Total
Unrealized
Losses
Investment Type:Nuclear Decommissioning TrustsOther Special Use FundsTotal
Equity securities$640,312 $47,570 $687,882 $451,387 $— 
Available for sale-fixed income securities682,227 309,904 992,131 (a)24,283 (4,063)
Other(27,782)936 (26,846)(b)— — 
Total$1,294,757 $358,410 $1,653,167 $475,670 $(4,063)
(a)As of December 31, 2021, the amortized cost basis of these available-for-sale investments is $972 million.
(b)Represents net pending securities sales and purchases.

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.
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 (dollars in thousands):
 
 Year Ended December 31,
 Nuclear Decommissioning TrustsOther Special Use FundsTotal
2021
Realized gains$134,610 $49 $134,659 
Realized losses(8,431)(7)(8,438)
Proceeds from the sale of securities (a)1,457,305 263,661 1,720,966 
2020
Realized gains12,194 176 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 
(a)Proceeds are reinvested in the nuclear decommissioning trusts and other special use funds, excluding amounts reimbursed to the Company for active union employee medical claims from the active union employee medical account.
Fair value of fixed income securities, summarized by contractual maturities
The fair value of APS’s fixed income securities, summarized by contractual maturities, at December 31, 2021, is as follows (dollars in thousands):
 
 Nuclear Decommissioning TrustsCoal Reclamation Escrow AccountActive Union Employee Medical AccountTotal
Less than one year$31,070 $36,852 $40,870 $108,792 
1 year – 5 years195,975 41,931 158,235 396,141 
5 years – 10 years155,202 1,775 21,846 178,823 
Greater than 10 years299,980 8,395 — 308,375 
Total$682,227 $88,953 $220,951 $992,131 
v3.22.0.1
Changes in Accumulated Other Comprehensive Loss (Tables)
 12 Months Ended
Dec. 31, 2021
Comprehensive Income (Loss), Net of Tax, Attributable to Parent [Abstract]  
Schedule of changes in accumulated other comprehensive loss including reclassification adjustments, by component
The following table shows the changes in Pinnacle West’s consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component (dollars in thousands): 
 Pension and Other Postretirement Benefits Derivative InstrumentsTotal
Balance at December 31, 2019$(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)
OCI (loss) before reclassifications2,439 1,077 3,516 
Amounts reclassified from accumulated other comprehensive loss4,401 (a)18 (b)4,419 
Balance at December 31, 2021$(53,885)$(976)$(54,861)
(a)These amounts primarily represent amortization of actuarial loss and are included in the computation of net periodic pension cost. See Note 8.
(b)These amounts represent realized gains and losses and are included in the computation of fuel and purchased power costs and are subject to the PSA. See Note 16.
The following table shows the changes in APS’s consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component (dollars in thousands): 
 Pension and Other Postretirement Benefits Derivative InstrumentsTotal
Balance at December 31, 2019$(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)
OCI (loss) before reclassifications2,043 (18)2,025 
Amounts reclassified from accumulated other comprehensive loss3,995 (a)18 (b)4,013 
Balance at December 31, 2021$(34,880)$— $(34,880)
(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.
v3.22.0.1
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, 2021
USD ($)
$ / shares
shares
Dec. 31, 2020
USD ($)
Dec. 31, 2019
USD ($)
Dec. 31, 2021
USD ($)
$ / shares
shares
Approximate remaining average useful lives of utility property          
Depreciation   $ 575 $ 553 $ 522  
Depreciation rates (as a percent)   2.87% 2.84% 2.81%  
Allowance for Funds Used During Construction          
Composite rate used to calculate AFUDC (as a percent)   6.75% 6.72% 6.98%  
Income Taxes          
Percent likelihood largest tax benefit amount is realized (greater than)   50.00%      
Intangible Assets          
Amortization expense   $ 80 $ 70 $ 66  
Estimated amortization expense on existing intangible assets over the next five years          
Estimated amortization expense, next year   75     $ 75
Estimated amortization expense, in two years   63     63
Estimated amortization expense, in three years   44     44
Estimated amortization expense, in four years   33     33
Estimated amortization expense, in five years   $ 27     $ 27
Remaining amortization period for intangible assets   6 years      
Pinnacle West          
Preferred Stock          
Preferred stock, shares authorized (in shares) | shares   10,000,000     10,000,000
Preferred stock, shares outstanding (in shares) | shares   0     0
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, shares outstanding (in shares) | shares   0     0
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)         1.37%
Maximum          
Approximate remaining average useful lives of utility property          
Depreciation rates (as a percent)         12.15%
Investments          
Ownership percentage for classification as cost method investments by El Dorado   20.00%      
Steam generation          
Approximate remaining average useful lives of utility property          
Average useful life   12 years      
Nuclear plant          
Approximate remaining average useful lives of utility property          
Average useful life   25 years      
Other generation          
Approximate remaining average useful lives of utility property          
Average useful life   19 years      
Transmission          
Approximate remaining average useful lives of utility property          
Average useful life   37 years      
Distribution          
Approximate remaining average useful lives of utility property          
Average useful life   33 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%
v3.22.0.1
Summary of Significant Accounting Policies - Summary of Property, Plant and Equipment (Details) - USD ($)
$ in Thousands
Dec. 31, 2021
Dec. 31, 2020
Utility Plant and Depreciation [Line Items]    
Net $ 14,184,058 $ 13,727,575
Construction work in progress 1,329,478 937,384
Intangible assets, net of accumulated amortization 273,693 282,570
Nuclear fuel, net of accumulated amortization 106,039 113,645
Total property, plant and equipment 15,987,434 15,159,210
Electric Service    
Utility Plant and Depreciation [Line Items]    
Generation 9,480,572 9,199,012
Transmission 3,402,016 3,290,477
Distribution 7,520,016 7,107,007
General plant 1,286,057 1,241,389
Plant in service and held for future use 21,688,661 20,837,885
Accumulated depreciation and amortization (7,504,603) (7,110,310)
Net 14,184,058 13,727,575
Construction work in progress 1,329,478 937,384
Intangible assets, net of accumulated amortization 273,693 282,570
Nuclear fuel, net of accumulated amortization 106,039 113,645
Total property, plant and equipment 15,987,434 15,159,210
Electric Service | Variable Interest Entity    
Utility Plant and Depreciation [Line Items]    
Total property, plant and equipment $ 94,166 $ 98,036
v3.22.0.1
Summary of Significant Accounting Policies - Supplemental Cash Flow Information (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2021
Dec. 31, 2020
Dec. 31, 2019
Cash and Cash Equivalents [Line Items]      
Income taxes, net of refunds $ 229 $ (3,019) $ 12,535
Interest, net of amounts capitalized 227,584 216,951 218,664
Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]      
Accrued capital expenditures 167,733 113,502 141,297
Dividends declared but not paid 95,988 93,531 87,982
Arizona Public Service Company      
Cash and Cash Equivalents [Line Items]      
Income taxes, net of refunds 19,783 41,176 (15,042)
Interest, net of amounts capitalized 217,749 206,328 204,261
Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]      
Accrued capital expenditures 167,657 113,502 141,297
Dividends declared but not paid $ 96,000 $ 93,500 $ 88,000
v3.22.0.1
Revenue - Sources of Revenue (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2021
Dec. 31, 2020
Dec. 31, 2019
Disaggregation of Revenue [Line Items]      
Total Operating Revenues $ 3,803,835 $ 3,586,982 $ 3,471,209
Electric Service | Residential      
Disaggregation of Revenue [Line Items]      
Total Operating Revenues 1,913,324 1,929,178 1,761,122
Electric Service | Non-Residential      
Disaggregation of Revenue [Line Items]      
Total Operating Revenues 1,586,940 1,486,098 1,509,514
Electric Service | Wholesale Energy Sales      
Disaggregation of Revenue [Line Items]      
Total Operating Revenues 187,640 93,345 121,805
Transmission Services for Others      
Disaggregation of Revenue [Line Items]      
Total Operating Revenues 99,285 65,859 62,460
Other Sources      
Disaggregation of Revenue [Line Items]      
Total Operating Revenues $ 16,646 $ 12,502 $ 16,308
v3.22.0.1
Revenue - Additional Information (Details) - USD ($)
$ in Thousands
 10 Months Ended 12 Months Ended
Jan. 21, 2021
Dec. 31, 2020
Dec. 31, 2021
Dec. 31, 2020
Dec. 31, 2019
Disaggregation of Revenue [Line Items]          
Operating revenues     $ 3,803,835 $ 3,586,982 $ 3,471,209
Regulatory cost recovery revenue     44,000 54,000 56,000
Damage from Fire, Explosion or Other Hazard | Arizona Public Service Company          
Disaggregation of Revenue [Line Items]          
Customer support fund, payment period 8 months 8 months      
Electric Service | Residential          
Disaggregation of Revenue [Line Items]          
Operating revenues     1,913,324 1,929,178 1,761,122
Electric Service | Arizona Attorney General Settlement | Residential          
Disaggregation of Revenue [Line Items]          
Operating revenues       (24,000)  
Electric and Transmission Service          
Disaggregation of Revenue [Line Items]          
Operating revenues     $ 3,760,000 $ 3,533,000 $ 3,415,000
v3.22.0.1
Revenue - Allowance for Doubtful Accounts (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2021
Dec. 31, 2020
Dec. 31, 2019
Accounts Receivable, Allowance for Credit Loss [Roll Forward]      
Allowance for doubtful accounts, balance at beginning of period $ 19,782 $ 8,171 $ 4,069
Bad debt expense 22,251 20,633 11,819
Actual write-offs (16,679) (9,022) (7,717)
Allowance for doubtful accounts, balance at end of period $ 25,354 $ 19,782 $ 8,171
v3.22.0.1
Regulatory Matters - COVID-19 Pandemic (Details) - Arizona Public Service Company - USD ($)
 1 Months Ended 10 Months Ended
Jan. 21, 2021
Mar. 31, 2021
Feb. 28, 2021
Dec. 31, 2020
Dec. 31, 2020
Dec. 31, 2021
Jun. 30, 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      
Percentage increase under PSA effective for first billing cycle beginning April 2021   50.00% 50.00%          
Remaining percentage increase under PSA effective for first billing cycle beginning November 2021   50.00% 50.00%          
Damage from Fire, Explosion or Other Hazard                
Public Utilities, General Disclosures [Line Items]                
Past due balance threshold qualifying for payment extension $ 75              
Customer support fund, payment period 8 months       8 months      
v3.22.0.1
Regulatory Matters - Retail Rate Case Filing (Details)
Oct. 27, 2021
USD ($)
Aug. 02, 2021
USD ($)
Nov. 06, 2020
USD ($)
Oct. 31, 2019
USD ($)
$ / kWh
GW
Jun. 30, 2019
USD ($)
Aug. 13, 2018
USD ($)
Mar. 27, 2017
USD ($)
$ / kWh
Dec. 31, 2021
USD ($)
Dec. 31, 2020
USD ($)
Dec. 04, 2020
USD ($)
Oct. 02, 2020
USD ($)
Residential Utility Consumer Office                      
Public Utilities, General Disclosures [Line Items]                      
Revenue increase (decrease)                   $ (50,100,000) $ (20,800,000)
Average annual customer bill increase (decrease), percent                   (1.52%) (0.63%)
Recommended return on equity, percentage                     8.74%
Increment of fair value rate, percentage                     0.00%
ACC                      
Public Utilities, General Disclosures [Line Items]                      
Revenue increase (decrease)     $ 169,000,000             $ 59,800,000 $ 89,700,000
Average annual customer bill increase (decrease), percent     5.14%             1.82% 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%
ACC | Coal Community Transition Plan                      
Public Utilities, General Disclosures [Line Items]                      
Amount funded by shareholders     $ 25,000,000           $ 25,200,000    
Amount funded by customers, term     10 years                
Amount funded by customers     $ 100,000,000                
ACC | Coal Community Transition Plan | Navajo Nation, Economic Development Organization                      
Public Utilities, General Disclosures [Line Items]                      
Amount funded by shareholders     $ 1,250,000                
Amount funded by shareholders, term     5 years                
ACC | Coal Community Transition Plan | Navajo Nation, Electrification Projects                      
Public Utilities, General Disclosures [Line Items]                      
Amount funded by shareholders     $ 10,000,000           $ 10,000,000    
Amount funded by customers     10,000,000                
ACC | Coal Community Transition Plan | Navajo Nation, Transmission Revenue Sharing                      
Public Utilities, General Disclosures [Line Items]                      
Amount funded by shareholders     $ 2,500,000                
ACC | Coal Community Transition Plan | Navajo County Communities, Cholla Power Plant Closure                      
Public Utilities, General Disclosures [Line Items]                      
Amount funded by customers, term     5 years                
Amount funded by customers     $ 12,000,000                
ACC | Coal Community Transition Plan | Navajo Nation, Generation Station                      
Public Utilities, General Disclosures [Line Items]                      
Amount funded by customers     $ 3,700,000         $ 900,000      
ACC | Arizona Public Service Company                      
Public Utilities, General Disclosures [Line Items]                      
Proposed annual revenue increase       $ 184,000,000   $ (86,500,000)          
ACC | Arizona Public Service Company | Retail Rate Case Filing with Arizona Corporation Commission                      
Public Utilities, General Disclosures [Line Items]                      
Base rate decrease, elimination of tax expense adjustment mechanism       $ 115,000,000              
Approximate percentage of increase in average customer bill       5.60%              
Approximate percentage of increase in average residential customer bill       5.40%              
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              
Revenue increase (decrease)   $ (111,000,000)                  
Recommended return on equity, percentage 8.70% 9.16%                  
Increment of fair value rate, percentage   0.30%                  
Reduction on equity percentage   0.03%                  
Effective fair value percentage   4.95%                  
Settlement agreement, net retail base rate increase             $ 94,600,000        
Settlement agreement, non-fuel, non-depreciation, base rate increase             87,200,000        
Fuel-related base rate decrease             53,600,000        
Base rate increase, changes in depreciation schedules             $ 61,000,000        
Authorized return on common equity (as a percent)             10.00%        
Percentage of debt in capital structure             44.20%        
Percentage of common equity in capital structure             55.80%        
Resource comparison proxy for exported energy (in dollars per kWh) | $ / kWh             0.129        
ACC | Arizona Public Service Company | Retail Rate Case Filing with Arizona Corporation Commission | Coal Community Transition Plan | Navajo Nation, Economic Development Organization                      
Public Utilities, General Disclosures [Line Items]                      
Amount funded by customers, term   10 years                  
Amount funded by customers   $ 50,000,000                  
Disallowance of annual amortization percentage   15.00%                  
ACC | Arizona Public Service Company | Retail Rate Case Filing with Arizona Corporation Commission | Coal Community Transition Plan | Navajo County Communities, Cholla Power Plant Closure                      
Public Utilities, General Disclosures [Line Items]                      
Amount funded by shareholders $ 500,000 $ 5,000,000                  
Amount funded by shareholders, term 60 days 5 years                  
ACC | Arizona Public Service Company | Retail Rate Case Filing with Arizona Corporation Commission | Coal Community Transition Plan | Navajo Nation, Hopi Tribe                      
Public Utilities, General Disclosures [Line Items]                      
Amount funded by shareholders $ 1,000,000 $ 1,675,000                  
Amount funded by shareholders, term 60 days                    
ACC | Arizona Public Service Company | Retail Rate Case Filing with Arizona Corporation Commission | Coal Community Transition Plan | Navajo Nation                      
Public Utilities, General Disclosures [Line Items]                      
Amount funded by shareholders $ 10,000,000                    
Amount funded by shareholders, term 3 years                    
ACC | Arizona Public Service Company | Retail Rate Case Filing with Arizona Corporation Commission | Coal Community Transition Plan | Navajo Nation, Hopi Reservation                      
Public Utilities, General Disclosures [Line Items]                      
Amount funded by shareholders $ 1,250,000                    
ACC | Arizona Public Service Company | Retail Rate Case Filing with Arizona Corporation Commission | Coal Community Transition Plan | Navajo Nation Reservation                      
Public Utilities, General Disclosures [Line Items]                      
Revenue increase (decrease) 4,800,000                    
Amount funded by shareholders $ 1,250,000                    
ACC | Arizona Public Service Company | Retail Rate Case Filing with Arizona Corporation Commission | AZ Sun II Program                      
Public Utilities, General Disclosures [Line Items]                      
Minimum annual renewable energy standard and tariff             $ 10,000,000        
Maximum annual renewable energy standard and tariff             $ 15,000,000        
Minimum | ACC | Arizona Public Service Company                      
Public Utilities, General Disclosures [Line Items]                      
Regulatory impact, operating results       $ 69,000,000              
Minimum | ACC | Arizona Public Service Company | Retail Rate Case Filing with Arizona Corporation Commission                      
Public Utilities, General Disclosures [Line Items]                      
Environmental surcharge cap rate (in dollars per kWh) | $ / kWh             0.00016        
Maximum | ACC | Arizona Public Service Company | Retail Rate Case Filing with Arizona Corporation Commission                      
Public Utilities, General Disclosures [Line Items]                      
Environmental surcharge cap rate (in dollars per kWh) | $ / kWh             0.00050        
v3.22.0.1
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%
v3.22.0.1
Regulatory Matters - Cost Recovery Mechanisms (Details) - Arizona Public Service Company
 12 Months Ended
Feb. 15, 2022
USD ($)
Feb. 01, 2022
USD ($)
$ / kWh
Nov. 01, 2021
$ / kWh
Jul. 01, 2021
USD ($)
Jun. 07, 2021
USD ($)
Jun. 01, 2021
USD ($)
Apr. 01, 2021
$ / kWh
Feb. 15, 2021
USD ($)
Feb. 01, 2021
USD ($)
$ / kWh
Jun. 01, 2020
USD ($)
Feb. 14, 2020
USD ($)
Feb. 01, 2020
$ / kWh
Oct. 31, 2019
USD ($)
$ / kWh
Oct. 29, 2019
USD ($)
Jun. 01, 2019
USD ($)
Apr. 10, 2019
Feb. 15, 2019
USD ($)
Feb. 01, 2019
$ / kWh
Aug. 13, 2018
USD ($)
Feb. 01, 2018
$ / kWh
Nov. 20, 2017
USD ($)
Dec. 31, 2021
USD ($)
Dec. 31, 2020
USD ($)
Dec. 31, 2017
$ / kWh
Dec. 17, 2021
USD ($)
Dec. 09, 2021
USD ($)
Oct. 28, 2021
agreement
Jul. 01, 2020
USD ($)
Jun. 30, 2020
USD ($)
May 15, 2020
USD ($)
May 05, 2020
USD ($)
Dec. 31, 2019
USD ($)
Jul. 01, 2019
USD ($)
Mar. 15, 2019
agreement
Nov. 14, 2017
USD ($)
Sep. 01, 2017
USD ($)
Regulatory Matters [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              
ACC                                                                        
Regulatory Matters [Line Items]                                                                        
Program term                                             18 years                          
Requested rate decrease for tax act                         $ (184,000,000)           $ 86,500,000                                  
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                                            
Arizona Renewable Energy Standard and Tariff | ACC                                                                        
Regulatory Matters [Line Items]                                                                        
Plan term                                           5 years                            
Arizona Renewable Energy Standard and Tariff 2018 | ACC                                                                        
Regulatory Matters [Line Items]                                                                        
Amount of proposed budget       $ 93,100,000                                           $ 100,500,000   $ 84,700,000         $ 86,300,000      
Request to meet revenue requirements                                                       $ 4,500,000                
Authorized amount to be collected         $ 68,300,000                                                              
Arizona Renewable Energy Standard and Tariff 2018 | ACC | Minimum                                                                        
Regulatory Matters [Line Items]                                                                        
Authorized spending in capital costs       20,000,000                                                                
Arizona Renewable Energy Standard and Tariff 2018 | ACC | Maximum                                                                        
Regulatory Matters [Line Items]                                                                        
Authorized spending in capital costs       $ 30,000,000                                                                
Arizona Renewable Energy Standard and Tariff 2018 | ACC | Solar Communities                                                                        
Regulatory Matters [Line Items]                                                                        
Program term                                         3 years                              
Arizona Renewable Energy Standard and Tariff 2018 | ACC | Solar Communities | Minimum                                                                        
Regulatory Matters [Line Items]                                                                        
Required annual capital investment                                         $ 10,000,000                              
Arizona Renewable Energy Standard and Tariff 2018 | ACC | Solar Communities | Maximum                                                                        
Regulatory Matters [Line Items]                                                                        
Required annual capital investment                                         $ 15,000,000                              
Demand Side Management Adjustor Charge 2018 | ACC                                                                        
Regulatory Matters [Line Items]                                                                        
Amount of proposed budget                                                                     $ 52,600,000 $ 52,600,000
Demand Side Management Adjustor Charge 2019 | ACC                                                                        
Regulatory Matters [Line Items]                                                                        
Amount of proposed budget                                                               $ 34,100,000        
Demand Side Management Adjustor Charge 2020 | ACC                                                                        
Regulatory Matters [Line Items]                                                                        
Amount of proposed budget                                             $ 51,900,000             $ 51,900,000            
Demand Side Management Adjustor Charge 2021 | ACC                                                                        
Regulatory Matters [Line Items]                                                                        
Amount of proposed budget                                             $ 63,700,000                          
Demand Side Management Adjustor Charge 2022 | ACC                                                                        
Regulatory Matters [Line Items]                                                                        
Amount of proposed budget                                                 $ 78,400,000                      
Rate Matter, Increase (Decrease) in Proposed Budget                                                 $ 14,000,000                      
Power Supply Adjustor (PSA) | ACC                                                                        
Regulatory Matters [Line Items]                                                                        
PSA rate (in dollars per kWh) | $ / kWh     0.003544       0.001544   0.003544     (0.000456)           0.001658   0.004555                                
Forward component of PSA rate (in dollars per kWh) | $ / kWh     (0.004444)       (0.004444)   0.003434     (0.002086)           0.000536                                    
Historical component of PSA rate (in dollars per kWh) | $ / kWh     0.007988       0.005988   0.000110     0.001630           0.001122                                    
Fuel and purchased power costs above annual cap                 $ 215,900,000                                                      
Power Supply Adjustor (PSA) | ACC | Subsequent Event                                                                        
Regulatory Matters [Line Items]                                                                        
PSA rate (in dollars per kWh) | $ / kWh   0.007544                                                                    
Forward component of PSA rate (in dollars per kWh) | $ / kWh   (0.004842)                                                                    
Historical component of PSA rate (in dollars per kWh) | $ / kWh   0.012386                                                                    
Fuel and purchased power costs above annual cap   $ 365,000,000                                                                    
Power Supply Adjustor (PSA) | ACC | Cost Recovery Mechanisms                                                                        
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                 0.004     (0.002115)           (0.002897)                                    
Number of agreements | agreement                                                     3             2    
Power Supply Adjustor (PSA) | ACC | Cost Recovery Mechanisms | Subsequent Event                                                                        
Regulatory Matters [Line Items]                                                                        
PSA rate in prior years (in dollars per kWh) | $ / kWh   0.004                                                                    
Environmental Improvement Surcharge | FERC                                                                        
Regulatory Matters [Line Items]                                                                        
Rate matters, increase (decrease) in cost recovery                 $ 11,400,000                                                      
Rate matters, increase (decrease) in cost recovery, excess of annual amount                 $ 1,100,000                                                      
Transmission rates, transmission cost adjustor and other transmission matters | FERC                                                                        
Regulatory Matters [Line Items]                                                                        
Rate matters, increase (decrease) in cost recovery           $ 4,000,000       $ (6,100,000)         $ 25,800,000                                          
Rate matters, increase (decrease) in cost recovery, wholesale customer rates           (3,200,000)       4,800,000         21,100,000                                          
Rate matters, increase (decrease) in cost recovery, retail customer rates           7,200,000       (10,900,000)         4,700,000                                          
Increase (decrease) in retail revenue requirement           $ (28,400,000)       $ (7,400,000)         $ 4,900,000                                          
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               $ 38,500,000     $ 26,600,000           $ 36,200,000                                      
Increase (decrease) in amount of adjustment representing prorated sales losses               $ 11,800,000     $ (9,600,000)           $ (24,500,000)                                      
Lost Fixed Cost Recovery Mechanism | Subsequent Event                                                                        
Regulatory Matters [Line Items]                                                                        
Amount of adjustment approved representing prorated sales losses pending approval $ 59,100,000                                                                      
Increase (decrease) in amount of adjustment representing prorated sales losses $ 32,500,000                                                                      
Retail Rate Case Filing with Arizona Corporation Commission | Minimum                                                                        
Regulatory Matters [Line Items]                                                                        
Fixed costs recoverable per power lost (in dollars per kWh) | $ / kWh                         0.0256                                              
Retail Rate Case Filing with Arizona Corporation Commission | Maximum                                                                        
Regulatory Matters [Line Items]                                                                        
Fixed costs recoverable per power lost (in dollars per kWh) | $ / kWh                         0.0268                                              
v3.22.0.1
Regulatory Matters - Deferred Fuel and Purchased Power Regulatory Asset (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2021
Dec. 31, 2020
Dec. 31, 2019
Change in regulatory asset      
Deferred fuel and purchased power costs — current period $ 256,871 $ 93,651 $ 82,481
Amounts refunded/(charged) to customers (44,557) 12,047 (49,508)
Arizona Public Service Company      
Change in regulatory asset      
Deferred fuel and purchased power costs — current period 256,871 93,651 82,481
Amounts refunded/(charged) to customers (44,557) 12,047 (49,508)
ACC | Arizona Public Service Company | Power Supply Adjustor (PSA)      
Change in regulatory asset      
Beginning balance 175,835 70,137  
Deferred fuel and purchased power costs — current period 256,871 93,651  
Amounts refunded/(charged) to customers (44,558) 12,047  
Ending balance $ 388,148 $ 175,835 $ 70,137
v3.22.0.1
Regulatory Matters - Additional Information (Details)
 1 Months Ended 10 Months Ended 12 Months Ended
Dec. 17, 2021
USD ($)
Nov. 02, 2021
USD ($)
Oct. 27, 2021
USD ($)
Oct. 01, 2021
$ / kWh
Feb. 22, 2021
USD ($)
Jan. 21, 2021
USD ($)
Aug. 20, 2020
USD ($)
Customer
May 01, 2020
$ / kWh
Nov. 14, 2019
USD ($)
Customer
May 01, 2019
$ / kWh
Dec. 20, 2016
Sep. 30, 2018
USD ($)
Apr. 30, 2018
USD ($)
Dec. 31, 2020
Dec. 31, 2020
program
MW
Dec. 31, 2021
USD ($)
Aug. 02, 2021
Regulatory Matters [Line Items]                                  
Number of customers | Customer             3,800   13,000                
Inconvenience payment             $ 25   $ 25                
Arizona Public Service Company | Retired power plant costs                                  
Regulatory Matters [Line Items]                                  
Regulatory asset, net book value                               $ 41,800,000  
Arizona Public Service Company | Navajo plant                                  
Regulatory Matters [Line Items]                                  
Regulatory asset, net book value                               62,200,000  
Arizona Public Service Company | Navajo plant, coal reclamation regulatory asset                                  
Regulatory Matters [Line Items]                                  
Regulatory asset, net book value                               16,800,000  
Arizona Public Service Company | SCE | Four Corners Units 4 and 5                                  
Regulatory Matters [Line Items]                                  
Settlement agreement, ACC approved rate adjustment, annualized customer impact                       $ 58,500,000 $ 67,500,000        
Recommended rate adjustment, annualized customer impact, disallowance of investments   $ 194,000,000                              
Recommended rate adjustment, annualized customer impact, cost deferrals   $ 215,500,000                              
Potential charges                               $ 154,400,000  
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                        
Arizona Public Service Company | Damage from Fire, Explosion or Other Hazard                                  
Regulatory Matters [Line Items]                                  
Customer support fund, payment period           8 months               8 months      
Past due balance threshold qualifying for payment extension           $ 75                      
ACC | Arizona Public Service Company                                  
Regulatory Matters [Line Items]                                  
Number of public utility programs | program                             2    
Program term                             18 years    
Solar power capacity | MW                             80    
Net Metering | ACC | Arizona Public Service Company                                  
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            
Request second-year energy price for exported energy | $ / kWh       0.094       0.094   0.105              
Retail Rate Case Filing with Arizona Corporation Commission | ACC | Arizona Public Service Company | Navajo Nation, Hopi Tribe | Coal Community Transition Plan                                  
Regulatory Matters [Line Items]                                  
Recommended rate adjustment, annualized customer impact, cost deferrals     $ 215,500,000                            
Retail Rate Case Filing with Arizona Corporation Commission | ACC | Arizona Public Service Company | Navajo Nation, Economic Development Organization | Coal Community Transition Plan                                  
Regulatory Matters [Line Items]                                  
Disallowance of annual amortization percentage                                 15.00%
Retail Rate Case Filing with Arizona Corporation Commission | ACC | Arizona Public Service Company | Navajo Nation Reservation | Coal Community Transition Plan                                  
Regulatory Matters [Line Items]                                  
Recommended rate adjustment, annualized customer impact, disallowance of investments $ 215,000,000                                
v3.22.0.1
Regulatory Matters - Schedule of Regulatory Assets (Details) - USD ($)
$ in Thousands
Dec. 31, 2021
Dec. 31, 2020
Detail of regulatory assets    
Regulatory assets, current $ 518,524 $ 291,713
Regulatory assets, non-current 1,192,987 1,133,987
Pension    
Detail of regulatory assets    
Regulatory assets, current 0 0
Regulatory assets, non-current 509,751 469,953
Deferred fuel and purchased power    
Detail of regulatory assets    
Regulatory assets, current 388,148 175,835
Regulatory assets, non-current 0 0
Income taxes — AFUDC equity    
Detail of regulatory assets    
Regulatory assets, current 7,625 7,169
Regulatory assets, non-current 164,768 158,776
Ocotillo deferral    
Detail of regulatory assets    
Regulatory assets, current 9,507 0
Regulatory assets, non-current 138,143 95,723
Retired power plant costs    
Detail of regulatory assets    
Regulatory assets, current 15,160 28,181
Regulatory assets, non-current 99,681 114,214
SCR deferral    
Detail of regulatory assets    
Regulatory assets, current 8,147 0
Regulatory assets, non-current 97,624 81,307
Lost fixed cost recovery    
Detail of regulatory assets    
Regulatory assets, current 63,889 41,807
Regulatory assets, non-current 0 0
Deferred property taxes    
Detail of regulatory assets    
Regulatory assets, current 8,569 8,569
Regulatory assets, non-current 41,057 49,626
Deferred compensation    
Detail of regulatory assets    
Regulatory assets, current 0 0
Regulatory assets, non-current 33,997 36,195
Income taxes — investment tax credit basis adjustment    
Detail of regulatory assets    
Regulatory assets, current 1,129 1,113
Regulatory assets, non-current 23,639 24,291
Four Corners cost deferral    
Detail of regulatory assets    
Regulatory assets, current 8,077 8,077
Regulatory assets, non-current 15,998 24,075
Palo Verde VIE    
Detail of regulatory assets    
Regulatory assets, current 0 0
Regulatory assets, non-current 21,094 21,255
Coal reclamation    
Detail of regulatory assets    
Regulatory assets, current 2,978 1,068
Regulatory assets, non-current 13,862 16,999
Loss on reacquired debt    
Detail of regulatory assets    
Regulatory assets, current 1,648 1,689
Regulatory assets, non-current 9,372 10,877
Mead-Phoenix transmission line — contributions in aid of construction    
Detail of regulatory assets    
Regulatory assets, current 332 332
Regulatory assets, non-current 9,048 9,380
Tax expense adjustor mechanism    
Detail of regulatory assets    
Regulatory assets, current 656 6,226
Regulatory assets, non-current 5,845 0
TCA balancing account    
Detail of regulatory assets    
Regulatory assets, current 170 0
Regulatory assets, non-current 3,663 0
Tax expense of Medicare subsidy    
Detail of regulatory assets    
Regulatory assets, current 1,235 1,235
Regulatory assets, non-current 2,469 3,704
Demand side management    
Detail of regulatory assets    
Regulatory assets, current 919 0
Regulatory assets, non-current 0 7,268
PSA interest    
Detail of regulatory assets    
Regulatory assets, current 335 4,355
Regulatory assets, non-current 0 0
Deferred fuel and purchased power - mark-to-market    
Detail of regulatory assets    
Regulatory assets, current 0 3,341
Regulatory assets, non-current 0 9,244
Other    
Detail of regulatory assets    
Regulatory assets, current 0 2,716
Regulatory assets, non-current $ 2,976 $ 1,100
v3.22.0.1
Regulatory Matters - Schedule of Regulatory Liabilities (Details) - USD ($)
$ in Thousands
Dec. 31, 2021
Dec. 31, 2020
Detail of regulatory liabilities    
Regulatory liabilities, current $ 296,271 $ 229,088
Regulatory liabilities, non-current 2,499,213 2,450,169
Asset retirement obligations    
Detail of regulatory liabilities    
Regulatory liabilities, current 0 0
Regulatory liabilities, non-current 614,683 506,049
Other postretirement benefits    
Detail of regulatory liabilities    
Regulatory liabilities, current 37,789 37,705
Regulatory liabilities, non-current 337,027 349,588
Removal costs    
Detail of regulatory liabilities    
Regulatory liabilities, current 69,476 52,844
Regulatory liabilities, non-current 50,104 103,008
Deferred fuel and purchased power - mark-to-market    
Detail of regulatory liabilities    
Regulatory liabilities, current 60,693 0
Regulatory liabilities, non-current 46,908 0
Income taxes — change in rates    
Detail of regulatory liabilities    
Regulatory liabilities, current 2,876 2,839
Regulatory liabilities, non-current 64,802 66,553
Four Corners coal reclamation    
Detail of regulatory liabilities    
Regulatory liabilities, current 2,316 5,460
Regulatory liabilities, non-current 53,076 49,435
Spent nuclear fuel    
Detail of regulatory liabilities    
Regulatory liabilities, current 6,701 6,768
Regulatory liabilities, non-current 38,581 44,221
Income taxes — deferred investment tax credit    
Detail of regulatory liabilities    
Regulatory liabilities, current 2,264 2,231
Regulatory liabilities, non-current 47,337 48,648
Renewable energy program    
Detail of regulatory liabilities    
Regulatory liabilities, current 38,453 39,442
Regulatory liabilities, non-current 187 103
FERC transmission true up    
Detail of regulatory liabilities    
Regulatory liabilities, current 21,379 6,598
Regulatory liabilities, non-current 12,924 3,008
Property tax deferral    
Detail of regulatory liabilities    
Regulatory liabilities, current 4,671 0
Regulatory liabilities, non-current 15,521 13,856
Sundance maintenance    
Detail of regulatory liabilities    
Regulatory liabilities, current 0 2,989
Regulatory liabilities, non-current 13,797 11,508
Demand side management    
Detail of regulatory liabilities    
Regulatory liabilities, current 0 10,819
Regulatory liabilities, non-current 5,417 0
Tax expense adjustor mechanism    
Detail of regulatory liabilities    
Regulatory liabilities, current 0 7,089
Regulatory liabilities, non-current 4,835 0
Deferred gains on utility property    
Detail of regulatory liabilities    
Regulatory liabilities, current 1,301 2,423
Regulatory liabilities, non-current 551 1,544
TCA balancing account    
Detail of regulatory liabilities    
Regulatory liabilities, current 0 2,902
Regulatory liabilities, non-current 0 4,672
Active union medical trust    
Detail of regulatory liabilities    
Regulatory liabilities, current 0 0
Regulatory liabilities, non-current 0 6,057
Other    
Detail of regulatory liabilities    
Regulatory liabilities, current 210 409
Regulatory liabilities, non-current 41 189
ACC | Excess deferred income taxes - ACC - Tax Cuts and Jobs Act    
Detail of regulatory liabilities    
Regulatory liabilities, current 40,903 41,330
Regulatory liabilities, non-current 971,545 1,012,583
FERC | Excess deferred income taxes - ACC - Tax Cuts and Jobs Act    
Detail of regulatory liabilities    
Regulatory liabilities, current 7,239 7,240
Regulatory liabilities, non-current $ 221,877 $ 229,147
v3.22.0.1
Income Taxes - Additional Information (Details) - USD ($)
$ in Millions
 3 Months Ended 12 Months Ended
Mar. 31, 2020
Dec. 31, 2021
Dec. 31, 2020
Dec. 31, 2017
Income Taxes        
Reduction in net deferred income tax liabilities       $ 1,140
Income tax benefit   $ 31 $ 31  
Amortization period   28 years 6 months    
Income tax expense attributable to non controlling interests   $ 0    
Interest expense to be received on the underpayment of income taxes   1    
Increase (decrease) in deferred income taxes due to regulation adoption   42    
Arizona Public Service Company        
Income Taxes        
Increase (decrease) in deferred income taxes due to regulation adoption   9    
Federal        
Income Taxes        
Income tax benefit $ 14      
General business tax credit carryforwards   51    
State        
Income Taxes        
State credit carryforwards net of federal benefit   42    
Arizona net operating loss carryforwards net of federal benefit   6    
State | Arizona Public Service Company        
Income Taxes        
State credit carryforwards net of federal benefit   24    
Arizona net operating loss carryforwards net of federal benefit   $ 4    
v3.22.0.1
Income Taxes - Reconciliation of Unrecognized Tax Benefits (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2021
Dec. 31, 2020
Dec. 31, 2019
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 $ 45,655 $ 43,435 $ 40,731
Additions for tax positions of the current year 3,305 3,418 3,373
Additions for tax positions of prior years 1,449 1,431 1,843
Reductions for tax positions of prior years for:      
Changes in judgment (2,659) (1,965) (2,078)
Settlements with taxing authorities 0 0 0
Lapses of applicable statute of limitations (2,664) (664) (434)
Total unrecognized tax benefits, end of the year 45,086 45,655 43,435
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 45,655 43,435 40,731
Additions for tax positions of the current year 3,305 3,418 3,373
Additions for tax positions of prior years 1,449 1,431 1,843
Reductions for tax positions of prior years for:      
Changes in judgment (2,659) (1,965) (2,078)
Settlements with taxing authorities 0 0 0
Lapses of applicable statute of limitations (2,664) (664) (434)
Total unrecognized tax benefits, end of the year $ 45,086 $ 45,655 $ 43,435
v3.22.0.1
Income Taxes - Summary of Unrecognized Tax Benefits (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2021
Dec. 31, 2020
Dec. 31, 2019
Income Tax [Line Items]      
Tax positions, that if recognized, would decrease our effective tax rate $ 26,300 $ 25,714 $ 22,813
Unrecognized tax benefit interest expense/(benefit) recognized (535) 266 459
Unrecognized tax benefit interest accrued 1,320 1,855 1,589
Arizona Public Service Company      
Income Tax [Line Items]      
Tax positions, that if recognized, would decrease our effective tax rate 26,300 25,714 22,813
Unrecognized tax benefit interest expense/(benefit) recognized (535) 266 459
Unrecognized tax benefit interest accrued $ 1,320 $ 1,855 $ 1,589
v3.22.0.1
Income Taxes - Components of Income Tax Expense (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2021
Dec. 31, 2020
Dec. 31, 2019
Current:      
Federal $ (5,041) $ 11,869 $ (13,551)
State 2,458 1,932 3,195
Total current (2,583) 13,801 (10,356)
Deferred:      
Federal 95,327 53,398 (14,982)
State 17,342 10,974 9,565
Total deferred 112,669 64,372 (5,417)
Income tax expense/(benefit) 110,086 78,173 (15,773)
Arizona Public Service Company      
Current:      
Federal 1,514 57,299 (54,697)
State (11) 99 695
Total current 1,503 57,398 (54,002)
Deferred:      
Federal 101,175 15,122 29,321
State 22,875 16,244 15,109
Total deferred 124,050 31,366 44,430
Income tax expense/(benefit) $ 125,553 $ 88,764 $ (9,572)
v3.22.0.1
Income Taxes - Effective Tax Rate Reconciliation (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2021
Dec. 31, 2020
Dec. 31, 2019
Income Tax Reconciliation Increases Reductions in Tax Expense [Abstract]      
Federal income tax expense at statutory rate $ 156,666 $ 136,127 $ 113,828
State income tax net of federal income tax benefit 22,656 19,146 18,599
State income tax credits net of federal income tax benefit (7,015) (8,951) (8,519)
Net operating loss carryback tax benefit (5,915) 0 0
Excess deferred income taxes — Tax Cuts and Jobs Act (36,558) (50,543) (124,082)
Allowance for equity funds used during construction (see Note 1) (4,180) (2,747) (2,476)
Palo Verde VIE noncontrolling interest (see Note 18) (3,617) (4,094) (4,094)
Investment tax credit amortization (7,620) (7,510) (6,851)
Other (4,331) (3,255) (2,178)
Income tax expense/(benefit) 110,086 78,173 (15,773)
Arizona Public Service Company      
Income Tax Reconciliation Increases Reductions in Tax Expense [Abstract]      
Federal income tax expense at statutory rate 162,762 142,020 120,790
State income tax net of federal income tax benefit 23,339 20,124 19,267
State income tax credits net of federal income tax benefit (5,277) (7,213) (6,781)
Net operating loss carryback tax benefit 0 0 0
Excess deferred income taxes — Tax Cuts and Jobs Act (36,558) (50,543) (124,082)
Allowance for equity funds used during construction (see Note 1) (4,180) (2,747) (2,476)
Palo Verde VIE noncontrolling interest (see Note 18) (3,617) (4,094) (4,094)
Investment tax credit amortization (7,620) (7,510) (6,851)
Other (3,296) (1,273) (5,345)
Income tax expense/(benefit) $ 125,553 $ 88,764 $ (9,572)
v3.22.0.1
Income Taxes - Components of Deferred Income Tax Liability (Details) - USD ($)
$ in Thousands
Dec. 31, 2021
Dec. 31, 2020
DEFERRED TAX ASSETS    
Risk management activities $ 677 $ 4,287
Regulatory liabilities:    
Excess deferred income taxes — Tax Cuts and Jobs Act 306,915 319,091
Asset retirement obligation and removal costs 174,952 157,470
Unamortized investment tax credits 49,601 50,879
Other postretirement liabilities 92,654 95,778
Other 65,815 43,551
Operating lease liabilities 204,890 107,853
Pension liabilities 42,136 45,853
Coal reclamation liabilities 43,165 42,065
Renewable energy incentives 22,646 25,355
Credit and loss carryforwards 57,077 26,460
Other 74,184 78,113
Total deferred tax assets 1,134,712 996,755
DEFERRED TAX LIABILITIES    
Plant-related (2,570,613) (2,489,899)
Risk management activities (27,276) (1,174)
Pension and other postretirement assets (133,624) (123,462)
Other special use funds (64,610) (42,927)
Operating lease right-of-use assets (204,890) (107,853)
Regulatory assets:    
Allowance for equity funds used during construction (42,616) (41,038)
Deferred fuel and purchased power (96,033) (47,673)
Pension benefits (126,010) (116,219)
Retired power plant costs (28,389) (35,214)
Other (123,902) (106,227)
Other (28,611) (20,472)
Total deferred tax liabilities (3,446,574) (3,132,158)
Deferred income taxes — net (2,311,862) (2,135,403)
Arizona Public Service Company    
DEFERRED TAX ASSETS    
Risk management activities 677 4,287
Regulatory liabilities:    
Excess deferred income taxes — Tax Cuts and Jobs Act 306,915 319,091
Asset retirement obligation and removal costs 174,952 157,470
Unamortized investment tax credits 49,601 50,879
Other postretirement liabilities 92,654 95,778
Other 65,815 43,551
Operating lease liabilities 204,378 107,414
Pension liabilities 37,814 40,168
Coal reclamation liabilities 43,165 42,065
Renewable energy incentives 22,646 25,355
Credit and loss carryforwards 18,902 8,034
Other 74,184 78,113
Total deferred tax assets 1,091,703 972,205
DEFERRED TAX LIABILITIES    
Plant-related (2,570,613) (2,489,899)
Risk management activities (27,276) (1,174)
Pension and other postretirement assets (132,769) (122,580)
Other special use funds (64,610) (42,927)
Operating lease right-of-use assets (204,378) (107,414)
Regulatory assets:    
Allowance for equity funds used during construction (42,616) (41,038)
Deferred fuel and purchased power (96,033) (47,673)
Pension benefits (126,010) (116,219)
Retired power plant costs (28,389) (35,214)
Other (123,902) (106,227)
Other (6,808) (5,513)
Total deferred tax liabilities (3,423,404) (3,115,878)
Deferred income taxes — net $ (2,331,701) $ (2,143,673)
v3.22.0.1
Lines of Credit and Short-Term Borrowings - Schedule of Credit Facilities (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2021
Dec. 31, 2020
Pinnacle West    
Lines of Credit and Short-Term Borrowings    
Commitment fees (as a percent) 0.175% 0.125%
Arizona Public Service Company    
Lines of Credit and Short-Term Borrowings    
Commitment fees (as a percent) 0.125% 0.10%
Revolving credit facility    
Lines of Credit and Short-Term Borrowings    
Commitments under Credit Facilities $ 1,200,000 $ 1,231,000
Outstanding Commercial Paper, Term Loan and Revolving Credit Facility Borrowings (292,000) (169,000)
Amount of Credit Facilities Available 908,000 1,062,000
Revolving credit facility | Pinnacle West    
Lines of Credit and Short-Term Borrowings    
Commitments under Credit Facilities 200,000 231,000
Outstanding Commercial Paper, Term Loan and Revolving Credit Facility Borrowings (13,300) (169,000)
Amount of Credit Facilities Available 186,700 62,000
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 (278,700) 0
Amount of Credit Facilities Available $ 721,300 $ 1,000,000
v3.22.0.1
Lines of Credit and Short-Term Borrowings - Additional Information (Details)
$ in Thousands
 12 Months Ended
Dec. 31, 2021
USD ($)
May 28, 2021
USD ($)
May 27, 2021
USD ($)
Facility
Dec. 31, 2020
USD ($)
Dec. 23, 2020
USD ($)
Dec. 17, 2020
USD ($)
May 05, 2020
USD ($)
May 04, 2020
USD ($)
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    
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
Notes issued         $ 150,000   $ 31,000  
Revolving credit facility                
Lines of Credit and Short-Term Borrowings                
Long-term line of credit $ 292,000     $ 169,000        
Amount committed 1,200,000     1,231,000        
Revolving credit facility | Pinnacle West                
Lines of Credit and Short-Term Borrowings                
Long-term line of credit 13,300     169,000        
Amount committed 200,000     231,000        
Revolving credit facility | Pinnacle West | Revolving credit facility maturing May 2026                
Lines of Credit and Short-Term Borrowings                
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders   $ 300,000            
Long-term line of credit 0              
Amount committed   200,000            
Revolving credit facility | Pinnacle West | Revolving credit facility maturing July 2023                
Lines of Credit and Short-Term Borrowings                
Amount committed     $ 200,000          
Revolving credit facility | Arizona Public Service Company                
Lines of Credit and Short-Term Borrowings                
Long-term line of credit 278,700     0        
Amount committed 1,000,000     $ 1,000,000        
Revolving credit facility | Arizona Public Service Company | Revolving credit facility maturing May 2026                
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            
Long-term line of credit 0              
Amount committed   1,000,000            
Revolving credit facility | Arizona Public Service Company | Revolving credit facility maturing May 2026, facility one                
Lines of Credit and Short-Term Borrowings                
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders   700,000            
Amount committed   500,000            
Revolving credit facility | Arizona Public Service Company | Revolving credit facility maturing May 2026, facility two                
Lines of Credit and Short-Term Borrowings                
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders   700,000            
Amount committed   $ 500,000            
Revolving credit facility | Arizona Public Service Company | Revolving credit facility maturing in 2022 and 2023                
Lines of Credit and Short-Term Borrowings                
Number of credit facilities | Facility     2          
Revolving credit facility | Arizona Public Service Company | Revolving credit facility maturing July 2023                
Lines of Credit and Short-Term Borrowings                
Amount committed     $ 500,000          
Revolving credit facility | Arizona Public Service Company | Revolving credit facility maturing June 2022                
Lines of Credit and Short-Term Borrowings                
Amount committed     $ 500,000          
Letter of credit | Pinnacle West | Revolving credit facility maturing May 2026                
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 5,000              
Letter of credit | Arizona Public Service Company | Revolving credit facility maturing May 2026                
Lines of Credit and Short-Term Borrowings                
Outstanding letters of credit 0              
Commercial paper | Pinnacle West | Revolving credit facility maturing May 2026                
Lines of Credit and Short-Term Borrowings                
Commercial paper 13,000              
Commercial paper | Arizona Public Service Company | Revolving credit facility maturing May 2026                
Lines of Credit and Short-Term Borrowings                
Commercial paper 279,000              
Maximum commercial paper support available under credit facility $ 750,000              
LIBOR | Term loan | Pinnacle West                
Lines of Credit and Short-Term Borrowings                
Debt instrument, basis spread on variable rate 1.40%              
v3.22.0.1
Long-Term Debt and Liquidity Matters - Components of Long-Term Debt (Details) - USD ($)
$ in Thousands
Dec. 31, 2021
Dec. 31, 2020
Long-Term Debt and Liquidity Matters [Line Items]    
Total long-term debt $ 7,063,735 $ 6,314,266
TOTAL LONG-TERM DEBT LESS CURRENT MATURITIES 6,913,735 6,314,266
Pinnacle West    
Long-Term Debt and Liquidity Matters [Line Items]    
Gross long-term debt 7,115,975  
Unamortized discount (34) (44)
Unamortized debt issue costs (2,924) (3,635)
Total long-term debt 797,042 496,321
Less current maturities 150,000 0
Total long-term debt less current maturities 647,042 496,321
TOTAL LONG-TERM DEBT LESS CURRENT MATURITIES 647,139 496,321
Arizona Public Service Company    
Long-Term Debt and Liquidity Matters [Line Items]    
Gross long-term debt 6,315,975  
Unamortized discount (14,995) (15,900)
Unamortized premium 13,575 14,781
Unamortized debt issue costs (47,862) (46,911)
Total long-term debt 6,266,693 5,817,945
Less current maturities 0 0
Total long-term debt less current maturities 6,266,693 5,817,945
TOTAL LONG-TERM DEBT LESS CURRENT MATURITIES 6,266,693 5,817,945
Pollution control bonds - Variable | Arizona Public Service Company    
Long-Term Debt and Liquidity Matters [Line Items]    
Gross long-term debt $ 35,975 $ 35,975
Weighted-average interest rate (as a percent) 0.22% 0.18%
Total pollution control bonds | Arizona Public Service Company    
Long-Term Debt and Liquidity Matters [Line Items]    
Gross long-term debt $ 35,975 $ 35,975
Senior unsecured notes | Pinnacle West    
Long-Term Debt and Liquidity Matters [Line Items]    
Gross long-term debt $ 500,000 500,000
Interest rate (as a percent) 1.30%  
Senior unsecured notes | Arizona Public Service Company    
Long-Term Debt and Liquidity Matters [Line Items]    
Gross long-term debt $ 6,280,000 5,830,000
Senior unsecured notes | Arizona Public Service Company | Minimum    
Long-Term Debt and Liquidity Matters [Line Items]    
Interest rate (as a percent) 2.20%  
Senior unsecured notes | Arizona Public Service Company | Maximum    
Long-Term Debt and Liquidity Matters [Line Items]    
Interest rate (as a percent) 6.88%  
Term loan | Pinnacle West    
Long-Term Debt and Liquidity Matters [Line Items]    
Term loans $ 300,000 $ 0
Term loan | Arizona Public Service Company    
Long-Term Debt and Liquidity Matters [Line Items]    
Weighted-average interest rate (as a percent) 0.81%  
v3.22.0.1
Long-Term Debt and Liquidity Matters - Additional Information (Details) - USD ($)
$ in Thousands
 12 Months Ended
Feb. 11, 2022
Jan. 06, 2022
Dec. 21, 2021
Dec. 31, 2021
Dec. 31, 2020
Dec. 31, 2019
Dec. 23, 2020
Dec. 17, 2020
Dec. 16, 2020
May 05, 2020
Long-Term Debt and Liquidity Matters [Line Items]                    
Proceeds from issuance of debt       $ 746,999 $ 1,596,672 $ 1,092,188        
Maximum                    
Debt Provisions                    
Ratio of consolidated debt to consolidated capitalization (as a percent)       65.00%            
Arizona Public Service Company                    
Long-Term Debt and Liquidity Matters [Line Items]                    
Proceeds from issuance of debt       $ 446,999 1,099,722 1,092,188        
Equity infusion from Pinnacle West       $ 150,000 150,000 150,000        
Debt Provisions                    
Actual ratio of consolidated debt to total consolidated capitalization required to be maintained as per the debt covenant (as a percent)       50.00%            
Arizona Public Service Company | ACC                    
Debt Provisions                    
Long term debt authorization               $ 7,500,000 $ 5,900,000  
Subsequent Event | Arizona Public Service Company                    
Long-Term Debt and Liquidity Matters [Line Items]                    
Equity infusion from Pinnacle West   $ 150,000                
Unsecured Senior Notes Maturing 2031 | Senior Notes | Arizona Public Service Company                    
Long-Term Debt and Liquidity Matters [Line Items]                    
Debt issued     $ 450,000              
Interest rate (as a percent)     2.20%              
Term Loan | Non-Recourse Construction Term Loan Facility | Subsequent Event | Bright Canyon Energy Corporation                    
Long-Term Debt and Liquidity Matters [Line Items]                    
Debt issued $ 42,000                  
Bridge Loan | Equity Bridge Loan Facility | Subsequent Event | Bright Canyon Energy Corporation                    
Long-Term Debt and Liquidity Matters [Line Items]                    
Debt issued 33,000                  
Proceeds from issuance of debt 12,000                  
Letter of Credit | Subsequent Event | Bright Canyon Energy Corporation                    
Long-Term Debt and Liquidity Matters [Line Items]                    
Debt issued $ 5,000                  
Pinnacle West                    
Long-Term Debt and Liquidity Matters [Line Items]                    
Proceeds from issuance of debt       $ 300,000 $ 496,950 $ 0        
Debt Provisions                    
Actual ratio of consolidated debt to total consolidated capitalization required to be maintained as per the debt covenant (as a percent)       56.00%            
Pinnacle West | Term Loan                    
Long-Term Debt and Liquidity Matters [Line Items]                    
Debt issued             $ 150,000     $ 31,000
Pinnacle West | Term Loan | Term Loan Maturing 2021                    
Long-Term Debt and Liquidity Matters [Line Items]                    
Debt issued     $ 450,000              
Proceeds from issuance of debt     $ 150,000              
Pinnacle West | Term Loan | Term Loan Maturing 2021 | Subsequent Event                    
Long-Term Debt and Liquidity Matters [Line Items]                    
Proceeds from issuance of debt   $ 300,000                
v3.22.0.1
Long-Term Debt and Liquidity Matters - Future Principal Payments (Details)
$ in Thousands
Dec. 31, 2021
USD ($)
Arizona Public Service Company  
Principal payments due on long-term debt  
2022 $ 0
2023 0
2024 250,000
2025 300,000
2026 250,000
Thereafter 5,515,975
Total 6,315,975
Pinnacle West  
Principal payments due on long-term debt  
2022 150,000
2023 0
2024 400,000
2025 800,000
2026 250,000
Thereafter 5,515,975
Total $ 7,115,975
v3.22.0.1
Long-Term Debt and Liquidity Matters - Fair Value of Long-Term Debt (Details) - USD ($)
$ in Thousands
Dec. 31, 2021
Dec. 31, 2020
Estimated fair value of long-term debt, including current maturities    
Carrying Amount $ 7,063,735 $ 6,314,266
Fair Value 7,726,354 7,612,841
Arizona Public Service Company    
Estimated fair value of long-term debt, including current maturities    
Carrying Amount 6,266,693 5,817,945
Fair Value 6,933,619 7,103,791
Pinnacle West    
Estimated fair value of long-term debt, including current maturities    
Carrying Amount 797,042 496,321
Fair Value $ 792,735 $ 509,050
v3.22.0.1
Retirement Plans and Other Postretirement Benefits - Additional Information (Details) - USD ($)
 12 Months Ended
Jan. 04, 2021
Dec. 31, 2021
Dec. 31, 2020
Dec. 31, 2019
Defined Benefit Plan Disclosure [Line Items]        
Initial pre-65 ultimate health care cost trend rate (as a percent)   4.75% 4.75% 4.75%
Initial post-65 healthcare cost trend rate (as a percent)   2.00% 2.00%  
Funded percentage (more than)   100.00%    
Partnership funding commitments, contribution amount (up to)   $ 50,000,000    
Partnership funding commitments, funded amount   38,000,000    
Pension Benefits        
Defined Benefit Plan Disclosure [Line Items]        
Transfer to active union medical account $ (106,000,000) $ 0 $ 0  
Expected long-term return on plan assets for next fiscal year (as a percent)   5.00%    
Contributions        
Employer contributions   $ 100,000,000 100,000,000 $ 150,000,000
Minimum contributions under MAP-21        
Minimum contributions under MAP-21   0    
Other Benefits        
Defined Benefit Plan Disclosure [Line Items]        
Transfer to active union medical account 106,000,000 $ 105,852,000 0  
Expected long-term return on plan assets for next fiscal year (as a percent)   5.50%    
Contributions        
Employer contributions   $ 0 0  
Minimum contributions under MAP-21        
Retiree medical cost reimbursement   24,000,000 26,000,000 30,000,000
Pinnacle West        
Minimum contributions under MAP-21        
Expenses recorded for the defined contribution savings plan   $ 12,000,000 $ 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%    
Arizona Public Service Company | Other Benefits        
Defined Benefit Plan Disclosure [Line Items]        
Transfer to active union medical account $ 106,000,000      
v3.22.0.1
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, 2021
Dec. 31, 2020
Dec. 31, 2019
Net periodic benefit costs and the portion of these costs charged to expense      
Portion of cost/(benefit) charged to expense $ (112,541) $ (56,341) $ (22,989)
Pension Benefits      
Net periodic benefit costs and the portion of these costs charged to expense      
Service cost-benefits earned during the period 61,236 56,233 49,902
Interest cost on benefit obligation 98,566 118,567 136,843
Expected return on plan assets (202,628) (187,443) (171,884)
Prior service credit 0 0 0
Net actuarial (gain)/loss 15,948 34,612 42,584
Net periodic benefit cost/(benefit) (26,878) 21,969 57,445
Portion of cost/(benefit) charged to expense (32,743) 3,386 30,312
Other Benefits      
Net periodic benefit costs and the portion of these costs charged to expense      
Service cost-benefits earned during the period 17,796 22,236 18,369
Interest cost on benefit obligation 16,513 25,857 29,894
Expected return on plan assets (41,444) (40,077) (38,412)
Prior service credit (37,705) (37,575) (37,821)
Net actuarial (gain)/loss (10,093) 0 0
Net periodic benefit cost/(benefit) (54,933) (29,559) (27,970)
Portion of cost/(benefit) charged to expense $ (38,657) $ (20,966) $ (19,859)
v3.22.0.1
Retirement Plans and Other Postretirement Benefits - Changes Benefit Obligations and Funded Status (Details) - USD ($)
$ in Thousands
 12 Months Ended
Jan. 04, 2021
Dec. 31, 2021
Dec. 31, 2020
Dec. 31, 2019
Pension Benefits        
Change in Benefit Obligation        
Benefit obligation at the beginning of the period   $ 3,902,867 $ 3,613,114  
Service cost   61,236 56,233 $ 49,902
Interest cost   98,566 118,567 136,843
Benefit payments   (207,928) (191,704)  
Actuarial (gain) loss   (137,917) 306,657  
Benefit obligation at the end of the period   3,716,824 3,902,867 3,613,114
Change in Plan Assets        
Balance at the beginning of the period   3,886,544 3,318,351  
Actual return on plan assets   18,169 642,373  
Employer contributions   100,000 100,000 150,000
Benefit payments   (192,672) (174,180)  
Transfer to active union medical account $ 106,000 0 0  
Balance at the end of the period   3,812,041 3,886,544 3,318,351
Funded Status at the end of the period   95,217 (16,323)  
Other Benefits        
Change in Benefit Obligation        
Benefit obligation at the beginning of the period   624,034 746,924  
Service cost   17,796 22,236 18,369
Interest cost   16,513 25,857 29,894
Benefit payments   (31,280) (31,511)  
Actuarial (gain) loss   (35,222) (139,472)  
Benefit obligation at the end of the period   591,841 624,034 746,924
Change in Plan Assets        
Balance at the beginning of the period   961,165 837,494  
Actual return on plan assets   41,432 150,076  
Employer contributions   0 0  
Benefit payments   (24,310) (26,405)  
Transfer to active union medical account $ (106,000) (105,852) 0  
Balance at the end of the period   872,435 961,165 $ 837,494
Funded Status at the end of the period   $ 280,594 $ 337,131  
v3.22.0.1
Retirement Plans and Other Postretirement Benefits - Projected Benefit Obligation for Pension Plans (Details) - Pension Benefits - USD ($)
$ in Thousands
Dec. 31, 2021
Dec. 31, 2020
Projected benefit obligation and the accumulated benefit obligation for pension plans with an accumulated obligation in excess of plan assets    
Accumulated benefit obligation $ 161,086 $ 171,672
Fair value of plan assets 0 0
Projected benefit obligation 169,912 182,184
Fair value of plan assets $ 0 $ 0
v3.22.0.1
Retirement Plans and Other Postretirement Benefits - Amounts Recognized on the Consolidated Balance Sheets (Details) - USD ($)
$ in Thousands
Dec. 31, 2021
Dec. 31, 2020
Amounts recognized on the Consolidated Balance Sheets    
Noncurrent asset $ 545,723 $ 502,992
Pension Benefits    
Amounts recognized on the Consolidated Balance Sheets    
Noncurrent asset 265,129 165,861
Current liability (17,047) (15,700)
Noncurrent liability (152,865) (166,484)
Net amount recognized (funded status) 95,217 (16,323)
Other Benefits    
Amounts recognized on the Consolidated Balance Sheets    
Noncurrent asset 280,594 337,131
Current liability 0 0
Noncurrent liability 0 0
Net amount recognized (funded status) $ 280,594 $ 337,131
v3.22.0.1
Retirement Plans and Other Postretirement Benefits - Impact to Accumulated Other Comprehensive Loss (Details) - USD ($)
$ in Thousands
Dec. 31, 2021
Dec. 31, 2020
Pension Benefits    
Details related to accumulated other comprehensive loss    
Net actuarial loss (gain) $ 582,895 $ 552,301
Prior service credit 0 0
APS’s portion recorded as a regulatory (asset) liability (509,751) (469,953)
Income tax expense (benefit) (18,081) (20,364)
Accumulated other comprehensive loss (gain) 55,063 61,984
Other Benefits    
Details related to accumulated other comprehensive loss    
Net actuarial loss (gain) (262,352) (237,233)
Prior service credit (114,632) (152,337)
APS’s portion recorded as a regulatory (asset) liability 374,816 387,293
Income tax expense (benefit) 990 1,018
Accumulated other comprehensive loss (gain) $ (1,178) $ (1,259)
v3.22.0.1
Retirement Plans and Other Postretirement Benefits - Weighted-Average Assumptions for Pensions and Other Benefits (Details)
 12 Months Ended
Dec. 31, 2021
Dec. 31, 2020
Dec. 31, 2019
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) 6.00% 6.50%  
Initial pre-65 ultimate health care cost trend rate (as a percent) 4.75% 4.75% 4.75%
Number of years to ultimate trend rate (pre-65 participants) 4 years 5 years  
Initial post-65 healthcare cost trend rate (as a percent) 2.00% 2.00%  
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) 6.50% 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) 4 years 5 years 7 years
Initial post-65 health care cost trend rate (as a percent) 2.00% 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) 2.92% 2.53%  
Weighted-average assumptions used to determine net periodic benefit costs      
Discount rate (as a percent) 2.53% 3.30% 4.34%
Rate of compensation increase (as a percent) 4.00% 4.00% 4.00%
Expected long-term return on plan assets (as a percent) 5.30% 5.75% 6.25%
Other Benefits      
Weighted-average assumptions used to determine benefit obligations      
Discount rate (as a percent) 2.98% 2.63%  
Weighted-average assumptions used to determine net periodic benefit costs      
Discount rate (as a percent) 2.63% 3.42% 4.39%
Expected long-term return on plan assets (as a percent) 4.90% 4.85% 5.40%
v3.22.0.1
Retirement Plans and Other Postretirement Benefits - Asset Allocation (Details)
Dec. 31, 2021
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 80.00%
Actual Allocation 79.00%
Pension Benefits | Return-generating assets  
Defined Benefit Plan Disclosure [Line Items]  
Target Allocation 20.00%
Actual Allocation 21.00%
Target Allocation 20.00%
Pension Benefits | Equities in US and other developed markets  
Defined Benefit Plan Disclosure [Line Items]  
Target Allocation 12.00%
Pension Benefits | Equities in emerging markets  
Defined Benefit Plan Disclosure [Line Items]  
Target Allocation 4.00%
Pension Benefits | Alternative investments  
Defined Benefit Plan Disclosure [Line Items]  
Target Allocation 4.00%
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 63.00%
Other Benefits | Return-generating assets  
Defined Benefit Plan Disclosure [Line Items]  
Actual Allocation 37.00%
v3.22.0.1
Retirement Plans and Other Postretirement Benefits - Fair Value of Pinnacle West's Pension Plan (Details) - USD ($)
$ in Thousands
Dec. 31, 2021
Dec. 31, 2020
Dec. 31, 2019
Pension Benefits      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Other $ 530,171 $ 691,233  
Fair value of plan assets 3,812,041 3,886,544 $ 3,318,351
Pension Benefits | 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 1,350,751 1,398,305  
Pension Benefits | 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 1,931,119 1,797,006  
Other Benefits      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Other 126,552 118,440  
Fair value of plan assets 872,435 961,165 $ 837,494
Other Benefits | 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 491,981 612,921  
Other Benefits | 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 253,902 229,804  
Cash and cash equivalents | Pension Benefits      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Other 0 0  
Fair value of plan assets 821 9,911  
Cash and cash equivalents | Pension Benefits | 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 821 9,911  
Cash and cash equivalents | Pension Benefits | 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  
Cash and cash equivalents | Other Benefits      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Other 0 0  
Fair value of plan assets 121 1,909  
Cash and cash equivalents | Other Benefits | 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 121 1,909  
Cash and cash equivalents | Other Benefits | 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  
Corporate | Pension Benefits      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Other 0 0  
Fair value of plan assets 1,765,623 1,684,782  
Corporate | Pension Benefits | 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 0 0  
Corporate | Pension Benefits | 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 1,765,623 1,684,782  
Corporate | Other Benefits      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Other 0 0  
Fair value of plan assets 244,572 221,488  
Corporate | Other Benefits | 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 0 0  
Corporate | Other Benefits | 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 244,572 221,488  
U.S. Treasury | Pension Benefits      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Other 0 0  
Fair value of plan assets 1,008,211 794,571  
U.S. Treasury | Pension Benefits | 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 1,008,211 794,571  
U.S. Treasury | Pension Benefits | 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  
U.S. Treasury | Other Benefits      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Other 0 0  
Fair value of plan assets 287,057 258,102  
U.S. Treasury | Other Benefits | 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 287,057 258,102  
U.S. Treasury | Other Benefits | 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  
Other fixed income | Pension Benefits      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Other 0 0  
Fair value of plan assets 165,496 112,224  
Other fixed income | Pension Benefits | 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 0 0  
Other fixed income | Pension Benefits | 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 165,496 112,224  
Other fixed income | Other Benefits      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Other 0 0  
Fair value of plan assets 9,330 8,316  
Other fixed income | Other Benefits | 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 0 0  
Other fixed income | Other Benefits | 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 9,330 8,316  
Common stock equities | Pension Benefits      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Other 0 0  
Fair value of plan assets 209,063 331,058  
Common stock equities | Pension Benefits | 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 209,063 331,058  
Common stock equities | Pension Benefits | 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  
Common stock equities | Other Benefits      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Other 0 0  
Fair value of plan assets 176,024 175,605  
Common stock equities | Other Benefits | 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 176,024 175,605  
Common stock equities | Other Benefits | 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  
Mutual funds | Pension Benefits      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Other 0 0  
Fair value of plan assets 132,656 262,765  
Mutual funds | Pension Benefits | 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 132,656 262,765  
Mutual funds | Pension Benefits | 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  
Mutual funds | Other Benefits      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Other 0 0  
Fair value of plan assets 26,262 34,310  
Mutual funds | Other Benefits | 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 26,262 34,310  
Mutual funds | Other Benefits | 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  
Equities | Pension Benefits      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Other 255,141 407,522  
Fair value of plan assets 255,141 407,522  
Equities | Pension Benefits | 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 0 0  
Equities | Pension Benefits | 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  
Equities | Other Benefits      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Other 96,547 94,674  
Fair value of plan assets 96,547 94,674  
Equities | Other Benefits | 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 0 0  
Equities | Other Benefits | 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  
Real estate | Pension Benefits      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Other 173,197 191,595  
Fair value of plan assets 173,197 191,595  
Real estate | Pension Benefits | 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 0 0  
Real estate | Pension Benefits | 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  
Real estate | Other Benefits      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Other 23,851 19,778  
Fair value of plan assets 23,851 19,778  
Real estate | Other Benefits | 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 0 0  
Real estate | Other Benefits | 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  
Partnerships | Pension Benefits      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Other 15,730 22,420  
Fair value of plan assets 15,730 22,420  
Partnerships | Pension Benefits | 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 0 0  
Partnerships | Pension Benefits | 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  
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 86,103 69,696  
Fair value of plan assets 86,103 69,696  
Short-term investments and other | Pension Benefits | 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 0 0  
Short-term investments and other | Pension Benefits | 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  
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 6,154 3,988  
Fair value of plan assets 8,671 146,983  
Short-term investments and other | Other Benefits | Level 1      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Gross fair value of plan assets 2,517 142,995  
Short-term investments and other | Other Benefits | 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  
v3.22.0.1
Retirement Plans and Other Postretirement Benefits - Estimated Future Benefit Payments (Details)
$ in Thousands
Dec. 31, 2021
USD ($)
Pension Benefits  
Estimated Future Benefit Payments  
2022 $ 220,549
2023 219,132
2024 221,724
2025 222,356
2026 221,709
Years 2027-2031 1,121,557
Other Benefits  
Estimated Future Benefit Payments  
2022 31,244
2023 31,658
2024 31,486
2025 30,988
2026 30,780
Years 2027-2031 $ 151,194
v3.22.0.1
Leases - Additional information (Details)
$ in Billions
Dec. 31, 2021
USD ($)
Counterparty
Leases [Abstract]  
Number of lease agreements, sell and lease back | Counterparty 3
Lease not yet commenced | $ $ 1.3
v3.22.0.1
Leases - Lease costs (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2021
Dec. 31, 2020
Dec. 31, 2019
Operating Leased Assets [Line Items]      
Operating Lease Cost $ 124,260 $ 87,376 $ 60,228
Variable lease cost 118,969 122,331 114,015
Short-term lease cost 3,872 3,804 4,385
Purchased Power Lease Contracts      
Operating Leased Assets [Line Items]      
Operating Lease Cost 105,762 68,883 42,190
Land, Property, and Other Equipment      
Operating Leased Assets [Line Items]      
Operating Lease Cost 18,498 18,493 18,038
Total lease cost $ 247,101 $ 213,511 $ 178,628
v3.22.0.1
Leases - Maturity of our operating lease liabilities (Details)
$ in Thousands
Dec. 31, 2021
USD ($)
Lessee, Lease, Description [Line Items]  
2022 $ 116,803
2023 116,909
2024 112,388
2025 112,616
2026 124,819
Thereafter 334,883
Total lease commitments 918,418
Less imputed interest 89,574
Total lease liabilities 828,844
Purchased Power Lease Contracts  
Lessee, Lease, Description [Line Items]  
2022 103,752
2023 106,151
2024 104,315
2025 106,582
2026 120,016
Thereafter 299,594
Total lease commitments 840,410
Less imputed interest 72,249
Total lease liabilities 768,161
Land, Property, and Other Equipment  
Lessee, Lease, Description [Line Items]  
2022 13,051
2023 10,758
2024 8,073
2025 6,034
2026 4,803
Thereafter 35,289
Total lease commitments 78,008
Less imputed interest 17,325
Total lease liabilities $ 60,683
v3.22.0.1
Leases - Other additional information related to operating lease liabilities (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2021
Dec. 31, 2020
Dec. 31, 2019
Leases [Abstract]      
Cash paid for amounts included in the measurement of lease liabilities - operating cash flows $ 116,661 $ 75,097 $ 69,075
Right-of-use operating lease assets obtained in exchange for operating lease liabilities $ 500,582 $ 441,653 $ 11,262
Weighted average remaining lease term 8 years 6 years  
Weighted average discount rate 2.13% 1.69%  
v3.22.0.1
Jointly-Owned Facilities (Details) - Arizona Public Service Company
$ in Thousands
Dec. 31, 2021
USD ($)
Palo Verde Units 1 and 3  
Interests in jointly-owned facilities  
Percent owned 29.10%
Plant in service $ 1,932,629
Accumulated depreciation 1,113,905
Construction work in progress $ 28,288
Palo Verde Unit 2  
Interests in jointly-owned facilities  
Percent owned 16.80%
Plant in service $ 657,102
Accumulated depreciation 384,193
Construction work in progress $ 14,084
Palo Verde Common  
Interests in jointly-owned facilities  
Percent owned 28.00%
Plant in service $ 792,849
Accumulated depreciation 334,804
Construction work in progress 43,690
Palo Verde Sale Leaseback  
Interests in jointly-owned facilities  
Plant in service 351,050
Accumulated depreciation 256,884
Construction work in progress $ 0
Four Corners Generating Station  
Interests in jointly-owned facilities  
Percent owned 63.00%
Plant in service $ 1,686,702
Accumulated depreciation 608,247
Construction work in progress $ 21,515
Cholla Common Facilities  
Interests in jointly-owned facilities  
Percent owned 50.50%
Plant in service $ 208,709
Accumulated depreciation 121,877
Construction work in progress $ 1,608
ANPP 500kV System  
Interests in jointly-owned facilities  
Percent owned 33.50%
Plant in service $ 133,289
Accumulated depreciation 53,708
Construction work in progress $ 115
Navajo Southern System  
Interests in jointly-owned facilities  
Percent owned 26.80%
Plant in service $ 89,895
Accumulated depreciation 35,144
Construction work in progress $ 1,535
Palo Verde — Yuma 500kV System  
Interests in jointly-owned facilities  
Percent owned 25.80%
Plant in service $ 23,650
Accumulated depreciation 7,188
Construction work in progress $ 716
Four Corners Switchyards  
Interests in jointly-owned facilities  
Percent owned 60.10%
Plant in service $ 73,133
Accumulated depreciation 18,637
Construction work in progress $ 258
Phoenix — Mead System  
Interests in jointly-owned facilities  
Percent owned 17.10%
Plant in service $ 39,523
Accumulated depreciation 20,150
Construction work in progress $ 0
Palo Verde — Rudd 500kV System  
Interests in jointly-owned facilities  
Percent owned 50.00%
Plant in service $ 96,376
Accumulated depreciation 29,426
Construction work in progress $ 0
Morgan — Pinnacle Peak System  
Interests in jointly-owned facilities  
Percent owned 64.70%
Plant in service $ 119,814
Accumulated depreciation 23,575
Construction work in progress $ 138
Round Valley System  
Interests in jointly-owned facilities  
Percent owned 50.00%
Plant in service $ 535
Accumulated depreciation 180
Construction work in progress $ 0
Palo Verde — Morgan System  
Interests in jointly-owned facilities  
Percent owned 87.80%
Plant in service $ 259,180
Accumulated depreciation 27,995
Construction work in progress $ 268
Hassayampa — North Gila System  
Interests in jointly-owned facilities  
Percent owned 80.00%
Plant in service $ 148,039
Accumulated depreciation 19,317
Construction work in progress $ 0
Cholla 500kV Switchyard  
Interests in jointly-owned facilities  
Percent owned 85.70%
Plant in service $ 8,287
Accumulated depreciation 2,163
Construction work in progress $ 5
Saguaro 500kV Switchyard  
Interests in jointly-owned facilities  
Percent owned 60.00%
Plant in service $ 21,655
Accumulated depreciation 13,471
Construction work in progress $ 0
Kyrene — Knox System  
Interests in jointly-owned facilities  
Percent owned 50.00%
Plant in service $ 578
Accumulated depreciation 328
Construction work in progress $ 0
v3.22.0.1
Commitments and Contingencies - Palo Verde Nuclear Generating Station, Contractual Obligations and Super-Fund Related Matters (Details)
$ in Thousands
 12 Months Ended 108 Months Ended
Nov. 01, 2021
USD ($)
claim
Apr. 05, 2018
plaintiff
Defendant
Dec. 16, 2016
plaintiff
Aug. 06, 2013
Defendant
Dec. 31, 2021
USD ($)
Trust
Dec. 31, 2020
USD ($)
Dec. 31, 2019
USD ($)
Jun. 30, 2020
USD ($)
claim
timePeriod
Fuel and Purchased Power Commitments and Purchase Obligations [Abstract]                
Total take-or-pay commitments         $ 174,616 $ 170,097    
Arizona Public Service Company                
Palo Verde Nuclear Generating Station [Abstract]                
Maximum insurance against public liability per occurrence for a nuclear incident         13,500,000      
Maximum available nuclear liability insurance         450,000      
Remaining nuclear liability insurance through mandatory industry wide retrospective assessment program         13,100,000      
Maximum assessment per reactor for each nuclear incident         137,600      
Annual limit per incident with respect to maximum assessment         $ 20,500      
Number of VIE lessor trusts | Trust         3      
Maximum potential retrospective assessment per incident of APS         $ 120,100      
Annual payment limitation with respect to maximum potential retrospective assessment         17,900      
Amount of "all risk" (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde         2,800,000      
Request second-year energy price for exported energy         22,400      
Collateral assurance based on rating triggers         $ 63,300      
Period to provide collateral assurance based on rating triggers         20 days      
Fuel and Purchased Power Commitments and Purchase Obligations [Abstract]                
2022         $ 1,000,000      
2023         765,000      
2024         703,000      
2025         686,000      
2026         687,000      
Thereafter         6,900,000      
Total take-or-pay commitments         174,616 170,097    
Arizona Public Service Company | Coal Take-or-Pay Commitments                
Fuel and Purchased Power Commitments and Purchase Obligations [Abstract]                
2022         202,917      
2023         201,826      
2024         203,638      
2025         194,192      
2026         195,121      
Thereafter         925,644      
Total take-or-pay commitments         1,900,000      
Present value of commitments         1,500,000      
Total purchases         219,958 189,817 $ 204,888  
Arizona Public Service Company | Renewable Energy Credits                
Fuel and Purchased Power Commitments and Purchase Obligations [Abstract]                
2022         32,000      
2023         30,000      
2024         29,000      
2025         26,000      
2026         22,000      
Thereafter         87,000      
Arizona Public Service Company | Coal Mine Reclamation Obligations                
Fuel and Purchased Power Commitments and Purchase Obligations [Abstract]                
2022         17,000      
2023         18,000      
2024         19,000      
2025         20,000      
2026         21,000      
Thereafter         48,000      
Arizona Public Service Company | Coal Mine Reclamation Balance Sheet Obligations                
Fuel and Purchased Power Commitments and Purchase Obligations [Abstract]                
Total take-or-pay commitments         175,000 $ 170,000    
Arizona Public Service Company | Contaminated Groundwater Wells                
Fuel and Purchased Power Commitments and Purchase Obligations [Abstract]                
Costs related to investigation and study under Superfund site         $ 3,000      
Number of defendants against whom Roosevelt Irrigation District ("RID") filed lawsuit | Defendant   28   24        
Number of plaintiffs | plaintiff     2          
Arizona Public Service Company | Contaminated Groundwater Wells | Settled Litigation                
Fuel and Purchased Power Commitments and Purchase Obligations [Abstract]                
Number of plaintiffs | plaintiff   2            
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             $ 111,800
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 8             7
Gain contingency, number of separate time periods | timePeriod               7
Settlement amount, awarded to company $ 3,600             $ 32,500
v3.22.0.1
Commitments and Contingencies - Additional Information (Details) - USD ($)
$ in Thousands
 12 Months Ended
Nov. 02, 2021
Feb. 22, 2021
Jul. 03, 2018
Jul. 06, 2016
Dec. 31, 2021
Financial Assurances          
Equity contribution guarantees         $ 2,000
Production tax credit guarantees         37,000
2017 Settlement Agreement and its Customer Education and Outreach Plan | Arizona Public Service Company          
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         5,000
Four Corners Units 4 and 5 | Arizona Public Service Company | SCE          
Four Corners SCR Cost Recovery [Abstract]          
Recommended rate adjustment, annualized customer impact, disallowance of investments $ 194,000        
Recommended rate adjustment, annualized customer impact, cost deferrals $ 215,500        
Potential charges         154,400
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         $ 9,200
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         $ 30,000
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         $ 14,000
v3.22.0.1
Asset Retirement Obligations (Details) - Arizona Public Service Company - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2021
Dec. 31, 2020
Change in asset retirement obligations    
Asset retirement obligations at the beginning of year $ 705,083 $ 657,218
Changes attributable to:    
Accretion expense 38,437 38,652
Settlements (4,111) (9,710)
Estimated cash flow revisions 27,973 18,923
Asset retirement obligations at the end of year 767,382 705,083
Cholla    
Asset Retirement Obligations    
Increase in asset retirement obligation $ 28,000  
Navajo Generating Station    
Asset Retirement Obligations    
Increase in asset retirement obligation   6,000
Four Corners Units 4 and 5    
Asset Retirement Obligations    
Increase in asset retirement obligation   $ 13,000
v3.22.0.1
Fair Value Measurements - Fair Value of Assets and Liabilities (Details) - USD ($)
$ in Thousands
Dec. 31, 2021
Dec. 31, 2020
Assets    
Commodity contracts, assets $ 110,389 $ 4,749
Commodity contracts, liabilities (4,690) (4,271)
Nuclear decommissioning trust 1,294,757 1,138,435
Nuclear decommissioning trust, other 567,266 592,227
Other special use fund 358,410 254,509
Other special use funds, other 936 504
Total assets 1,763,556 1,397,693
Total assets, other 563,512 588,460
Liabilities    
Derivative instruments, other 3,105 2,986
Derivative instruments, total (4,373) (18,619)
Equity securities    
Assets    
Nuclear decommissioning trust 17,482 11,968
Nuclear decommissioning trust, other (27,782) (17,828)
Other special use fund 48,506 37,841
Other special use funds, other 936 504
U.S. commingled equity funds    
Assets    
Nuclear decommissioning trust 595,048 610,055
U.S. Treasury debt    
Assets    
Nuclear decommissioning trust 240,745 164,514
Other special use fund 298,170 203,220
Corporate debt    
Assets    
Nuclear decommissioning trust 203,454 149,509
Mortgage-backed securities    
Assets    
Nuclear decommissioning trust 155,574 99,623
Municipal bonds    
Assets    
Nuclear decommissioning trust 72,189 89,705
Other special use fund 11,734 13,448
Other fixed income    
Assets    
Nuclear decommissioning trust 10,265 13,061
Level 1    
Assets    
Commodity contracts, assets 0 0
Nuclear decommissioning trust 286,009 194,310
Other special use fund 345,740 240,557
Total assets 631,749 434,867
Liabilities    
Derivative instruments 0 0
Level 1 | Equity securities    
Assets    
Nuclear decommissioning trust 45,264 29,796
Other special use fund 47,570 37,337
Level 1 | U.S. commingled equity funds    
Assets    
Nuclear decommissioning trust 0 0
Level 1 | U.S. Treasury debt    
Assets    
Nuclear decommissioning trust 240,745 164,514
Other special use fund 298,170 203,220
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 115,079 9,016
Nuclear decommissioning trust 441,482 351,898
Other special use fund 11,734 13,448
Total assets 568,295 374,362
Liabilities    
Derivative instruments (4,740) (20,498)
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 203,454 149,509
Level 2 | Mortgage-backed securities    
Assets    
Nuclear decommissioning trust 155,574 99,623
Level 2 | Municipal bonds    
Assets    
Nuclear decommissioning trust 72,189 89,705
Other special use fund 11,734 13,448
Level 2 | Other fixed income    
Assets    
Nuclear decommissioning trust 10,265 13,061
Level 3    
Assets    
Commodity contracts, assets 0 4
Nuclear decommissioning trust 0 0
Other special use fund 0 0
Total assets 0 4
Liabilities    
Derivative instruments (2,738) (1,107)
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
NAV | U.S. commingled equity funds    
Assets    
Nuclear decommissioning trust $ 595,048 $ 610,055
v3.22.0.1
Fair Value Measurements - Additional Information (Details)
$ in Millions
Dec. 31, 2021
USD ($)
Fair Value Disclosures [Abstract]  
Stated interest rate for notes receivable 3.90%
Financing receivable $ 9
v3.22.0.1
Earnings Per Share (Details) - USD ($)
$ / shares in Units, shares in Thousands, $ in Thousands
 12 Months Ended
Dec. 31, 2021
Dec. 31, 2020
Dec. 31, 2019
Earnings Per Share [Abstract]      
Net income attributable to common shareholders $ 618,720 $ 550,559 $ 538,320
Weighted average common shares outstanding — basic (in shares) 112,910 112,666 112,443
Net effect of dilutive securities:      
Contingently issuable performance shares and restricted stock units (in shares) 282 276 315
Weighted average common shares outstanding — diluted (in shares) 113,192 112,942 112,758
Earnings per weighted-average common share outstanding      
Net income attributable to common shareholders - basic (in dollars per share) $ 5.48 $ 4.89 $ 4.79
Net Income attributable to common shareholders - diluted (in dollars per share) $ 5.47 $ 4.87 $ 4.77
v3.22.0.1
Stock-Based Compensation - Additional Information (Details)
shares in Millions, $ in Millions
 12 Months Ended
Dec. 31, 2021
USD ($)
performance_criteria
shares
Dec. 31, 2020
USD ($)
Dec. 31, 2019
USD ($)
Stock-Based Compensation      
Compensation cost that has been charged against income $ 18 $ 18 $ 18
Total income tax benefit recognized 3 4 7
Total unrecognized compensation cost related to nonvested share-based compensation arrangements granted $ 11    
Expected weighted-average period of recognition of unrecognized compensation cost 2 years    
Total fair value of shares vested $ 22 22 21
Performance Share Awards      
Number of performance element criteria | performance_criteria 2    
Performance period 3 years    
Restricted Stock Units      
Stock-Based Compensation      
Share-based liabilities paid $ 4 6 5
Cash flow effect, cash used to settle awards $ 3 $ 4 $ 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 | Minimum      
Performance Share Awards      
Exact number of shares issued as a percentage of the target award 0.00%    
Performance Shares | Maximum      
Performance Share Awards      
Exact number of shares issued as a percentage of the target award 200.00%    
Officers and Key Employees | Restricted Stock Units      
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 Units      
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 1.5    
Common shares available for issuance (in shares) | shares 1.2    
v3.22.0.1
Stock-Based Compensation - Summary of Restricted Stock, Stock Grants, Stock Units and Performance Shares (Details) - $ / shares
 12 Months Ended
Dec. 31, 2021
Dec. 31, 2020
Dec. 31, 2019
Restricted Stock Units, Stock Grants, and Stock Units      
Stocks granted and the weighted average fair value      
Units granted (in shares) 152,345 118,403 109,106
Grant date fair value (in dollars per share) $ 76.72 $ 71.70 $ 89.15
Number of granted awards to be settled in cash (in shares) 51,074 45,646 48,972
Performance Shares      
Stocks granted and the weighted average fair value      
Units granted (in shares) 161,840 122,830 142,874
Grant date fair value (in dollars per share) $ 82.42 $ 104.74 $ 92.16
v3.22.0.1
Stock-Based Compensation - Status of Nonvested Restricted Stock, Stock Grants, Stock Units and Performance Shares (Details) - $ / shares
 12 Months Ended
Dec. 31, 2021
Dec. 31, 2020
Dec. 31, 2019
Restricted Stock Units, Stock Grants, and Stock Units      
Nonvested shares      
Balance at the beginning of the period (in shares) 220,557    
Granted (in shares) 152,345    
Vested (in shares) (115,099)    
Forfeited (in shares) (4,647)    
Balance at the end of the period (in shares) 253,156 220,557  
Weighted-Average Grant-Date Fair Value      
Balance at the beginning of the period (in dollars per share) $ 77.93    
Granted (in dollars per share) 76.72 $ 71.70 $ 89.15
Vested (in dollars per share) 80.50    
Forfeited (in dollars per share) 80.11    
Balance at the end of the period (in dollars per share) $ 79.37 $ 77.93  
Vested awards outstanding at end of year (in shares) 88,706    
Vested awards outstanding at end of year (in dollars per share)    
Number of nonvested awards to be settled in cash (in shares) 118,538    
Performance Shares      
Nonvested shares      
Balance at the beginning of the period (in shares) 260,004    
Granted (in shares) 161,840    
Vested (in shares) (136,070)    
Forfeited (in shares) (5,092)    
Balance at the end of the period (in shares) 280,682 260,004  
Weighted-Average Grant-Date Fair Value      
Balance at the beginning of the period (in dollars per share) $ 98.28    
Granted (in dollars per share) 82.42 $ 104.74 $ 92.16
Vested (in dollars per share) 92.16    
Forfeited (in dollars per share) 95.07    
Balance at the end of the period (in dollars per share) $ 92.16 $ 98.28  
Vested awards outstanding at end of year (in shares) 136,070    
Vested awards outstanding at end of year (in dollars per share)    
v3.22.0.1
Derivative Accounting - Additional Information (Details)
 12 Months Ended
Dec. 31, 2021
USD ($)
Derivative [Line Items]  
Amounts reclassified from accumulated other comprehensive income $ 0
Commodity Contracts  
Derivative [Line Items]  
Aggregate fair value of derivative instruments in a net liability position 7,478,000
Additional collateral to counterparties for energy related non-derivative instrument contracts 88,000,000
Risk Management Assets | Credit Concentration Risk  
Derivative [Line Items]  
Aggregate fair value of derivative instruments in a net liability position $ 110,000,000
Risk Management Assets | Credit Concentration Risk | Four Counterparties  
Derivative [Line Items]  
Concentration risk, percentage 38.00%
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%
v3.22.0.1
Derivative Accounting - Outstanding Gross Notional Amounts Outstanding (Details) - Commodity Contracts
MWh in Thousands
 12 Months Ended
Dec. 31, 2021
MWh
Bcf
Dec. 31, 2020
MWh
Bcf
Outstanding gross notional amount of derivatives    
Power (in MWh) | MWh 0 368
Gas (in bcf) | Bcf 155 205
v3.22.0.1
Derivative Accounting - Gains and Losses from Derivative Instruments (Details) - Commodity Contracts - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2021
Dec. 31, 2020
Dec. 31, 2019
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
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) 0 (763) (1,512)
Fuel and purchased power | Not Designated as Hedging Instruments      
Derivative Instruments Not Designated as Cash Flows Hedges      
Net Gain (Loss) Recognized in Income $ 216,847 $ (3,178) $ (84,953)
v3.22.0.1
Derivative Accounting - Derivative Instruments in the Balance Sheet (Details) - USD ($)
$ in Thousands
Dec. 31, 2021
Dec. 31, 2020
Assets    
Gross Recognized Derivatives $ 110,389 $ 4,749
Liabilities    
Amount Reported on Balance Sheet (4,373) (18,619)
Commodity Contracts    
Assets    
Gross Recognized Derivatives 115,079 9,020
Amounts Offset (4,740) (4,271)
Net Recognized Derivatives 110,339 4,749
Other 50 0
Amount Reported on Balance Sheet 110,389 4,749
Liabilities    
Gross Recognized Derivatives (7,478) (21,605)
Amounts Offset 4,740 4,271
Net Recognized Derivatives (2,738) (17,334)
Other (1,635) (1,285)
Amount Reported on Balance Sheet (4,373) (18,619)
Assets and Liabilities    
Gross Recognized Derivatives 107,601 (12,585)
Amounts Offset 0 0
Net Recognized Derivatives 107,601 (12,585)
Other (1,585) (1,285)
Amount Reported on Balance Sheet 106,016 (13,870)
Commodity Contracts | Current Assets    
Assets    
Gross Recognized Derivatives 66,777 5,870
Amounts Offset (3,346) (2,939)
Net Recognized Derivatives 63,431 2,931
Other 50 0
Amount Reported on Balance Sheet 63,481 2,931
Commodity Contracts | Investments and Other Assets    
Assets    
Gross Recognized Derivatives 48,302 3,150
Amounts Offset (1,394) (1,332)
Net Recognized Derivatives 46,908 1,818
Other 0 0
Amount Reported on Balance Sheet 46,908 1,818
Commodity Contracts | Current Liabilities    
Liabilities    
Gross Recognized Derivatives (6,084) (9,211)
Amounts Offset 3,346 2,939
Net Recognized Derivatives (2,738) (6,272)
Other (1,635) (1,285)
Amount Reported on Balance Sheet (4,373) (7,557)
Commodity Contracts | Deferred Credits and Other    
Liabilities    
Gross Recognized Derivatives (1,394) (12,394)
Amounts Offset 1,394 1,332
Net Recognized Derivatives 0 (11,062)
Other 0 0
Amount Reported on Balance Sheet $ 0 $ (11,062)
v3.22.0.1
Derivative Accounting - Credit Risk and Related Contingent Features (Details) - Commodity Contracts
$ in Thousands
Dec. 31, 2021
USD ($)
Credit Risk and Credit-Related Contingent Features  
Aggregate fair value of derivative instruments in a net liability position $ 7,478
Cash collateral posted 0
Additional cash collateral in the event credit-risk related contingent features were fully triggered $ 2,658
v3.22.0.1
Other Income and Other Expense (Details) - USD ($)
 12 Months Ended
Dec. 31, 2021
Dec. 31, 2020
Dec. 31, 2019
Nov. 06, 2020
Other income:        
Interest income $ 6,726,000 $ 12,210,000 $ 10,377,000  
Investment gains (losses) — net 0 2,358,000 0  
Miscellaneous 53,000 149,000 63,000  
Total other income 45,100,000 56,703,000 50,263,000  
Other expense:        
Non-operating costs (13,008,000) (12,400,000) (10,663,000)  
Investment gains (losses) — net (1,367,000) 0 (1,835,000)  
Miscellaneous (11,021,000) (45,376,000) (5,382,000)  
Total other expense (25,396,000) (57,776,000) (17,880,000)  
Arizona Public Service Company        
Other income:        
Interest income 4,692,000 9,621,000 6,998,000  
Miscellaneous 40,000 148,000 63,000  
Total other income 43,053,000 51,755,000 46,884,000  
Other expense:        
Non-operating costs (10,080,000) (10,659,000) (9,612,000)  
Miscellaneous (8,817,000) (43,035,000) (3,378,000)  
Total other expense (18,897,000) (53,694,000) (12,990,000)  
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 14,955,000 15,865,000 19,541,000  
SCR deferral | Arizona Public Service Company        
Other income:        
Debt return 14,955,000 15,865,000 19,541,000  
Octotillo modernization project        
Other income:        
Debt return 23,366,000 26,121,000 20,282,000  
Octotillo modernization project | Arizona Public Service Company        
Other income:        
Debt return $ 23,366,000 $ 26,121,000 $ 20,282,000  
v3.22.0.1
Palo Verde Sale Leaseback Variable Interest Entities - Additional Information (Details)
$ in Thousands
 12 Months Ended
Dec. 31, 2021
USD ($)
Trust
lease
Lease
Dec. 31, 2020
USD ($)
Dec. 31, 2019
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 $ 17,224 $ 19,493 $ 19,493  
Arizona Public Service Company        
Palo Verde Sale Leaseback Variable Interest Entities        
Number of VIE lessor trusts | Trust 3      
Increase in net income due to consolidation of Palo Verde Sale Leaseback Trusts $ 17,224 19,493 19,493  
Arizona Public Service Company | Variable Interest Entity        
Palo Verde Sale Leaseback Variable Interest Entities        
Number of VIE lessor trusts | Trust       3
Increase in net income due to consolidation of Palo Verde Sale Leaseback Trusts 17,000 $ 19,000 $ 19,000  
Initial loss exposure to the VIEs noncontrolling equity participants during lease extension period 315,000      
Maximum loss exposure to the VIE's noncontrolling equity participants during lease extension period $ 501,000      
Arizona Public Service Company | Period Through 2023 | Variable Interest Entity        
Palo Verde Sale Leaseback Variable Interest Entities        
Number of leases under which assets are retained | Lease 1      
Arizona Public Service Company | Period Through 2033 | Variable Interest Entity        
Palo Verde Sale Leaseback Variable Interest Entities        
Number of leases under which assets are retained | Lease 2      
Arizona Public Service Company | Period 2022 through 2023 | Variable Interest Entity        
Palo Verde Sale Leaseback Variable Interest Entities        
Number of leases under which assets are retained | lease 3      
Annual lease payments $ 21,000      
Lease period 2 years      
v3.22.0.1
Palo Verde Sale Leaseback Variable Interest Entities - Schedule of VIEs (Details) - USD ($)
$ in Thousands
Dec. 31, 2021
Dec. 31, 2020
Palo Verde Sale Leaseback Variable Interest Entities    
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation $ 15,987,434 $ 15,159,210
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets    
Equity — Noncontrolling interests 115,260 119,290
Arizona Public Service Company    
Palo Verde Sale Leaseback Variable Interest Entities    
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation 15,985,346 15,158,846
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets    
Equity — Noncontrolling interests 115,260 119,290
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 94,166 98,036
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets    
Equity — Noncontrolling interests $ 115,260 $ 119,290
v3.22.0.1
Investments in Nuclear Decommissioning Trusts and Other Special Use Funds - Additional Information (Details) - USD ($)
$ in Thousands
 12 Months Ended
Jan. 04, 2021
Dec. 31, 2021
Dec. 31, 2020
Other Benefits      
Schedule of Equity Method Investments [Line Items]      
Transfer to active union medical account $ 106,000 $ 105,852 $ 0
Arizona Public Service Company      
Schedule of Equity Method Investments [Line Items]      
Employee medical claims amount   $ 15,000 $ 14,000
Arizona Public Service Company | Other Benefits      
Schedule of Equity Method Investments [Line Items]      
Transfer to active union medical account $ 106,000    
v3.22.0.1
Investments in Nuclear Decommissioning Trusts and Other Special Use Funds (Details) - Arizona Public Service Company - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2021
Dec. 31, 2020
Dec. 31, 2019
Nuclear decommissioning trust fund assets      
Fair Value $ 1,653,167 $ 1,392,944  
Total Unrealized Gains 475,670 468,247  
Total Unrealized Losses (4,063) (398)  
Amortized cost 972,000 687,000  
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds      
Realized gains 134,659 12,370 $ 11,132
Realized losses (8,438) (5,568) (6,972)
Proceeds from the sale of securities 1,720,966 819,519 719,034
Equity securities      
Nuclear decommissioning trust fund assets      
Fair Value 687,882 677,188  
Total Unrealized Gains 451,387 421,666  
Total Unrealized Losses 0 0  
Available for sale-fixed income securities      
Nuclear decommissioning trust fund assets      
Fair Value 992,131 733,080  
Total Unrealized Gains 24,283 46,581  
Total Unrealized Losses (4,063) (398)  
Fair value of fixed income securities, summarized by contractual maturities      
Less than one year 108,792    
1 year – 5 years 396,141    
5 years – 10 years 178,823    
Greater than 10 years 308,375    
Total 992,131    
Other      
Nuclear decommissioning trust fund assets      
Fair Value (26,846) (17,324)  
Total Unrealized Gains 0 0  
Total Unrealized Losses 0 0  
Nuclear Decommissioning Trust      
Nuclear decommissioning trust fund assets      
Fair Value 1,294,757 1,138,435  
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds      
Realized gains 134,610 12,194 11,024
Realized losses (8,431) (5,553) (6,972)
Proceeds from the sale of securities 1,457,305 675,035 473,806
Nuclear Decommissioning Trust | Equity securities      
Nuclear decommissioning trust fund assets      
Fair Value 640,312 639,851  
Nuclear Decommissioning Trust | Available for sale-fixed income securities      
Nuclear decommissioning trust fund assets      
Fair Value 682,227 516,412  
Fair value of fixed income securities, summarized by contractual maturities      
Less than one year 31,070    
1 year – 5 years 195,975    
5 years – 10 years 155,202    
Greater than 10 years 299,980    
Total 682,227    
Nuclear Decommissioning Trust | Other      
Nuclear decommissioning trust fund assets      
Fair Value (27,782) (17,828)  
Other Special Use Funds      
Nuclear decommissioning trust fund assets      
Fair Value 358,410 254,509  
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds      
Realized gains 49 176 108
Realized losses (7) (15) 0
Proceeds from the sale of securities 263,661 144,484 $ 245,228
Other Special Use Funds | Equity securities      
Nuclear decommissioning trust fund assets      
Fair Value 47,570 37,337  
Other Special Use Funds | Available for sale-fixed income securities      
Nuclear decommissioning trust fund assets      
Fair Value 309,904 216,668  
Other Special Use Funds | Other      
Nuclear decommissioning trust fund assets      
Fair Value 936 $ 504  
Coal Reclamation Escrow Account | Available for sale-fixed income securities      
Fair value of fixed income securities, summarized by contractual maturities      
Less than one year 36,852    
1 year – 5 years 41,931    
5 years – 10 years 1,775    
Greater than 10 years 8,395    
Total 88,953    
Active Union Employee Medical Account | Available for sale-fixed income securities      
Fair value of fixed income securities, summarized by contractual maturities      
Less than one year 40,870    
1 year – 5 years 158,235    
5 years – 10 years 21,846    
Greater than 10 years 0    
Total $ 220,951    
v3.22.0.1
Changes in Accumulated Other Comprehensive Loss (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2021
Dec. 31, 2020
Changes in accumulated other comprehensive income (loss) by component    
Beginning balance $ 5,752,793 $ 5,553,188
Ending balance 6,021,460 5,752,793
Pension and Other Postretirement Benefits    
Changes in accumulated other comprehensive income (loss) by component    
Beginning balance (60,725) (56,522)
OCI (loss) before reclassifications 2,439 (8,370)
Amounts reclassified from accumulated other comprehensive loss 4,401 4,167
Ending balance (53,885) (60,725)
Derivative Instruments    
Changes in accumulated other comprehensive income (loss) by component    
Beginning balance (2,071) (574)
OCI (loss) before reclassifications 1,077 (2,089)
Amounts reclassified from accumulated other comprehensive loss 18 592
Ending balance (976) (2,071)
Accumulated Other Comprehensive Income (Loss)    
Changes in accumulated other comprehensive income (loss) by component    
Beginning balance (62,796) (57,096)
OCI (loss) before reclassifications 3,516 (10,459)
Amounts reclassified from accumulated other comprehensive loss 4,419 4,759
Ending balance (54,861) (62,796)
Arizona Public Service Company    
Changes in accumulated other comprehensive income (loss) by component    
Beginning balance 6,345,185 5,998,803
Ending balance 6,750,473 6,345,185
Arizona Public Service Company | Pension and Other Postretirement Benefits    
Changes in accumulated other comprehensive income (loss) by component    
Beginning balance (40,918) (34,948)
OCI (loss) before reclassifications 2,043 (9,568)
Amounts reclassified from accumulated other comprehensive loss 3,995 3,598
Ending balance (34,880) (40,918)
Arizona Public Service Company | Derivative Instruments    
Changes in accumulated other comprehensive income (loss) by component    
Beginning balance 0 (574)
OCI (loss) before reclassifications (18) (18)
Amounts reclassified from accumulated other comprehensive loss 18 592
Ending balance 0 0
Arizona Public Service Company | Accumulated Other Comprehensive Income (Loss)    
Changes in accumulated other comprehensive income (loss) by component    
Beginning balance (40,918) (35,522)
OCI (loss) before reclassifications 2,025 (9,586)
Amounts reclassified from accumulated other comprehensive loss 4,013 4,190
Ending balance $ (34,880) $ (40,918)
v3.22.0.1
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT - Comprehensive Income (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2021
Dec. 31, 2020
Dec. 31, 2019
CONDENSED FINANCIAL STATEMENTS      
Operating expenses $ 2,998,525 $ 2,798,830 $ 2,799,249
Other      
Total 173,982 89,044 86,803
Interest expense 254,314 247,501 235,251
Income tax benefit 110,086 78,173 (15,773)
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS 618,720 550,559 538,320
Other comprehensive income (loss) — attributable to common shareholders 7,935 (5,700) (9,388)
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS 626,655 544,859 528,932
Pinnacle West      
CONDENSED FINANCIAL STATEMENTS      
Operating expenses 10,245 7,901 12,451
Other      
Equity in earnings of subsidiaries 628,916 566,147 562,946
Other expense (4,919) (4,586) (3,957)
Total 623,997 561,561 558,989
Interest expense 10,672 14,021 15,069
Income before income taxes 603,080 539,639 531,469
Income tax benefit (15,640) (10,920) (6,851)
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS 618,720 550,559 538,320
Other comprehensive income (loss) — attributable to common shareholders 7,935 (5,700) (9,388)
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS $ 626,655 $ 544,859 $ 528,932
v3.22.0.1
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT - Balance Sheets (Details) - USD ($)
$ in Thousands
Dec. 31, 2021
Dec. 31, 2020
Dec. 31, 2019
Dec. 31, 2018
Current assets        
Cash and cash equivalents $ 9,969 $ 59,968    
Accounts receivable 391,923 313,576    
Income tax receivable 7,514 6,792    
Other current assets 83,896 76,627    
Total current assets 1,551,100 1,198,319    
Investments and other assets        
Other assets 97,884 91,104    
Total investments and other assets 1,797,959 1,485,866    
Total Assets 22,003,222 20,020,421    
Current liabilities        
Accounts payable 393,083 318,585    
Accrued taxes 168,645 159,551    
Common dividends payable 95,988 93,531    
Short-term borrowings 292,000 169,000    
Current maturities of long-term debt 150,000 0    
Operating lease liabilities 100,443 74,785    
Other current liabilities 151,968 187,448    
Total current liabilities 1,756,869 1,360,433    
Deferred credits and other        
Long-term debt less current maturities (Note 7) 6,913,735 6,314,266    
Operating lease liabilities 728,401 361,336    
Other 232,914 190,643    
Total deferred credits and other 7,311,158 6,592,929    
COMMITMENTS AND CONTINGENCIES (SEE NOTES)    
Common stock equity        
Common stock 2,702,743 2,677,482    
Accumulated other comprehensive loss (54,861) (62,796)    
Retained earnings 3,264,719 3,025,106    
Total shareholders’ equity 5,906,200 5,633,503    
Noncontrolling interests 115,260 119,290    
Total equity 6,021,460 5,752,793 $ 5,553,188 $ 5,348,705
Total Liabilities and Equity 22,003,222 20,020,421    
Pinnacle West        
Current assets        
Cash and cash equivalents 594 19    
Accounts receivable 125,457 123,980    
Income tax receivable 1,498 14,719    
Other current assets 13 298    
Total current assets 127,562 139,016    
Investments and other assets        
Investments in subsidiaries 6,797,528 6,400,339    
Deferred income taxes 19,520 7,589    
Other assets 57,608 52,595    
Total investments and other assets 6,874,656 6,460,523    
Total Assets 7,002,218 6,599,539    
Current liabilities        
Accounts payable 3,071 5,669    
Accrued taxes 19,855 16,998    
Common dividends payable 95,988 93,531    
Short-term borrowings 13,300 169,000    
Current maturities of long-term debt 150,000 0    
Operating lease liabilities 107 90    
Other current liabilities 14,684 15,306    
Total current liabilities 297,005 300,594    
Deferred credits and other        
Long-term debt less current maturities (Note 7) 647,139 496,321    
Pension liabilities 14,537 17,541    
Operating lease liabilities 1,576 1,683    
Other 20,501 30,607    
Total deferred credits and other 36,614 49,831    
COMMITMENTS AND CONTINGENCIES (SEE NOTES)    
Common stock equity        
Common stock 2,696,342 2,671,193    
Accumulated other comprehensive loss (54,861) (62,796)    
Retained earnings 3,264,719 3,025,106    
Total shareholders’ equity 5,906,200 5,633,503    
Noncontrolling interests 115,260 119,290    
Total equity 6,021,460 5,752,793    
Total Liabilities and Equity $ 7,002,218 $ 6,599,539    
v3.22.0.1
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT - Cash Flows (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2021
Dec. 31, 2020
Dec. 31, 2019
Cash Flows from Operating Activities      
Net income $ 635,944 $ 570,052 $ 557,813
Adjustments to reconcile net income to net cash provided by operating activities:      
Depreciation and amortization 719,141 686,253 664,140
Deferred income taxes 117,471 69,469 (1,479)
Accounts receivable (72,559) (18,191) (12,789)
Accounts payable 20,267 (6,059) 50,641
Net cash provided by operating activities 860,014 966,365 956,726
Cash flows from investing activities      
Net cash used for investing activities (1,386,929) (1,277,818) (1,130,977)
Cash flows from financing activities      
Issuance of long-term debt 746,999 1,596,672 1,092,188
Short-term debt borrowings under revolving credit facility 0 751,690 49,000
Short-term debt repayments under revolving credit facility (19,000) (770,690) (65,000)
Short-term borrowings and (repayments) — net 142,000 73,325 54,275
Dividends paid on common stock (369,478) (350,577) (329,643)
Repayment of long-term debt 0 (915,150) (600,000)
Common stock equity issuance and purchases — net (2,350) (1,389) 692
Net cash provided by financing activities 476,916 361,138 178,768
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (49,999) 49,685 4,517
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 59,968 10,283 5,766
CASH AND CASH EQUIVALENTS AT END OF YEAR 9,969 59,968 10,283
Pinnacle West      
Cash Flows from Operating Activities      
Net income 618,720 550,559 538,320
Adjustments to reconcile net income to net cash provided by operating activities:      
Equity in earnings of subsidiaries — net (628,916) (566,147) (562,946)
Depreciation and amortization 93 76 76
Deferred income taxes (11,381) 33,007 (35,831)
Accounts receivable 8,897 (7,903) 182
Accounts payable (2,598) (1,964) (2,129)
Accrued taxes and income tax receivables — net 16,079 9,610 16,400
Dividends received from subsidiaries 376,500 357,500 336,300
Other 4,214 20,163 (1,300)
Net cash provided by operating activities 381,608 394,901 289,072
Cash flows from investing activities      
Investments in subsidiaries (145,266) (137,881) 1,557
Repayments of loans from subsidiaries 4,017 932 4,190
Advances of loans to subsidiaries (12,256) (7,261) (4,165)
Net cash used for investing activities (153,505) (144,210) 1,582
Cash flows from financing activities      
Issuance of long-term debt 300,000 496,950 0
Short-term debt borrowings under revolving credit facility 0 211,690 49,000
Short-term debt repayments under revolving credit facility (19,000) (230,690) (65,000)
Short-term borrowings and (repayments) — net (136,700) 73,325 54,275
Dividends paid on common stock (369,478) (350,577) (329,643)
Repayment of long-term debt 0 (450,000) 0
Common stock equity issuance and purchases — net (2,350) (1,389) 692
Net cash provided by financing activities (227,528) (250,691) (290,676)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 575 0 (22)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 19 19 41
CASH AND CASH EQUIVALENTS AT END OF YEAR $ 594 $ 19 $ 19