PINNACLE WEST CAPITAL CORP, 10-K filed on 2/27/2023
Annual Report
v3.22.4
Cover Page - USD ($)
 12 Months Ended
Dec. 31, 2022
Feb. 21, 2023
Jun. 30, 2022
Entity Information [Line Items]      
Document Type 10-K    
Document Annual Report true    
Document Period End Date Dec. 31, 2022    
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 Public Float     $ 8,247,902,707
Entity Common Stock, Shares Outstanding   113,175,507  
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 17, 2023 are incorporated by reference into Part III hereof.    
Entity Central Index Key 0000764622    
Amendment Flag false    
Document Fiscal Year Focus 2022    
Document Fiscal Period Focus FY    
Entity Shell Company false    
Arizona Public Service Company      
Entity Information [Line Items]      
Document Type 10-K    
Document Period End Date Dec. 31, 2022    
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 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 2022    
Document Fiscal Period Focus FY    
Entity Shell Company false    
v3.22.4
Audit Information
 12 Months Ended
Dec. 31, 2022
Auditor [Line Items]  
Auditor Name Deloitte & Touche LLP
Auditor Location Tempe, Arizona
Auditor Firm ID 34
Arizona Public Service Company  
Auditor [Line Items]  
Auditor Name Deloitte & Touche LLP
Auditor Location Tempe, Arizona
Auditor Firm ID 34
v3.22.4
CONSOLIDATED STATEMENTS OF INCOME - USD ($)
shares in Thousands, $ in Thousands
 12 Months Ended
Dec. 31, 2022
Dec. 31, 2021
Dec. 31, 2020
Income Statement [Abstract]      
OPERATING REVENUES (Note 2) $ 4,324,385 $ 3,803,835 $ 3,586,982
OPERATING EXPENSES      
Fuel and purchased power 1,629,343 1,152,551 993,419
Operations and maintenance 987,072 954,067 958,910
Depreciation and amortization 753,195 650,875 614,378
Taxes other than income taxes 220,370 234,639 224,835
Other expenses 2,494 6,393 7,288
Total 3,592,474 2,998,525 2,798,830
OPERATING INCOME 731,911 805,310 788,152
OTHER INCOME (DEDUCTIONS)      
Allowance for equity funds used during construction (Note 1) 45,263 41,737 33,776
Pension and other postretirement non-service credits — net (Note 7) 98,487 112,541 56,341
Other income (Note 16) 7,916 45,100 56,703
Other expense (Note 16) (52,385) (25,396) (57,776)
Total 99,281 173,982 89,044
INTEREST EXPENSE      
Interest charges 283,569 254,314 247,501
Allowance for borrowed funds used during construction (Note 1) (28,030) (21,052) (18,530)
Total 255,539 233,262 228,971
INCOME BEFORE INCOME TAXES 575,653 746,030 648,225
INCOME TAXES (Note 4) 74,827 110,086 78,173
NET INCOME 500,826 635,944 570,052
Less: Net income attributable to noncontrolling interests (Note 17) 17,224 17,224 19,493
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS $ 483,602 $ 618,720 $ 550,559
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — BASIC (in shares) 113,196 112,910 112,666
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — DILUTED (in shares) 113,416 113,192 112,942
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING      
Net income attributable to common shareholders - basic (in dollars per share) $ 4.27 $ 5.48 $ 4.89
Net income attributable to common shareholders — diluted (in dollars per share) $ 4.26 $ 5.47 $ 4.87
v3.22.4
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2022
Dec. 31, 2021
Dec. 31, 2020
Statement of Comprehensive Income [Abstract]      
NET INCOME $ 500,826 $ 635,944 $ 570,052
Derivative instruments:      
Net unrealized gain (loss), net of tax benefit (expense) of $(615), $(378), and $662 1,873 1,077 (2,089)
Reclassification of net realized gain, net of tax benefit (expense) of $0, $18, and $(171) (Note 15) 0 18 592
Pension and other postretirement benefits activity, net of tax benefit (expense) of $(7,078), $(2,256), and $1,371 (Note 7) 21,553 6,840 (4,203)
Total other comprehensive income (loss) 23,426 7,935 (5,700)
COMPREHENSIVE INCOME 524,252 643,879 564,352
Less: Comprehensive income attributable to noncontrolling interests 17,224 17,224 19,493
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS $ 507,028 $ 626,655 $ 544,859
v3.22.4
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2022
Dec. 31, 2021
Dec. 31, 2020
Statement of Comprehensive Income [Abstract]      
Net unrealized loss, tax benefit (expense) $ (615) $ (378) $ 662
Reclassification of net realized gain, tax benefit (expense) 0 18 (171)
Pension and other postretirement benefits activity, tax benefit (expense) $ (7,078) $ (2,256) $ 1,371
v3.22.4
CONSOLIDATED BALANCE SHEETS - USD ($)
$ in Thousands
Dec. 31, 2022
Dec. 31, 2021
CURRENT ASSETS    
Cash and cash equivalents $ 4,832 $ 9,969
Customer and other receivables 453,209 391,923
Accrued unbilled revenues 164,764 133,980
Allowance for doubtful accounts (Note 2) (23,778) (25,354)
Materials and supplies (at average cost) 410,481 349,135
Fossil fuel (at average cost) 40,155 18,032
Income tax receivable (Note 4) 14,086 7,514
Assets from risk management activities (Note 15) 87,835 63,481
Deferred fuel and purchased power regulatory asset (Note 3) 460,561 388,148
Other regulatory assets (Note 3) 78,318 130,376
Other current assets 60,091 83,896
Total current assets 1,750,554 1,551,100
INVESTMENTS AND OTHER ASSETS    
Nuclear decommissioning trusts (Notes 12 and 18) 1,073,410 1,294,757
Other special use funds (Notes 12 and 18) 347,231 358,410
Assets from risk management activities (Note 15) 44,394 46,908
Other assets 125,672 97,884
Total investments and other assets 1,590,707 1,797,959
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6 and 9)    
Plant in service and held for future use 22,452,146 21,688,661
Accumulated depreciation and amortization (7,929,878) (7,504,603)
Net 14,522,268 14,184,058
Construction work in progress 1,882,791 1,329,478
Palo Verde sale leaseback, net of accumulated depreciation of $260,754 and $256,884 (Note 17) 90,296 94,166
Intangible assets, net of accumulated amortization of $817,961 and $737,694 258,880 273,693
Nuclear fuel, net of accumulated amortization of $126,157 and $133,122 100,119 106,039
Total property, plant and equipment 16,854,354 15,987,434
DEFERRED DEBITS    
Regulatory assets (Notes 1, 3 and 4) 1,283,221 1,192,987
Operating lease right-of-use assets (Note 8) 801,688 890,057
Assets for pension and other postretirement benefits (Note 7) 396,599 545,723
Other 46,282 37,962
Total deferred debits 2,527,790 2,666,729
TOTAL ASSETS 22,723,405 22,003,222
CURRENT LIABILITIES    
Accounts payable 430,425 393,083
Accrued taxes 164,440 168,645
Accrued interest 61,217 57,332
Common dividends payable 97,895 95,988
Short-term borrowings (Note 5) 340,720 292,000
Current maturities of long-term debt (Note 6) 50,685 150,000
Customer deposits 41,769 42,293
Liabilities from risk management activities (Note 15) 37,697 4,373
Liabilities for asset retirements (Note 11) 12,232 4,473
Operating lease liabilities (Note 8) 105,210 100,443
Less: current regulatory liabilities 271,575 296,271
Other current liabilities 148,276 151,968
Total current liabilities 1,762,141 1,756,869
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 6) 7,741,286 6,913,735
DEFERRED CREDITS AND OTHER    
Deferred income taxes (Note 4) 2,384,421 2,311,862
Regulatory liabilities (Notes 1, 3, 4 and 7) 2,061,776 2,499,213
Liabilities for asset retirements (Note 11) 785,530 762,909
Liabilities for pension benefits (Note 7) 116,286 152,865
Customer advances 422,103 257,151
Coal mine reclamation 179,255 174,616
Deferred investment tax credit 180,677 186,570
Unrecognized tax benefits (Note 4) 38,658 4,657
Operating lease liabilities (Note 8) 639,247 728,401
Other 252,149 232,914
Total deferred credits and other 7,060,102 7,311,158
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
EQUITY    
Common stock, no par value; authorized 150,000,000 shares, 113,247,189 and 113,014,528 issued at respective dates 2,724,740 2,702,743
Treasury stock at cost; 73,613 and 87,608 shares at respective dates (5,005) (6,401)
Total common stock 2,719,735 2,696,342
Retained earnings 3,360,347 3,264,719
Accumulated other comprehensive loss (Note 19) (31,435) (54,861)
Total shareholders’ equity 6,048,647 5,906,200
Noncontrolling interests (Note 17) 111,229 115,260
Total equity 6,159,876 6,021,460
TOTAL LIABILITIES AND EQUITY $ 22,723,405 $ 22,003,222
v3.22.4
CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($)
$ in Thousands
Dec. 31, 2022
Dec. 31, 2021
PROPERTY, PLANT AND EQUIPMENT    
Accumulated depreciation of Palo Verde sale leaseback $ 260,754 $ 256,884
Accumulated amortization on intangible assets 817,961 737,694
Accumulated amortization on nuclear fuel $ 126,157 $ 133,122
EQUITY    
Common stock, authorized shares (in shares) 150,000,000 150,000,000
Common stock, issued shares (in shares) 113,247,189 113,014,528
Treasury stock (in shares) 73,613 87,608
v3.22.4
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2022
Dec. 31, 2021
Dec. 31, 2020
CASH FLOWS FROM OPERATING ACTIVITIES      
Net income $ 500,826 $ 635,944 $ 570,052
Adjustments to reconcile net income to net cash provided by operating activities:      
Depreciation and amortization including nuclear fuel 817,814 719,141 686,253
Deferred fuel and purchased power (291,992) (256,871) (93,651)
Deferred fuel and purchased power amortization 219,579 44,557 (12,047)
Allowance for equity funds used during construction (45,263) (41,737) (33,776)
Deferred income taxes 43,202 117,471 69,469
Deferred investment tax credit (5,893) (4,802) (5,096)
Change in derivative instruments fair value 777 0 0
Stock compensation 15,942 18,460 18,292
Changes in current assets and liabilities:      
Customer and other receivables (63,869) (72,559) (18,191)
Accrued unbilled revenues (30,784) (1,783) (4,032)
Materials, supplies and fossil fuel (83,469) (32,870) 11,623
Income tax receivable (6,572) (722) 14,935
Other current assets 76,067 (22,720) (30,640)
Accounts payable 90,076 20,267 (6,059)
Accrued taxes (4,205) 9,094 14,652
Other current liabilities (6,056) (52,086) 22,520
Change in margin and collateral accounts — assets 22 (50) 404
Change in margin and collateral accounts — liabilities 4,200 350 100
Change in unrecognized tax benefits (1,989) (568) 2,220
Change in long-term regulatory liabilities (332,470) 57,549 13,017
Change in other long-term assets 276,821 (246,473) (67,453)
Change in other long-term liabilities 68,677 (29,578) (186,227)
Net cash provided by operating activities 1,241,441 860,014 966,365
CASH FLOWS FROM INVESTING ACTIVITIES      
Capital expenditures (1,707,490) (1,473,475) (1,326,584)
Contributions in aid of construction 137,436 105,654 62,503
Allowance for borrowed funds used during construction (28,030) (21,052) (18,530)
Proceeds from nuclear decommissioning trust sales and other special use funds 1,207,713 1,720,966 819,518
Investment in nuclear decommissioning trust and other special use funds (1,212,063) (1,725,480) (822,608)
Other (15,612) 6,458 7,883
Net cash used for investing activities (1,618,046) (1,386,929) (1,277,818)
CASH FLOWS FROM FINANCING ACTIVITIES      
Issuance of long-term debt 875,537 746,999 1,596,672
Repayment of long-term debt (150,000) 0 (915,150)
Short-term borrowings and (repayments) — net 48,720 142,000 73,325
Short-term debt borrowings under revolving credit facility 0 0 751,690
Short-term debt repayments under revolving credit facility 0 (19,000) (770,690)
Dividends paid on common stock (378,881) (369,478) (350,577)
Common stock equity issuance and purchases — net (2,653) (2,350) (1,389)
Distributions to noncontrolling interests (21,255) (21,255) (22,743)
Net cash provided by financing activities 371,468 476,916 361,138
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (5,137) (49,999) 49,685
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 9,969 59,968 10,283
CASH AND CASH EQUIVALENTS AT END OF YEAR $ 4,832 $ 9,969 $ 59,968
v3.22.4
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, 2019   112,540,126        
Beginning balance (in shares) at Dec. 31, 2019     (103,546)      
Beginning 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        
Ending balance (in shares) at Dec. 31, 2020     (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        
Ending balance (in shares) at Dec. 31, 2021 (87,608)   (87,608)      
Ending balance at Dec. 31, 2021 $ 6,021,460 $ 2,702,743 $ (6,401) 3,264,719 (54,861) 115,260
Increase (Decrease) in Shareholders' Equity            
Net income 500,826     483,602   17,224
Other comprehensive income (loss) 23,426       23,426  
Dividends on common stock (387,975)     (387,975)    
Issuance of common stock (in shares)   232,661        
Issuance of common stock 21,996 $ 21,996        
Purchase of treasury stock (in shares) [1]     (77,152)      
Purchase of treasury stock [1] (5,152)   $ (5,152)      
Reissuance of treasury stock for stock-based compensation and other (in shares)     91,147      
Reissuance of treasury stock for stock-based compensation and other 6,548   $ 6,548      
Capital activities by noncontrolling interests (21,255)         (21,255)
Other $ 2 $ 1   1    
Ending balance (in shares) at Dec. 31, 2022 113,247,189 113,247,189        
Ending balance (in shares) at Dec. 31, 2022 (73,613)   (73,613)      
Ending balance at Dec. 31, 2022 $ 6,159,876 $ 2,724,740 $ (5,005) $ 3,360,347 $ (31,435) $ 111,229
[1] Primarily represents shares of common stock withheld from certain stock awards for tax purposes.
v3.22.4
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Parenthetical) - $ / shares
 12 Months Ended
Dec. 31, 2022
Dec. 31, 2021
Dec. 31, 2020
Statement of Stockholders' Equity [Abstract]      
Dividends declared per common share (in dollars per share) $ 3.43 $ 3.36 $ 3.23
v3.22.4
APS - CONSOLIDATED STATEMENTS OF INCOME - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2022
Dec. 31, 2021
Dec. 31, 2020
OPERATING REVENUES (Note 2) $ 4,324,385 $ 3,803,835 $ 3,586,982
OPERATING EXPENSES      
Fuel and purchased power 1,629,343 1,152,551 993,419
Operations and maintenance 987,072 954,067 958,910
Depreciation and amortization 753,195 650,875 614,378
Taxes other than income taxes 220,370 234,639 224,835
Other expenses 2,494 6,393 7,288
Total 3,592,474 2,998,525 2,798,830
OPERATING INCOME 731,911 805,310 788,152
OTHER INCOME (DEDUCTIONS)      
Allowance for equity funds used during construction (Note 1) 45,263 41,737 33,776
Pension and other postretirement non-service credits — net (Note 7) 98,487 112,541 56,341
Other income (Note 16) 7,916 45,100 56,703
Other expense (Note 16) (52,385) (25,396) (57,776)
Total 99,281 173,982 89,044
INTEREST EXPENSE      
Interest charges 283,569 254,314 247,501
Allowance for borrowed funds used during construction (Note 1) (28,030) (21,052) (18,530)
Total 255,539 233,262 228,971
INCOME BEFORE INCOME TAXES 575,653 746,030 648,225
INCOME TAXES (Note 4) 74,827 110,086 78,173
NET INCOME 500,826 635,944 570,052
Less: Net income attributable to noncontrolling interests (Note 17) 17,224 17,224 19,493
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS 483,602 618,720 550,559
Arizona Public Service Company      
OPERATING REVENUES (Note 2) 4,324,385 3,803,835 3,586,982
OPERATING EXPENSES      
Fuel and purchased power 1,629,343 1,152,551 993,419
Operations and maintenance 974,220 940,588 945,181
Depreciation and amortization 753,110 650,773 614,293
Taxes other than income taxes 220,277 234,569 224,790
Other expenses 2,494 6,393 7,288
Total 3,579,444 2,984,874 2,784,971
OPERATING INCOME 744,941 818,961 802,011
OTHER INCOME (DEDUCTIONS)      
Allowance for equity funds used during construction (Note 1) 45,263 41,737 33,776
Pension and other postretirement non-service credits — net (Note 7) 98,945 112,742 57,359
Other income (Note 16) 5,888 43,053 51,755
Other expense (Note 16) (26,108) (18,897) (53,694)
Total 123,988 178,635 89,196
INTEREST EXPENSE      
Interest charges 262,815 243,592 233,452
Allowance for borrowed funds used during construction (Note 1) (26,839) (21,052) (18,530)
Total 235,976 222,540 214,922
INCOME BEFORE INCOME TAXES 632,953 775,056 676,285
INCOME TAXES (Note 4) 90,800 125,553 88,764
NET INCOME 542,153 649,503 587,521
Less: Net income attributable to noncontrolling interests (Note 17) 17,224 17,224 19,493
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS $ 524,929 $ 632,279 $ 568,028
v3.22.4
APS - CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2022
Dec. 31, 2021
Dec. 31, 2020
NET INCOME $ 500,826 $ 635,944 $ 570,052
Derivative instruments:      
Net unrealized gain (loss), net of tax benefit (expense) of $(615), $(378), and $662 1,873 1,077 (2,089)
Reclassification of net realized gain, net of tax benefit (expense) of $0, $18, and $(171) (Note 15) 0 18 592
Pension and other postretirement benefits activity, net of tax benefit (expense) of $(7,078), $(2,256), and $1,371 (Note 7) 21,553 6,840 (4,203)
Total other comprehensive income (loss) 23,426 7,935 (5,700)
COMPREHENSIVE INCOME 524,252 643,879 564,352
Less: Comprehensive income attributable to noncontrolling interests 17,224 17,224 19,493
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS 507,028 626,655 544,859
Arizona Public Service Company      
NET INCOME 542,153 649,503 587,521
Derivative instruments:      
Net unrealized gain (loss), net of tax benefit (expense) of $(615), $(378), and $662 0 (18) (18)
Reclassification of net realized gain, net of tax benefit (expense) of $0, $18, and $(171) (Note 15) 0 18 592
Pension and other postretirement benefits activity, net of tax benefit (expense) of $(7,078), $(2,256), and $1,371 (Note 7) 19,284 6,038 (5,970)
Total other comprehensive income (loss) 19,284 6,038 (5,396)
COMPREHENSIVE INCOME 561,437 655,541 582,125
Less: Comprehensive income attributable to noncontrolling interests 17,224 17,224 19,493
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS $ 544,213 $ 638,317 $ 562,632
v3.22.4
APS - CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2022
Dec. 31, 2021
Dec. 31, 2020
Net unrealized loss, tax benefit (expense) $ (615) $ (378) $ 662
Reclassification of net realized gain, tax benefit (expense) 0 18 (171)
Pension and other postretirement benefits activity, tax benefit (expense) (7,078) (2,256) 1,371
Arizona Public Service Company      
Net unrealized loss, tax benefit (expense) 0 18 18
Reclassification of net realized gain, tax benefit (expense) 0 18 (171)
Pension and other postretirement benefits activity, tax benefit (expense) $ (6,332) $ (1,990) $ 1,955
v3.22.4
APS - CONSOLIDATED BALANCE SHEETS - USD ($)
$ in Thousands
Dec. 31, 2022
Dec. 31, 2021
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6 and 9)    
Plant in service and held for future use $ 22,452,146 $ 21,688,661
Accumulated depreciation and amortization (7,929,878) (7,504,603)
Net 14,522,268 14,184,058
Construction work in progress 1,882,791 1,329,478
Palo Verde sale leaseback, net of accumulated depreciation of $260,754 and $256,884 (Note 17) 90,296 94,166
Intangible assets, net of accumulated amortization of $817,961 and $737,694 258,880 273,693
Nuclear fuel, net of accumulated amortization of $126,157 and $133,122 100,119 106,039
Total property, plant and equipment 16,854,354 15,987,434
INVESTMENTS AND OTHER ASSETS    
Nuclear decommissioning trusts (Notes 12 and 18) 1,073,410 1,294,757
Other special use funds (Notes 12 and 18) 347,231 358,410
Assets from risk management activities (Note 15) 44,394 46,908
Other assets 125,672 97,884
Total investments and other assets 1,590,707 1,797,959
CURRENT ASSETS    
Cash and cash equivalents 4,832 9,969
Customer and other receivables 453,209 391,923
Accrued unbilled revenues 164,764 133,980
Allowance for doubtful accounts (Note 2) (23,778) (25,354)
Materials and supplies (at average cost) 410,481 349,135
Fossil fuel (at average cost) 40,155 18,032
Income tax receivable (Note 4) 14,086 7,514
Assets from risk management activities (Note 15) 87,835 63,481
Deferred fuel and purchased power regulatory asset (Note 3) 460,561 388,148
Other regulatory assets (Note 3) 78,318 130,376
Other current assets 60,091 83,896
Total current assets 1,750,554 1,551,100
DEFERRED DEBITS    
Regulatory assets (Notes 1, 3 and 4) 1,283,221 1,192,987
Operating lease right-of-use assets (Note 8) 801,688 890,057
Assets for pension and other postretirement benefits (Note 7) 396,599 545,723
Other 46,282 37,962
Total deferred debits 2,527,790 2,666,729
TOTAL ASSETS 22,723,405 22,003,222
EQUITY    
Retained earnings 3,360,347 3,264,719
Accumulated other comprehensive loss (Note 19) (31,435) (54,861)
Total shareholders’ equity 6,048,647 5,906,200
Noncontrolling interests (Note 17) 111,229 115,260
Total equity 6,159,876 6,021,460
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 6) 7,741,286 6,913,735
CURRENT LIABILITIES    
Short-term borrowings (Note 5) 340,720 292,000
Accounts payable 430,425 393,083
Accrued taxes 164,440 168,645
Accrued interest 61,217 57,332
Common dividends payable 97,895 95,988
Customer deposits 41,769 42,293
Liabilities from risk management activities (Note 15) 37,697 4,373
Liabilities for asset retirements (Note 11) 12,232 4,473
Operating lease liabilities (Note 8) 105,210 100,443
Less: current regulatory liabilities 271,575 296,271
Other current liabilities 148,276 151,968
Total current liabilities 1,762,141 1,756,869
DEFERRED CREDITS AND OTHER    
Deferred income taxes (Note 4) 2,384,421 2,311,862
Regulatory liabilities (Notes 1, 3, 4 and 7) 2,061,776 2,499,213
Liabilities for asset retirements (Note 11) 785,530 762,909
Liabilities for pension benefits (Note 7) 116,286 152,865
Customer advances 422,103 257,151
Coal mine reclamation 179,255 174,616
Deferred investment tax credit 180,677 186,570
Unrecognized tax benefits (Note 4) 38,658 4,657
Operating lease liabilities (Note 8) 639,247 728,401
Other 252,149 232,914
Total deferred credits and other 7,060,102 7,311,158
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
TOTAL LIABILITIES AND EQUITY 22,723,405 22,003,222
Arizona Public Service Company    
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6 and 9)    
Plant in service and held for future use 22,448,685 21,685,200
Accumulated depreciation and amortization (7,926,575) (7,501,317)
Net 14,522,110 14,183,883
Construction work in progress 1,829,004 1,327,721
Palo Verde sale leaseback, net of accumulated depreciation of $260,754 and $256,884 (Note 17) 90,296 94,166
Intangible assets, net of accumulated amortization of $817,961 and $737,694 258,725 273,537
Nuclear fuel, net of accumulated amortization of $126,157 and $133,122 100,119 106,039
Total property, plant and equipment 16,800,254 15,985,346
INVESTMENTS AND OTHER ASSETS    
Nuclear decommissioning trusts (Notes 12 and 18) 1,073,410 1,294,757
Other special use funds (Notes 12 and 18) 347,231 358,410
Assets from risk management activities (Note 15) 44,394 46,908
Other assets 43,344 42,440
Total investments and other assets 1,508,379 1,742,515
CURRENT ASSETS    
Cash and cash equivalents 4,042 9,374
Customer and other receivables 448,880 390,533
Accrued unbilled revenues 164,764 133,980
Allowance for doubtful accounts (Note 2) (23,778) (25,354)
Materials and supplies (at average cost) 410,481 349,135
Fossil fuel (at average cost) 40,155 18,032
Income tax receivable (Note 4) 1,102 10,756
Assets from risk management activities (Note 15) 87,704 63,481
Deferred fuel and purchased power regulatory asset (Note 3) 460,561 388,148
Other regulatory assets (Note 3) 78,318 130,376
Other current assets 50,043 57,729
Total current assets 1,722,272 1,526,190
DEFERRED DEBITS    
Regulatory assets (Notes 1, 3 and 4) 1,283,221 1,192,987
Operating lease right-of-use assets (Note 8) 796,544 888,207
Assets for pension and other postretirement benefits (Note 7) 389,142 537,092
Other 44,040 37,319
Total deferred debits 2,512,947 2,655,605
TOTAL ASSETS 22,543,852 21,909,656
EQUITY    
Common stock 178,162 178,162
Additional paid-in capital 3,171,696 3,021,696
Retained earnings 3,607,464 3,470,235
Accumulated other comprehensive loss (Note 19) (15,596) (34,880)
Total shareholders’ equity 6,941,726 6,635,213
Noncontrolling interests (Note 17) 111,229 115,260
Total equity 7,052,955 6,750,473
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 6) 6,793,529 6,266,693
Total capitalization 13,846,484 13,017,166
CURRENT LIABILITIES    
Short-term borrowings (Note 5) 325,000 278,700
Accounts payable 417,732 389,365
Accrued taxes 156,746 152,012
Accrued interest 60,518 56,622
Common dividends payable 97,900 96,000
Customer deposits 41,769 42,293
Liabilities from risk management activities (Note 15) 37,697 4,373
Liabilities for asset retirements (Note 11) 12,232 4,473
Operating lease liabilities (Note 8) 104,728 100,199
Less: current regulatory liabilities 271,575 296,271
Other current liabilities 144,733 145,286
Total current liabilities 1,670,630 1,565,594
DEFERRED CREDITS AND OTHER    
Deferred income taxes (Note 4) 2,385,647 2,331,701
Regulatory liabilities (Notes 1, 3, 4 and 7) 2,061,776 2,499,213
Liabilities for asset retirements (Note 11) 785,530 762,909
Liabilities for pension benefits (Note 7) 108,068 138,328
Customer advances 422,103 257,151
Coal mine reclamation 179,255 174,616
Deferred investment tax credit 180,677 186,570
Unrecognized tax benefits (Note 4) 38,658 37,423
Operating lease liabilities (Note 8) 634,199 726,572
Other 230,825 212,413
Total deferred credits and other 7,026,738 7,326,896
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
TOTAL LIABILITIES AND EQUITY $ 22,543,852 $ 21,909,656
v3.22.4
APS - CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($)
$ in Thousands
Dec. 31, 2022
Dec. 31, 2021
PROPERTY, PLANT AND EQUIPMENT    
Accumulated depreciation of Palo Verde sale leaseback $ 260,754 $ 256,884
Accumulated amortization on intangible assets 817,961 737,694
Accumulated amortization on nuclear fuel $ 126,157 $ 133,122
EQUITY    
Common stock, authorized shares (in shares) 150,000,000 150,000,000
Common stock, issued shares (in shares) 113,247,189 113,014,528
Treasury stock (in shares) 73,613 87,608
Arizona Public Service Company    
PROPERTY, PLANT AND EQUIPMENT    
Accumulated depreciation of Palo Verde sale leaseback $ 260,754 $ 256,884
Accumulated amortization on intangible assets 816,827 736,560
Accumulated amortization on nuclear fuel $ 126,157 $ 133,122
v3.22.4
APS - CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2022
Dec. 31, 2021
Dec. 31, 2020
CASH FLOWS FROM OPERATING ACTIVITIES      
Net income $ 500,826 $ 635,944 $ 570,052
Adjustments to reconcile net income to net cash provided by operating activities:      
Depreciation and amortization including nuclear fuel 817,814 719,141 686,253
Deferred fuel and purchased power (291,992) (256,871) (93,651)
Deferred fuel and purchased power amortization 219,579 44,557 (12,047)
Allowance for equity funds used during construction (45,263) (41,737) (33,776)
Deferred income taxes 43,202 117,471 69,469
Deferred investment tax credit (5,893) (4,802) (5,096)
Changes in current assets and liabilities:      
Customer and other receivables (63,869) (72,559) (18,191)
Accrued unbilled revenues (30,784) (1,783) (4,032)
Materials, supplies and fossil fuel (83,469) (32,870) 11,623
Income tax receivable (6,572) (722) 14,935
Other current assets 76,067 (22,720) (30,640)
Accounts payable 90,076 20,267 (6,059)
Accrued taxes (4,205) 9,094 14,652
Other current liabilities (6,056) (52,086) 22,520
Change in margin and collateral accounts — assets 22 (50) 404
Change in margin and collateral accounts — liabilities 4,200 350 100
Change in unrecognized tax benefits (1,989) (568) 2,220
Change in long-term regulatory liabilities (332,470) 57,549 13,017
Change in other long-term assets 276,821 (246,473) (67,453)
Change in other long-term liabilities 68,677 (29,578) (186,227)
Net cash provided by operating activities 1,241,441 860,014 966,365
CASH FLOWS FROM INVESTING ACTIVITIES      
Capital expenditures (1,707,490) (1,473,475) (1,326,584)
Contributions in aid of construction 137,436 105,654 62,503
Allowance for borrowed funds used during construction (28,030) (21,052) (18,530)
Proceeds from nuclear decommissioning trust sales and other special use funds 1,207,713 1,720,966 819,518
Investment in nuclear decommissioning trust and other special use funds (1,212,063) (1,725,480) (822,608)
Other (15,612) 6,458 7,883
Net cash used for investing activities (1,618,046) (1,386,929) (1,277,818)
CASH FLOWS FROM FINANCING ACTIVITIES      
Issuance of long-term debt 875,537 746,999 1,596,672
Repayment of long-term debt (150,000) 0 (915,150)
Short-term borrowings and (repayments) — net 48,720 142,000 73,325
Short-term debt borrowings under revolving credit facility 0 0 751,690
Short-term debt repayments under revolving credit facility 0 (19,000) (770,690)
Dividends paid on common stock (378,881) (369,478) (350,577)
Noncontrolling interests (21,255) (21,255) (22,743)
Net cash provided by financing activities 371,468 476,916 361,138
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (5,137) (49,999) 49,685
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 9,969 59,968 10,283
CASH AND CASH EQUIVALENTS AT END OF YEAR 4,832 9,969 59,968
Arizona Public Service Company      
CASH FLOWS FROM OPERATING ACTIVITIES      
Net income 542,153 649,503 587,521
Adjustments to reconcile net income to net cash provided by operating activities:      
Depreciation and amortization including nuclear fuel 817,729 719,039 686,168
Deferred fuel and purchased power (291,992) (256,871) (93,651)
Deferred fuel and purchased power amortization 219,579 44,557 (12,047)
Allowance for equity funds used during construction (45,263) (41,737) (33,776)
Deferred income taxes (6,817) 128,852 36,462
Deferred investment tax credit (5,893) (4,802) (5,096)
Changes in current assets and liabilities:      
Customer and other receivables (60,930) (72,101) (28,206)
Accrued unbilled revenues (30,784) (1,783) (4,032)
Materials, supplies and fossil fuel (83,469) (32,870) 11,623
Income tax receivable 9,654 (10,756) 7,313
Other current assets 59,948 (25,587) (24,669)
Accounts payable 79,492 23,510 (4,503)
Accrued taxes 4,734 3,042 12,642
Other current liabilities (3,010) (61,647) 29,587
Change in margin and collateral accounts — assets 22 (50) 404
Change in margin and collateral accounts — liabilities 4,200 350 100
Change in unrecognized tax benefits (1,989) (568) 2,220
Change in long-term regulatory liabilities (332,470) 57,549 13,017
Change in other long-term assets 288,077 (231,804) (65,139)
Change in other long-term liabilities 67,131 (20,272) (186,871)
Net cash provided by operating activities 1,230,102 865,554 929,067
CASH FLOWS FROM INVESTING ACTIVITIES      
Capital expenditures (1,655,051) (1,471,795) (1,326,584)
Contributions in aid of construction 137,436 105,654 62,503
Allowance for borrowed funds used during construction (26,839) (21,052) (18,530)
Proceeds from nuclear decommissioning trust sales and other special use funds 1,207,713 1,720,966 819,518
Investment in nuclear decommissioning trust and other special use funds (1,212,063) (1,725,480) (822,608)
Other (727) 273 (554)
Net cash used for investing activities (1,549,531) (1,391,434) (1,286,255)
CASH FLOWS FROM FINANCING ACTIVITIES      
Issuance of long-term debt 524,852 446,999 1,099,722
Repayment of long-term debt 0 0 (465,150)
Short-term borrowings and (repayments) — net 46,300 278,700 0
Short-term debt borrowings under revolving credit facility 0 0 540,000
Short-term debt repayments under revolving credit facility 0 0 (540,000)
Dividends paid on common stock (385,800) (376,500) (357,500)
Equity infusion from Pinnacle West 150,000 150,000 150,000
Noncontrolling interests (21,255) (21,255) (22,743)
Net cash provided by financing activities 314,097 477,944 404,329
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (5,332) (47,936) 47,141
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 9,374 57,310 10,169
CASH AND CASH EQUIVALENTS AT END OF YEAR $ 4,042 $ 9,374 $ 57,310
v3.22.4
APS - 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, 2019   112,540,126         71,264,947        
Beginning 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, Common Stock, Net 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         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, Common Stock, Net 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
Increase (Decrease) in Shareholders' Equity                      
Equity infusion from Pinnacle West           150,000   150,000      
Net income 500,826   483,602   17,224 542,153     524,929   17,224
Other comprehensive income (loss) 23,426     23,426   19,284       19,284  
Dividends, Common Stock, Net 387,975   387,975     387,700     387,700    
Capital activities by noncontrolling interests (21,255)       (21,255) (21,255)         (21,255)
Other $ 2 $ 1 1                
Ending balance (in shares) at Dec. 31, 2022 113,247,189 113,247,189         71,264,947        
Ending balance at Dec. 31, 2022 $ 6,159,876 $ 2,724,740 $ 3,360,347 $ (31,435) $ 111,229 $ 7,052,955 $ 178,162 $ 3,171,696 $ 3,607,464 $ (15,596) $ 111,229
v3.22.4
Summary of Significant Accounting Policies
 12 Months Ended
Dec. 31, 2022
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 10 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 17 for additional information. We have determined that Pinnacle West is the primary beneficiary of a captive insurance protected cell VIE. As of December 31, 2022, 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 3 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.

Certain cost recovery mechanisms may qualify as 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 3 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, 2022, and 2021 Consolidated Balance Sheets is composed of the following (dollars in thousands):

Property, Plant and Equipment:20222021
Generation$9,563,145 $9,480,572 
Transmission3,589,456 3,402,016 
Distribution7,951,867 7,520,016 
General plant1,347,678 1,286,057 
Plant in service and held for future use
22,452,146 21,688,661 
Accumulated depreciation and amortization(7,929,878)(7,504,603)
Net
14,522,268 14,184,058 
Construction work in progress1,882,791 1,329,478 
Palo Verde sale leaseback, net of accumulated depreciation90,296 94,166 
Intangible assets, net of accumulated amortization258,880 273,693 
Nuclear fuel, net of accumulated amortization100,119 106,039 
Total property, plant and equipment$16,854,354 $15,987,434 

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 11 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, 2022, were as follows:
•Steam generation — 12 years;
•Nuclear plant — 25 years;
•Other generation — 18 years;
•Transmission — 38 years;
•Distribution — 33 years; and
•General plant — 6 years.
 
Depreciation of utility property, plant and equipment is computed on a straight-line, remaining-life basis. Depreciation expense was $632 million in 2022, $575 million in 2021, and $553 million in 2020. For the years 2020 through 2022, the depreciation rates ranged from a low of 1.37% to a high of 12.15%.  The weighted-average depreciation rate was 3.03% in 2022, 2.87% in 2021, and 2.84% in 2020.

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 11 for further information on Asset Retirement Obligations.

Allowance for Funds Used During Construction
 
AFUDC represents the approximate net composite interest cost of borrowed funds and an allowed return on the equity funds used for construction of regulated utility plant.  Both the debt and equity components of AFUDC are non-cash amounts within the Consolidated Statements of Income.  Plant 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 5.75% for 2022, 6.75% for 2021, and 6.72% for 2020.  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 provided a simplified approach that companies may have elected to implement in order to minimize the significant distorted effect on the AFUDC formula which resulted from increased short-term debt financing during the COVID-19 pandemic.  APS 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 left all other aspects of the AFUDC formula composite rate calculation unchanged. This change impacted the AFUDC composite rate in 2020 and 2021 but did not impact prior years or 2022.  Furthermore, the change in the composite rate calculation did 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 net realizable value, 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 6 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 12 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 as well as interest rate risk.  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 15 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 7 for additional information on pension and other postretirement benefits.
 
Nuclear Fuel
 
APS amortizes nuclear fuel by using the unit-of-production method.  The unit-of-production method is based on actual physical usage.  APS divides the cost of the fuel by the estimated number of thermal units it expects to produce with that fuel.  APS then multiplies that rate by the number of thermal units produced within the current period.  This calculation determines the current period nuclear fuel expense.
 
APS also charges nuclear fuel expense for the interim storage and permanent disposal of spent nuclear fuel.  The DOE is responsible for the permanent disposal of spent nuclear fuel and charged APS
$0.001 per kWh of nuclear generation through May 2014, at which point the DOE reduced the fee to zero.  In accordance with a settlement agreement with the DOE in August 2014 for interim storage, we accrued a receivable and an offsetting regulatory liability through the settlement period which ended December of 2022. See Note 10 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 4 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,
 202220212020
Cash paid (received) during the period for:   
Income taxes, net of refunds$46,227 $229 $(3,019)
Interest, net of amounts capitalized245,271 227,584 216,951 
Significant non-cash investing and financing activities:   
Accrued capital expenditures$114,999 $167,733 $113,502 
Dividends declared but not paid97,895 95,988 93,531 

The following table summarizes supplemental APS cash flow information for each of the last three years (dollars in thousands):
 Year ended December 31,
 202220212020
Cash paid during the period for:   
Income taxes, net of refunds$95,985 $19,783 $41,176 
Interest, net of amounts capitalized227,159 217,749 206,328 
Significant non-cash investing and financing activities:   
Accrued capital expenditures$116,533 $167,657 $113,502 
Dividends declared but not paid97,900 96,000 93,500 
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 $84 million in 2022, $80 million in 2021, and $70 million in 2020.  Estimated amortization expense on existing intangible assets over the next five years is $81 million in 2023, $60 million in 2024, $48 million in 2025, $33 million in 2026, and $14 million in 2027.  At December 31, 2022, 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 12 and 18 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 3. We also may enter into lease agreements related to vehicles, office space, land, and other equipment. See Note 8 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, 2022, 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.
v3.22.4
Revenue
 12 Months Ended
Dec. 31, 2022
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,
202220212020
Retail Electric Service
Residential$2,046,111 $1,913,324 $1,929,178 (a)
Non-Residential1,767,616 1,586,940 1,486,098 
Wholesale Energy Sales383,126 187,640 93,345 
Transmission Services for Others116,628 99,285 65,859 
Other Sources10,904 16,646 12,502 
Total Operating Revenues$4,324,385 $3,803,835 $3,586,982 
(a)     Residential revenues for the year ended December 31, 2020, reflect a $24 million reduction related to the Arizona Attorney General matter. See Note 10.

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, 2022, 2021 and 2020 were $4,302 million, $3,760 million, and $3,533 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, 2022, 2021 and 2020, our revenues that do not qualify as revenue from contracts with customers were $22 million, $44 million and $54 million, respectively. This amount includes revenues related 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 3 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, 2022, and 2021.

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. We continue to monitor the impacts of our disconnection policies, payment arrangements, among other considerations impacting our estimated write-off factor, and 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, 2022Year Ended December 31, 2021Year Ended December 31, 2020
Allowance for doubtful accounts, balance at beginning of period$25,354 $19,782 $8,171 
Bad debt expense17,006 22,251 20,633 
Actual write-offs(18,582)(16,679)(9,022)
Allowance for doubtful accounts, balance at end of period$23,778 $25,354 $19,782 
v3.22.4
Regulatory Matters
 12 Months Ended
Dec. 31, 2022
Regulated Operations [Abstract]  
Regulatory Matters Regulatory Matters
2022 Retail Rate Case

APS filed an application with the ACC on October 28, 2022 (the “2022 Rate Case”) seeking an increase in annual retail base rates on the date rates become effective (“Day 1”) of a net $460 million. This Day 1 net impact represents a total base revenue deficiency of $772 million offset by proposed adjustor transfers of cost recovery to annual retail rates and adjustor mechanism modifications. The average annual customer bill impact of APS’s request on Day 1 is an increase of 13.6%.
The principal provisions of APS’s application are:

•a test year comprised of twelve months ended June 30, 2022, adjusted as described below;
•an original cost rate base of $10.5 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 StructureCost of Capital
Long-term debt48.07 %3.85 %
Common stock equity51.93 %10.25 %
Weighted-average cost of capital7.17 %

•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 $0.038321 per kWh for the portion of APS’s retail base rates attributable to fuel and purchased power costs (“Base Fuel Rate”);
•modification of its adjustment mechanisms including:
▪eliminate the Environmental Improvement Surcharge and collect costs through base rates,
▪eliminate the Lost Fixed Cost Recovery mechanism and collect costs through base rates and the Demand Side Management Adjustment Charge (“DSMAC”),
▪maintain as inactive the Tax Expense Adjustor Mechanism,
▪maintain the Transmission Cost Adjustment mechanism,
▪modify the performance incentive in the DSMAC, and
▪modify the Renewable Energy Adjustment Charge to include recovery of capital carrying costs of APS owned renewable and storage resources;
•changes to its limited-income program, including a second tier to provide an additional discount for customers with greater need; and
•twelve months of post-Test Year plant investments to reflect used and useful projects that will be placed into service prior to July 1, 2023.

APS requested that the increase become effective December 1, 2023. The hearing for this rate case is currently scheduled to begin in August 2023. APS cannot predict the outcome of its request.

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 Power Plant (“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 Tax Expense Adjustment Mechanism (“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 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 megawatt (“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 Generating Station (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) an $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, (i) a $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 (“AEM”), to enable more timely recovery of clean investments as APS pursues its clean energy commitment, (vi) recognition that securitization is a potentially useful financing tool to recover the remaining book value of retiring assets and effectuate a transition to a cleaner energy future that APS intends to pursue, provided legislative hurdles are addressed, and (vii) a Coal Community Transition (“CCT”) plan related to the closure or future closure of coal-fired generation facilities, of which $25 million would be funds that are not recoverable through rates with a proposal that the remainder be funded by customers over 10 years.

The CCT plan includes the following proposed components: (i) $100 million that will be paid over 10 years to the Navajo Nation for a sustainable transition to a post-coal economy, which would be funded by customers, (ii) $1.25 million that will be paid over five years to the Navajo Nation to fund an economic development organization, which would be funds not recoverable through rates, (iii) $10 million to facilitate electrification projects within the Navajo Nation, which would be funded equally by funds not recoverable through rates and by customers, (iv) $2.5 million per year in transmission revenue sharing to be paid to the Navajo Nation beginning after the closure of the Four Corners 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 $0.9 million to be paid to the Hopi Tribe related to APS’s ownership interests in the Navajo Plant, and this amount was recognized in its 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 Arizona Renewable Energy Standard and Tariff (“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 $215.5 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. The Arizona Court of Appeals heard oral arguments on November 30, 2022. The Court took the matter under advisement and will issue its decision in due course. 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. 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 completed the implementation of the new on-peak hours for residential customers before the September 1, 2022 deadline. APS cannot predict if the ACC will take any further action on this matter.

Additionally, consistent with the 2019 Rate Case decision, as of April 2022, APS has completed the following payments that will be recoverable through rates related to the CCT: (i) $3.33 million to the Navajo Nation; (ii) $0.5 million to the Navajo County communities; and (iii) $1 million to the Hopi Tribe. Consistent with APS’s commitment to the impacted communities, APS has also completed the following payments: (i) $0.5 million to the Navajo Nation for CCT; (ii) $1.1 million to the Navajo County Communities for CCT and economic development; and (iii) $1.25 million to the Hopi Tribe for CCT and economic development. The ACC has also authorized $1.25 million to be recovered through rates for electrification of homes and businesses on both the Navajo Nation and Hopi reservation. Expenditure of the recoverable funds for electrification of homes and businesses on the Navajo Nation and the Hopi reservations is contingent upon completion of a census of the unelectrified homes and businesses in each that are also within APS service territory.

Matter of Impact of the Closures of Fossil-Based Generation Plan on Impacted Communities

On September 28, 2022, ACC Staff filed their staff report in the Matter of Impact of the Closures of Fossil-Based Generation Plan on Impacted Communities. APS and other interested parties filed comments on the report. On October 21, 2022, ACC Staff filed a revised report and proposed order. The revised report and proposed order recommended that funds for CCT shall not be collected from rate payers. On December 8, 2022, the ACC voted against ACC Staff’s proposed order. APS cannot predict if the ACC will take any further action on this matter.

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. APS cannot predict the outcome of this matter.
2016 Retail Rate Case Filing and the 2017 Settlement Agreement
 
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, 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, among other things, 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.

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. See “2022 Retail Rate Case” above for proposed modifications of adjustment mechanisms in the 2022 rate case.
 
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 Demand Side Management Implementation Plan (“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 waiver of the RES residential and non-residential distributed energy requirements for 2022. On May 18, 2022, the ACC approved the 2022 RES Implementation Plan, including an amendment requiring a stakeholder working group convene to develop a community solar program for the Commission’s consideration at a future date. On September 23, 2022, APS filed a community solar proposal in compliance with the ACC order that was informed by a stakeholder working group. APS is proposing a small, pilot-scale program size of up to 140MW that would be selected through a competitive RFP. The ACC has not yet ruled on the proposal. However, on November 10, 2022, the ACC approved a bifurcated community solar process, directing ACC Staff to develop a statewide policy through additional stakeholder involvement and establishing a separate evidentiary hearing to define other policy components. The community solar program was deferred to the ACC’s Hearing Division so that a formal evidentiary hearing could be held to consider issues of substance related to community solar. APS cannot predict the outcomes of these future activities.

On July 1, 2022, APS filed its 2023 RES Implementation Plan and proposed a budget of approximately $86.2 million, excluding any funding offsets. This budget contains funding for programs to comply with Commission-approved initiatives, including the 2019 Rate Case decision. APS’s budget proposal supports existing approved projects and commitments and requests a waiver of the RES
residential and non-residential distributed energy requirements for 2022. On November 10, 2022, the ACC approved the 2023 RES Implementation Plan, including APS’s requested waiver of the distributed energy requirement for 2023.

In response to an ACC inquiry, the ACC Staff filed a report providing the history of APS’s long-term purchased power contract of the 280 MW Concentrating Solar Power Plant. This report outlines alternative options that the ACC could pursue to address the costs of this contract, which was executed in February 2008. On July 13, 2022, the ACC approved an option to take no action at this time.

Demand Side Management Adjustor Charge.  The ACC Electric Energy Efficiency Standards require APS to submit a 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 Lost Fixed Cost Recovery (“LFCR”) mechanism. See below for discussion of the LFCR.

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 Implementation 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 Implementation Plan that proposed an additional one-time 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 Implementation Plan.

On December 17, 2021, APS filed its 2022 DSM Implementation Plan in accordance with an extension granted in 2021. The 2022 DSM requested a budget of $78.4 million and represents an increase of approximately $14 million in DSM spending above 2021. On November 10, 2022, the ACC approved the 2022 DSM Implementation Plan, including a proposed performance incentive. On November 30, 2022,
APS filed its 2023 DSM Implementation Plan, which requested a budget of $88 million. The ACC has not yet ruled on the 2023 DSM Implementation Plan.

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

•APS records deferrals for recovery or refund to the extent actual retail fuel and purchased power costs vary from the Base Fuel Rate;
•an adjustment to the PSA rate is made annually each February 1 (unless otherwise approved by the ACC) and goes into effect automatically unless suspended by the ACC;
•the PSA uses a forward-looking estimate of fuel and purchased power costs to set the annual PSA rate, which is reconciled to actual costs experienced for each PSA Year (February 1 through January 31) (see the following bullet point);
•the PSA rate includes (a) a “forward component,” under which APS recovers or refunds differences between expected fuel and purchased power costs for the upcoming calendar year and those embedded in the Base Fuel Rate; (b) a “historical component,” under which differences between actual fuel and purchased power costs and those recovered or refunded through the combination of the Base Fuel Rate and the Forward Component are recovered during the next PSA Year; and (c) a “transition component,” under which APS may seek mid-year PSA changes due to large variances between actual fuel and purchased power costs and the combination of the Base Fuel Rate and the Forward Component; and
•the PSA rate may not be increased or decreased more than $0.004 per kWh in a year without permission of the ACC.

The following table shows the changes in the deferred fuel and purchased power regulatory asset for 2022 and 2021 (dollars in thousands):
 Twelve Months Ended
December 31,
 20222021
Beginning balance$388,148 $175,835 
Deferred fuel and purchased power costs — current period291,992 256,871 
Amounts charged to customers(219,579)(44,558)
Ending balance$460,561 $388,148 

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 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 rate of $0.003544 per kWh and 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 to better understand the factors that contributed to the increase in fuel costs.

On April 1, 2022, the ACC filed a final report of its third-party audit findings regarding APS’s fuel and purchased power costs for the period January 2019 through January 2021. The report contains an in-depth review of APS’s fuel and purchased power contracts, its monthly fuel accounting activities, its forecasting and dispatching procedures, and its monthly PSA filings, among other fuel-related activities. The report finds that the APS’s fuel processing accounting practices, dispatching procedures, and procedures for hedging activity are reasonable and appropriate. The report includes several recommendations for the ACC’s consideration, including review of current contracts, maintenance schedules, and certain changes and improvements to the schedules in APS’s monthly PSA filings. On December 27, 2022, ACC Staff filed a proposed order supporting adoption of the recommendations in the third-party audit report, and the ACC approved the proposed order on February 22, 2023.

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.

On November 30, 2022, APS filed its PSA rate for the PSA year beginning February 1, 2023. To address the growing under-collected PSA balance, APS also requested that one of three different options be adopted, including a temporary or permanent increase of the annual cap to $0.006 per kWh. As of October 31, 2022, the amount in the PSA balancing account was approximately $456 million of fuel and purchased power costs. On February 23, 2023, the ACC approved a rate of $0.019074 per kWh that will continue until further notice of the ACC. The rate will become effective with the first billing cycle in March 2023 and is designed to bring the PSA balancing account to near-zero over a 24-month period. APS will also be required to notify the ACC when the PSA balancing account approaches $500,000.

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, and on January 12, 2021, the ACC approved this application. 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, and on December 16, 2021, the ACC approved this application. On February 22, 2022, APS filed an application requesting similar recovery through the PSA for a solar plus energy storage project, and on April 13, 2022, the ACC approved this application. On December 21, 2022, APS filed an application requesting similar recovery through the PSA for a solar plus energy storage project, and on February 22, 2023, the ACC approved this application. For the applications that were approved by the ACC, the ACC has not yet ruled on prudency.
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 $15 million per year).  APS’s February 1, 2023 application requested an increase in the charge to $14.7 million, or $3.3 million over the prior-period charge, and it will become effective with the first billing cycle in April 2023 absent the ACC taking action.
 
Transmission Rates, Transmission Cost Adjustor (“TCA”) 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 Cuts and Job Act (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, 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.

Effective June 1, 2022, APS’s annual wholesale transmission revenue requirement for all users of its transmission system decreased by approximately $33 million for the 12-month period beginning June 1, 2022, in accordance with the FERC-approved formula. Of this net amount, wholesale customer rates decreased by approximately $6.4 million and retail customer rates would have decreased by approximately $26.6 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 $2.4 million, resulting in a reduction to the residential rate and increases to commercial rates. An adjustment to APS’s retail rates to recover FERC-approved transmission charges went into effect automatically on June 1, 2022.

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 for lost 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 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 continued to remain intact and the $11.8 million increase was reflected in APS’s 2022 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 effective on December 1, 2021, did not materially impact its results of operations and financial statements for the year ended December 31, 2021. However, as a result of certain changes made to the LFCR mechanism in the 2019 Rate Case decision, the mechanism no longer qualified for alternative revenue program accounting treatment, which impacts the future timing of related revenue recognition.

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, which was inclusive of the $11.8 million balance from the 2021 filing). On May 9, 2022, the ACC Staff filed its revised report and proposed order regarding APS’s 2022 LFCR adjustment, concluding that APS calculated the adjustment in accordance with its Plan of Administration. On May 18, 2022, the ACC approved the 2022 LFCR adjustment, with a rate effective date of June 1, 2022.

On February 15, 2023, APS filed a letter to the ACC docket stating that, in accordance with Decision No. 78585, APS and ACC Staff have agreed to move the filing date for the annual LFCR adjustment to July 31 each year. APS does not believe further ACC approval is needed to move the filing date, and APS intends to file its 2023 annual LFCR adjustment later in 2023 in accordance with the July 31 deadline.

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 were recorded as a part of the balancing account and were 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 were 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 provided 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 were 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 a subsequent APS rate case.

Net Metering

APS’s 2017 Rate Case Decision provides that payments by utilities for energy exported to the grid from residential DG solar facilities will be determined using a RCP methodology as determined in the ACC’s generic Value and Cost of Distributed Generation docket. RCP is a method that is based on the most recent five-year rolling average price that APS incurs for utility-scale solar projects.  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. The ACC is no longer pursuing development of a forecasted avoided cost methodology as an option for utilities in place of the RCP. Commercial customers, grandfathered residential solar customers, and residential customers with DG systems other than solar facilities continue to qualify for net metering.

In addition, the ACC made the following determinations in the Value and Cost of Distributed Generation docket:

•RCP customers who have interconnected a DG system or submitted an application for interconnection for DG systems will be grandfathered for a period of 20 years from the date the customer’s interconnection application was accepted by the utility (for APS residential customers, as of September 1, 2017, based on APS’s 2017 Rate Case Decision);
•customers with DG solar systems are to be considered a separate class of customers for ratemaking purposes; and
•once an initial export price is set for utilities, 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 a RCP 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. On April 29, 2022, APS filed an application to decrease the RCP price to 8.46 cents per kWh, reflecting a 10% annual reduction, to become effective September 1, 2022. On July 12, 2022, the ACC approved the RCP as filed.
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 heard oral argument on March 8, 2022. On September 27, 2022, the Arizona Supreme Court issued a decision in favor of Burns reversing the Court of Appeals’ decision. The Court held that the ACC acting by a majority of its commissioners may not prevent an individual commissioner from exercising investigatory powers pursuant to certain provisions of the Arizona Constitution and that a commissioner aggrieved by such action may seek judicial recourse by way of declaratory judgment. Pinnacle West and APS do not believe there will be any immediate implications given the underlying issues at hand are moot, but the Company cannot predict if or how this authority may be used by commissioners in the future.

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. Draft energy rules were subsequently issued and a series of revisions were made to the draft rules in 2019 and 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 Energy Efficiency Standard (“EES”) was not included in the proposed rules.

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 revised 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. During the August 2022 Open Meeting, Commissioners voted to postpone a decision on the All-Source RFP and IRP rulemaking package until 2023. 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 January 1, 2030. APS intends to file its next IRP later in 2023. 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. The new rules became effective on April 18, 2022, and APS has employed the calendar method for its disconnection moratorium.

In accordance with the ACC service disconnection rules, APS now uses the calendar based method to suspend the disconnection of customers for nonpayment from June 1 through October 15 each year (“Annual Disconnection Moratorium”). Customers with past due balances of $75 or greater as of the beginning of the Annual Disconnection Moratorium are automatically placed on six-month payment arrangements. In addition, APS voluntarily began waiving late payment fees of its customers (“Late Fee Waivers”) on March 13, 2020. Effective February 1, 2023 late payment fees for residential customers were reinstated. Late payment fees for commercial and industrial customers were reinstated effective May 1, 2022. Since the suspensions and moratoriums on disconnections began, APS has experienced an increase in bad debt expense and the related write-offs of delinquent customer accounts.
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. In April 2022, the Arizona Legislature passed and the Governor signed a bill that repealed the electric deregulation law that had been in place in Arizona since 1998. APS cannot predict what impact, if any, this change will 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 of 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 to 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. The Arizona Court of Appeals heard oral argument on November 30, 2022. The Court took the matter under advisement and will issue its decision in due course. 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, 2022. 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 the Cholla Power Plant (“Cholla”) and cease burning coal at the other APS-owned units (Units 1 and 3) at the plant by the mid-2020s, if the United States Environmental Protection Agency (“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, $37.2 million as of December 31, 2022, 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, $52.6 million as of December 31, 2022, 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, $13.9 million as of December 31, 2022. 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,
 Amortization Through20222021
Pension(a)$637,656 $509,751 
Deferred fuel and purchased power (b) (c)2023460,561 388,148 
Income taxes — AFUDC equity2052179,631 172,393 
Ocotillo deferral (e)2031138,143 147,650 
Retired power plant costs203398,692 114,841 
SCR deferral (e) (f)203197,624 105,771 
Deferred property taxes202741,057 49,626 
Deferred compensation203633,660 33,997 
Income taxes — investment tax credit basis adjustment205623,977 24,768 
Palo Verde VIEs (Note 17)
204620,933 21,094 
Active union medical trust(g)18,226 1,175 
Four Corners cost deferral202415,999 24,075 
Navajo coal reclamation202613,862 16,840 
Lost fixed cost recovery (b)20239,547 63,889 
Loss on reacquired debt20389,468 11,020 
Mead-Phoenix transmission line — contributions in aid of construction20509,048 9,380 
Tax expense adjustor mechanism (b)20315,845 6,501 
OtherVarious8,171 10,592 
Total regulatory assets (d)$1,822,100 $1,711,511 
Less: current regulatory assets$538,879 $518,524 
Total noncurrent regulatory assets$1,283,221 $1,192,987 
(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 7 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.
(g)Collected in retail rates.
The detail of regulatory liabilities is as follows (dollars in thousands):
 December 31,
 Amortization Through20222021
Excess deferred income taxes - ACC — Tax Cuts and Jobs Act (a)2046$971,545 $1,012,448 
Excess deferred income taxes - FERC — Tax Cuts and Jobs Act (a)2058221,877 229,116 
Asset retirement obligations2057354,002 614,683 
Other postretirement benefits(d)270,604 374,816 
Removal costs (c) 106,889 119,580 
Deferred fuel and purchased power — mark-to-market (Note 15)
202496,367 107,601 
Income taxes — change in rates205164,806 67,678 
Four Corners coal reclamation203852,592 55,392 
Income taxes — deferred investment tax credit205648,035 49,601 
Spent nuclear fuel202739,217 45,282 
Renewable energy standard (b)202435,720 38,640 
FERC transmission true up (b)202422,895 34,303 
Property tax deferral (e)202415,521 20,192 
Sundance maintenance203116,893 13,797 
Demand side management (b)20238,461 5,417 
Tax expense adjustor mechanism (b) (e)N/A4,835 4,835 
OtherVarious3,092 2,103 
Total regulatory liabilities$2,333,351 $2,795,484 
Less: current regulatory liabilities$271,575 $296,271 
Total noncurrent regulatory liabilities$2,061,776 $2,499,213 
(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 7.
(e)Balance includes amounts for future regulatory consideration and amortization period determination.
v3.22.4
Income Taxes
 12 Months Ended
Dec. 31, 2022
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.    

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 17 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
 202220212020202220212020
Total unrecognized tax benefits, January 1$45,086 $45,655 $43,435 $45,086 $45,655 $43,435 
Additions for tax positions of the current year1,399 3,305 3,418 1,399 3,305 3,418 
Additions for tax positions of prior years2,069 1,449 1,431 2,069 1,449 1,431 
Reductions for tax positions of prior years for:      
Changes in judgment(3,495)(2,659)(1,965)(3,495)(2,659)(1,965)
Settlements with taxing authorities— — — — — — 
Lapses of applicable statute of limitations(1,962)(2,664)(664)(1,962)(2,664)(664)
Total unrecognized tax benefits, December 31$43,097 $45,086 $45,655 $43,097 $45,086 $45,655 

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
 202220212020202220212020
Tax positions, that if recognized, would decrease our effective tax rate$28,246 $26,300 $25,714 $28,246 $26,300 $25,714 

As of the balance sheet date, the tax year ended December 31, 2019, 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 2018.
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
 202220212020202220212020
Unrecognized tax benefit interest expense/(benefit) recognized$(139)$(535)$266 $(139)$(535)$266 

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
 202220212020202220212020
Unrecognized tax benefit interest accrued $1,181 $1,320 $1,855 $1,181 $1,320 $1,855 

Additionally, as of December 31, 2022, 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,
 202220212020202220212020
Current:   
Federal$35,617 $(5,041)$11,869 $103,349 $1,514 $57,299 
State1,950 2,458 1,932 161 (11)99 
Total current37,567 (2,583)13,801 103,510 1,503 57,398 
Deferred:      
Federal23,693 95,327 53,398 (31,860)101,175 15,122 
State13,567 17,342 10,974 19,150 22,875 16,244 
Total deferred37,260 112,669 64,372 (12,710)124,050 31,366 
Income tax expense/(benefit)$74,827 $110,086 $78,173 $90,800 $125,553 $88,764 
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,
 202220212020202220212020
Federal income tax expense at statutory rate$120,887 $156,666 $136,127 $132,920 $162,762 $142,020 
Increases (reductions) in tax expense resulting from:      
State income tax net of federal income tax benefit17,740 22,656 19,146 19,000 23,339 20,124 
State income tax credits net of federal income tax benefit(5,482)(7,015)(8,951)(3,744)(5,277)(7,213)
Net operating loss carryback tax benefit— (5,915)— — — — 
Excess deferred income taxes — Tax Cuts and Jobs Act(36,241)(36,558)(50,543)(36,241)(36,558)(50,543)
Allowance for equity funds used during construction (see Note 1)
(4,629)(4,180)(2,747)(4,629)(4,180)(2,747)
Palo Verde VIE noncontrolling interest (see Note 17)
(3,617)(3,617)(4,094)(3,617)(3,617)(4,094)
Investment tax credit amortization(5,608)(7,620)(7,510)(5,608)(7,620)(7,510)
   Other federal income tax credits(10,867)(6,976)(4,616)(7,721)(3,912)(3,035)
Other2,644 2,645 1,361 440 616 1,762 
Income tax expense/(benefit)$74,827 $110,086 $78,173 $90,800 $125,553 $88,764 
     The components of the net deferred income tax liability were as follows (dollars in thousands):
Pinnacle West ConsolidatedAPS Consolidated
 December 31,December 31,
 2022202120222021
DEFERRED TAX ASSETS  
Risk management activities$8,826 $677 $8,826 $677 
Regulatory liabilities:   
Excess deferred income taxes — Tax Cuts and Jobs Act295,014 306,915 295,014 306,915 
Asset retirement obligation and removal costs107,104 174,952 107,104 174,952 
Unamortized investment tax credits48,035 49,601 48,035 49,601 
Other postretirement benefits66,893 92,654 66,893 92,654 
Other62,915 65,815 62,915 65,815 
Operating lease liabilities184,030 204,890 182,663 204,378 
Pension liabilities33,674 42,136 30,436 37,814 
Coal reclamation liabilities44,312 43,165 44,312 43,165 
Renewable energy incentives19,948 22,646 19,948 22,646 
Credit and loss carryforwards37,647 57,077 13,654 18,902 
Other72,605 74,184 72,605 74,184 
Total deferred tax assets981,003 1,134,712 952,405 1,091,703 
DEFERRED TAX LIABILITIES   
Plant-related(2,518,164)(2,570,613)(2,518,164)(2,570,613)
Risk management activities(32,648)(27,276)(32,648)(27,276)
Pension and other postretirement assets(96,845)(133,624)(96,196)(132,769)
Other special use funds(57,572)(64,610)(57,572)(64,610)
Operating lease right-of-use assets(184,030)(204,890)(182,663)(204,378)
Regulatory assets:   
Allowance for equity funds used during construction(44,405)(42,616)(44,405)(42,616)
Deferred fuel and purchased power(114,232)(96,033)(114,232)(96,033)
Pension benefits(157,629)(126,010)(157,629)(126,010)
Retired power plant costs (24,397)(28,389)(24,397)(28,389)
Other(103,023)(123,902)(103,023)(123,902)
Other(32,479)(28,611)(7,123)(6,808)
Total deferred tax liabilities(3,365,424)(3,446,574)(3,338,052)(3,423,404)
Deferred income taxes — net$(2,384,421)$(2,311,862)$(2,385,647)$(2,331,701)
As of December 31, 2022, PNW consolidated deferred tax assets for credit and loss carryforwards relate to state credit carryforwards net of federal benefit of $43 million, which first begin to expire in 2024. PNW consolidated credit and loss carryforwards amount above has been reduced by $5 million of unrecognized tax benefits.

As of December 31, 2022, APS consolidated deferred tax assets for credit and loss carryforwards relate to state credit carryforwards net of federal benefit of $19 million, which first begin to expire in 2025. APS consolidated credit and loss carryforwards amount above has been reduced by $5 million of unrecognized tax benefits.
v3.22.4
Lines of Credit and Short-Term Borrowings
 12 Months Ended
Dec. 31, 2022
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, 2022December 31, 2021
Pinnacle WestAPSTotalPinnacle WestAPSTotal
Commitments under Credit Facilities$200,000 $1,000,000 $1,200,000 $200,000 $1,000,000 $1,200,000 
Outstanding Commercial Paper, Term Loan and Revolving Credit Facility Borrowings(15,720)(325,000)(340,720)(13,300)(278,700)(292,000)
Amount of Credit Facilities Available$184,280 $675,000 $859,280 $186,700 $721,300 $908,000 
Commitment Fees0.175%0.125%0.175%0.125%

Pinnacle West

At December 31, 2022, Pinnacle West had a $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 credit. At December 31, 2022, Pinnacle West had no outstanding borrowings under its revolving credit facility, no letters of credit outstanding under the credit facility, and $16 million of outstanding commercial paper borrowings.

APS

At December 31, 2022, APS had two $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, 2022, APS had no outstanding borrowings under its revolving credit facilities, no letters of credit outstanding under the credit facilities and $325 million of outstanding commercial paper borrowings.

See “Financial Assurances” in Note 10 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 the 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). On December 15, 2022, the ACC issued a financing order that, among other things, reaffirmed the short-term debt authorization from the 2020 financing order. See Note 6 for additional long-term debt provisions.
v3.22.4
Long-Term Debt and Liquidity Matters
 12 Months Ended
Dec. 31, 2022
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)Rates20222021
APS    
Pollution control bonds:    
Variable2029(b)$163,975 $35,975 
Total pollution control bonds  163,975 35,975 
Senior unsecured notes2024-2050
2.20%-6.88%
6,680,000 6,280,000 
Unamortized discount  (14,548)(14,995)
Unamortized premium  12,368 13,575 
Unamortized debt issuance cost(48,266)(47,862)
Total APS long-term debt  6,793,529 6,266,693 
Less current maturities — — 
Total APS long-term debt less current maturities  6,793,529 6,266,693 
BCE
Los Alamitos equity bridge loan(d)(d)27,575 — 
Los Alamitos construction facility(e)(e)23,110 — 
Unamortized debt issuance cost(135)— 
Total BCE long-term debt50,550 — 
Less current maturities50,685 — 
Total BCE long-term debt less current maturities(135)— 
Pinnacle West    
Senior unsecured notes20251.3%500,000 500,000 
Term loans2024(c)450,000 300,000 
Unamortized discount(25)(34)
Unamortized debt issuance cost(2,083)(2,924)
Total Pinnacle West long-term debt947,892 797,042 
Less current maturities— 150,000 
Total Pinnacle West long-term debt less current maturities947,892 647,042 
TOTAL LONG-TERM DEBT LESS CURRENT MATURITIES
$7,741,286 $6,913,735 
(a)    This schedule does not reflect the timing of redemptions that may occur prior to maturities.
(b)    The weighted-average interest rate for the variable rate pollution control bonds was 3.96% at December 31, 2022, and 0.22% at December 31, 2021. See additional details below.
(c)    The weighted-average interest rate was 5.1% at December 31, 2022, and 0.81% at December 31, 2021. See additional details below.
(d)    The weighted-average interest rate for the variable rate equity bridge loan is 5.18% at December 31, 2022 and will mature on the project’s commercial operation date, expected on or before August 15, 2023. See additional details below.
(e)    The weighted-average interest rate for the variable rate construction facility is 5.71% at December 31, 2022 and will mature on the project’s commercial operation date, expected on or before August 15, 2023. See additional details below.

The following table shows principal payments due on Pinnacle West’s, APS’s and BCE’s total long-term debt (dollars in thousands):
YearConsolidated
Pinnacle West		Consolidated
APS
BCE
2023$50,685 $— $50,685 
2024700,000 250,000 — 
2025800,000 300,000 — 
2026250,000 250,000 — 
2027300,000 300,000 — 
Thereafter5,743,975 5,743,975 — 
Total$7,844,660 $6,843,975 $50,685 
 
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, 2022		As of
December 31, 2021
 Carrying
Amount		Fair ValueCarrying
Amount		Fair Value
Pinnacle West$947,892 $905,525 $797,042 $792,735 
APS6,793,529 5,629,491 6,266,693 6,933,619 
BCE50,550 50,685 — — 
Total$7,791,971 $6,585,701 $7,063,735 $7,726,354 
 
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 was set to mature 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.
On December 16, 2022, Pinnacle West entered into a $175 million term loan facility that matures December 16, 2024. The proceeds were received on January 6, 2023 and used for general corporate purposes. We recognized the term loan facility as long-term debt upon settlement on January 6, 2023.
 
APS

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.

On September 15, 2022, APS remarketed $128 million of the Maricopa County, Arizona Pollution Control Corporation Revenue Refunding Bonds, 2009 Series B, C, D and E, due May 1, 2029 (the “Bonds”). The Bonds were originally issued on June 26, 2009, and prior to this remarketing were held as treasury bonds. Each series of the Bonds has a principal amount of $32 million. All series of the Bonds have been remarketed and issued in weekly variable interest rate modes and are classified as long-term debt on our Consolidated Balance Sheets.

On November 8, 2022, APS issued $400 million of 6.35% unsecured senior notes that mature December 15, 2032. 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 January 6, 2023, 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 5 and “Financial Assurances” in Note 10 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 31 MW solar and battery storage project in Los Alamitos, California (“Los Alamitos”) that is under development by the subsidiary. The credit agreement consists of an approximately $33 million equity bridge loan facility, an approximately $42 million non-recourse construction facility, and an approximately $5 million letter of credit facility. In connection with the credit agreement, Pinnacle West has issued a guarantee of up to $42 million primarily relating to the equity bridge loan. As of December 31, 2022, $28 million has been drawn from the equity bridge loan and there is a $23 million outstanding balance for the construction facility and $2.5 million letters of credit outstanding under the credit facility. The equity bridge loan and construction facility mature and are due on the project’s commercial operation date, expected on or before August 15, 2023.  BCE expects to convert the construction facility into a term loan upon the project’s commercial operation date. On October 19, 2022, BCE executed an interest rate swap to hedge the variable interest rate exposure of this credit facility. See Note 15.
 
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, 2022, the ratio was approximately 57.7% for Pinnacle West and 50.8% 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 of $7.5 billion. On December 15, 2022, the ACC issued a financing order approving APS’s application filed on April 6, 2022 requesting to increase the long-term debt limit from $7.5 billion to $8.0 billion and to exclude financing lease PPAs from the definition of long-term indebtedness for purposes of the ACC financing orders. See Note 5 for additional short-term debt provisions.
v3.22.4
Retirement Plans and Other Postretirement Benefits
 12 Months Ended
Dec. 31, 2022
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 directly 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 12 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 expense, which allows for recovery or return of this regulatory asset/liability. See Note 3.
 
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
 202220212020202220212020
Service cost-benefits earned during the period$55,473 $61,236 $56,233 $16,470 $17,796 $22,236 
Non-service costs (credits):
Interest cost on benefit obligation107,492 98,566 118,567 17,491 16,513 25,857 
Expected return on plan assets(185,775)(202,628)(187,443)(46,042)(41,444)(40,077)
Amortization of:      
Prior service credit— — — (37,789)(37,705)(37,575)
Net actuarial (gain)/loss17,515 15,948 34,612 (12,835)(10,093)— 
Net periodic benefit cost/(benefit)$(5,295)$(26,878)$21,969 $(62,705)$(54,933)$(29,559)
Portion of cost/(benefit) charged to expense$(16,431)$(32,743)$3,386 $(45,042)$(38,657)$(20,966)
 
The following table shows the plans’ changes in the benefit obligations and funded status (dollars in thousands):
 Pension PlansOther Benefits Plans
 2022202120222021
Change in Benefit Obligation    
Benefit obligation at January 1$3,716,824 $3,902,867 $591,841 $624,034 
Service cost55,473 61,236 16,470 17,796 
Interest cost107,492 98,566 17,491 16,513 
Benefit payments(212,565)(207,928)(30,913)(31,280)
Actuarial (gain) loss(857,695)(137,917)(185,428)(35,222)
Benefit obligation at December 312,809,529 3,716,824 409,461 591,841 
Change in Plan Assets    
Fair value of plan assets at January 13,812,041 3,886,544 872,435 961,165 
Actual return on plan assets(787,874)18,169 (193,807)41,432 
Employer contributions— 100,000 — — 
Benefit payments(194,682)(192,672)(26,341)(24,310)
Transfer to active union medical account— — — (105,852)
Fair value of plan assets at December 312,829,485 3,812,041 652,287 872,435 
Funded Status at December 31$19,956 $95,217 $242,826 $280,594 

The following table shows information for pension plans with an accumulated obligation in excess of plan assets (dollars in thousands):
As of December 31,
 20222021
Accumulated benefit obligation126,759 161,086 
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, 2022 and December 31, 2021, therefore the only pension plan with an accumulated benefit obligation in excess of plan assets in 2022 and 2021 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,
 20222021
Projected benefit obligation133,818 169,912 
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, 2022, and December 31, 2021, therefore the only pension plan with a projected benefit obligation in excess of plan assets in 2022 and 2021 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
 2022202120222021
Noncurrent asset$153,773 $265,129 $242,826 $280,594 
Current liability(17,531)(17,047)— — 
Noncurrent liability(116,286)(152,865)— — 
Net amount recognized (funded status)$19,956 $95,217 $242,826 $280,594 
 
The following table shows the details related to accumulated other comprehensive loss (gain) as of December 31, 2022, and 2021 (dollars in thousands): 
 Pension PlansOther Benefits Plans
 2022202120222021
Net actuarial loss (gain)$681,335 $582,895 $(195,095)$(262,352)
Prior service credit— — (76,843)(114,632)
APS’s portion recorded as a regulatory (asset) liability(637,656)(509,751)270,604 374,816 
Income tax expense (benefit)(10,797)(18,081)784 990 
Accumulated other comprehensive loss (gain)$32,882 $55,063 $(550)$(1,178)
 
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,
 20222021202220212020
Discount rate – pension plans5.56 %2.92 %2.92 %2.53 %3.30 %
Discount rate – other benefits plans5.58 %2.98 %2.98 %2.63 %3.42 %
Rate of compensation increase4.57 %4.00 %4.00 %4.00 %4.00 %
Expected long-term return on plan assets - pension plansN/AN/A5.00 %5.30 %5.75 %
Expected long-term return on plan assets - other benefit plansN/AN/A5.35 %4.90 %4.85 %
Initial healthcare cost trend rate (pre-65 participants)6.50 %6.00 %6.00 %6.50 %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)64345
Initial and ultimate healthcare cost trend rate (post-65 participants) (a)2.00 %2.00 %2.00 %2.00 %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 2023, we are assuming a 6.70% long-term rate of return for pension assets and 6.95% (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-seeking assets.  The target allocation between return-seeking 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-seeking assets are intended to provide a reasonable long-term rate of investment return with a prudent level of volatility.  Return-seeking 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-seeking 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 2022, the target and actual allocation for the pension plan at December 31, 2022, are as follows:
 Target AllocationActual Allocation
Long-term fixed income assets80 %78 %
Return-seeking assets20 %22 %
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-seeking 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, 2022, 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, 2022:
Actual Allocation
Long-term fixed income assets62 %
Return-seeking assets38 %
Total100 %
See Note 12 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. 

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, 2022, 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, 2022, by asset category, are as follows (dollars in thousands):
 
 Level 1Level 2Other (a)Total
Pension Plan:   
Cash and cash equivalents$1,252 $— $— $1,252 
Fixed income securities:   
Corporate— 1,374,810 — 1,374,810 
U.S. Treasury635,245 — — 635,245 
Other (b)— 131,999 — 131,999 
Common stock equities (c)155,231 — — 155,231 
Mutual funds (d)101,557 — — 101,557 
Common and collective trusts:
Equities— — 181,912 181,912 
Real estate— — 174,228 174,228 
Partnerships— — 13,359 13,359 
Short-term investments and other (e)— — 59,892 59,892 
Total$893,285 $1,506,809 $429,391 $2,829,485 
Other Benefits:    
Cash and cash equivalents$204 $— $— $204 
Fixed income securities:   
Corporate— 166,879 — 166,879 
U.S. Treasury221,936 — — 221,936 
Other (b)— 7,321 — 7,321 
Common stock equities (c)127,493 — — 127,493 
Mutual funds (d)18,824 — — 18,824 
Common and collective trusts:   
Equities— — 73,956 73,956 
Real estate— — 23,541 23,541 
Short-term investments and other (e)3,274 — 8,859 12,133 
Total$371,731 $174,200 $106,356 $652,287 
(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, 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.
(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 $0 million in 2022, $100 million in 2021, and $100 million in 2020.  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 2023, 2024 or 2025.  With regard to contributions to our other postretirement benefit plan, we did not make a contribution in 2022 or 2021 and do not expect to make any contributions in 2023, 2024 or 2025. The Company was reimbursed
$26 million in 2022, $24 million in 2021, and $26 million in 2020 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
2023$240,034 $31,235 
2024227,234 30,865 
2025223,813 30,251 
2026224,881 30,135 
2027221,976 29,790 
Years 2028-20321,117,192 146,725 
 
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 2022, 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 2022, $12 million for 2021, and $11 million for 2020.
v3.22.4
Leases
 12 Months Ended
Dec. 31, 2022
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 2023 through 2052. 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 17 for a discussion of VIEs.

APS has purchased power lease agreements that 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,
202220212020
Operating Lease Cost - Purchased Power Lease Contracts$104,001 $105,762 68,883 
Operating Lease Cost - Land, Property, and Other Equipment18,061 18,498 18,493 
Total Operating Lease Cost122,062 124,260 87,376 
Variable lease cost (a)122,040 118,969 122,331 
Short-term lease cost9,928 3,872 3,804 
Total lease cost$254,030 $247,101 $213,511 
(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 3. 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, 2022
YearPurchased Power Lease ContractsLand, Property & Equipment LeasesTotal
2023$106,151 $14,254 $120,405 
2024104,315 11,330 115,645 
2025106,582 8,655 115,237 
2026120,016 7,207 127,223 
202789,108 5,292 94,400 
Thereafter210,486 37,873 248,359 
Total lease commitments736,658 84,611 821,269 
Less imputed interest57,682 19,130 76,812 
Total lease liabilities$678,976 $65,481 $744,457 
    
We recognize lease assets and liabilities upon lease commencement. At December 31, 2022, we have various lease arrangements that have been executed but have not yet commenced. These arrangements primarily relate to energy storage assets. The lease commencement dates for these arrangements have experienced delays. APS continues to work with the lessors to determine revised commencement dates. We expected lease commencement dates ranging from June 2023 through June 2025, with lease terms expiring through May 2045. We expect the total fixed consideration paid for these arrangements, which includes both lease and non-lease payments, will approximate $2.7 billion over the 20-year terms of the agreements.

In January 2023, APS modified two existing purchase power operating lease agreements. Among other changes, the modifications extend the expiration dates of these contracts from October 2027 to October 2032 for one of the leases, and from September 2026 to October 2034 for the other lease. These lease agreements previously commenced in 2020 and 2021. In January 2023, as a result of these modifications, APS recorded an additional $537 million of operating lease liabilities and right-of-use operating lease assets. These obligations relate to payments that will occur during the periods 2023 through 2034.
The following tables provide other additional information related to operating lease liabilities (dollars in thousands):
Year Ended December 31, 2022Year Ended December 31, 2021Year Ended December 31, 2020
Cash paid for amounts included in the measurement of lease liabilities — operating cash flows:$118,463 $116,661 $75,097 
Right-of-use operating lease assets obtained in exchange for operating lease liabilities16,990 500,582 441,653 


December 31, 2022December 31, 2021
Weighted average remaining lease term7 years8 years
Weighted average discount rate (a)2.21 %2.13 %
(a)Most of our lease agreements do not contain an implicit rate that is readily determinable. For these agreements we use our incremental borrowing rate to measure the present value of lease liabilities. We determine our incremental borrowing rate at lease commencement based on the rate of interest that we would have to pay to borrow, on a collateralized basis over a similar term, an amount equal to the lease payments in a similar economic environment. We use the implicit rate when it is readily determinable.
v3.22.4
Jointly-Owned Facilities
 12 Months Ended
Dec. 31, 2022
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, 2022 (dollars in thousands):

 Percent
Owned		 Plant in
Service		Accumulated
Depreciation		Construction
Work in
Progress
Generating facilities:     
Palo Verde Units 1 and 329.1 %$1,947,593 $1,099,132 $39,933 
Palo Verde Unit 2 (a)16.8 %659,514 383,775 14,784 
Palo Verde Common28.0 %(b)799,794 346,705 52,631 
Palo Verde Sale Leaseback (a)351,050 260,754 — 
Four Corners Generating Station 63.0 %1,665,042 620,918 46,643 
Cholla Common Facilities (c)50.5 %207,104 140,886 2,988 
Transmission facilities:     
ANPP 500kV System33.4 %(b)133,887 55,704 2,820 
Navajo Southern System26.8 %(b)90,345 36,929 1,945 
Palo Verde — Yuma 500kV System25.4 %(b)24,026 7,559 128 
Four Corners Switchyards61.9 %(b)73,243 20,350 120 
Phoenix — Mead System17.1 %(b)39,705 20,055 51 
Palo Verde — Rudd 500kV System50.0 %95,736 31,118 391 
Morgan — Pinnacle Peak System64.7 %(b)119,785 25,791 96 
Round Valley System50.0 %548 193 — 
Palo Verde — Morgan System87.8 %(b)263,576 34,415 1,414 
Hassayampa — North Gila System80.0 %148,174 22,566 3,771 
Cholla 500kV Switchyard85.7 %8,100 2,380 — 
Saguaro 500kV Switchyard60.0 %21,656 13,809 — 
Kyrene — Knox System50.0 %578 336 — 
Agua Fria Switchyard10.0 %— — 32 
(a)See Note 17.
(b)Weighted-average of interests.
(c)PacifiCorp owns Cholla Unit 4 (see Note 3 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.
v3.22.4
Commitments and Contingencies
 12 Months Ended
Dec. 31, 2022
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. In addition, the settlement agreement provided APS with a method for submitting claims and getting recovery for costs incurred through December 31, 2016, which was extended to December 31, 2022. An additional extension is currently pending.

APS has submitted eight claims pursuant to the terms of the August 18, 2014 settlement agreement, for eight separate time periods during July 1, 2011 through June 30, 2021. The DOE has approved and paid $123.9 million for these claims (APS’s share is $36.0 million). The amounts recovered were primarily recorded as adjustments to a regulatory liability and had no impact on reported net income. In accordance with the 2017 Rate Case Decision, this regulatory liability is being refunded to customers. See Note 4. On October 31, 2022, APS filed its ninth claim pursuant to the terms of the August 18, 2014 settlement agreement in the amount of $14.3 million (APS’s share is $4.2 million). In February 2023, 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 $13.7 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 $13.2 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 $22.3 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 $62.8 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 2023 and 2043 that include required purchase provisions.  APS estimates the contract requirements to be approximately $955 million in 2023; $823 million in 2024; $882 million in 2025; $905 million in 2026; $819 million in 2027; and $8.7 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 8.
 
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,
 20232024202520262027Thereafter
Coal take-or-pay commitments (a)$216,729 $211,823 $232,594 $225,345 $204,845 $880,113 
 
(a)Total take-or-pay commitments are approximately $2.0 billion.  The total net present value of these commitments is approximately $1.6 billion.
 
    APS may spend more to meet its actual fuel requirements than the minimum purchase obligations in our coal take-or-pay contracts. The following table summarizes actual amounts purchased under the coal contracts which include take-or-pay provisions for each of the last three years (dollars in thousands):

 Years Ended December 31,
 202220212020
Total purchases$305,502 $219,958 $189,817 
 
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 $31 million in 2023; $29 million in 2024; $27 million in 2025; $23 million in 2026; $19 million in 2027; and $69 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 $179 million at December 31, 2022, and $175 million at December 31, 2021. Under our current coal supply agreements, APS expects to make payments for the final mine reclamation as follows: $18 million in 2023; $19 million in 2024; $20 million in 2025; $21 million in 2026; $22 million in 2027; and $25 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”). The RI/FS for OU3 was finalized and submitted to EPA at the end of 2022. APS cannot predict the EPA’s timing with respect to this matter. 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 ultimate remediation requirements are not yet finalized by EPA, 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 ancillary service provider lawsuit, filed a third-party complaint seeking contribution for its liability, if any, from APS and 28 other third-party defendants. While this lawsuit remains pending, on September 30, 2022, the U.S. District Court for the District of Arizona granted partial summary judgment to the direct defendants for $20.7 million of the $21 million in CERCLA response costs claimed by the service provider. We are unable to predict the outcome of any further litigation related to the remaining response costs at issue in this litigation; however, we do not expect the outcome to have a material impact on our financial position, results of operations, or cash flows.

On February 28, 2022, EPA provided APS with a request for information under CERCLA related to APS’s Ocotillo power plant site located in Tempe, Arizona. In particular, EPA seeks information from APS regarding APS’s use, storage, and disposal of substances containing per-and polyfluoroalkyl (“PFAS”) compounds at the Ocotillo power plant site in order to aid EPA’s investigation into actual or threatened releases of PFAS into groundwater within the South Indian Bend Wash (“SIBW”) Superfund site. The SIBW Superfund site includes the APS Ocotillo power plant site. APS filed its response to this information request on April 29, 2022. On January 17, 2023, EPA contacted APS to inform the Company that it would be commencing on-site investigations within the SIBW site, including the Ocotillo power plant, and performing a remedial investigation and feasibility study related to potential PFAS impacts to groundwater over the next two to three years. At the present time, we are unable to predict the outcome of this matter and expenditures related to this matter cannot be reasonably estimated.

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. The Arizona Court of Appeals heard oral arguments on November 30, 2022. The Court took the matter under advisement and will issue its decision in due course. 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, 2022. 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 3 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. 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 3 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, including supporting the passage of new state legislation providing ADEQ with appropriate permitting authority for CCR under the state solid waste management 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. The proposal remains pending.

•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.

•With respect to APS’s Cholla facility, APS’s application for alternative closure was submitted to EPA on November 30, 2020. While EPA has deemed APS’s application administratively “complete,” the Agency’s approval remains pending. If granted, this application would allow the continued disposal of CCR within Cholla’s existing unlined CCR surface impoundments until the required date for ceasing coal-fired boiler operations in April 2025. This application will be subject to public comment and, potentially, judicial review. We expect to have a proposed decision from EPA regarding Cholla sometime in 2023.

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, APS cannot predict any ultimate impacts to the Company; however, at this time APS does not believe the cost estimates for Cholla and any potential change to the cost estimate for Four Corners would have a material impact on its 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 decision, which endorsed an expansive view of the federal Clean Air Act consistent with EPA’s 2015 CPP, was subsequently reversed by the U.S. Supreme Court on June 30, 2022. While the current administration has expressed its intent to develop new carbon emission regulations governing existing power plants sometime in 2023, such action will be constrained by the U.S. Supreme Court’s decision that the CPP violated the Clean Air Act. Nonetheless, we cannot at this time predict the outcome of pending EPA rulemaking proceedings related to 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 fossil-fuel powered 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. While 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 parties to this litigation (including APS) finalized a settlement on May 2, 2022. This settlement requires investigation of thermal wastewater discharges from Four Corners, administratively closes the litigation filed in January of 2021, and is not expected to have a material impact on APS’s 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 paid 4CA the purchase price over a period of four years pursuant to a secured interest-bearing promissory note, which was paid in full as of June 30, 2022.

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.

BCE Matters

Tenaska Clear Creek Wind, LLC, the developer, owner, and operator of the Clear Creek wind farm, has disputed the proposed cost allocation of system upgrades related to connecting the Clear Creek wind farm to the transmission system and filed a complaint with FERC on May 21, 2021, which was denied on September 9, 2022. Subsequently, Tenaska Clear Creek Wind, LLC filed with FERC a request for rehearing and a motion for stay of the September 9, 2022 order. On October 7, 2022, the request for rehearing was denied by FERC. FERC has not ruled on the motion for stay. Clear Creek has filed a Petition for Review with the U.S. Court of Appeals and Motion for Stay Pending Appeal, both of which are still pending.

Tenaska Clear Creek Wind, LLC filed a second complaint with FERC on May 25, 2022, alleging that the wind farm was being curtailed in a discriminatory manner. The May 25, 2022 Complaint was denied by FERC on December 15, 2022 and Tenaska Clear Creek Wind, LLC requested Rehearing of the denial on January 13, 2023.

Due to the disputed system upgrades and the related curtailment, the Clear Creek wind farm has experienced a significant reduction in power generation that has had a material adverse impact on the project’s ability to generate cash flow for investors. These energy curtailments are expected to persist, unless and until system upgrades are implemented to alleviate the present transmission system congestion,
or the disputes are determined in favor of, or settled in a manner favorable to, Tenaska Clear Creek Wind, LLC. As such, during the fourth quarter of 2022, due to these on-going disputes, cost allocation uncertainties, and no probable favorable resolution, BCE determined its equity method investment was fully impaired. Prior to the impairment, the investment had a carrying value of $17.1 million, which has been written-down to reflect the investment’s estimated fair value of zero as of December 31, 2022. Pinnacle West’s Consolidated Statement of Income for the year ended December 31, 2022 includes an after-tax loss of $12.8 million relating to this impairment.

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, 2022, standby letters of credit totaled approximately $10 million and will expire in 2023. As of December 31, 2022, surety bonds expiring through 2025 totaled approximately $8 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, 2022. 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. As of December 31, 2022 there is approximately $34 million of remaining guarantees primarily relating to the PTC Guarantees that is expected to terminate by 2030.
In connection with the credit agreement entered into by a special purpose subsidiary of BCE on February 11, 2022, Pinnacle West has issued a guarantee of up to $42 million primarily related to the bridge loan. See Note 6 for additional details.
v3.22.4
Asset Retirement Obligations
 12 Months Ended
Dec. 31, 2022
Asset Retirement Obligation Disclosure [Abstract]  
Asset Retirement Obligations Asset Retirement Obligations
 
In 2022, APS did not revise any cost estimates related to existing AROs, and no new AROs were necessary.

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 3 and 10.

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

 20222021
Asset retirement obligations at the beginning of year$767,382 $705,083 
Changes attributable to:  
Accretion expense41,240 38,437 
Settlements(10,860)(4,111)
Estimated cash flow revisions— 27,973 
Asset retirement obligations at the end of year$797,762 $767,382 
 
In accordance with regulatory accounting, APS accrues removal costs for its regulated utility assets, even if there is no legal obligation for removal.  See detail of regulatory liabilities in Note 3.
v3.22.4
Fair Value Measurements
 12 Months Ended
Dec. 31, 2022
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.

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 7 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 — Energy 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. 

Risk Management Activities — Interest Rate Derivatives

Our interest rate derivative instruments relate to an interest rate swap, which is valued using financial models that utilize observable inputs for similar instruments and are classified as Level 2. Inputs include yield curves and credit quality of the counterparties.
 
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 18 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, 2022, 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$— $127,129 $26,132 $(21,163)(a)$132,098 
Interest rate swaps— 131 — — 131 
Subtotal risk management activities - derivative instruments— 127,260 26,132 (21,163)132,229 
Nuclear decommissioning trust:
Equity securities14,658 — — 3,827 (b)18,485 
U.S. commingled equity funds— — — 472,582 (c)472,582 
U.S. Treasury debt211,923 — — — 211,923 
Corporate debt— 149,226 — — 149,226 
Mortgage-backed securities— 147,938 — — 147,938 
Municipal bonds— 64,881 — — 64,881 
Other fixed income— 8,375 — — 8,375 
Subtotal nuclear decommissioning trust226,581 370,420 — 476,409 1,073,410 
Other special use funds:
Equity securities66,974 — — 963 (b)67,937 
U.S. Treasury debt275,267 — — — 275,267 
Municipal bonds— 4,027 — — 4,027 
Subtotal other special use funds342,241 4,027 — 963 347,231 
Total assets$568,822 $501,707 $26,132 $456,209 $1,552,870 
LIABILITIES
Risk management activities — derivative instruments:
Commodity contracts$— $(25,874)$(31,020)$15,357 (a)$(41,537)
Interest rate swaps— (909)— — (909)
Subtotal risk management activities - derivative instruments— (26,783)(31,020)15,357 (42,446)
Total liabilities$— $(26,783)$(31,020)$15,357 $(42,446)
(a)Represents counterparty netting, margin, and collateral. See Note 15.
(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, 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 15.
(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 3.
 
Because our forward commodity contracts classified as Level 3 are currently in a net purchase position, we would expect price increases of the underlying commodity to result in increases in the net fair value of the related contracts.  Conversely, if the price of the underlying commodity decreases, the net fair value of the related contracts would likely decrease.

Other unobservable valuation inputs include credit and liquidity reserves which do not have a material impact on our valuations; however, significant changes in these inputs could also result in higher or lower fair value measurements.

The following tables provide information regarding our significant unobservable inputs used to value our risk management derivative Level 3 instruments at December 31, 2022 and December 31, 2021:

December 31, 2022
 Fair Value (thousands) 		ValuationSignificantWeighted-Average
Commodity ContractsAssetsLiabilitiesTechniqueUnobservable InputRange (b)
Electricity:
Forward Contracts (a)$26,132 $1,759 Discounted cash flowsElectricity forward price (per MWh)
$37.79
-
$310.69
$163.92 
Natural Gas:
Forward Contracts (a)— 29,261 Discounted cash flowsNatural gas forward price (per MMBtu)
$(11.81)
-
$0.00
$(5.08)
Total$26,132 $31,020 
(a)Includes swaps and physical and financial contracts.
(b)Unobservable inputs were weighted by the relative fair value of the instrument.

 
December 31, 2021
 Fair Value (thousands) 		ValuationSignificantWeighted-Average
Commodity ContractsAssetsLiabilitiesTechniqueUnobservable InputRange(b)
Natural Gas:
Forward Contracts (a)$— $2,738 Discounted cash flowsNatural gas forward price (per MMBtu)$(0.76)-
 $(0.65)
$(0.71)
Total$— $2,738 
(a)Includes swaps and physical and financial contracts.
(b)Unobservable inputs were weighted by the relative fair value of the instrument.
The following table shows the changes in fair value for our risk management activities’ assets and liabilities that are measured at fair value on a recurring basis using Level 3 inputs for the years ended December 31, 2022 and 2021 (dollars in thousands):
 Year Ended
December 31,
Commodity Contracts20222021
Net derivative balance at beginning of period$(2,738)$(1,102)
Total net gains (losses) realized/unrealized:
Deferred as a regulatory asset or liability(374)13,827 
Settlements(1,123)(15,463)
Transfers into Level 3 from Level 2(846)— 
Transfers from Level 3 into Level 2193 — 
Net derivative balance at end of period$(4,888)$(2,738)
Net unrealized gains included in earnings related to instruments still held at end of period$— $— 

Transfers in or out of Level 3 are typically related to our long dated energy transactions that extend beyond available quoted periods.

Financial Instruments Not Carried at Fair Value
 
The carrying value of our short-term borrowings approximate fair value and are classified within Level 2 of the fair value hierarchy.  See Note 6 for our long-term debt fair values.

Nonrecurring Fair Value Measurements

As of December 31, 2022, the fair value of BCE’s impaired equity method investment that is measured at fair value on a nonrecurring basis was zero, which was valued using significant unobservable inputs (Level 3). The total tax effected impairment charge included in net income for the year ended December 31, 2022 was $12.8 million. See Note 10 for additional information.
v3.22.4
Earnings Per Share
 12 Months Ended
Dec. 31, 2022
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):
 202220212020
Net income attributable to common shareholders$483,602 $618,720 $550,559 
Weighted average common shares outstanding — basic113,196 112,910 112,666 
Net effect of dilutive securities:   
Contingently issuable performance shares and restricted stock units220 282 276 
Weighted average common shares outstanding — diluted113,416 113,192 112,942 
Earnings per weighted-average common share outstanding
Net income attributable to common shareholders — basic$4.27 $5.48 $4.89 
Net income attributable to common shareholders — diluted$4.26 $5.47 $4.87 
v3.22.4
Stock-Based Compensation
 12 Months Ended
Dec. 31, 2022
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 1.3 million common shares to be available for grant.  As of December 31, 2022, 0.9 million common shares were available for issuance under the 2021 Plan. During 2022, 2021, and 2020, 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 $16 million in 2022, $18 million in 2021, and $18 million in 2020.  The compensation cost capitalized is immaterial for all years. Income tax benefits related to stock-based compensation arrangements were $2 million in 2022, $3 million in 2021, and $4 million in 2020.

As of December 31, 2022, there were approximately $20 million of unrecognized compensation costs related to nonvested stock-based compensation arrangements. We expect to recognize these costs over a weighted-average period of two years. 

The total fair value of shares vested was $25 million in 2022, $22 million in 2021 and $22 million in 2020.
 
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)
 202220212020202220212020
Units granted174,791 152,345 118,403 208,736 161,840 122,830 
Weighted-average grant date fair value$69.66 $76.72 $71.70 $77.63 $82.42 $104.74 
(a)Units granted includes awards that will be cash settled of 0 in 2022, 51,074 in 2021, and 45,646 in 2020. See below for additional information on restricted stock unit grants.
(b)Reflects the target payout level.
 
The following table shows the change of nonvested awards:

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 December 31, 2021
253,156 $79.37 280,682 $92.16 
Granted174,791 69.66 208,736 77.63 
Vested(101,216)84.52 (136,034)103.30 
Forfeited (c)(9,144)76.56 (22,690)78.29 
Nonvested at December 31, 2022
317,587 (a)73.91 330,694 78.91 
Vested Awards Outstanding at December 31, 2022
78,912 136,034 
(a)Includes 69,413 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 $3 million, $4 million, and $6 million in 2022, 2021 and 2020, respectively. This includes cash used to settle restricted stock units of $3 million, $3 million, and $4 million in 2022, 2021 and 2020, 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 and 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.

Beginning in 2022, restricted stock unit awards are issued in stock. Awards include a dividend equivalent feature that allows each award to accrue dividends and treat them as reinvested, from the date of grant until the applicable vesting date. If the award is forfeited the employee is not entitled to the accrued reinvested dividends on those shares. Awards granted to retirement-eligible employees will vest on a pro-rata basis upon the employee’s retirement.

Prior to 2022, awardees typically elected to receive payment in either 100% stock, 100% cash, or 50% in cash and 50% in stock.  Awards included a dividend equivalent feature that accrued dividend rights from the date of grant until the applicable vesting date, plus interest compounded quarterly. If the award was forfeited the employee was not entitled to the accrued dividends on those shares. Awards granted to retirement-eligible employees typically vested upon the employee’s retirement.

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.  The stock units include a dividend equivalent feature that accrues dividend rights from the date of grant to the date of payment, plus interest compounded quarterly.
 
Performance Share Awards
 
Performance share awards are granted to officers and key employees.  The awards contain separate performance metric 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.

Beginning in 2022, performance share awards contain three separate, unrelated performance criteria. The first performance 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 second performance criteria is based upon Pinnacle West’s earnings per share (“EPS”) performance relative to an approved target (i.e., the EPS component). The third performance criteria is based upon APS’s clean MW installed of renewable or other carbon free resources compared to the approved target (i.e., the Clean component). The exact number of shares issued is calculated separately for each performance component and can vary from 0% to 200% of the target award for each separate performance criteria. Shares received include a dividend equivalent feature that treats accrued dividends as reinvested, from the date of grant until the date of payment, equal to the number of vested performance shares. If the award is forfeited or if the performance criteria are not achieved, the employee is not entitled to the dividends on those shares. Awards granted to retirement-eligible employees will vest on a pro-rata basis upon the employee’s retirement.

Prior to 2022, performance share awards had two performance criteria. The first performance criteria was based upon non-financial performance metrics (i.e., the Metric component). The second performance criteria was based upon Pinnacle West’s 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 included a dividend equivalent feature that allows accrued dividend rights from the date of grant until the date of payment, plus interest compounded quarterly, equal to the number of vested performance shares. If the award was forfeited, the employee was not entitled to the accrued dividends on those shares. Awards granted to retirement-eligible employees typically vested upon the employee’s retirement.
 
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 EPS, Clean and Metric component of the respective awards 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 EPS, Clean and Metric component at each balance sheet date. If the EPS, Clean and Metric component criteria are not ultimately achieved, no
compensation cost is recognized relating to the EPS, Clean and Metric component, and any previously recognized compensation cost is reversed. Compensation cost relating to the TSR component of the respective awards is determined using a Monte Carlo simulation valuation model, with compensation cost recognized ratably over the requisite service period, regardless of the number of shares that actually vest.
v3.22.4
Derivative Accounting
 12 Months Ended
Dec. 31, 2022
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 12 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.

Energy Derivatives

For its regulated operations, APS defers for future rate treatment 100% of the unrealized gains and losses on energy derivatives pursuant to the PSA mechanism that would otherwise be recognized in income.  Realized gains and losses on energy derivatives are deferred in accordance with the PSA to the extent the amounts are above or below the Base Fuel Rate. See Note 3.  Gains and losses from energy 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 energy derivatives, which represent both purchases and sales (does not reflect net position):
 
Quantity
CommodityUnit of MeasureDecember 31, 2022December 31, 2021
PowerGWh1,197 — 
GasBillion cubic feet149 155 
 
Gains and Losses from Energy Derivative Instruments
 
The following table provides information about APS’s gains and losses from energy derivative instruments in designated cash flow accounting hedging relationships (dollars in thousands):
Financial Statement Year Ended
December 31,
Commodity ContractsLocation202220212020
Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a)Fuel and purchased power (b)$— $— $(763)
(a)During the years ended December 31, 2022, 2021, and 2020, 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 energy derivative instruments in designated cash flow accounting hedging relationships have lapsed.

The following table provides information about gains and losses from energy derivative instruments not designated as accounting hedging instruments (dollars in thousands):

Financial Statement Year Ended
December 31,
Commodity ContractsLocation202220212020
Net Gain (Loss) Recognized in IncomeFuel and purchased power (a)$307,287 $216,847 $(3,178)
(a)Amounts are before the effect of PSA deferrals.

Energy Derivative Instruments in the Consolidated Balance Sheets

Our energy 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 energy derivative contracts with the counterparty’s non-current energy 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 APS's 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 APS's Consolidated Balance Sheets.

As of December 31, 2022:
 (dollars in thousands) 		Gross 
Recognized 
Derivatives
 (a)		Amounts 
Offset
(b)		Net
 Recognized
 Derivatives		Other
 (c)		Amounts 
Reported on 
Balance Sheets
Current assets$103,484 $(15,808)$87,676 $28 $87,704 
Investments and other assets49,777 (5,383)44,394 — 44,394 
Total assets153,261 (21,191)132,070 28 132,098 
Current liabilities(47,670)15,808 (31,862)(5,835)(37,697)
Deferred credits and other(9,223)5,383 (3,840)— (3,840)
Total liabilities(56,893)21,191 (35,702)(5,835)(41,537)
Total$96,368 $— $96,368 $(5,807)$90,561 
(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 $5,835 thousand and cash margin provided to counterparties of $28 thousand.
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 thousand and cash margin provided to counterparties of $50 thousand.
Interest Rate Derivatives

On October 19, 2022, Bright Canyon Energy entered into an interest rate swap to hedge the variable interest rate exposure relating to the Los Alamitos credit agreement. The transaction qualifies and has been designated as cash flow hedge. The hedge’s gain or loss is reported as a component of other comprehensive income and subsequently will be reclassified into earnings in the periods during which the related interest expense on the debt is incurred. As of December 31, 2022, the interest rate swap has a notional value of $32 million with a maturity in 2041. Relating to this derivative, our Consolidated Balance Sheet as of December 31, 2022 includes approximately $0.9 million reported within the liabilities from risk management activities line within the deferred credits and other section, and $0.1 million reported within the current assets from risk management activities line. For the year ended December 31, 2022, the Consolidated Income Statement includes a pretax loss of approximately $0.8 million recognized in other comprehensive income relating to the interest rate swap. There were no gains or losses reclassified out of accumulated other comprehensive income for the year ended December 31, 2022, and we expect no significant amounts will be reclassified into earnings over the next 12 months.

Credit Risk and Credit Related Contingent Features
 
We are exposed to losses in the event of nonperformance or nonpayment by energy derivative counterparties and have risk management contracts with many energy derivative counterparties. As of December 31, 2022, we have two counterparties for which our exposure represents approximately 21% of Pinnacle West’s $132 million of risk management assets. This exposure relates to master agreements with the counterparties and both 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 energy 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 energy 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 energy derivative instruments that have credit-risk-related contingent features (dollars in thousands):
 December 31, 2022
Aggregate fair value of derivative instruments in a net liability position$56,893 
Cash collateral posted— 
Additional cash collateral in the event credit-risk related contingent features were fully triggered (a)32,884 
(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 $76 million if our debt credit ratings were to fall below investment grade.
v3.22.4
Other Income and Other Expense
 12 Months Ended
Dec. 31, 2022
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 2022, 2021 and 2020 (dollars in thousands):
 
 202220212020
Other income:   
Interest income$7,326 $6,726 $12,210 
Investment gains (losses) — net— — 2,358 
Debt return on Four Corners SCR deferral (Note 3)
— 14,955 15,865 
Debt return on Ocotillo modernization project (Note 3)
— 23,366 26,121 
Miscellaneous590 53 149 
Total other income$7,916 $45,100 $56,703 
Other expense:   
Non-operating costs$(18,619)$(13,008)$(12,400)
Investment gains (losses) — net(20,537)(b)(1,367)— 
Miscellaneous(13,229)(a)(11,021)(45,376)(a)
Total other expense$(52,385)$(25,396)$(57,776)
(a)The 2022 miscellaneous amount includes donations of $7 million to the APS Foundation. 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 3.
(b)The 2022 investment loss is primarily related to an impairment write-off of BCE’s Clear Creek wind farm investment. See Note 10.
 
Other Income and Other Expense - APS
 
The following table provides detail of APS’s other income and other expense for 2022, 2021 and 2020 (dollars in thousands):
 
 202220212020
Other income:   
Interest income$5,332 $4,692 $9,621 
Debt return on Four Corners SCR deferral (Note 3)
— 14,955 15,865 
Debt return on Ocotillo modernization project (Note 3)
— 23,366 26,121 
Miscellaneous556 40 148 
Total other income$5,888 $43,053 $51,755 
Other expense:   
Non-operating costs$(15,579)$(10,080)$(10,659)
Miscellaneous(10,529)(a)(8,817)(43,035)(a)
Total other expense$(26,108)$(18,897)$(53,694)
(a)The 2022 miscellaneous amount includes donations of $7 million to the APS Foundation. 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 3.
v3.22.4
Palo Verde Sale Leaseback Variable Interest Entities
 12 Months Ended
Dec. 31, 2022
Variable Interest Entities [Abstract]  
Palo Verde Sale Leaseback Variable Interest Entities Palo Verde Sale Leaseback Variable Interest Entities
 
In 1986, APS entered into agreements with three separate VIE lessor trust entities in order to sell and lease back interests in Palo Verde Unit 2 and related common facilities. APS will retain the assets through 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 2023 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 2022, $17 million for 2021 and $19 million for 2020. 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, 2022December 31, 2021
Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation$90,296 $94,166 
Equity-Noncontrolling interests111,229 115,260 
 
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 $324 million beginning in 2023, 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.
v3.22.4
Investments in Nuclear Decommissioning Trusts and Other Special Use Funds
 12 Months Ended
Dec. 31, 2022
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 12 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 2022 and 2021, APS was reimbursed $15 million for each year, 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.

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, 2022
 Fair ValueTotal
Unrealized
Gains		Total
Unrealized
Losses
Investment Type:Nuclear Decommissioning TrustsOther Special Use FundsTotal
Equity securities$487,240 $66,974 $554,214 $334,817 $(267)
Available for sale-fixed income securities582,343 279,294 861,637 (a)3,177 (68,795)
Other3,827 963 4,790 (b)— (29)
Total$1,073,410 $347,231 $1,420,641 $337,994 $(69,091)
(a)As of December 31, 2022, the amortized cost basis of these available-for-sale investments is $927 million.
(b)Represents net pending securities sales and purchases.

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.
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
2022
Realized gains$9,017 $420 $9,437 
Realized losses(40,239)— (40,239)
Proceeds from the sale of securities (a)979,639 227,558 1,207,197 
2021
Realized gains134,610 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 
(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, 2022, is as follows (dollars in thousands):
 
 Nuclear Decommissioning TrustsCoal Reclamation Escrow AccountActive Union Employee Medical AccountTotal
Less than one year$9,422 $49,917 $38,157 $97,496 
1 year – 5 years181,640 36,484 143,878 362,002 
5 years – 10 years122,340 — 6,831 129,171 
Greater than 10 years268,941 4,027 — 272,968 
Total$582,343 $90,428 $188,866 $861,637 
v3.22.4
Changes in Accumulated Other Comprehensive Loss
 12 Months Ended
Dec. 31, 2022
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, 2020$(60,725)$(2,071)$(62,796)
OCI (loss) before reclassifications2,439 1,077 3,516 
Amounts reclassified from accumulated other comprehensive loss4,401 (a)18 (b)4,419 
Balance at December 31, 2021(53,885)(976)(54,861)
OCI (loss) before reclassifications17,550 1,873 19,423 
Amounts reclassified from accumulated other comprehensive loss4,003 (a)— 4,003 
Balance at December 31, 2022$(32,332)$897 $(31,435)
(a)These amounts primarily represent amortization of actuarial loss and are included in the computation of net periodic pension cost. See Note 7.
(b)These amounts represent realized gains and losses and are included in the computation of fuel and purchased power costs and are subject to the PSA. See Note 15.
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, 2020$(40,918)$— $(40,918)
OCI (loss) before reclassifications2,043 (18)2,025 
Amounts reclassified from accumulated other comprehensive loss3,995 (a)18 (b)4,013 
Balance at December 31, 2021(34,880)— (34,880)
OCI (loss) before reclassifications15,646 — 15,646 
Amounts reclassified from accumulated other comprehensive loss3,638 (a)— 3,638 
Balance at December 31, 2022$(15,596)$— $(15,596)
(a)These amounts primarily represent amortization of actuarial loss and are included in the computation of net periodic pension cost. See Note 7.
(b)These amounts represent realized gains and losses and are included in the computation of fuel and purchased power costs and are subject to the PSA. See Note 15.
v3.22.4
Schedule I - Condensed Financial Information of Registrant
 12 Months Ended
Dec. 31, 2022
Condensed Financial Information Disclosure [Abstract]  
Schedule I - 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,
 202220212020
Operating expenses$8,850 $10,245 $7,901 
Other   
Equity in earnings of subsidiaries500,042 628,916 566,147 
Other expense(4,725)(4,919)(4,586)
Total495,317 623,997 561,561 
Interest expense18,861 10,672 14,021 
Income before income taxes467,606 603,080 539,639 
Income tax benefit(15,996)(15,640)(10,920)
Net income attributable to common shareholders483,602 618,720 550,559 
Other comprehensive income (loss) — attributable to common shareholders23,426 7,935 (5,700)
Total comprehensive income — attributable to common shareholders$507,028 $626,655 $544,859 
 
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,
 20222021
ASSETS  
Current assets  
Cash and cash equivalents$— $594 
Accounts receivable132,061 125,457 
Income tax receivable14,494 1,498 
Other current assets288 13 
Total current assets146,843 127,562 
Investments and other assets  
Investments in subsidiaries7,105,789 6,797,528 
Deferred income taxes1,521 19,520 
Other assets23,153 57,608 
Total investments and other assets7,130,463 6,874,656 
TOTAL ASSETS$7,277,306 $7,002,218 
  
LIABILITIES AND EQUITY
Current liabilities  
Accounts payable$6,499 $3,071 
Accrued taxes7,694 19,855 
Common dividends payable97,895 95,988 
Short-term borrowings15,720 13,300 
Current maturities of long-term debt— 150,000 
Operating lease liabilities 117 107 
Other current liabilities14,637 14,684 
Total current liabilities142,562 297,005 
Long-term debt less current maturities (Note 6)
947,892 647,139 
Pension liabilities8,218 14,537 
Operating lease liabilities1,459 1,576 
Other17,299 20,501 
Total deferred credits and other26,976 36,614 
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
Common stock equity
Common stock2,719,735 2,696,342 
Accumulated other comprehensive loss(31,435)(54,861)
Retained earnings3,360,347 3,264,719 
Total Pinnacle West Shareholders’ equity6,048,647 5,906,200 
Noncontrolling interests111,229 115,260 
Total Equity6,159,876 6,021,460 
TOTAL LIABILITIES AND EQUITY$7,277,306 $7,002,218 
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,
 202220212020
Cash flows from operating activities   
Net income$483,602 $618,720 $550,559 
Adjustments to reconcile net income to net cash provided by operating activities: 
Equity in earnings of subsidiaries — net(500,042)(628,916)(566,147)
Depreciation and amortization76 93 76 
Deferred income taxes17,256 (11,381)33,007 
Accounts receivable(8,535)8,897 (7,903)
Accounts payable3,431 (2,598)(1,964)
Accrued taxes and income tax receivables — net(25,157)16,079 9,610 
Dividends received from subsidiaries385,800 376,500 357,500 
Other47,719 4,214 20,163 
Net cash flow provided by operating activities404,150 381,608 394,901 
Cash flows from investing activities   
Investments in subsidiaries(186,630)(145,266)(137,881)
Repayments of loans from subsidiaries14,308 4,017 932 
Advances of loans to subsidiaries(3,308)(12,256)(7,261)
Net cash flow used for investing activities(175,630)(153,505)(144,210)
Cash flows from financing activities   
Issuance of long-term debt300,000 300,000 496,950 
Short-term debt borrowings under revolving credit facility— — 211,690 
Short-term debt repayments under revolving credit facility— (19,000)(230,690)
Short-term borrowings and (repayments) — net2,420 (136,700)73,325 
Dividends paid on common stock(378,881)(369,478)(350,577)
Repayment of long-term debt(150,000)— (450,000)
Common stock equity issuance and purchases — net(2,653)(2,350)(1,389)
Net cash flow used for financing activities(229,114)(227,528)(250,691)
Net decrease in cash and cash equivalents(594)575 — 
Cash and cash equivalents at beginning of year594 19 19 
Cash and cash equivalents at end of year$— $594 $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.
v3.22.4
Summary of Significant Accounting Policies (Policies)
 12 Months Ended
Dec. 31, 2022
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 10 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 17 for additional information. We have determined that Pinnacle West is the primary beneficiary of a captive insurance protected cell VIE. As of December 31, 2022, 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.

Certain cost recovery mechanisms may qualify as 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 11 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, 2022, were as follows:
•Steam generation — 12 years;
•Nuclear plant — 25 years;
•Other generation — 18 years;
•Transmission — 38 years;
•Distribution — 33 years; and
•General plant — 6 years.
 
Depreciation of utility property, plant and equipment is computed on a straight-line, remaining-life basis.
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 5.75% for 2022, 6.75% for 2021, and 6.72% for 2020.  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 provided a simplified approach that companies may have elected to implement in order to minimize the significant distorted effect on the AFUDC formula which resulted from increased short-term debt financing during the COVID-19 pandemic.  APS 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 left all other aspects of the AFUDC formula composite rate calculation unchanged. This change impacted the AFUDC composite rate in 2020 and 2021 but did not impact prior years or 2022.  Furthermore, the change in the composite rate calculation did 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 net realizable value, 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 6 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 as well as interest rate risk.  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 7 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 accrued a receivable and an offsetting regulatory liability through the settlement period which ended 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 4 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 12 and 18 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 3. We also may enter into lease agreements related to vehicles, office space, land, and other equipment. See Note 8 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.
v3.22.4
Summary of Significant Accounting Policies (Tables)
 12 Months Ended
Dec. 31, 2022
Accounting Policies [Abstract]  
Schedule of property, plant and equipment
Pinnacle West’s property, plant and equipment included in the December 31, 2022, and 2021 Consolidated Balance Sheets is composed of the following (dollars in thousands):

Property, Plant and Equipment:20222021
Generation$9,563,145 $9,480,572 
Transmission3,589,456 3,402,016 
Distribution7,951,867 7,520,016 
General plant1,347,678 1,286,057 
Plant in service and held for future use
22,452,146 21,688,661 
Accumulated depreciation and amortization(7,929,878)(7,504,603)
Net
14,522,268 14,184,058 
Construction work in progress1,882,791 1,329,478 
Palo Verde sale leaseback, net of accumulated depreciation90,296 94,166 
Intangible assets, net of accumulated amortization258,880 273,693 
Nuclear fuel, net of accumulated amortization100,119 106,039 
Total property, plant and equipment$16,854,354 $15,987,434 
Schedule 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,
 202220212020
Cash paid (received) during the period for:   
Income taxes, net of refunds$46,227 $229 $(3,019)
Interest, net of amounts capitalized245,271 227,584 216,951 
Significant non-cash investing and financing activities:   
Accrued capital expenditures$114,999 $167,733 $113,502 
Dividends declared but not paid97,895 95,988 93,531 

The following table summarizes supplemental APS cash flow information for each of the last three years (dollars in thousands):
 Year ended December 31,
 202220212020
Cash paid during the period for:   
Income taxes, net of refunds$95,985 $19,783 $41,176 
Interest, net of amounts capitalized227,159 217,749 206,328 
Significant non-cash investing and financing activities:   
Accrued capital expenditures$116,533 $167,657 $113,502 
Dividends declared but not paid97,900 96,000 93,500 
v3.22.4
Revenue (Tables)
 12 Months Ended
Dec. 31, 2022
Revenue from Contract with Customer [Abstract]  
Schedule of 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,
202220212020
Retail Electric Service
Residential$2,046,111 $1,913,324 $1,929,178 (a)
Non-Residential1,767,616 1,586,940 1,486,098 
Wholesale Energy Sales383,126 187,640 93,345 
Transmission Services for Others116,628 99,285 65,859 
Other Sources10,904 16,646 12,502 
Total Operating Revenues$4,324,385 $3,803,835 $3,586,982 
(a)     Residential revenues for the year ended December 31, 2020, reflect a $24 million reduction related to the Arizona Attorney General matter. See Note 10.
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, 2022Year Ended December 31, 2021Year Ended December 31, 2020
Allowance for doubtful accounts, balance at beginning of period$25,354 $19,782 $8,171 
Bad debt expense17,006 22,251 20,633 
Actual write-offs(18,582)(16,679)(9,022)
Allowance for doubtful accounts, balance at end of period$23,778 $25,354 $19,782 
v3.22.4
Regulatory Matters (Tables)
 12 Months Ended
Dec. 31, 2022
Regulated Operations [Abstract]  
Schedule Of Capital Structure And Cost Of Capital, Regulatory Matter the following proposed capital structure and costs of capital:
Capital StructureCost of Capital
Long-term debt48.07 %3.85 %
Common stock equity51.93 %10.25 %
Weighted-average cost of capital7.17 %
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 2022 and 2021 (dollars in thousands):
 Twelve Months Ended
December 31,
 20222021
Beginning balance$388,148 $175,835 
Deferred fuel and purchased power costs — current period291,992 256,871 
Amounts charged to customers(219,579)(44,558)
Ending balance$460,561 $388,148 
Schedule of regulatory assets
The detail of regulatory assets is as follows (dollars in thousands):
SDecember 31,
 Amortization Through20222021
Pension(a)$637,656 $509,751 
Deferred fuel and purchased power (b) (c)2023460,561 388,148 
Income taxes — AFUDC equity2052179,631 172,393 
Ocotillo deferral (e)2031138,143 147,650 
Retired power plant costs203398,692 114,841 
SCR deferral (e) (f)203197,624 105,771 
Deferred property taxes202741,057 49,626 
Deferred compensation203633,660 33,997 
Income taxes — investment tax credit basis adjustment205623,977 24,768 
Palo Verde VIEs (Note 17)
204620,933 21,094 
Active union medical trust(g)18,226 1,175 
Four Corners cost deferral202415,999 24,075 
Navajo coal reclamation202613,862 16,840 
Lost fixed cost recovery (b)20239,547 63,889 
Loss on reacquired debt20389,468 11,020 
Mead-Phoenix transmission line — contributions in aid of construction20509,048 9,380 
Tax expense adjustor mechanism (b)20315,845 6,501 
OtherVarious8,171 10,592 
Total regulatory assets (d)$1,822,100 $1,711,511 
Less: current regulatory assets$538,879 $518,524 
Total noncurrent regulatory assets$1,283,221 $1,192,987 
(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 7 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.
(g)Collected in retail rates.
Schedule of regulatory liabilities
The detail of regulatory liabilities is as follows (dollars in thousands):
 December 31,
 Amortization Through20222021
Excess deferred income taxes - ACC — Tax Cuts and Jobs Act (a)2046$971,545 $1,012,448 
Excess deferred income taxes - FERC — Tax Cuts and Jobs Act (a)2058221,877 229,116 
Asset retirement obligations2057354,002 614,683 
Other postretirement benefits(d)270,604 374,816 
Removal costs (c) 106,889 119,580 
Deferred fuel and purchased power — mark-to-market (Note 15)
202496,367 107,601 
Income taxes — change in rates205164,806 67,678 
Four Corners coal reclamation203852,592 55,392 
Income taxes — deferred investment tax credit205648,035 49,601 
Spent nuclear fuel202739,217 45,282 
Renewable energy standard (b)202435,720 38,640 
FERC transmission true up (b)202422,895 34,303 
Property tax deferral (e)202415,521 20,192 
Sundance maintenance203116,893 13,797 
Demand side management (b)20238,461 5,417 
Tax expense adjustor mechanism (b) (e)N/A4,835 4,835 
OtherVarious3,092 2,103 
Total regulatory liabilities$2,333,351 $2,795,484 
Less: current regulatory liabilities$271,575 $296,271 
Total noncurrent regulatory liabilities$2,061,776 $2,499,213 
(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 7.
(e)Balance includes amounts for future regulatory consideration and amortization period determination.
v3.22.4
Income Taxes (Tables)
 12 Months Ended
Dec. 31, 2022
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
 202220212020202220212020
Total unrecognized tax benefits, January 1$45,086 $45,655 $43,435 $45,086 $45,655 $43,435 
Additions for tax positions of the current year1,399 3,305 3,418 1,399 3,305 3,418 
Additions for tax positions of prior years2,069 1,449 1,431 2,069 1,449 1,431 
Reductions for tax positions of prior years for:      
Changes in judgment(3,495)(2,659)(1,965)(3,495)(2,659)(1,965)
Settlements with taxing authorities— — — — — — 
Lapses of applicable statute of limitations(1,962)(2,664)(664)(1,962)(2,664)(664)
Total unrecognized tax benefits, December 31$43,097 $45,086 $45,655 $43,097 $45,086 $45,655 
Schedule 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
 202220212020202220212020
Tax positions, that if recognized, would decrease our effective tax rate$28,246 $26,300 $25,714 $28,246 $26,300 $25,714 
The amount of interest expense or benefit recognized related to unrecognized tax benefits are as follows (dollars in thousands):
Pinnacle West ConsolidatedAPS Consolidated
 202220212020202220212020
Unrecognized tax benefit interest expense/(benefit) recognized$(139)$(535)$266 $(139)$(535)$266 

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
 202220212020202220212020
Unrecognized tax benefit interest accrued $1,181 $1,320 $1,855 $1,181 $1,320 $1,855 
Schedule 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,
 202220212020202220212020
Current:   
Federal$35,617 $(5,041)$11,869 $103,349 $1,514 $57,299 
State1,950 2,458 1,932 161 (11)99 
Total current37,567 (2,583)13,801 103,510 1,503 57,398 
Deferred:      
Federal23,693 95,327 53,398 (31,860)101,175 15,122 
State13,567 17,342 10,974 19,150 22,875 16,244 
Total deferred37,260 112,669 64,372 (12,710)124,050 31,366 
Income tax expense/(benefit)$74,827 $110,086 $78,173 $90,800 $125,553 $88,764 
Schedule 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,
 202220212020202220212020
Federal income tax expense at statutory rate$120,887 $156,666 $136,127 $132,920 $162,762 $142,020 
Increases (reductions) in tax expense resulting from:      
State income tax net of federal income tax benefit17,740 22,656 19,146 19,000 23,339 20,124 
State income tax credits net of federal income tax benefit(5,482)(7,015)(8,951)(3,744)(5,277)(7,213)
Net operating loss carryback tax benefit— (5,915)— — — — 
Excess deferred income taxes — Tax Cuts and Jobs Act(36,241)(36,558)(50,543)(36,241)(36,558)(50,543)
Allowance for equity funds used during construction (see Note 1)
(4,629)(4,180)(2,747)(4,629)(4,180)(2,747)
Palo Verde VIE noncontrolling interest (see Note 17)
(3,617)(3,617)(4,094)(3,617)(3,617)(4,094)
Investment tax credit amortization(5,608)(7,620)(7,510)(5,608)(7,620)(7,510)
   Other federal income tax credits(10,867)(6,976)(4,616)(7,721)(3,912)(3,035)
Other2,644 2,645 1,361 440 616 1,762 
Income tax expense/(benefit)$74,827 $110,086 $78,173 $90,800 $125,553 $88,764 
Schedule 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,
 2022202120222021
DEFERRED TAX ASSETS  
Risk management activities$8,826 $677 $8,826 $677 
Regulatory liabilities:   
Excess deferred income taxes — Tax Cuts and Jobs Act295,014 306,915 295,014 306,915 
Asset retirement obligation and removal costs107,104 174,952 107,104 174,952 
Unamortized investment tax credits48,035 49,601 48,035 49,601 
Other postretirement benefits66,893 92,654 66,893 92,654 
Other62,915 65,815 62,915 65,815 
Operating lease liabilities184,030 204,890 182,663 204,378 
Pension liabilities33,674 42,136 30,436 37,814 
Coal reclamation liabilities44,312 43,165 44,312 43,165 
Renewable energy incentives19,948 22,646 19,948 22,646 
Credit and loss carryforwards37,647 57,077 13,654 18,902 
Other72,605 74,184 72,605 74,184 
Total deferred tax assets981,003 1,134,712 952,405 1,091,703 
DEFERRED TAX LIABILITIES   
Plant-related(2,518,164)(2,570,613)(2,518,164)(2,570,613)
Risk management activities(32,648)(27,276)(32,648)(27,276)
Pension and other postretirement assets(96,845)(133,624)(96,196)(132,769)
Other special use funds(57,572)(64,610)(57,572)(64,610)
Operating lease right-of-use assets(184,030)(204,890)(182,663)(204,378)
Regulatory assets:   
Allowance for equity funds used during construction(44,405)(42,616)(44,405)(42,616)
Deferred fuel and purchased power(114,232)(96,033)(114,232)(96,033)
Pension benefits(157,629)(126,010)(157,629)(126,010)
Retired power plant costs (24,397)(28,389)(24,397)(28,389)
Other(103,023)(123,902)(103,023)(123,902)
Other(32,479)(28,611)(7,123)(6,808)
Total deferred tax liabilities(3,365,424)(3,446,574)(3,338,052)(3,423,404)
Deferred income taxes — net$(2,384,421)$(2,311,862)$(2,385,647)$(2,331,701)
v3.22.4
Lines of Credit and Short-Term Borrowings (Tables)
 12 Months Ended
Dec. 31, 2022
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, 2022December 31, 2021
Pinnacle WestAPSTotalPinnacle WestAPSTotal
Commitments under Credit Facilities$200,000 $1,000,000 $1,200,000 $200,000 $1,000,000 $1,200,000 
Outstanding Commercial Paper, Term Loan and Revolving Credit Facility Borrowings(15,720)(325,000)(340,720)(13,300)(278,700)(292,000)
Amount of Credit Facilities Available$184,280 $675,000 $859,280 $186,700 $721,300 $908,000 
Commitment Fees0.175%0.125%0.175%0.125%
v3.22.4
Long-Term Debt and Liquidity Matters (Tables)
 12 Months Ended
Dec. 31, 2022
Debt Disclosure [Abstract]  
Schedule of 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)Rates20222021
APS    
Pollution control bonds:    
Variable2029(b)$163,975 $35,975 
Total pollution control bonds  163,975 35,975 
Senior unsecured notes2024-2050
2.20%-6.88%
6,680,000 6,280,000 
Unamortized discount  (14,548)(14,995)
Unamortized premium  12,368 13,575 
Unamortized debt issuance cost(48,266)(47,862)
Total APS long-term debt  6,793,529 6,266,693 
Less current maturities — — 
Total APS long-term debt less current maturities  6,793,529 6,266,693 
BCE
Los Alamitos equity bridge loan(d)(d)27,575 — 
Los Alamitos construction facility(e)(e)23,110 — 
Unamortized debt issuance cost(135)— 
Total BCE long-term debt50,550 — 
Less current maturities50,685 — 
Total BCE long-term debt less current maturities(135)— 
Pinnacle West    
Senior unsecured notes20251.3%500,000 500,000 
Term loans2024(c)450,000 300,000 
Unamortized discount(25)(34)
Unamortized debt issuance cost(2,083)(2,924)
Total Pinnacle West long-term debt947,892 797,042 
Less current maturities— 150,000 
Total Pinnacle West long-term debt less current maturities947,892 647,042 
TOTAL LONG-TERM DEBT LESS CURRENT MATURITIES
$7,741,286 $6,913,735 
(a)    This schedule does not reflect the timing of redemptions that may occur prior to maturities.
(b)    The weighted-average interest rate for the variable rate pollution control bonds was 3.96% at December 31, 2022, and 0.22% at December 31, 2021. See additional details below.
(c)    The weighted-average interest rate was 5.1% at December 31, 2022, and 0.81% at December 31, 2021. See additional details below.
(d)    The weighted-average interest rate for the variable rate equity bridge loan is 5.18% at December 31, 2022 and will mature on the project’s commercial operation date, expected on or before August 15, 2023. See additional details below.
(e)    The weighted-average interest rate for the variable rate construction facility is 5.71% at December 31, 2022 and will mature on the project’s commercial operation date, expected on or before August 15, 2023. See additional details below.
Schedule of 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, APS’s and BCE’s total long-term debt (dollars in thousands):
YearConsolidated
Pinnacle West		Consolidated
APS
BCE
2023$50,685 $— $50,685 
2024700,000 250,000 — 
2025800,000 300,000 — 
2026250,000 250,000 — 
2027300,000 300,000 — 
Thereafter5,743,975 5,743,975 — 
Total$7,844,660 $6,843,975 $50,685 
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, 2022		As of
December 31, 2021
 Carrying
Amount		Fair ValueCarrying
Amount		Fair Value
Pinnacle West$947,892 $905,525 $797,042 $792,735 
APS6,793,529 5,629,491 6,266,693 6,933,619 
BCE50,550 50,685 — — 
Total$7,791,971 $6,585,701 $7,063,735 $7,726,354 
v3.22.4
Retirement Plans and Other Postretirement Benefits (Tables)
 12 Months Ended
Dec. 31, 2022
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
 202220212020202220212020
Service cost-benefits earned during the period$55,473 $61,236 $56,233 $16,470 $17,796 $22,236 
Non-service costs (credits):
Interest cost on benefit obligation107,492 98,566 118,567 17,491 16,513 25,857 
Expected return on plan assets(185,775)(202,628)(187,443)(46,042)(41,444)(40,077)
Amortization of:      
Prior service credit— — — (37,789)(37,705)(37,575)
Net actuarial (gain)/loss17,515 15,948 34,612 (12,835)(10,093)— 
Net periodic benefit cost/(benefit)$(5,295)$(26,878)$21,969 $(62,705)$(54,933)$(29,559)
Portion of cost/(benefit) charged to expense$(16,431)$(32,743)$3,386 $(45,042)$(38,657)$(20,966)
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
 2022202120222021
Change in Benefit Obligation    
Benefit obligation at January 1$3,716,824 $3,902,867 $591,841 $624,034 
Service cost55,473 61,236 16,470 17,796 
Interest cost107,492 98,566 17,491 16,513 
Benefit payments(212,565)(207,928)(30,913)(31,280)
Actuarial (gain) loss(857,695)(137,917)(185,428)(35,222)
Benefit obligation at December 312,809,529 3,716,824 409,461 591,841 
Change in Plan Assets    
Fair value of plan assets at January 13,812,041 3,886,544 872,435 961,165 
Actual return on plan assets(787,874)18,169 (193,807)41,432 
Employer contributions— 100,000 — — 
Benefit payments(194,682)(192,672)(26,341)(24,310)
Transfer to active union medical account— — — (105,852)
Fair value of plan assets at December 312,829,485 3,812,041 652,287 872,435 
Funded Status at December 31$19,956 $95,217 $242,826 $280,594 
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,
 20222021
Accumulated benefit obligation126,759 161,086 
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,
 20222021
Projected benefit obligation133,818 169,912 
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
 2022202120222021
Noncurrent asset$153,773 $265,129 $242,826 $280,594 
Current liability(17,531)(17,047)— — 
Noncurrent liability(116,286)(152,865)— — 
Net amount recognized (funded status)$19,956 $95,217 $242,826 $280,594 
Schedule of accumulated other comprehensive loss
The following table shows the details related to accumulated other comprehensive loss (gain) as of December 31, 2022, and 2021 (dollars in thousands): 
 Pension PlansOther Benefits Plans
 2022202120222021
Net actuarial loss (gain)$681,335 $582,895 $(195,095)$(262,352)
Prior service credit— — (76,843)(114,632)
APS’s portion recorded as a regulatory (asset) liability(637,656)(509,751)270,604 374,816 
Income tax expense (benefit)(10,797)(18,081)784 990 
Accumulated other comprehensive loss (gain)$32,882 $55,063 $(550)$(1,178)
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,
 20222021202220212020
Discount rate – pension plans5.56 %2.92 %2.92 %2.53 %3.30 %
Discount rate – other benefits plans5.58 %2.98 %2.98 %2.63 %3.42 %
Rate of compensation increase4.57 %4.00 %4.00 %4.00 %4.00 %
Expected long-term return on plan assets - pension plansN/AN/A5.00 %5.30 %5.75 %
Expected long-term return on plan assets - other benefit plansN/AN/A5.35 %4.90 %4.85 %
Initial healthcare cost trend rate (pre-65 participants)6.50 %6.00 %6.00 %6.50 %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)64345
Initial and ultimate healthcare cost trend rate (post-65 participants) (a)2.00 %2.00 %2.00 %2.00 %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 2022, the target and actual allocation for the pension plan at December 31, 2022, are as follows:
 Target AllocationActual Allocation
Long-term fixed income assets80 %78 %
Return-seeking assets20 %22 %
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-seeking 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, 2022:
Actual Allocation
Long-term fixed income assets62 %
Return-seeking assets38 %
Total100 %
The fair value of Pinnacle West’s pension plan and other postretirement benefit plan assets at December 31, 2022, by asset category, are as follows (dollars in thousands):
 
 Level 1Level 2Other (a)Total
Pension Plan:   
Cash and cash equivalents$1,252 $— $— $1,252 
Fixed income securities:   
Corporate— 1,374,810 — 1,374,810 
U.S. Treasury635,245 — — 635,245 
Other (b)— 131,999 — 131,999 
Common stock equities (c)155,231 — — 155,231 
Mutual funds (d)101,557 — — 101,557 
Common and collective trusts:
Equities— — 181,912 181,912 
Real estate— — 174,228 174,228 
Partnerships— — 13,359 13,359 
Short-term investments and other (e)— — 59,892 59,892 
Total$893,285 $1,506,809 $429,391 $2,829,485 
Other Benefits:    
Cash and cash equivalents$204 $— $— $204 
Fixed income securities:   
Corporate— 166,879 — 166,879 
U.S. Treasury221,936 — — 221,936 
Other (b)— 7,321 — 7,321 
Common stock equities (c)127,493 — — 127,493 
Mutual funds (d)18,824 — — 18,824 
Common and collective trusts:   
Equities— — 73,956 73,956 
Real estate— — 23,541 23,541 
Short-term investments and other (e)3,274 — 8,859 12,133 
Total$371,731 $174,200 $106,356 $652,287 
(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, 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.
(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
2023$240,034 $31,235 
2024227,234 30,865 
2025223,813 30,251 
2026224,881 30,135 
2027221,976 29,790 
Years 2028-20321,117,192 146,725 
v3.22.4
Leases (Tables)
 12 Months Ended
Dec. 31, 2022
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,
202220212020
Operating Lease Cost - Purchased Power Lease Contracts$104,001 $105,762 68,883 
Operating Lease Cost - Land, Property, and Other Equipment18,061 18,498 18,493 
Total Operating Lease Cost122,062 124,260 87,376 
Variable lease cost (a)122,040 118,969 122,331 
Short-term lease cost9,928 3,872 3,804 
Total lease cost$254,030 $247,101 $213,511 
(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, 2022Year Ended December 31, 2021Year Ended December 31, 2020
Cash paid for amounts included in the measurement of lease liabilities — operating cash flows:$118,463 $116,661 $75,097 
Right-of-use operating lease assets obtained in exchange for operating lease liabilities16,990 500,582 441,653 


December 31, 2022December 31, 2021
Weighted average remaining lease term7 years8 years
Weighted average discount rate (a)2.21 %2.13 %
(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, 2022
YearPurchased Power Lease ContractsLand, Property & Equipment LeasesTotal
2023$106,151 $14,254 $120,405 
2024104,315 11,330 115,645 
2025106,582 8,655 115,237 
2026120,016 7,207 127,223 
202789,108 5,292 94,400 
Thereafter210,486 37,873 248,359 
Total lease commitments736,658 84,611 821,269 
Less imputed interest57,682 19,130 76,812 
Total lease liabilities$678,976 $65,481 $744,457 
v3.22.4
Jointly-Owned Facilities (Tables)
 12 Months Ended
Dec. 31, 2022
Jointly Owned Utility Plant, Net Ownership Amount [Abstract]  
Schedule Of 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, 2022 (dollars in thousands):
 Percent
Owned		 Plant in
Service		Accumulated
Depreciation		Construction
Work in
Progress
Generating facilities:     
Palo Verde Units 1 and 329.1 %$1,947,593 $1,099,132 $39,933 
Palo Verde Unit 2 (a)16.8 %659,514 383,775 14,784 
Palo Verde Common28.0 %(b)799,794 346,705 52,631 
Palo Verde Sale Leaseback (a)351,050 260,754 — 
Four Corners Generating Station 63.0 %1,665,042 620,918 46,643 
Cholla Common Facilities (c)50.5 %207,104 140,886 2,988 
Transmission facilities:     
ANPP 500kV System33.4 %(b)133,887 55,704 2,820 
Navajo Southern System26.8 %(b)90,345 36,929 1,945 
Palo Verde — Yuma 500kV System25.4 %(b)24,026 7,559 128 
Four Corners Switchyards61.9 %(b)73,243 20,350 120 
Phoenix — Mead System17.1 %(b)39,705 20,055 51 
Palo Verde — Rudd 500kV System50.0 %95,736 31,118 391 
Morgan — Pinnacle Peak System64.7 %(b)119,785 25,791 96 
Round Valley System50.0 %548 193 — 
Palo Verde — Morgan System87.8 %(b)263,576 34,415 1,414 
Hassayampa — North Gila System80.0 %148,174 22,566 3,771 
Cholla 500kV Switchyard85.7 %8,100 2,380 — 
Saguaro 500kV Switchyard60.0 %21,656 13,809 — 
Kyrene — Knox System50.0 %578 336 — 
Agua Fria Switchyard10.0 %— — 32 
(a)See Note 17.
(b)Weighted-average of interests.
(c)PacifiCorp owns Cholla Unit 4 (see Note 3 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.
v3.22.4
Commitments and Contingencies (Tables)
 12 Months Ended
Dec. 31, 2022
Commitments and Contingencies Disclosure [Abstract]  
Schedule 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,
 20232024202520262027Thereafter
Coal take-or-pay commitments (a)$216,729 $211,823 $232,594 $225,345 $204,845 $880,113 
 
(a)Total take-or-pay commitments are approximately $2.0 billion.  The total net present value of these commitments is approximately $1.6 billion.
Schedule 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,
 202220212020
Total purchases$305,502 $219,958 $189,817 
v3.22.4
Asset Retirement Obligations (Tables)
 12 Months Ended
Dec. 31, 2022
Asset Retirement Obligation Disclosure [Abstract]  
Schedule of Change In Asset Retirement Obligations
The following table shows the change in our AROs (dollars in thousands):

 20222021
Asset retirement obligations at the beginning of year$767,382 $705,083 
Changes attributable to:  
Accretion expense41,240 38,437 
Settlements(10,860)(4,111)
Estimated cash flow revisions— 27,973 
Asset retirement obligations at the end of year$797,762 $767,382 
v3.22.4
Fair Value Measurements (Tables)
 12 Months Ended
Dec. 31, 2022
Fair Value Disclosures [Abstract]  
Schedule of 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, 2022, 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$— $127,129 $26,132 $(21,163)(a)$132,098 
Interest rate swaps— 131 — — 131 
Subtotal risk management activities - derivative instruments— 127,260 26,132 (21,163)132,229 
Nuclear decommissioning trust:
Equity securities14,658 — — 3,827 (b)18,485 
U.S. commingled equity funds— — — 472,582 (c)472,582 
U.S. Treasury debt211,923 — — — 211,923 
Corporate debt— 149,226 — — 149,226 
Mortgage-backed securities— 147,938 — — 147,938 
Municipal bonds— 64,881 — — 64,881 
Other fixed income— 8,375 — — 8,375 
Subtotal nuclear decommissioning trust226,581 370,420 — 476,409 1,073,410 
Other special use funds:
Equity securities66,974 — — 963 (b)67,937 
U.S. Treasury debt275,267 — — — 275,267 
Municipal bonds— 4,027 — — 4,027 
Subtotal other special use funds342,241 4,027 — 963 347,231 
Total assets$568,822 $501,707 $26,132 $456,209 $1,552,870 
LIABILITIES
Risk management activities — derivative instruments:
Commodity contracts$— $(25,874)$(31,020)$15,357 (a)$(41,537)
Interest rate swaps— (909)— — (909)
Subtotal risk management activities - derivative instruments— (26,783)(31,020)15,357 (42,446)
Total liabilities$— $(26,783)$(31,020)$15,357 $(42,446)
(a)Represents counterparty netting, margin, and collateral. See Note 15.
(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, 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 15.
(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 shows the changes in fair value for our risk management activities’ assets and liabilities that are measured at fair value on a recurring basis using Level 3 inputs for the years ended December 31, 2022 and 2021 (dollars in thousands):
 Year Ended
December 31,
Commodity Contracts20222021
Net derivative balance at beginning of period$(2,738)$(1,102)
Total net gains (losses) realized/unrealized:
Deferred as a regulatory asset or liability(374)13,827 
Settlements(1,123)(15,463)
Transfers into Level 3 from Level 2(846)— 
Transfers from Level 3 into Level 2193 — 
Net derivative balance at end of period$(4,888)$(2,738)
Net unrealized gains included in earnings related to instruments still held at end of period$— $— 
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
The following tables provide information regarding our significant unobservable inputs used to value our risk management derivative Level 3 instruments at December 31, 2022 and December 31, 2021:

December 31, 2022
 Fair Value (thousands) 		ValuationSignificantWeighted-Average
Commodity ContractsAssetsLiabilitiesTechniqueUnobservable InputRange (b)
Electricity:
Forward Contracts (a)$26,132 $1,759 Discounted cash flowsElectricity forward price (per MWh)
$37.79
-
$310.69
$163.92 
Natural Gas:
Forward Contracts (a)— 29,261 Discounted cash flowsNatural gas forward price (per MMBtu)
$(11.81)
-
$0.00
$(5.08)
Total$26,132 $31,020 
(a)Includes swaps and physical and financial contracts.
(b)Unobservable inputs were weighted by the relative fair value of the instrument.

 
December 31, 2021
 Fair Value (thousands) 		ValuationSignificantWeighted-Average
Commodity ContractsAssetsLiabilitiesTechniqueUnobservable InputRange(b)
Natural Gas:
Forward Contracts (a)$— $2,738 Discounted cash flowsNatural gas forward price (per MMBtu)$(0.76)-
 $(0.65)
$(0.71)
Total$— $2,738 
(a)Includes swaps and physical and financial contracts.
(b)Unobservable inputs were weighted by the relative fair value of the instrument.
v3.22.4
Earnings Per Share (Tables)
 12 Months Ended
Dec. 31, 2022
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):
 202220212020
Net income attributable to common shareholders$483,602 $618,720 $550,559 
Weighted average common shares outstanding — basic113,196 112,910 112,666 
Net effect of dilutive securities:   
Contingently issuable performance shares and restricted stock units220 282 276 
Weighted average common shares outstanding — diluted113,416 113,192 112,942 
Earnings per weighted-average common share outstanding
Net income attributable to common shareholders — basic$4.27 $5.48 $4.89 
Net income attributable to common shareholders — diluted$4.26 $5.47 $4.87 
v3.22.4
Stock-Based Compensation (Tables)
 12 Months Ended
Dec. 31, 2022
Share-Based Payment Arrangement [Abstract]  
Schedule 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)
 202220212020202220212020
Units granted174,791 152,345 118,403 208,736 161,840 122,830 
Weighted-average grant date fair value$69.66 $76.72 $71.70 $77.63 $82.42 $104.74 
(a)Units granted includes awards that will be cash settled of 0 in 2022, 51,074 in 2021, and 45,646 in 2020. See below for additional information on restricted stock unit grants.
(b)Reflects the target payout level.
The following table shows the change of nonvested awards:

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 December 31, 2021
253,156 $79.37 280,682 $92.16 
Granted174,791 69.66 208,736 77.63 
Vested(101,216)84.52 (136,034)103.30 
Forfeited (c)(9,144)76.56 (22,690)78.29 
Nonvested at December 31, 2022
317,587 (a)73.91 330,694 78.91 
Vested Awards Outstanding at December 31, 2022
78,912 136,034 
(a)Includes 69,413 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.
Schedule 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)
 202220212020202220212020
Units granted174,791 152,345 118,403 208,736 161,840 122,830 
Weighted-average grant date fair value$69.66 $76.72 $71.70 $77.63 $82.42 $104.74 
(a)Units granted includes awards that will be cash settled of 0 in 2022, 51,074 in 2021, and 45,646 in 2020. See below for additional information on restricted stock unit grants.
(b)Reflects the target payout level.
The following table shows the change of nonvested awards:

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 December 31, 2021
253,156 $79.37 280,682 $92.16 
Granted174,791 69.66 208,736 77.63 
Vested(101,216)84.52 (136,034)103.30 
Forfeited (c)(9,144)76.56 (22,690)78.29 
Nonvested at December 31, 2022
317,587 (a)73.91 330,694 78.91 
Vested Awards Outstanding at December 31, 2022
78,912 136,034 
(a)Includes 69,413 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.
v3.22.4
Derivative Accounting (Tables)
 12 Months Ended
Dec. 31, 2022
Derivative Instruments and Hedging Activities Disclosure [Abstract]  
Schedule of 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 energy derivatives, which represent both purchases and sales (does not reflect net position):
 
Quantity
CommodityUnit of MeasureDecember 31, 2022December 31, 2021
PowerGWh1,197 — 
GasBillion cubic feet149 155 
Schedule of 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 energy derivative instruments in designated cash flow accounting hedging relationships (dollars in thousands):
Financial Statement Year Ended
December 31,
Commodity ContractsLocation202220212020
Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a)Fuel and purchased power (b)$— $— $(763)
(a)During the years ended December 31, 2022, 2021, and 2020, 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.
Schedule of Gains and losses from derivative instruments not designated as accounting hedges instruments
The following table provides information about gains and losses from energy derivative instruments not designated as accounting hedging instruments (dollars in thousands):

Financial Statement Year Ended
December 31,
Commodity ContractsLocation202220212020
Net Gain (Loss) Recognized in IncomeFuel and purchased power (a)$307,287 $216,847 $(3,178)
(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 APS's 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 APS's Consolidated Balance Sheets.

As of December 31, 2022:
 (dollars in thousands) 		Gross 
Recognized 
Derivatives
 (a)		Amounts 
Offset
(b)		Net
 Recognized
 Derivatives		Other
 (c)		Amounts 
Reported on 
Balance Sheets
Current assets$103,484 $(15,808)$87,676 $28 $87,704 
Investments and other assets49,777 (5,383)44,394 — 44,394 
Total assets153,261 (21,191)132,070 28 132,098 
Current liabilities(47,670)15,808 (31,862)(5,835)(37,697)
Deferred credits and other(9,223)5,383 (3,840)— (3,840)
Total liabilities(56,893)21,191 (35,702)(5,835)(41,537)
Total$96,368 $— $96,368 $(5,807)$90,561 
(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 $5,835 thousand and cash margin provided to counterparties of $28 thousand.
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 thousand and cash margin provided to counterparties of $50 thousand.
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 APS's 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 APS's Consolidated Balance Sheets.

As of December 31, 2022:
 (dollars in thousands) 		Gross 
Recognized 
Derivatives
 (a)		Amounts 
Offset
(b)		Net
 Recognized
 Derivatives		Other
 (c)		Amounts 
Reported on 
Balance Sheets
Current assets$103,484 $(15,808)$87,676 $28 $87,704 
Investments and other assets49,777 (5,383)44,394 — 44,394 
Total assets153,261 (21,191)132,070 28 132,098 
Current liabilities(47,670)15,808 (31,862)(5,835)(37,697)
Deferred credits and other(9,223)5,383 (3,840)— (3,840)
Total liabilities(56,893)21,191 (35,702)(5,835)(41,537)
Total$96,368 $— $96,368 $(5,807)$90,561 
(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 $5,835 thousand and cash margin provided to counterparties of $28 thousand.
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 thousand and cash margin provided to counterparties of $50 thousand.
Schedule of Information about derivative instruments that have credit-risk-related contingent features
The following table provides information about our energy derivative instruments that have credit-risk-related contingent features (dollars in thousands):
 December 31, 2022
Aggregate fair value of derivative instruments in a net liability position$56,893 
Cash collateral posted— 
Additional cash collateral in the event credit-risk related contingent features were fully triggered (a)32,884 
(a)This amount is after counterparty netting and includes those contracts which qualify for scope exceptions, which are excluded from the derivative details above.
v3.22.4
Other Income and Other Expense (Tables)
 12 Months Ended
Dec. 31, 2022
Other Income and Expenses [Abstract]  
Schedule of other income and other expense
The following table provides detail of Pinnacle West’s Consolidated other income and other expense for 2022, 2021 and 2020 (dollars in thousands):
 
 202220212020
Other income:   
Interest income$7,326 $6,726 $12,210 
Investment gains (losses) — net— — 2,358 
Debt return on Four Corners SCR deferral (Note 3)
— 14,955 15,865 
Debt return on Ocotillo modernization project (Note 3)
— 23,366 26,121 
Miscellaneous590 53 149 
Total other income$7,916 $45,100 $56,703 
Other expense:   
Non-operating costs$(18,619)$(13,008)$(12,400)
Investment gains (losses) — net(20,537)(b)(1,367)— 
Miscellaneous(13,229)(a)(11,021)(45,376)(a)
Total other expense$(52,385)$(25,396)$(57,776)
(a)The 2022 miscellaneous amount includes donations of $7 million to the APS Foundation. 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 3.
(b)The 2022 investment loss is primarily related to an impairment write-off of BCE’s Clear Creek wind farm investment. See Note 10.
 
The following table provides detail of APS’s other income and other expense for 2022, 2021 and 2020 (dollars in thousands):
 
 202220212020
Other income:   
Interest income$5,332 $4,692 $9,621 
Debt return on Four Corners SCR deferral (Note 3)
— 14,955 15,865 
Debt return on Ocotillo modernization project (Note 3)
— 23,366 26,121 
Miscellaneous556 40 148 
Total other income$5,888 $43,053 $51,755 
Other expense:   
Non-operating costs$(15,579)$(10,080)$(10,659)
Miscellaneous(10,529)(a)(8,817)(43,035)(a)
Total other expense$(26,108)$(18,897)$(53,694)
(a)The 2022 miscellaneous amount includes donations of $7 million to the APS Foundation. 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 3.
v3.22.4
Palo Verde Sale Leaseback Variable Interest Entities (Tables)
 12 Months Ended
Dec. 31, 2022
Variable Interest Entities [Abstract]  
Schedule of 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, 2022December 31, 2021
Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation$90,296 $94,166 
Equity-Noncontrolling interests111,229 115,260 
v3.22.4
Investments in Nuclear Decommissioning Trusts and Other Special Use Funds (Tables)
 12 Months Ended
Dec. 31, 2022
Investments, Debt and Equity Securities [Abstract]  
Schedule of 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, 2022
 Fair ValueTotal
Unrealized
Gains		Total
Unrealized
Losses
Investment Type:Nuclear Decommissioning TrustsOther Special Use FundsTotal
Equity securities$487,240 $66,974 $554,214 $334,817 $(267)
Available for sale-fixed income securities582,343 279,294 861,637 (a)3,177 (68,795)
Other3,827 963 4,790 (b)— (29)
Total$1,073,410 $347,231 $1,420,641 $337,994 $(69,091)
(a)As of December 31, 2022, the amortized cost basis of these available-for-sale investments is $927 million.
(b)Represents net pending securities sales and purchases.

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.
Schedule of 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
2022
Realized gains$9,017 $420 $9,437 
Realized losses(40,239)— (40,239)
Proceeds from the sale of securities (a)979,639 227,558 1,207,197 
2021
Realized gains134,610 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 
(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.
Schedule of 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, 2022, is as follows (dollars in thousands):
 
 Nuclear Decommissioning TrustsCoal Reclamation Escrow AccountActive Union Employee Medical AccountTotal
Less than one year$9,422 $49,917 $38,157 $97,496 
1 year – 5 years181,640 36,484 143,878 362,002 
5 years – 10 years122,340 — 6,831 129,171 
Greater than 10 years268,941 4,027 — 272,968 
Total$582,343 $90,428 $188,866 $861,637 
v3.22.4
Changes in Accumulated Other Comprehensive Loss (Tables)
 12 Months Ended
Dec. 31, 2022
Comprehensive Income (Loss), Net of Tax, Attributable to Parent [Abstract]  
Schedule of changes in accumulated other comprehensive loss including reclassification adjustments, by component
The following table shows the changes in Pinnacle West’s consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component (dollars in thousands): 
 Pension and Other Postretirement Benefits Derivative InstrumentsTotal
Balance at December 31, 2020$(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)
OCI (loss) before reclassifications17,550 1,873 19,423 
Amounts reclassified from accumulated other comprehensive loss4,003 (a)— 4,003 
Balance at December 31, 2022$(32,332)$897 $(31,435)
(a)These amounts primarily represent amortization of actuarial loss and are included in the computation of net periodic pension cost. See Note 7.
(b)These amounts represent realized gains and losses and are included in the computation of fuel and purchased power costs and are subject to the PSA. See Note 15.
The following table shows the changes in APS’s consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component (dollars in thousands): 
 Pension and Other Postretirement Benefits Derivative InstrumentsTotal
Balance at December 31, 2020$(40,918)$— $(40,918)
OCI (loss) before reclassifications2,043 (18)2,025 
Amounts reclassified from accumulated other comprehensive loss3,995 (a)18 (b)4,013 
Balance at December 31, 2021(34,880)— (34,880)
OCI (loss) before reclassifications15,646 — 15,646 
Amounts reclassified from accumulated other comprehensive loss3,638 (a)— 3,638 
Balance at December 31, 2022$(15,596)$— $(15,596)
(a)These amounts primarily represent amortization of actuarial loss and are included in the computation of net periodic pension cost. See Note 7.
(b)These amounts represent realized gains and losses and are included in the computation of fuel and purchased power costs and are subject to the PSA. See Note 15.
v3.22.4
Summary of Significant Accounting Policies - Additional Information (Details)
$ / shares in Units, $ in Millions
 1 Months Ended 12 Months Ended 36 Months Ended
May 31, 2014
$ / kWh
Dec. 31, 2022
USD ($)
$ / shares
shares
Dec. 31, 2021
USD ($)
Dec. 31, 2020
USD ($)
Dec. 31, 2022
USD ($)
$ / shares
shares
Approximate remaining average useful lives of utility property          
Depreciation   $ 632 $ 575 $ 553  
Depreciation rates (as a percent)   3.03% 2.87% 2.84%  
Allowance for Funds Used During Construction          
Composite rate used to calculate AFUDC (as a percent)   5.75% 6.75% 6.72%  
Income Taxes          
Percent likelihood largest tax benefit amount is realized (greater than)   50.00%      
Intangible Assets          
Amortization expense   $ 84 $ 80 $ 70  
Estimated amortization expense on existing intangible assets over the next five years          
Estimated amortization expense, next year   81     $ 81
Estimated amortization expense, in two years   60     60
Estimated amortization expense, in three years   48     48
Estimated amortization expense, in four years   33     33
Estimated amortization expense, in five years   $ 14     $ 14
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   18 years      
Transmission          
Approximate remaining average useful lives of utility property          
Average useful life   38 years      
Distribution          
Approximate remaining average useful lives of utility property          
Average useful life   33 years      
General Plant          
Approximate remaining average useful lives of utility property          
Average useful life   6 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%
v3.22.4
Summary of Significant Accounting Policies - Summary of Property, Plant and Equipment (Details) - USD ($)
$ in Thousands
Dec. 31, 2022
Dec. 31, 2021
Utility Plant and Depreciation [Line Items]    
Net $ 14,522,268 $ 14,184,058
Construction work in progress 1,882,791 1,329,478
Intangible assets, net of accumulated amortization 258,880 273,693
Nuclear fuel, net of accumulated amortization 100,119 106,039
Total property, plant and equipment 16,854,354 15,987,434
Electric Service    
Utility Plant and Depreciation [Line Items]    
Generation 9,563,145 9,480,572
Transmission 3,589,456 3,402,016
Distribution 7,951,867 7,520,016
General plant 1,347,678 1,286,057
Plant in service and held for future use 22,452,146 21,688,661
Accumulated depreciation and amortization (7,929,878) (7,504,603)
Net 14,522,268 14,184,058
Construction work in progress 1,882,791 1,329,478
Intangible assets, net of accumulated amortization 258,880 273,693
Nuclear fuel, net of accumulated amortization 100,119 106,039
Total property, plant and equipment 16,854,354 15,987,434
Electric Service | Variable Interest Entity    
Utility Plant and Depreciation [Line Items]    
Total property, plant and equipment $ 90,296 $ 94,166
v3.22.4
Summary of Significant Accounting Policies - Supplemental Cash Flow Information (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2022
Dec. 31, 2021
Dec. 31, 2020
Cash and Cash Equivalents [Line Items]      
Income taxes, net of refunds $ 46,227 $ 229 $ (3,019)
Interest, net of amounts capitalized 245,271 227,584 216,951
Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]      
Accrued capital expenditures 114,999 167,733 113,502
Dividends declared but not paid 97,895 95,988 93,531
Arizona Public Service Company      
Cash and Cash Equivalents [Line Items]      
Income taxes, net of refunds 95,985 19,783 41,176
Interest, net of amounts capitalized 227,159 217,749 206,328
Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]      
Accrued capital expenditures 116,533 167,657 113,502
Dividends declared but not paid $ 97,900 $ 96,000 $ 93,500
v3.22.4
Revenue - Schedule of Disaggregation (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2022
Dec. 31, 2021
Dec. 31, 2020
Disaggregation of Revenue [Line Items]      
Total Operating Revenues $ 4,324,385 $ 3,803,835 $ 3,586,982
Retail Electric Service | Residential      
Disaggregation of Revenue [Line Items]      
Total Operating Revenues 2,046,111 1,913,324 1,929,178
Retail Electric Service | Non-Residential      
Disaggregation of Revenue [Line Items]      
Total Operating Revenues 1,767,616 1,586,940 1,486,098
Wholesale Energy Sales      
Disaggregation of Revenue [Line Items]      
Total Operating Revenues 383,126 187,640 93,345
Transmission Services for Others      
Disaggregation of Revenue [Line Items]      
Total Operating Revenues 116,628 99,285 65,859
Other Sources      
Disaggregation of Revenue [Line Items]      
Total Operating Revenues $ 10,904 $ 16,646 $ 12,502
v3.22.4
Revenue - Additional Information (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2022
Dec. 31, 2021
Dec. 31, 2020
Disaggregation of Revenue [Line Items]      
Operating revenues $ 4,324,385 $ 3,803,835 $ 3,586,982
Regulatory cost recovery revenue 22,000 44,000 54,000
Retail Electric Service | Residential      
Disaggregation of Revenue [Line Items]      
Operating revenues 2,046,111 1,913,324 1,929,178
Retail 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 $ 4,302,000 $ 3,760,000 $ 3,533,000
v3.22.4
Revenue - Allowance for Doubtful Accounts (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2022
Dec. 31, 2021
Dec. 31, 2020
Accounts Receivable, Allowance for Credit Loss [Roll Forward]      
Allowance for doubtful accounts, balance at beginning of period $ 25,354 $ 19,782 $ 8,171
Bad debt expense 17,006 22,251 20,633
Actual write-offs (18,582) (16,679) (9,022)
Allowance for doubtful accounts, balance at end of period $ 23,778 $ 25,354 $ 19,782
v3.22.4
Regulatory Matters - Retail Rate Case Filing (Details)
Oct. 28, 2022
USD ($)
$ / kWh
Sep. 23, 2022
MW
Jun. 30, 2022
USD ($)
Mar. 31, 2022
MW
Oct. 27, 2021
USD ($)
Aug. 02, 2021
USD ($)
Nov. 06, 2020
USD ($)
Oct. 31, 2019
USD ($)
$ / kWh
MW
Jun. 30, 2019
USD ($)
Aug. 13, 2018
USD ($)
Mar. 27, 2017
USD ($)
Dec. 31, 2022
USD ($)
Apr. 30, 2022
USD ($)
Dec. 31, 2021
USD ($)
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         $ 7,000,000 $ 500,000   $ 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                    
ACC | Coal Community Transition Plan | Navajo Nation, Generation Station                                  
Public Utilities, General Disclosures [Line Items]                                  
Amount funded by customers                           $ 900,000      
ACC | Coal Community Transition Plan | Navajo Nation, Hopi Tribe                                  
Public Utilities, General Disclosures [Line Items]                                  
Regulatory matters, amounts recoverable by rates                         1,000,000        
ACC | Coal Community Transition Plan | Navajo Nation                                  
Public Utilities, General Disclosures [Line Items]                                  
Regulatory matters, amounts recoverable by rates                         3,330,000        
ACC | Coal Community Transition Plan | Navajo Nation, Hopi Reservation                                  
Public Utilities, General Disclosures [Line Items]                                  
Regulatory matters, amounts recoverable by rates                         1,250,000        
ACC | Coal Community Transition Plan | Navajo County Communities                                  
Public Utilities, General Disclosures [Line Items]                                  
Regulatory matters, amounts recoverable by rates                         500,000        
ACC | Coal Community Transition Plan | Navajo County Communities, CCT and Economic Development                                  
Public Utilities, General Disclosures [Line Items]                                  
Amount funded by shareholders                         1,100,000        
ACC | Coal Community Transition Plan | Navajo Nation, Hopi Tribe for CCT and Economic Development                                  
Public Utilities, General Disclosures [Line Items]                                  
Amount funded by shareholders                         $ 1,250,000        
ACC | Arizona Public Service Company                                  
Public Utilities, General Disclosures [Line Items]                                  
Total revenue deficiency $ 772,000,000                                
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]                                  
Approximate percentage of increase in average residential customer bill 13.60%             5.40%                  
Rate matter, cost base rate     $ 10,500,000,000           $ 8,870,000,000                
Base fuel rate (in dollars per kWh) | $ / kWh 0.038321             0.030168                  
Base rate decrease, elimination of tax expense adjustment mechanism               $ 115,000,000                  
Approximate percentage of increase in average customer bill               5.60%                  
Funding limited income crisis bill program               $ 1,250,000                  
Commercial customers, market pricing, threshold | MW   140   280       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 and non depreciation base rate, increase                     87,200,000            
Fuel-related base rate decrease                     53,600,000            
Settlement agreement, base rate increase, changes in depreciation schedules                     $ 61,000,000            
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 not recoverable         215,500,000                        
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                        
Minimum | ACC | Arizona Public Service Company                                  
Public Utilities, General Disclosures [Line Items]                                  
Annual increase in retail base rates $ 460,000,000             $ 69,000,000                  
v3.22.4
Regulatory Matters - Capital Structure and Costs of Capital (Details) - Arizona Public Service Company
Oct. 28, 2022
Oct. 31, 2019
Cost of Capital    
Long-term debt 3.85% 4.10%
Common stock equity 10.25% 10.15%
Weighted-average cost of capital 7.17% 7.41%
Retail Rate Case Filing with Arizona Corporation Commission    
Capital Structure    
Common stock equity 51.93% 54.70%
Retail Rate Case Filing with Arizona Corporation Commission | ACC    
Capital Structure    
Long-term debt 48.07% 45.30%
v3.22.4
Regulatory Matters - Cost Recovery Mechanisms (Details)
 1 Months Ended 12 Months Ended
Feb. 23, 2023
USD ($)
$ / MWh
Feb. 01, 2023
USD ($)
$ / kWh
Oct. 31, 2022
USD ($)
Sep. 23, 2022
MW
Jul. 12, 2022
USD ($)
$ / kWh
Jun. 01, 2022
USD ($)
Mar. 31, 2022
MW
Feb. 15, 2022
USD ($)
Feb. 01, 2022
USD ($)
$ / KWH_Kilowatt_hour
$ / kWh
Nov. 01, 2021
$ / kWh
Oct. 01, 2021
$ / kWh
Jun. 07, 2021
USD ($)
Jun. 01, 2021
USD ($)
Apr. 01, 2021
$ / kWh
Feb. 22, 2021
USD ($)
Feb. 15, 2021
USD ($)
Feb. 01, 2021
USD ($)
$ / kWh
Aug. 20, 2020
USD ($)
customer
Jun. 01, 2020
USD ($)
May 01, 2020
$ / kWh
Feb. 14, 2020
USD ($)
Feb. 01, 2020
$ / kWh
Nov. 14, 2019
USD ($)
customer
Oct. 31, 2019
USD ($)
$ / KWH_Kilowatt_hour
MW
Oct. 29, 2019
USD ($)
May 01, 2019
$ / kWh
Apr. 10, 2019
Aug. 13, 2018
USD ($)
Nov. 20, 2017
USD ($)
Sep. 01, 2017
Mar. 31, 2021
Dec. 31, 2022
USD ($)
Dec. 31, 2021
USD ($)
Dec. 31, 2020
USD ($)
program
MW
Dec. 31, 2017
$ / kWh
Dec. 31, 2017
$ / KWH_Kilowatt_hour
Nov. 30, 2022
USD ($)
Jul. 01, 2022
USD ($)
Apr. 18, 2022
USD ($)
Dec. 17, 2021
USD ($)
Dec. 09, 2021
USD ($)
Oct. 28, 2021
agreement
Jul. 01, 2021
USD ($)
Jul. 01, 2020
USD ($)
May 15, 2020
USD ($)
May 05, 2020
USD ($)
Dec. 31, 2019
USD ($)
Jul. 01, 2019
USD ($)
Mar. 15, 2019
agreement
Change in regulatory asset                                                                                                  
Deferred fuel and purchased power costs — current period                                                               $ 291,992,000 $ 256,871,000 $ 93,651,000                              
Amounts charged to customers                                                               (219,579,000) (44,557,000) 12,047,000                              
Number of customers | customer                                   3,800         13,000                                                    
Inconvenience payment                                   $ 25         $ 25                                                    
Arizona Public Service Company                                                                                                  
Change in regulatory asset                                                                                                  
Deferred fuel and purchased power costs — current period                                                               291,992,000 256,871,000 93,651,000                              
Amounts charged to customers                                                               $ (219,579,000) (44,557,000) $ 12,047,000                              
Demand side management funds                                                                                           $ 36,000,000      
Customer credits                                                                 43,000,000                                
Customer credits, additional funds                                                                 7,000,000                                
Percentage increase under PSA effective for first billing cycle beginning April 2021                                                             50.00%                                    
Remaining percentage increase under PSA effective for first billing cycle beginning November 2021                                                             50.00%                                    
Arizona Public Service Company | 2017 Settlement Agreement and its Customer Education and Outreach Plan                                                                                                  
Change in regulatory asset                                                                                                  
Settlement amount                             $ 24,750,000                                                                    
Settlement amount returned to customers                             $ 24,000,000                                                                    
Arizona Public Service Company | Damage from Fire, Explosion or Other Hazard                                                                                                  
Change in regulatory asset                                                                                                  
Past due balance threshold qualifying for payment extension                                                                             $ 75                    
ACC | Arizona Public Service Company                                                                                                  
Settlement Agreement                                                                                                  
Program term                                                                   18 years                              
Change in regulatory asset                                                                                                  
Public utilities, requested rate increase (decrease), income tax amount                                               $ (184,000,000)       $ 86,500,000                                          
Requested rate increase (decrease), deferred taxes amortization, period                                                     28 years 6 months                                            
Public utilities, requested rate increase (decrease), amount, one-time bill credit                                                 $ 64,000,000                                                
Public utilities, requested rate increase (decrease), amount, one-time bill credit, additional benefit                                                 $ 39,500,000                                                
Number of public utility programs | program                                                                   2                              
Solar power capacity | MW                                                                   80                              
Arizona Renewable Energy Standard and Tariff | ACC | Arizona Public Service Company                                                                                                  
Settlement Agreement                                                                                                  
Plan term                                                               5 years                                  
Arizona Renewable Energy Standard and Tariff 2018 | ACC | Arizona Public Service Company                                                                                                  
Settlement Agreement                                                                                                  
Amount of proposed budget                                                                           $ 86,200,000     $ 100,500,000   $ 93,100,000 $ 84,700,000       $ 86,300,000  
Revenue requirements                                                                                       $ 4,500,000          
Authorized amount to be collected                       $ 68,300,000                                                                          
Arizona Renewable Energy Standard and Tariff 2018 | ACC | Arizona Public Service Company | Minimum                                                                                                  
Change in regulatory asset                                                                                                  
Authorized spending in capital costs         $ 20,000,000                                                                                        
Arizona Renewable Energy Standard and Tariff 2018 | ACC | Arizona Public Service Company | Maximum                                                                                                  
Change in regulatory asset                                                                                                  
Authorized spending in capital costs         $ 30,000,000                                                                                        
Arizona Renewable Energy Standard and Tariff 2018 | ACC | Arizona Public Service Company | Solar Communities                                                                                                  
Settlement Agreement                                                                                                  
Program term                                                         3 years                                        
Arizona Renewable Energy Standard and Tariff 2018 | ACC | Arizona Public Service Company | Solar Communities | Minimum                                                                                                  
Settlement Agreement                                                                                                  
Required annual capital investment                                                         $ 10,000,000                                        
Arizona Renewable Energy Standard and Tariff 2018 | ACC | Arizona Public Service Company | Solar Communities | Maximum                                                                                                  
Settlement Agreement                                                                                                  
Required annual capital investment                                                         $ 15,000,000                                        
Power Supply Adjustor (PSA) | ACC | Arizona Public Service Company                                                                                                  
Change in regulatory asset                                                                                                  
Beginning balance                                                               $ 388,148,000 175,835,000                                
Deferred fuel and purchased power costs — current period                                                               291,992,000 256,871,000                                
Amounts charged to customers                                                               (219,579,000) (44,558,000)                                
Ending balance                                                               $ 460,561,000 $ 388,148,000 $ 175,835,000                              
PSA rate (in dollars per kWh) | $ / kWh                 0.007544 0.003544       0.001544     0.003544         (0.000456)                                                      
Forward component Of PSA rate1 (in dollars per kWh) | $ / kWh                 (0.004842) (0.004444)       (0.004444)     0.003434         (0.002086)                                                      
Historical component Of PSA rate1 (in dollars per kWh)                 0.012386 0.007988       0.005988     0.000110         0.001630                                                      
Fuel and purchased power costs above annual cap     $ 456,000,000                           $ 215,900,000                                                                
Power Supply Adjustor (PSA) | ACC | Arizona Public Service Company | Subsequent Event                                                                                                  
Change in regulatory asset                                                                                                  
PSA rate (in dollars per kWh) 0.019074 0.006                                                                                              
Period to reduce balancing account 24 months                                                                                                
Reporting threshold of balancing account $ 500,000                                                                                                
Power Supply Adjustor (PSA) | ACC | Arizona Public Service Company | Cost Recovery Mechanisms                                                                                                  
Change in regulatory asset                                                                                                  
Maximum increase decrease in PSA rate (in dollars per kWh) | $ / kWh                                           0.004                                                      
PSA rate In prior years1 (in dollars per kWh) | $ / kWh                 (0.004)               (0.004)         0.002115                                                      
Number of agreements | agreement                                                                                   3             2
Retail Rate Case Filing with Arizona Corporation Commission | Arizona Public Service Company | Maximum                                                                                                  
Change in regulatory asset                                                                                                  
Fixed costs recoverable per power lost (in dollars per kWh) | $ / KWH_Kilowatt_hour                                               2.68                                                  
Retail Rate Case Filing with Arizona Corporation Commission | ACC | Arizona Public Service Company                                                                                                  
Change in regulatory asset                                                                                                  
Commercial customers, market pricing, threshold | MW       140     280                                 200                                                  
Demand Side Management Adjustor Charge 2020 | ACC | Arizona Public Service Company                                                                                                  
Settlement Agreement                                                                                                  
Amount of proposed budget                                                                                         $ 51,900,000   $ 51,900,000    
Demand Side Management Adjustor Charge 2021 | ACC | Arizona Public Service Company                                                                                                  
Settlement Agreement                                                                                                  
Amount of proposed budget                                                                   $ 63,700,000                              
Demand Side Management Adjustor Charge 2022 | ACC | Arizona Public Service Company                                                                                                  
Settlement Agreement                                                                                                  
Amount of proposed budget                                                                               $ 78,400,000                  
Change in regulatory asset                                                                                                  
Rate matter, increase (decrease) in proposed budget                                                                               $ 14,000,000                  
Demand Side Management Adjustor Charge 2023 | ACC | Arizona Public Service Company                                                                                                  
Settlement Agreement                                                                                                  
Amount of proposed budget                                                                         $ 88,000,000                        
Environmental Improvement Surcharge | FERC | Arizona Public Service Company                                                                                                  
Change in regulatory asset                                                                                                  
Rate matters, environmental surcharge cap rate1 (in dollars per kWh) | $ / KWH_Kilowatt_hour                 0.0005                                                                                
Environmental Improvement Surcharge | FERC | Arizona Public Service Company | Subsequent Event                                                                                                  
Change in regulatory asset                                                                                                  
Rate matters, increase (decrease) In cost recovery   $ 14,700,000                                                                                              
Rate matters, increase (decrease) In cost recovery, excess Of annual amount   $ 3,300,000                                                                                              
Environmental Improvement Surcharge | FERC | Arizona Public Service Company | Minimum                                                                                                  
Change in regulatory asset                                                                                                  
Rate matters, environmental surcharge cap rate1, amount                 $ 13,000,000                                                                                
Environmental Improvement Surcharge | FERC | Arizona Public Service Company | Maximum                                                                                                  
Change in regulatory asset                                                                                                  
Rate matters, environmental surcharge cap rate1, amount                 $ 15,000,000                                                                                
Transmission rates, transmission cost adjustor and other transmission matters | FERC | Arizona Public Service Company                                                                                                  
Change in regulatory asset                                                                                                  
Rate matters, increase (decrease) In cost recovery           $ 33,000,000             $ 4,000,000           $ (6,100,000)                                                            
Rate matters, increase (decrease) in cost recovery, wholesale customer rates           6,400,000             3,200,000           (4,800,000)                                                            
Rate matters, increase (decrease) in cost recovery, retail customer rates           26,600,000             7,200,000           (10,900,000)                                                            
Rate matters, increase (decrease) In retail revenue requirements           $ 2,400,000             $ 28,400,000           $ 7,400,000                                                            
Lost Fixed Cost Recovery Mechanism | Arizona Public Service Company                                                                                                  
Change in regulatory asset                                                                                                  
Fixed costs recoverable per power lost (in dollars per kWh)                                                                     0.025 2.56                          
Rate matter cap percentage of retail revenue                                                               1.00%                                  
Amount of adjustment approved representing prorated sales losses pending approval               $ 59,100,000               $ 38,500,000         $ 26,600,000                                                        
Increase (decrease) In amount Of adjustment representing prorated sales losses               $ 32,500,000               $ 11,800,000         $ (9,600,000)                                                        
Net Metering | ACC | Arizona Public Service Company                                                                                                  
Change in regulatory asset                                                                                                  
Rate matters, cost of service, resource comparison proxy method, maximum annual percentage decrease         10.00%                                                 10.00%                                      
Rate matters, cost of service for interconnected dg system customers, grandfathered period                                                           20 years                                      
Rate matters, cost of service for new customers, guaranteed export price period                                                           10 years                                      
Rate matter, request second-year energy price for exported energy1 (in dollars per kwh) | $ / kWh         0.0846           0.094                 0.094           0.105                                              
v3.22.4
Regulatory Matters - Four Corners, Cholla and Navajo Plant (Details) - Arizona Public Service Company - USD ($)
$ in Millions
 1 Months Ended 12 Months Ended
Nov. 02, 2021
Sep. 30, 2018
Apr. 30, 2018
Dec. 31, 2022
Aug. 02, 2021
Coal Community Transition Plan | Navajo Nation, Economic Development Organization | Retail Rate Case Filing with Arizona Corporation Commission | ACC          
Acquisition          
Disallowance of annual amortization percentage         15.00%
Retired power plant costs          
Acquisition          
Net book value       $ 37.2  
Navajo Plant          
Acquisition          
Net book value       52.6  
Navajo Plant, Coal Reclamation Regulatory Asset          
Acquisition          
Net book value       13.9  
SCE | Four Corners Units 4 and 5          
Acquisition          
Settlement agreement, ACC approved rate adjustment, annualized customer impact   $ 58.5 $ 67.5    
Disallowance of plant investments $ 194.0        
Cost deferrals $ 215.5        
Amount not recoverable       $ 154.4  
v3.22.4
Regulatory Matters - Schedule of Regulatory Assets (Details) - USD ($)
$ in Thousands
Dec. 31, 2022
Dec. 31, 2021
Detail of regulatory assets    
Total noncurrent regulatory assets $ 1,822,100 $ 1,711,511
Less: current regulatory assets 538,879 518,524
Total noncurrent regulatory assets 1,283,221 1,192,987
Pension    
Detail of regulatory assets    
Total noncurrent regulatory assets 637,656 509,751
Deferred fuel and purchased power    
Detail of regulatory assets    
Total noncurrent regulatory assets 460,561 388,148
Income taxes — AFUDC equity    
Detail of regulatory assets    
Total noncurrent regulatory assets 179,631 172,393
Ocotillo deferral    
Detail of regulatory assets    
Total noncurrent regulatory assets 138,143 147,650
Retired power plant costs    
Detail of regulatory assets    
Total noncurrent regulatory assets 98,692 114,841
SCR deferral    
Detail of regulatory assets    
Total noncurrent regulatory assets 97,624 105,771
Deferred property taxes    
Detail of regulatory assets    
Total noncurrent regulatory assets 41,057 49,626
Deferred compensation    
Detail of regulatory assets    
Total noncurrent regulatory assets 33,660 33,997
Income taxes — investment tax credit basis adjustment    
Detail of regulatory assets    
Total noncurrent regulatory assets 23,977 24,768
Palo Verde VIEs (Note 17)    
Detail of regulatory assets    
Total noncurrent regulatory assets 20,933 21,094
Active union medical trust    
Detail of regulatory assets    
Total noncurrent regulatory assets 18,226 1,175
Four Corners cost deferral    
Detail of regulatory assets    
Total noncurrent regulatory assets 15,999 24,075
Navajo coal reclamation    
Detail of regulatory assets    
Total noncurrent regulatory assets 13,862 16,840
Lost fixed cost recovery    
Detail of regulatory assets    
Total noncurrent regulatory assets 9,547 63,889
Loss on reacquired debt    
Detail of regulatory assets    
Total noncurrent regulatory assets 9,468 11,020
Mead-Phoenix transmission line — contributions in aid of construction    
Detail of regulatory assets    
Total noncurrent regulatory assets 9,048 9,380
Tax expense adjustor mechanism    
Detail of regulatory assets    
Total noncurrent regulatory assets 5,845 6,501
Other    
Detail of regulatory assets    
Total noncurrent regulatory assets $ 8,171 $ 10,592
v3.22.4
Regulatory Matters - Schedule of Regulatory Liabilities (Details) - USD ($)
$ in Thousands
Dec. 31, 2022
Dec. 31, 2021
Detail of regulatory liabilities    
Total regulatory liabilities $ 2,333,351 $ 2,795,484
Less: current regulatory liabilities 271,575 296,271
Total noncurrent regulatory liabilities 2,061,776 2,499,213
Asset retirement obligations    
Detail of regulatory liabilities    
Total regulatory liabilities 354,002 614,683
Other postretirement benefits    
Detail of regulatory liabilities    
Total regulatory liabilities 270,604 374,816
Removal costs    
Detail of regulatory liabilities    
Total regulatory liabilities 106,889 119,580
Deferred Fuel and Purchased Power MTM Costs [Member]    
Detail of regulatory liabilities    
Total regulatory liabilities 96,367 107,601
Income taxes — change in rates    
Detail of regulatory liabilities    
Total regulatory liabilities 64,806 67,678
Four Corners coal reclamation    
Detail of regulatory liabilities    
Total regulatory liabilities 52,592 55,392
Income taxes — deferred investment tax credit    
Detail of regulatory liabilities    
Total regulatory liabilities 48,035 49,601
Spent nuclear fuel    
Detail of regulatory liabilities    
Total regulatory liabilities 39,217 45,282
Renewable energy program    
Detail of regulatory liabilities    
Total regulatory liabilities 35,720 38,640
FERC transmission true up    
Detail of regulatory liabilities    
Total regulatory liabilities 22,895 34,303
Property tax deferral    
Detail of regulatory liabilities    
Total regulatory liabilities 15,521 20,192
Sundance maintenance    
Detail of regulatory liabilities    
Total regulatory liabilities 16,893 13,797
Demand side management    
Detail of regulatory liabilities    
Total regulatory liabilities 8,461 5,417
Tax expense adjustor mechanism    
Detail of regulatory liabilities    
Total regulatory liabilities 4,835 4,835
Other    
Detail of regulatory liabilities    
Total regulatory liabilities 3,092 2,103
ACC | Excess deferred income taxes - ACC - Tax Cuts and Jobs Act    
Detail of regulatory liabilities    
Total regulatory liabilities 971,545 1,012,448
FERC | Excess deferred income taxes - ACC - Tax Cuts and Jobs Act    
Detail of regulatory liabilities    
Total regulatory liabilities $ 221,877 $ 229,116
v3.22.4
Income Taxes - Additional Information (Details)
$ in Millions
 12 Months Ended
Dec. 31, 2022
USD ($)
Income Taxes  
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 5
Arizona Public Service Company  
Income Taxes  
Increase (decrease) in deferred income taxes due to regulation adoption 5
State  
Income Taxes  
State credit carryforwards net of federal benefit 43
State | Arizona Public Service Company  
Income Taxes  
State credit carryforwards net of federal benefit $ 19
v3.22.4
Income Taxes - Reconciliation of Unrecognized Tax Benefits (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2022
Dec. 31, 2021
Dec. 31, 2020
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 $ 45,086 $ 45,655 $ 43,435
Additions for tax positions of the current year 1,399 3,305 3,418
Additions for tax positions of prior years 2,069 1,449 1,431
Reductions for tax positions of prior years for:      
Changes in judgment (3,495) (2,659) (1,965)
Settlements with taxing authorities 0 0 0
Lapses of applicable statute of limitations (1,962) (2,664) (664)
Total unrecognized tax benefits, end of the year 43,097 45,086 45,655
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 45,086 45,655 43,435
Additions for tax positions of the current year 1,399 3,305 3,418
Additions for tax positions of prior years 2,069 1,449 1,431
Reductions for tax positions of prior years for:      
Changes in judgment (3,495) (2,659) (1,965)
Settlements with taxing authorities 0 0 0
Lapses of applicable statute of limitations (1,962) (2,664) (664)
Total unrecognized tax benefits, end of the year $ 43,097 $ 45,086 $ 45,655
v3.22.4
Income Taxes - Summary of Unrecognized Tax Benefits (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2022
Dec. 31, 2021
Dec. 31, 2020
Income Tax [Line Items]      
Tax positions, that if recognized, would decrease our effective tax rate $ 28,246 $ 26,300 $ 25,714
Unrecognized tax benefit interest expense/(benefit) recognized (139) (535) 266
Unrecognized tax benefit interest accrued 1,181 1,320 1,855
Arizona Public Service Company      
Income Tax [Line Items]      
Tax positions, that if recognized, would decrease our effective tax rate 28,246 26,300 25,714
Unrecognized tax benefit interest expense/(benefit) recognized (139) (535) 266
Unrecognized tax benefit interest accrued $ 1,181 $ 1,320 $ 1,855
v3.22.4
Income Taxes - Components of Income Tax Expense (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2022
Dec. 31, 2021
Dec. 31, 2020
Current:      
Federal $ 35,617 $ (5,041) $ 11,869
State 1,950 2,458 1,932
Total current 37,567 (2,583) 13,801
Deferred:      
Federal 23,693 95,327 53,398
State 13,567 17,342 10,974
Total deferred 37,260 112,669 64,372
Income tax expense/(benefit) 74,827 110,086 78,173
Arizona Public Service Company      
Current:      
Federal 103,349 1,514 57,299
State 161 (11) 99
Total current 103,510 1,503 57,398
Deferred:      
Federal (31,860) 101,175 15,122
State 19,150 22,875 16,244
Total deferred (12,710) 124,050 31,366
Income tax expense/(benefit) $ 90,800 $ 125,553 $ 88,764
v3.22.4
Income Taxes - Effective Tax Rate Reconciliation (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2022
Dec. 31, 2021
Dec. 31, 2020
Income Tax Reconciliation Increases Reductions in Tax Expense [Abstract]      
Federal income tax expense at statutory rate $ 120,887 $ 156,666 $ 136,127
State income tax net of federal income tax benefit 17,740 22,656 19,146
State income tax credits net of federal income tax benefit (5,482) (7,015) (8,951)
Net operating loss carryback tax benefit 0 (5,915) 0
Excess deferred income taxes — Tax Cuts and Jobs Act (36,241) (36,558) (50,543)
Allowance for equity funds used during construction (see Note 1) (4,629) (4,180) (2,747)
Palo Verde VIE noncontrolling interest (see Note 17) (3,617) (3,617) (4,094)
Investment tax credit amortization (5,608) (7,620) (7,510)
Other federal income tax credits (10,867) (6,976) (4,616)
Other 2,644 2,645 1,361
Income tax expense/(benefit) 74,827 110,086 78,173
Arizona Public Service Company      
Income Tax Reconciliation Increases Reductions in Tax Expense [Abstract]      
Federal income tax expense at statutory rate 132,920 162,762 142,020
State income tax net of federal income tax benefit 19,000 23,339 20,124
State income tax credits net of federal income tax benefit (3,744) (5,277) (7,213)
Net operating loss carryback tax benefit 0 0 0
Excess deferred income taxes — Tax Cuts and Jobs Act (36,241) (36,558) (50,543)
Allowance for equity funds used during construction (see Note 1) (4,629) (4,180) (2,747)
Palo Verde VIE noncontrolling interest (see Note 17) (3,617) (3,617) (4,094)
Investment tax credit amortization (5,608) (7,620) (7,510)
Other federal income tax credits (7,721) (3,912) (3,035)
Other 440 616 1,762
Income tax expense/(benefit) $ 90,800 $ 125,553 $ 88,764
v3.22.4
Income Taxes - Components of Deferred Income Tax Liability (Details) - USD ($)
$ in Thousands
Dec. 31, 2022
Dec. 31, 2021
DEFERRED TAX ASSETS    
Risk management activities $ 8,826 $ 677
Regulatory liabilities:    
Excess deferred income taxes — Tax Cuts and Jobs Act 295,014 306,915
Asset retirement obligation and removal costs 107,104 174,952
Unamortized investment tax credits 48,035 49,601
Other postretirement benefits 66,893 92,654
Other 62,915 65,815
Operating lease liabilities 184,030 204,890
Pension liabilities 33,674 42,136
Coal reclamation liabilities 44,312 43,165
Renewable energy incentives 19,948 22,646
Credit and loss carryforwards 37,647 57,077
Other 72,605 74,184
Total deferred tax assets 981,003 1,134,712
DEFERRED TAX LIABILITIES    
Plant-related (2,518,164) (2,570,613)
Risk management activities (32,648) (27,276)
Pension and other postretirement assets (96,845) (133,624)
Other special use funds (57,572) (64,610)
Operating lease right-of-use assets (184,030) (204,890)
Regulatory assets:    
Allowance for equity funds used during construction (44,405) (42,616)
Deferred fuel and purchased power (114,232) (96,033)
Pension benefits (157,629) (126,010)
Retired power plant costs (24,397) (28,389)
Other (103,023) (123,902)
Other (32,479) (28,611)
Total deferred tax liabilities (3,365,424) (3,446,574)
Deferred income taxes — net (2,384,421) (2,311,862)
Arizona Public Service Company    
DEFERRED TAX ASSETS    
Risk management activities 8,826 677
Regulatory liabilities:    
Excess deferred income taxes — Tax Cuts and Jobs Act 295,014 306,915
Asset retirement obligation and removal costs 107,104 174,952
Unamortized investment tax credits 48,035 49,601
Other postretirement benefits 66,893 92,654
Other 62,915 65,815
Operating lease liabilities 182,663 204,378
Pension liabilities 30,436 37,814
Coal reclamation liabilities 44,312 43,165
Renewable energy incentives 19,948 22,646
Credit and loss carryforwards 13,654 18,902
Other 72,605 74,184
Total deferred tax assets 952,405 1,091,703
DEFERRED TAX LIABILITIES    
Plant-related (2,518,164) (2,570,613)
Risk management activities (32,648) (27,276)
Pension and other postretirement assets (96,196) (132,769)
Other special use funds (57,572) (64,610)
Operating lease right-of-use assets (182,663) (204,378)
Regulatory assets:    
Allowance for equity funds used during construction (44,405) (42,616)
Deferred fuel and purchased power (114,232) (96,033)
Pension benefits (157,629) (126,010)
Retired power plant costs (24,397) (28,389)
Other (103,023) (123,902)
Other (7,123) (6,808)
Total deferred tax liabilities (3,338,052) (3,423,404)
Deferred income taxes — net $ (2,385,647) $ (2,331,701)
v3.22.4
Lines of Credit and Short-Term Borrowings - Schedule of Credit Facilities (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2022
Dec. 31, 2021
Pinnacle West    
Lines of Credit and Short-Term Borrowings    
Commitment fees (as a percent) 0.175% 0.175%
Arizona Public Service Company    
Lines of Credit and Short-Term Borrowings    
Commitment fees (as a percent) 0.125% 0.125%
Revolving credit facility    
Lines of Credit and Short-Term Borrowings    
Commitments under Credit Facilities $ 1,200,000 $ 1,200,000
Outstanding Commercial Paper, Term Loan and Revolving Credit Facility Borrowings (340,720) (292,000)
Amount of Credit Facilities Available 859,280 908,000
Revolving credit facility | Pinnacle West    
Lines of Credit and Short-Term Borrowings    
Commitments under Credit Facilities 200,000 200,000
Outstanding Commercial Paper, Term Loan and Revolving Credit Facility Borrowings (15,720) (13,300)
Amount of Credit Facilities Available 184,280 186,700
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 (325,000) (278,700)
Amount of Credit Facilities Available $ 675,000 $ 721,300
v3.22.4
Lines of Credit and Short-Term Borrowings - Additional Information (Details)
$ in Thousands
Dec. 31, 2022
USD ($)
Facility
Dec. 31, 2021
USD ($)
Dec. 17, 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
Revolving credit facility      
Lines of Credit and Short-Term Borrowings      
Commitments under Credit Facilities $ 1,200,000 $ 1,200,000  
Long-term line of credit 340,720 292,000  
Revolving credit facility | Arizona Public Service Company      
Lines of Credit and Short-Term Borrowings      
Commitments under Credit Facilities 1,000,000 1,000,000  
Long-term line of credit 325,000 278,700  
Revolving credit facility | Revolving credit facility maturing May 2026 | Arizona Public Service Company      
Lines of Credit and Short-Term Borrowings      
Commitments under Credit Facilities 500,000    
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders 1,400,000    
Long-term line of credit $ 0    
Number of credit facilities | Facility 2    
Revolving credit facility | Revolving credit facility maturing May 2026, facility two | Arizona Public Service Company      
Lines of Credit and Short-Term Borrowings      
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders $ 700,000    
Revolving credit facility | Revolving credit facility maturing May 2026, facility one | Arizona Public Service Company      
Lines of Credit and Short-Term Borrowings      
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders 700,000    
Letter of Credit | Arizona Public Service Company      
Lines of Credit and Short-Term Borrowings      
Outstanding letters of credit 10,000    
Letter of Credit | Revolving credit facility maturing May 2026 | Arizona Public Service Company      
Lines of Credit and Short-Term Borrowings      
Outstanding letters of credit 0    
Commercial paper | Arizona Public Service Company      
Lines of Credit and Short-Term Borrowings      
Maximum commercial paper support available under credit facility 750,000    
Commercial paper | Revolving credit facility maturing May 2026 | Arizona Public Service Company      
Lines of Credit and Short-Term Borrowings      
Commercial paper 325,000    
Pinnacle West | Revolving credit facility      
Lines of Credit and Short-Term Borrowings      
Commitments under Credit Facilities 200,000 200,000  
Long-term line of credit 15,720 $ 13,300  
Pinnacle West | Revolving credit facility | Revolving credit facility maturing May 2026      
Lines of Credit and Short-Term Borrowings      
Commitments under Credit Facilities 200,000    
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders 300,000    
Long-term line of credit 0    
Pinnacle West | Letter of Credit | Revolving credit facility maturing May 2026      
Lines of Credit and Short-Term Borrowings      
Outstanding letters of credit 0    
Pinnacle West | Commercial paper | Revolving credit facility maturing May 2026      
Lines of Credit and Short-Term Borrowings      
Commercial paper $ 16,000    
v3.22.4
Long-Term Debt and Liquidity Matters - Components of Long-Term Debt (Details) - USD ($)
$ in Thousands
Dec. 31, 2022
Dec. 31, 2021
Long-Term Debt and Liquidity Matters [Line Items]    
Total long-term debt $ 7,791,971 $ 7,063,735
TOTAL LONG-TERM DEBT LESS CURRENT MATURITIES 7,741,286 6,913,735
Pinnacle West    
Long-Term Debt and Liquidity Matters [Line Items]    
Gross long-term debt 7,844,660  
Unamortized discount (25) (34)
Unamortized debt issuance cost (2,083) (2,924)
Total long-term debt 947,892 797,042
Less current maturities 0 150,000
Total long-term debt less current maturities 947,892 647,042
TOTAL LONG-TERM DEBT LESS CURRENT MATURITIES 947,892 647,139
Arizona Public Service Company    
Long-Term Debt and Liquidity Matters [Line Items]    
Gross long-term debt 6,843,975  
Unamortized discount (14,548) (14,995)
Unamortized premium 12,368 13,575
Unamortized debt issuance cost (48,266) (47,862)
Total long-term debt 6,793,529 6,266,693
Less current maturities 0 0
Total long-term debt less current maturities 6,793,529 6,266,693
TOTAL LONG-TERM DEBT LESS CURRENT MATURITIES 6,793,529 6,266,693
Bright Canyon Energy Corporation    
Long-Term Debt and Liquidity Matters [Line Items]    
Gross long-term debt 50,685  
Los Alamitos equity bridge loan 27,575 0
Los Alamitos construction facility 23,110 0
Unamortized debt issuance cost (135) 0
Total long-term debt 50,550 0
Less current maturities 50,685 0
Total long-term debt less current maturities (135) 0
Pollution Control Bonds - Variable | Arizona Public Service Company    
Long-Term Debt and Liquidity Matters [Line Items]    
Gross long-term debt $ 163,975 $ 35,975
Weighted-average interest rate (as a percent) 3.96% 0.22%
Total Pollution Control Bonds | Arizona Public Service Company    
Long-Term Debt and Liquidity Matters [Line Items]    
Gross long-term debt $ 163,975 $ 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 $ 6,680,000 6,280,000
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 $ 450,000 $ 300,000
Term Loan | Arizona Public Service Company    
Long-Term Debt and Liquidity Matters [Line Items]    
Weighted-average interest rate (as a percent) 5.10% 0.81%
Variable Rate Construction Facility | Bright Canyon Energy Corporation    
Long-Term Debt and Liquidity Matters [Line Items]    
Weighted-average interest rate (as a percent) 5.71%  
Bridge Loan | Bright Canyon Energy Corporation    
Long-Term Debt and Liquidity Matters [Line Items]    
Weighted-average interest rate (as a percent) 5.18%  
v3.22.4
Long-Term Debt and Liquidity Matters - Future Principal Payments (Details)
$ in Thousands
Dec. 31, 2022
USD ($)
Arizona Public Service Company  
Principal payments due on long-term debt  
2023 $ 0
2024 250,000
2025 300,000
2026 250,000
2027 300,000
Thereafter 5,743,975
Total 6,843,975
Bright Canyon Energy Corporation  
Principal payments due on long-term debt  
2023 50,685
2024 0
2025 0
2026 0
2027 0
Thereafter 0
Total 50,685
Pinnacle West  
Principal payments due on long-term debt  
2023 50,685
2024 700,000
2025 800,000
2026 250,000
2027 300,000
Thereafter 5,743,975
Total $ 7,844,660
v3.22.4
Long-Term Debt and Liquidity Matters - Fair Value of Long-Term Debt (Details) - USD ($)
$ in Thousands
Dec. 31, 2022
Dec. 31, 2021
Estimated fair value of long-term debt, including current maturities    
Carrying Amount $ 7,791,971 $ 7,063,735
Fair Value 6,585,701 7,726,354
Arizona Public Service Company    
Estimated fair value of long-term debt, including current maturities    
Carrying Amount 6,793,529 6,266,693
Fair Value 5,629,491 6,933,619
Bright Canyon Energy Corporation    
Estimated fair value of long-term debt, including current maturities    
Carrying Amount 50,550 0
Fair Value 50,685 0
Pinnacle West    
Estimated fair value of long-term debt, including current maturities    
Carrying Amount 947,892 797,042
Fair Value $ 905,525 $ 792,735
v3.22.4
Long-Term Debt and Liquidity Matters - Additional Information (Details)
$ in Thousands
 12 Months Ended
Jan. 06, 2023
USD ($)
Sep. 15, 2022
USD ($)
Feb. 11, 2022
USD ($)
MW
Jan. 06, 2022
USD ($)
Dec. 21, 2021
USD ($)
Dec. 31, 2022
USD ($)
Dec. 31, 2021
USD ($)
Dec. 31, 2020
USD ($)
Dec. 16, 2022
USD ($)
Nov. 08, 2022
USD ($)
Dec. 23, 2020
USD ($)
Dec. 17, 2020
USD ($)
Dec. 16, 2020
USD ($)
Long-Term Debt and Liquidity Matters [Line Items]                          
Issuance of long-term debt           $ 875,537 $ 746,999 $ 1,596,672          
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]                          
Issuance of long-term debt           $ 524,852 446,999 1,099,722          
Equity infusion from Pinnacle West       $ 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)           50.80%              
Arizona Public Service Company | Subsequent Event                          
Long-Term Debt and Liquidity Matters [Line Items]                          
Equity infusion from Pinnacle West $ 150,000                        
Arizona Public Service Company | Pollution Control Revenue Bonds                          
Long-Term Debt and Liquidity Matters [Line Items]                          
Notes issued   $ 32,000                      
Issuance of long-term debt   $ 128,000                      
Arizona Public Service Company | ACC                          
Debt Provisions                          
Long term debt authorization                       $ 8,000,000 $ 7,500,000
Bright Canyon Energy Corporation                          
Long-Term Debt and Liquidity Matters [Line Items]                          
Public Utilities, Solar and Battery Storage Capacity | MW     31                    
Unsecured Senior Notes Maturing 2032 | Arizona Public Service Company | Senior Notes                          
Long-Term Debt and Liquidity Matters [Line Items]                          
Notes issued                   $ 400,000      
Interest rate (as a percent)                   6.35%      
Term Loan | Non-Recourse Construction Term Loan Facility | Bright Canyon Energy Corporation                          
Long-Term Debt and Liquidity Matters [Line Items]                          
Notes issued     $ 42,000                    
Long-term line of credit           $ 23,000              
Bridge Loan | Equity Bridge Loan Facility | Bright Canyon Energy Corporation                          
Long-Term Debt and Liquidity Matters [Line Items]                          
Notes issued     33,000                    
Issuance of long-term debt           28,000              
Letter of Credit | Arizona Public Service Company                          
Long-Term Debt and Liquidity Matters [Line Items]                          
Outstanding letters of credit           10,000              
Letter of Credit | Bright Canyon Energy Corporation                          
Long-Term Debt and Liquidity Matters [Line Items]                          
Notes issued     5,000                    
Letter of Credit | Revolving credit facility maturing May 2026 | Arizona Public Service Company                          
Long-Term Debt and Liquidity Matters [Line Items]                          
Outstanding letters of credit           0              
Letter of Credit | Revolving credit facility maturing May 2026 | Bright Canyon Energy Corporation                          
Long-Term Debt and Liquidity Matters [Line Items]                          
Outstanding letters of credit           2,500              
Pinnacle West                          
Long-Term Debt and Liquidity Matters [Line Items]                          
Issuance of long-term debt           $ 300,000 $ 300,000 $ 496,950          
Debt Provisions                          
Actual ratio of consolidated debt to total consolidated capitalization required to be maintained as per the debt covenant (as a percent)           57.70%              
Pinnacle West | Term Loan                          
Long-Term Debt and Liquidity Matters [Line Items]                          
Notes issued                 $ 175,000   $ 150,000    
Pinnacle West | Term Loan | Term Loan Maturing 2024                          
Long-Term Debt and Liquidity Matters [Line Items]                          
Notes issued         $ 450,000                
Issuance of long-term debt       $ 300,000 $ 150,000                
Pinnacle West | Bridge Loan | Bright Canyon Energy Corporation                          
Long-Term Debt and Liquidity Matters [Line Items]                          
Debt guarantee     $ 42,000                    
Pinnacle West | Letter of Credit | Revolving credit facility maturing May 2026                          
Long-Term Debt and Liquidity Matters [Line Items]                          
Outstanding letters of credit           $ 0              
v3.22.4
Retirement Plans and Other Postretirement Benefits - Additional Information (Details) - USD ($)
 12 Months Ended
Jan. 04, 2021
Dec. 31, 2022
Dec. 31, 2021
Dec. 31, 2020
Dec. 31, 2019
Defined Benefit Plan Disclosure [Line Items]          
Ultimate healthcare cost trend rate (pre-65 participants)   4.75% 4.75%   4.75%
Initial and ultimate healthcare cost trend rate (post-65 participants) (a)   2.00% 2.00%    
Funded percentage (more than)   100.00% 100.00%    
Partnership funding commitments, contribution amount (up to)   $ 50,000,000      
Partnership funding commitments, funded amount   38,000,000      
Other Benefits          
Defined Benefit Plan Disclosure [Line Items]          
Transfer to active union medical account $ 106,000,000 $ 0 $ 105,852,000    
Expected long-term return on plan assets for next fiscal year (as a percent)   6.95%      
Contributions          
Employer contributions   $ 0 0    
Minimum contributions under MAP-21          
Retiree medical cost reimbursement   26,000,000 24,000,000 $ 26,000,000  
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)   6.70%      
Contributions          
Employer contributions   $ 0 100,000,000 100,000,000  
Minimum contributions under MAP-21          
Minimum contributions under MAP-21   0      
Pinnacle West          
Minimum contributions under MAP-21          
Expenses recorded for the defined contribution savings plan   $ 12,000,000 $ 12,000,000 $ 11,000,000  
Arizona Public Service Company          
Minimum contributions under MAP-21          
APS's employees share of total cost of the plans (as a percent)   99.00%      
v3.22.4
Retirement Plans and Other Postretirement Benefits - Net Periodic Benefit Costs and Portion including Portion Charged to Expense (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2022
Dec. 31, 2021
Dec. 31, 2020
Net periodic benefit costs and the portion of these costs charged to expense      
Portion of cost/(benefit) charged to expense $ (98,487) $ (112,541) $ (56,341)
Pension Benefits      
Net periodic benefit costs and the portion of these costs charged to expense      
Service cost-benefits earned during the period 55,473 61,236 56,233
Interest cost on benefit obligation 107,492 98,566 118,567
Expected return on plan assets (185,775) (202,628) (187,443)
Prior service credit 0 0 0
Net actuarial (gain)/loss 17,515 15,948 34,612
Net periodic benefit cost/(benefit) (5,295) (26,878) 21,969
Portion of cost/(benefit) charged to expense (16,431) (32,743) 3,386
Other Benefits      
Net periodic benefit costs and the portion of these costs charged to expense      
Service cost-benefits earned during the period 16,470 17,796 22,236
Interest cost on benefit obligation 17,491 16,513 25,857
Expected return on plan assets (46,042) (41,444) (40,077)
Prior service credit (37,789) (37,705) (37,575)
Net actuarial (gain)/loss (12,835) (10,093) 0
Net periodic benefit cost/(benefit) (62,705) (54,933) (29,559)
Portion of cost/(benefit) charged to expense $ (45,042) $ (38,657) $ (20,966)
v3.22.4
Retirement Plans and Other Postretirement Benefits - Changes Benefit Obligations and Funded Status (Details) - USD ($)
$ in Thousands
 12 Months Ended
Jan. 04, 2021
Dec. 31, 2022
Dec. 31, 2021
Dec. 31, 2020
Pension Benefits        
Change in Benefit Obligation        
Benefit obligation at the beginning of the period   $ 3,716,824 $ 3,902,867  
Service cost   55,473 61,236 $ 56,233
Interest cost   107,492 98,566 118,567
Benefit payments   (212,565) (207,928)  
Actuarial (gain) loss   (857,695) (137,917)  
Benefit obligation at the end of the period   2,809,529 3,716,824 3,902,867
Change in Plan Assets        
Balance at the beginning of the period   3,812,041 3,886,544  
Actual return on plan assets   (787,874) 18,169  
Employer contributions   0 100,000 100,000
Benefit payments   (194,682) (192,672)  
Transfer to active union medical account $ 106,000 0 0  
Balance at the end of the period   2,829,485 3,812,041 3,886,544
Funded Status at the end of the period   19,956 95,217  
Other Benefits        
Change in Benefit Obligation        
Benefit obligation at the beginning of the period   591,841 624,034  
Service cost   16,470 17,796 22,236
Interest cost   17,491 16,513 25,857
Benefit payments   (30,913) (31,280)  
Actuarial (gain) loss   (185,428) (35,222)  
Benefit obligation at the end of the period   409,461 591,841 624,034
Change in Plan Assets        
Balance at the beginning of the period   872,435 961,165  
Actual return on plan assets   (193,807) 41,432  
Employer contributions   0 0  
Benefit payments   (26,341) (24,310)  
Transfer to active union medical account $ (106,000) 0 (105,852)  
Balance at the end of the period   652,287 872,435 $ 961,165
Funded Status at the end of the period   $ 242,826 $ 280,594  
v3.22.4
Retirement Plans and Other Postretirement Benefits - Projected Benefit Obligation for Pension Plans (Details) - Pension Benefits - USD ($)
$ in Thousands
Dec. 31, 2022
Dec. 31, 2021
Projected benefit obligation and the accumulated benefit obligation for pension plans with an accumulated obligation in excess of plan assets    
Accumulated benefit obligation $ 126,759 $ 161,086
Fair value of plan assets 0 0
Projected benefit obligation 133,818 169,912
Fair value of plan assets $ 0 $ 0
v3.22.4
Retirement Plans and Other Postretirement Benefits - Amounts Recognized on the Consolidated Balance Sheets (Details) - USD ($)
$ in Thousands
Dec. 31, 2022
Dec. 31, 2021
Amounts recognized on the Consolidated Balance Sheets    
Noncurrent asset $ 396,599 $ 545,723
Pension Benefits    
Amounts recognized on the Consolidated Balance Sheets    
Noncurrent asset 153,773 265,129
Current liability (17,531) (17,047)
Noncurrent liability (116,286) (152,865)
Net amount recognized (funded status) 19,956 95,217
Other Benefits    
Amounts recognized on the Consolidated Balance Sheets    
Noncurrent asset 242,826 280,594
Current liability 0 0
Noncurrent liability 0 0
Net amount recognized (funded status) $ 242,826 $ 280,594
v3.22.4
Retirement Plans and Other Postretirement Benefits - Impact to Accumulated Other Comprehensive Loss (Details) - USD ($)
$ in Thousands
Dec. 31, 2022
Dec. 31, 2021
Pension Benefits    
Details related to accumulated other comprehensive loss    
Net actuarial loss (gain) $ 681,335 $ 582,895
Prior service credit 0 0
APS’s portion recorded as a regulatory (asset) liability (637,656) (509,751)
Income tax expense (benefit) (10,797) (18,081)
Accumulated other comprehensive loss (gain) 32,882 55,063
Other Benefits    
Details related to accumulated other comprehensive loss    
Net actuarial loss (gain) (195,095) (262,352)
Prior service credit (76,843) (114,632)
APS’s portion recorded as a regulatory (asset) liability 270,604 374,816
Income tax expense (benefit) 784 990
Accumulated other comprehensive loss (gain) $ (550) $ (1,178)
v3.22.4
Retirement Plans and Other Postretirement Benefits - Weighted-Average Assumptions for Pensions and Other Benefits (Details)
 12 Months Ended
Dec. 31, 2022
Dec. 31, 2021
Dec. 31, 2020
Dec. 31, 2019
Weighted-average assumptions used to determine benefit obligations        
Rate of compensation increase 4.57% 4.00%    
Initial healthcare cost trend rate (pre-65 participants) 6.50% 6.00%    
Ultimate healthcare cost trend rate (pre-65 participants) 4.75% 4.75%   4.75%
Number of years to ultimate trend rate (pre-65 participants) 6 years 4 years    
Initial and ultimate healthcare cost trend rate (post-65 participants) (a) 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 healthcare cost trend rate (pre-65 participants) 6.00% 6.50% 7.00%  
Ultimate healthcare cost trend rate (pre-65 participants) 4.75% 4.75% 4.75%  
Number of years to ultimate trend rate (pre-65 participants) 3 years 4 years 5 years  
Initial and ultimate healthcare cost trend rate (post-65 participants) (a) 2.00% 2.00% 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) 5.56% 2.92%    
Weighted-average assumptions used to determine net periodic benefit costs        
Discount rate (as a percent) 2.92% 2.53% 3.30%  
Rate of compensation increase 4.00% 4.00% 4.00%  
Expected long-term return on plan assets (as a percent) 5.00% 5.30% 5.75%  
Other Benefits        
Weighted-average assumptions used to determine benefit obligations        
Discount rate (as a percent) 5.58% 2.98%    
Weighted-average assumptions used to determine net periodic benefit costs        
Discount rate (as a percent) 2.98% 2.63% 3.42%  
Expected long-term return on plan assets (as a percent) 5.35% 4.90% 4.85%  
v3.22.4
Retirement Plans and Other Postretirement Benefits - Asset Allocation (Details)
Dec. 31, 2022
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 78.00%
Pension Benefits | Return-seeking assets  
Defined Benefit Plan Disclosure [Line Items]  
Target Allocation 20.00%
Actual Allocation 22.00%
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 62.00%
Other Benefits | Return-seeking assets  
Defined Benefit Plan Disclosure [Line Items]  
Actual Allocation 38.00%
v3.22.4
Retirement Plans and Other Postretirement Benefits - Fair Value of Pinnacle West's Pension Plan (Details) - USD ($)
$ in Thousands
Dec. 31, 2022
Dec. 31, 2021
Dec. 31, 2020
Pension Benefits      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Other $ 429,391 $ 530,171  
Fair value of plan assets 2,829,485 3,812,041 $ 3,886,544
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 893,285 1,350,751  
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 1,506,809 1,931,119  
Other Benefits      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Other 106,356 126,552  
Fair value of plan assets 652,287 872,435 $ 961,165
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 371,731 491,981  
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 174,200 253,902  
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 1,252 821  
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 1,252 821  
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 204 121  
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 204 121  
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 1,374,810 1,765,623  
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 1,374,810 1,765,623  
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 166,879 244,572  
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 166,879 244,572  
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 635,245 1,008,211  
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 635,245 1,008,211  
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 221,936 287,057  
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 221,936 287,057  
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 131,999 165,496  
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 131,999 165,496  
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 7,321 9,330  
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 7,321 9,330  
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 155,231 209,063  
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 155,231 209,063  
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 127,493 176,024  
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 127,493 176,024  
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 101,557 132,656  
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 101,557 132,656  
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 18,824 26,262  
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 18,824 26,262  
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 181,912 255,141  
Fair value of plan assets 181,912 255,141  
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 73,956 96,547  
Fair value of plan assets 73,956 96,547  
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 174,228 173,197  
Fair value of plan assets 174,228 173,197  
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 23,541 23,851  
Fair value of plan assets 23,541 23,851  
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 13,359 15,730  
Fair value of plan assets 13,359 15,730  
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 59,892 86,103  
Fair value of plan assets 59,892 86,103  
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 8,859 6,154  
Fair value of plan assets 12,133 8,671  
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 3,274 2,517  
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  
v3.22.4
Retirement Plans and Other Postretirement Benefits - Estimated Future Benefit Payments (Details)
$ in Thousands
Dec. 31, 2022
USD ($)
Pension Benefits  
Estimated Future Benefit Payments  
2023 $ 240,034
2024 227,234
2025 223,813
2026 224,881
2027 221,976
Years 2028-2032 1,117,192
Other Benefits  
Estimated Future Benefit Payments  
2023 31,235
2024 30,865
2025 30,251
2026 30,135
2027 29,790
Years 2028-2032 $ 146,725
v3.22.4
Leases - Additional information (Details)
$ in Thousands
 12 Months Ended
Dec. 31, 2022
USD ($)
Counterparty
Jan. 31, 2023
USD ($)
program
Dec. 31, 2021
USD ($)
Lessee, Lease, Description [Line Items]      
Number of lease agreements, sell and lease back | Counterparty 3    
Lease not yet commenced $ 2,700,000    
Lease not yet commenced period 20 years    
Operating lease right-of-use assets (Note 8) $ 801,688   $ 890,057
Total lease liabilities $ 744,457    
Subsequent Event      
Lessee, Lease, Description [Line Items]      
Number of purchase power operating lease agreements | program   2  
Operating lease right-of-use assets (Note 8)   $ 537,000  
Total lease liabilities   $ 537,000  
v3.22.4
Leases - Lease costs (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2022
Dec. 31, 2021
Dec. 31, 2020
Operating Leased Assets [Line Items]      
Operating Lease Cost $ 122,062 $ 124,260 $ 87,376
Variable lease cost 122,040 118,969 122,331
Short-term lease cost 9,928 3,872 3,804
Purchased Power Lease Contracts      
Operating Leased Assets [Line Items]      
Operating Lease Cost 104,001 105,762 68,883
Land, Property & Equipment Leases      
Operating Leased Assets [Line Items]      
Operating Lease Cost 18,061 18,498 18,493
Total lease cost $ 254,030 $ 247,101 $ 213,511
v3.22.4
Leases - Maturity of our operating lease liabilities (Details)
$ in Thousands
Dec. 31, 2022
USD ($)
Lessee, Lease, Description [Line Items]  
2023 $ 120,405
2024 115,645
2025 115,237
2026 127,223
2027 94,400
Thereafter 248,359
Total lease commitments 821,269
Less imputed interest 76,812
Total lease liabilities 744,457
Purchased Power Lease Contracts  
Lessee, Lease, Description [Line Items]  
2023 106,151
2024 104,315
2025 106,582
2026 120,016
2027 89,108
Thereafter 210,486
Total lease commitments 736,658
Less imputed interest 57,682
Total lease liabilities 678,976
Land, Property & Equipment Leases  
Lessee, Lease, Description [Line Items]  
2023 14,254
2024 11,330
2025 8,655
2026 7,207
2027 5,292
Thereafter 37,873
Total lease commitments 84,611
Less imputed interest 19,130
Total lease liabilities $ 65,481
v3.22.4
Leases - Other additional information related to operating lease liabilities (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2022
Dec. 31, 2021
Dec. 31, 2020
Leases [Abstract]      
Cash paid for amounts included in the measurement of lease liabilities - operating cash flows $ 118,463 $ 116,661 $ 75,097
Right-of-use operating lease assets obtained in exchange for operating lease liabilities $ 16,990 $ 500,582 $ 441,653
Weighted average remaining lease term 7 years 8 years  
Weighted average discount rate 2.21% 2.13%  
v3.22.4
Jointly-Owned Facilities (Details) - Arizona Public Service Company
$ in Thousands
Dec. 31, 2022
USD ($)
Palo Verde Units 1 and 3  
Interests in jointly-owned facilities  
Percent Owned 29.10%
Plant in Service $ 1,947,593
Accumulated Depreciation 1,099,132
Construction Work in Progress $ 39,933
Palo Verde Unit 2  
Interests in jointly-owned facilities  
Percent Owned 16.80%
Plant in Service $ 659,514
Accumulated Depreciation 383,775
Construction Work in Progress $ 14,784
Palo Verde Common  
Interests in jointly-owned facilities  
Percent Owned 28.00%
Plant in Service $ 799,794
Accumulated Depreciation 346,705
Construction Work in Progress 52,631
Palo Verde Sale Leaseback  
Interests in jointly-owned facilities  
Plant in Service 351,050
Accumulated Depreciation 260,754
Construction Work in Progress $ 0
Four Corners Generating Station  
Interests in jointly-owned facilities  
Percent Owned 63.00%
Plant in Service $ 1,665,042
Accumulated Depreciation 620,918
Construction Work in Progress $ 46,643
Cholla Common Facilities  
Interests in jointly-owned facilities  
Percent Owned 50.50%
Plant in Service $ 207,104
Accumulated Depreciation 140,886
Construction Work in Progress $ 2,988
ANPP 500kV System  
Interests in jointly-owned facilities  
Percent Owned 33.40%
Plant in Service $ 133,887
Accumulated Depreciation 55,704
Construction Work in Progress $ 2,820
Navajo Southern System  
Interests in jointly-owned facilities  
Percent Owned 26.80%
Plant in Service $ 90,345
Accumulated Depreciation 36,929
Construction Work in Progress $ 1,945
Palo Verde — Yuma 500kV System  
Interests in jointly-owned facilities  
Percent Owned 25.40%
Plant in Service $ 24,026
Accumulated Depreciation 7,559
Construction Work in Progress $ 128
Four Corners Switchyards  
Interests in jointly-owned facilities  
Percent Owned 61.90%
Plant in Service $ 73,243
Accumulated Depreciation 20,350
Construction Work in Progress $ 120
Phoenix — Mead System  
Interests in jointly-owned facilities  
Percent Owned 17.10%
Plant in Service $ 39,705
Accumulated Depreciation 20,055
Construction Work in Progress $ 51
Palo Verde — Rudd 500kV System  
Interests in jointly-owned facilities  
Percent Owned 50.00%
Plant in Service $ 95,736
Accumulated Depreciation 31,118
Construction Work in Progress $ 391
Morgan — Pinnacle Peak System  
Interests in jointly-owned facilities  
Percent Owned 64.70%
Plant in Service $ 119,785
Accumulated Depreciation 25,791
Construction Work in Progress $ 96
Round Valley System  
Interests in jointly-owned facilities  
Percent Owned 50.00%
Plant in Service $ 548
Accumulated Depreciation 193
Construction Work in Progress $ 0
Palo Verde — Morgan System  
Interests in jointly-owned facilities  
Percent Owned 87.80%
Plant in Service $ 263,576
Accumulated Depreciation 34,415
Construction Work in Progress $ 1,414
Hassayampa — North Gila System  
Interests in jointly-owned facilities  
Percent Owned 80.00%
Plant in Service $ 148,174
Accumulated Depreciation 22,566
Construction Work in Progress $ 3,771
Cholla 500kV Switchyard  
Interests in jointly-owned facilities  
Percent Owned 85.70%
Plant in Service $ 8,100
Accumulated Depreciation 2,380
Construction Work in Progress $ 0
Saguaro 500kV Switchyard  
Interests in jointly-owned facilities  
Percent Owned 60.00%
Plant in Service $ 21,656
Accumulated Depreciation 13,809
Construction Work in Progress $ 0
Kyrene — Knox System  
Interests in jointly-owned facilities  
Percent Owned 50.00%
Plant in Service $ 578
Accumulated Depreciation 336
Construction Work in Progress $ 0
Agua Fria Switchyard  
Interests in jointly-owned facilities  
Percent Owned 10.00%
Plant in Service $ 0
Accumulated Depreciation 0
Construction Work in Progress $ 32
v3.22.4
Commitments and Contingencies - Palo Verde Nuclear Generating Station, Contractual Obligations and Super-Fund Related Matters (Details)
$ in Thousands
 12 Months Ended
Apr. 05, 2018
Defendant
plaintiff
Dec. 16, 2016
plaintiff
Aug. 06, 2013
Defendant
Dec. 31, 2022
USD ($)
Dec. 31, 2021
USD ($)
Dec. 31, 2020
USD ($)
Fuel and Purchased Power Commitments and Purchase Obligations [Abstract]            
Total take-or-pay commitments       $ 179,255 $ 174,616  
Arizona Public Service Company            
Fuel and Purchased Power Commitments and Purchase Obligations [Abstract]            
2023       955,000    
2024       823,000    
2025       882,000    
2026       905,000    
2027       819,000    
Thereafter       8,700,000    
Total take-or-pay commitments       179,255 174,616  
Arizona Public Service Company | Coal Take-or-Pay Commitments            
Fuel and Purchased Power Commitments and Purchase Obligations [Abstract]            
2023       216,729    
2024       211,823    
2025       232,594    
2026       225,345    
2027       204,845    
Thereafter       880,113    
Total take-or-pay commitments       2,000,000    
Present value of commitments       1,600,000    
Total purchases       305,502 219,958 $ 189,817
Arizona Public Service Company | Renewable Energy Credits            
Fuel and Purchased Power Commitments and Purchase Obligations [Abstract]            
2023       31,000    
2024       29,000    
2025       27,000    
2026       23,000    
2027       19,000    
Thereafter       69,000    
Arizona Public Service Company | Coal Mine Reclamation Obligations            
Fuel and Purchased Power Commitments and Purchase Obligations [Abstract]            
2023       18,000    
2024       19,000    
2025       20,000    
2026       21,000    
2027       22,000    
Thereafter       25,000    
Arizona Public Service Company | Coal Mine Reclamation Balance Sheet Obligations            
Fuel and Purchased Power Commitments and Purchase Obligations [Abstract]            
Total take-or-pay commitments       179,000 $ 175,000  
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          
v3.22.4
Commitments and Contingencies - Additional Information (Details)
$ in Thousands
 9 Months Ended 12 Months Ended 108 Months Ended
Oct. 31, 2022
claim
Sep. 30, 2022
USD ($)
Nov. 02, 2021
USD ($)
Nov. 01, 2021
USD ($)
Feb. 22, 2021
USD ($)
Jul. 03, 2018
USD ($)
Jul. 06, 2016
Sep. 30, 2022
USD ($)
Dec. 31, 2022
USD ($)
Trust
Jun. 30, 2020
USD ($)
timePeriod
claim
Feb. 11, 2022
USD ($)
Financial Assurances                      
Production tax credit guarantees                 $ 34,000    
Arizona Public Service Company                      
Palo Verde Nuclear Generating Station [Abstract]                      
Maximum insurance against public liability per occurrence for a nuclear incident                 13,700,000    
Maximum available nuclear liability insurance                 450,000    
Remaining nuclear liability insurance through mandatory industry wide retrospective assessment program                 13,200,000    
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                 22,300    
Collateral assurance based on rating triggers                 $ 62,800    
Period to provide collateral assurance based on rating triggers                 20 days    
Arizona Public Service Company | Contaminated Groundwater Wells                      
Palo Verde Nuclear Generating Station [Abstract]                      
Costs claimed               $ 21,000      
Arizona Public Service Company | Pending Litigation | Contaminated Groundwater Wells                      
Arizona Attorney General [Abstract]                      
Settlement amount   $ 20,700                  
Bright Canyon Energy Corporation | Clear Creek Wind Farm                      
BCE Matters [Abstract]                      
Equity method investments   $ 17,100           $ 17,100 $ 0    
Impairment of equity method investments                 12,800    
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            
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       $ 14,300           $ 123,900  
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 9                 8  
Gain contingency, number of settlement agreement time periods | timePeriod                   8  
Settlement amount, awarded to company       $ 4,200           $ 36,000  
Letter of Credit | Arizona Public Service Company                      
Financial Assurances                      
Outstanding letters of credit                 10,000    
Bridge Loan | Bright Canyon Energy Corporation | Pinnacle West                      
Financial Assurances                      
Debt guarantee                     $ 42,000
Four Corners Units 4 and 5 | Arizona Public Service Company | SCE                      
Four Corners SCR Cost Recovery [Abstract]                      
Disallowance of plant investments     $ 194,000                
Cost deferrals     $ 215,500                
Amount not recoverable                 $ 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          
Financial Assurances                      
Option to purchase, ownership interest (as a percent)           7.00%          
Four Corners | 4CA                      
Environmental Matters                      
Percentage share cost of control             7.00%        
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 2025 | Arizona Public Service Company                      
Financial Assurances                      
Surety bonds expiring, amount                 $ 8,000    
v3.22.4
Asset Retirement Obligations (Details) - Arizona Public Service Company - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2022
Dec. 31, 2021
Change in asset retirement obligations    
Asset retirement obligations at the beginning of year $ 767,382 $ 705,083
Changes attributable to:    
Accretion expense 41,240 38,437
Settlements (10,860) (4,111)
Estimated cash flow revisions 0 27,973
Asset retirement obligations at the end of year $ 797,762 767,382
Cholla    
Asset Retirement Obligations    
Increase in asset retirement obligation   $ 28,000
v3.22.4
Fair Value Measurements - Fair Value of Assets and Liabilities (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2022
Dec. 31, 2021
ASSETS    
Commodity contracts, assets $ 132,229  
Commodity contracts, liabilities (21,163)  
Nuclear decommissioning trust 1,073,410 $ 1,294,757
Nuclear decommissioning trust, other 476,409 567,266
Other special use fund 347,231 358,410
Other special use funds, other 963 936
Total assets 1,552,870 1,763,556
Total assets, other 456,209 $ 563,512
LIABILITIES    
Derivative instruments, other 15,357  
Derivative instruments, total (42,446)  
Total liabilities (42,446)  
Total liabilities other $ 15,357  
DerivativeLiabilityStatementOfFinancialPositionExtensibleEnumerationNotDisclosedFlag Subtotal risk management activities - derivative instruments Subtotal risk management activities - derivative instruments
Commodity Contracts    
ASSETS    
Commodity contracts, assets $ 153,261 $ 115,079
LIABILITIES    
Derivative instruments (56,893) (7,478)
Derivative instruments, total (41,537) (4,373)
Commodity contracts    
ASSETS    
Commodity contracts, assets 132,098 110,389
Commodity contracts, liabilities (21,163) (4,690)
LIABILITIES    
Derivative instruments, other 15,357 3,105
Derivative instruments, total (41,537) (4,373)
Interest rate swaps    
ASSETS    
Commodity contracts, assets 131  
Commodity contracts, liabilities 0  
LIABILITIES    
Derivative instruments, other 0  
Derivative instruments, total (909)  
Equity securities    
ASSETS    
Nuclear decommissioning trust 18,485 17,482
Nuclear decommissioning trust, other 3,827 (27,782)
Other special use fund 67,937 48,506
Other special use funds, other 963 936
U.S. commingled equity funds    
ASSETS    
Nuclear decommissioning trust 472,582 595,048
U.S. Treasury debt    
ASSETS    
Nuclear decommissioning trust 211,923 240,745
Other special use fund 275,267 298,170
Corporate debt    
ASSETS    
Nuclear decommissioning trust 149,226 203,454
Mortgage-backed securities    
ASSETS    
Nuclear decommissioning trust 147,938 155,574
Municipal bonds    
ASSETS    
Nuclear decommissioning trust 64,881 72,189
Other special use fund 4,027 11,734
Other fixed income    
ASSETS    
Nuclear decommissioning trust 8,375 10,265
Level 1    
ASSETS    
Commodity contracts, assets 0  
Nuclear decommissioning trust 226,581 286,009
Other special use fund 342,241 345,740
Total assets 568,822 631,749
LIABILITIES    
Derivative instruments 0  
Total liabilities 0  
Level 1 | Commodity contracts    
ASSETS    
Commodity contracts, assets 0 0
LIABILITIES    
Derivative instruments 0 0
Level 1 | Interest rate swaps    
ASSETS    
Commodity contracts, assets 0  
LIABILITIES    
Derivative instruments 0  
Level 1 | Equity securities    
ASSETS    
Nuclear decommissioning trust 14,658 45,264
Other special use fund 66,974 47,570
Level 1 | U.S. commingled equity funds    
ASSETS    
Nuclear decommissioning trust 0 0
Level 1 | U.S. Treasury debt    
ASSETS    
Nuclear decommissioning trust 211,923 240,745
Other special use fund 275,267 298,170
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 127,260  
Nuclear decommissioning trust 370,420 441,482
Other special use fund 4,027 11,734
Total assets 501,707 568,295
LIABILITIES    
Derivative instruments (26,783)  
Total liabilities (26,783)  
Level 2 | Commodity contracts    
ASSETS    
Commodity contracts, assets 127,129 115,079
LIABILITIES    
Derivative instruments (25,874) (4,740)
Level 2 | Interest rate swaps    
ASSETS    
Commodity contracts, assets 131  
LIABILITIES    
Derivative instruments (909)  
Level 2 | Equity securities    
ASSETS    
Nuclear decommissioning trust 0 0
Other special use fund 0 0
Level 2 | U.S. commingled equity funds    
ASSETS    
Nuclear decommissioning trust 0 0
Level 2 | U.S. Treasury debt    
ASSETS    
Nuclear decommissioning trust 0 0
Other special use fund 0 0
Level 2 | Corporate debt    
ASSETS    
Nuclear decommissioning trust 149,226 203,454
Level 2 | Mortgage-backed securities    
ASSETS    
Nuclear decommissioning trust 147,938 155,574
Level 2 | Municipal bonds    
ASSETS    
Nuclear decommissioning trust 64,881 72,189
Other special use fund 4,027 11,734
Level 2 | Other fixed income    
ASSETS    
Nuclear decommissioning trust 8,375 10,265
Level 3    
ASSETS    
Commodity contracts, assets 26,132  
Nuclear decommissioning trust 0 0
Other special use fund 0 0
Total assets 26,132 0
LIABILITIES    
Derivative instruments (31,020)  
Total liabilities (31,020)  
Level 3 | Commodity contracts    
ASSETS    
Commodity contracts, assets 26,132 0
LIABILITIES    
Derivative instruments (31,020) (2,738)
Level 3 | Interest rate swaps    
ASSETS    
Commodity contracts, assets 0  
LIABILITIES    
Derivative instruments 0  
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
Level 3 | Forward Contracts | Commodity Contracts    
ASSETS    
Total assets 26,132 0
LIABILITIES    
Total liabilities (31,020) (2,738)
Level 3 | Forward Contracts | Natural Gas: | Commodity Contracts | Discounted Cash Flows    
ASSETS    
Total assets 0 0
LIABILITIES    
Total liabilities (29,261) (2,738)
NAV | U.S. commingled equity funds    
ASSETS    
Nuclear decommissioning trust $ 472,582 $ 595,048
v3.22.4
Fair Value Measurements - Additional Information (Details)
$ in Millions
 12 Months Ended
Dec. 31, 2022
USD ($)
Bright Canyon Energy Corporation | Clear Creek Wind Farm  
Fair value of assets and liabilities that are measured at fair value on a recurring basis  
Impairment of equity method investments $ 12.8
v3.22.4
Fair Value Measurements - Significant Unobservable Inputs (Details)
$ in Thousands
 12 Months Ended
Dec. 31, 2022
USD ($)
$ / MMBTU
$ / MWh
Dec. 31, 2021
USD ($)
$ / MMBTU
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments    
Assets $ 1,552,870 $ 1,763,556
Liabilities 42,446  
Level 3    
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments    
Assets 26,132 0
Liabilities 31,020  
Level 3 | Forward Contracts | Commodity Contracts    
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments    
Assets 26,132 0
Liabilities $ 31,020 $ 2,738
Level 3 | Forward Contracts | Discounted Cash Flows | Commodity Contracts | Weighted Average    
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments    
Electricity forward price (in usd per MWh) | $ / MWh 163.92  
Natural gas forward price (in usd per MMBTu) | $ / MMBTU (5.08) (0.71)
Level 3 | Forward Contracts | Discounted Cash Flows | Commodity Contracts | Minimum    
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments    
Electricity forward price (in usd per MWh) | $ / MWh 37.79  
Natural gas forward price (in usd per MMBTu) | $ / MMBTU (11.81) 0.76
Level 3 | Forward Contracts | Discounted Cash Flows | Commodity Contracts | Maximum    
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments    
Electricity forward price (in usd per MWh) | $ / MWh 310.69  
Natural gas forward price (in usd per MMBTu) | $ / MMBTU 0.00 0.65
Level 3 | Forward Contracts | Discounted Cash Flows | Electricity: | Commodity Contracts    
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments    
Assets $ 26,132  
Liabilities 1,759  
Level 3 | Forward Contracts | Discounted Cash Flows | Natural Gas: | Commodity Contracts    
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments    
Assets 0 $ 0
Liabilities $ 29,261 $ 2,738
v3.22.4
Fair Value Measurements - Fair value for our risk management activities (Details) - Commodity Contracts - Level 3 - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2022
Dec. 31, 2021
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]    
Net derivative beginning balance $ (2,738) $ (1,102)
Deferred as a regulatory asset or liability (374) 13,827
Settlements (1,123) (15,463)
Transfers into Level 3 from Level 2 (846) 0
Transfers from Level 3 into Level 2 193 0
Net derivative ending balance (4,888) (2,738)
Net unrealized gains included in earnings related to instruments still held at end of period $ 0 $ 0
v3.22.4
Earnings Per Share (Details) - USD ($)
$ / shares in Units, shares in Thousands, $ in Thousands
 12 Months Ended
Dec. 31, 2022
Dec. 31, 2021
Dec. 31, 2020
Earnings Per Share [Abstract]      
Net income attributable to common shareholders $ 483,602 $ 618,720 $ 550,559
Weighted average common shares outstanding — basic (in shares) 113,196 112,910 112,666
Net effect of dilutive securities:      
Contingently issuable performance shares and restricted stock units (in shares) 220 282 276
Weighted average common shares outstanding — diluted (in shares) 113,416 113,192 112,942
Earnings per weighted-average common share outstanding      
Net income attributable to common shareholders - basic (in dollars per share) $ 4.27 $ 5.48 $ 4.89
Net Income attributable to common shareholders - diluted (in dollars per share) $ 4.26 $ 5.47 $ 4.87
v3.22.4
Stock-Based Compensation - Additional Information (Details)
shares in Millions, $ in Millions
 12 Months Ended
Dec. 31, 2022
USD ($)
program
shares
Dec. 31, 2021
USD ($)
performance_criteria
Dec. 31, 2020
USD ($)
Stock-Based Compensation      
Compensation cost that has been charged against income $ 16 $ 18 $ 18
Total income tax benefit recognized 2 3 4
Total unrecognized compensation cost related to nonvested share-based compensation arrangements granted $ 20    
Expected weighted-average period of recognition of unrecognized compensation cost 2 years    
Total fair value of shares vested $ 25 $ 22 22
Performance Share Awards      
Performance period 3 years    
Number of unrelated performance element criteria | program 3    
Number of performance element criteria | performance_criteria   2  
Restricted Stock Units      
Stock-Based Compensation      
Share-based liabilities paid $ 3 $ 4 6
Cash flow effect, cash used to settle awards $ 3 $ 3 $ 4
Restricted Stock Units, Stock Grants and Stock Units      
Vesting period 4 years    
Percentage of cash that the participant may elect as a dividend for the first option available under the plan 50.00%    
Percentage of stock that the participant may elect as dividend under second option of plan 50.00%    
Performance Shares | Minimum      
Performance Share Awards      
Exact number of shares issued as a percentage of the target award 0.00% 0.00%  
Performance Shares | Maximum      
Performance Share Awards      
Exact number of shares issued as a percentage of the target award 200.00% 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 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 1.3    
Common shares available for issuance (in shares) | shares 0.9    
v3.22.4
Stock-Based Compensation - Summary of Restricted Stock, Stock Grants, Stock Units and Performance Shares (Details) - $ / shares
 12 Months Ended
Dec. 31, 2022
Dec. 31, 2021
Dec. 31, 2020
Restricted Stock Units, Stock Grants, and Stock Units      
Stocks granted and the weighted average fair value      
Units granted (in shares) 174,791 152,345 118,403
Weighted-average grant date fair value (in dollars per share) $ 69.66 $ 76.72 $ 71.70
Number of granted awards to be settled in cash (in shares) 0 51,074 45,646
Performance Shares      
Stocks granted and the weighted average fair value      
Units granted (in shares) 208,736 161,840 122,830
Weighted-average grant date fair value (in dollars per share) $ 77.63 $ 82.42 $ 104.74
v3.22.4
Stock-Based Compensation - Status of Nonvested Restricted Stock, Stock Grants, Stock Units and Performance Shares (Details) - $ / shares
 12 Months Ended
Dec. 31, 2022
Dec. 31, 2021
Dec. 31, 2020
Restricted Stock Units, Stock Grants, and Stock Units      
Nonvested shares      
Balance at the beginning of the period (in shares) 253,156    
Granted (in shares) 174,791 152,345 118,403
Vested (in shares) (101,216)    
Forfeited (in shares) (9,144)    
Balance at the end of the period (in shares) 317,587 253,156  
Weighted-Average Grant-Date Fair Value      
Balance at the beginning of the period (in dollars per share) $ 79.37    
Granted (in dollars per share) 69.66 $ 76.72 $ 71.70
Vested (in dollars per share) 84.52    
Forfeited (in dollars per share) 76.56    
Balance at the end of the period (in dollars per share) $ 73.91 $ 79.37  
Vested awards outstanding at end of year (in shares) 78,912    
Vested awards outstanding at end of year (in dollars per share)    
Number of nonvested awards to be settled in cash (in shares) 69,413    
Performance Shares      
Nonvested shares      
Balance at the beginning of the period (in shares) 280,682    
Granted (in shares) 208,736 161,840 122,830
Vested (in shares) (136,034)    
Forfeited (in shares) (22,690)    
Balance at the end of the period (in shares) 330,694 280,682  
Weighted-Average Grant-Date Fair Value      
Balance at the beginning of the period (in dollars per share) $ 92.16    
Granted (in dollars per share) 77.63 $ 82.42 $ 104.74
Vested (in dollars per share) 103.30    
Forfeited (in dollars per share) 78.29    
Balance at the end of the period (in dollars per share) $ 78.91 $ 92.16  
Vested awards outstanding at end of year (in shares) 136,034    
Vested awards outstanding at end of year (in dollars per share)    
v3.22.4
Derivative Accounting - Additional Information (Details)
$ in Thousands
 12 Months Ended
Dec. 31, 2022
USD ($)
Commodity Contracts  
Derivative [Line Items]  
Aggregate fair value of derivative instruments in a net liability position $ 56,893
Additional collateral to counterparties for energy related non-derivative instrument contracts 76,000
Interest Rate Contract  
Derivative [Line Items]  
Derivative, notional amount 32,000
Derivative, loss on derivative 900
Gain (Loss) price risk management activity 100
Loss on derivative instruments, pretax 800
Risk Management Assets | Credit Concentration Risk  
Derivative [Line Items]  
Aggregate fair value of derivative instruments in a net liability position $ 132,000
Risk Management Assets | Credit Concentration Risk | Three Counterparties  
Derivative [Line Items]  
Concentration risk, percentage 21.00%
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%
v3.22.4
Derivative Accounting - Outstanding Gross Notional Amounts Outstanding (Details) - Commodity Contracts
MWh in Thousands
 12 Months Ended
Dec. 31, 2022
MWh
Bcf
Dec. 31, 2021
MWh
Bcf
Outstanding gross notional amount of derivatives    
Power | MWh 1,197 0
Gas | Bcf 149 155
v3.22.4
Derivative Accounting - Gains and Losses from Derivative Instruments (Details) - Commodity Contracts - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2022
Dec. 31, 2021
Dec. 31, 2020
Designated as Hedging Instruments      
Derivative Instruments in Designated Cash Flows Hedges      
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income on Discontinuation $ 0 $ 0 $ 0
Fuel and purchased power | Not Designated as Hedging Instruments      
Derivative Instruments Not Designated as Cash Flows Hedges      
Net Gain (Loss) Recognized in Income 307,287 216,847 (3,178)
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 $ 0 $ (763)
v3.22.4
Derivative Accounting - Derivative Instruments in the Balance Sheet (Details) - USD ($)
$ in Thousands
Dec. 31, 2022
Dec. 31, 2021
Assets    
Gross Recognized Derivatives $ 132,229  
Liabilities    
Amounts  Reported on  Balance Sheets (42,446)  
Commodity Contracts    
Assets    
Gross Recognized Derivatives 153,261 $ 115,079
Amounts Offset (21,191) (4,740)
Net Recognized Derivatives 132,070 110,339
Other 28 50
Amounts  Reported on  Balance Sheets 132,098 110,389
Liabilities    
Gross Recognized Derivatives (56,893) (7,478)
Amounts Offset 21,191 4,740
Net Recognized Derivatives (35,702) (2,738)
Other (5,835) (1,635)
Amounts  Reported on  Balance Sheets (41,537) (4,373)
Assets and Liabilities    
Gross Recognized Derivatives 96,368 107,601
Amounts Offset 0 0
Net Recognized Derivatives 96,368 107,601
Other (5,807) (1,585)
Amounts  Reported on  Balance Sheets 90,561 106,016
Commodity Contracts | Current assets    
Assets    
Gross Recognized Derivatives 103,484 66,777
Amounts Offset (15,808) (3,346)
Net Recognized Derivatives 87,676 63,431
Other 28 50
Amounts  Reported on  Balance Sheets 87,704 63,481
Commodity Contracts | Investments and other assets    
Assets    
Gross Recognized Derivatives 49,777 48,302
Amounts Offset (5,383) (1,394)
Net Recognized Derivatives 44,394 46,908
Other 0 0
Amounts  Reported on  Balance Sheets 44,394 46,908
Commodity Contracts | Current liabilities    
Liabilities    
Gross Recognized Derivatives (47,670) (6,084)
Amounts Offset 15,808 3,346
Net Recognized Derivatives (31,862) (2,738)
Other (5,835) (1,635)
Amounts  Reported on  Balance Sheets (37,697) (4,373)
Commodity Contracts | Deferred credits and other    
Liabilities    
Gross Recognized Derivatives (9,223) (1,394)
Amounts Offset 5,383 1,394
Net Recognized Derivatives (3,840) 0
Other 0 0
Amounts  Reported on  Balance Sheets $ (3,840) $ 0
v3.22.4
Derivative Accounting - Credit Risk and Related Contingent Features (Details) - Commodity Contracts
$ in Thousands
Dec. 31, 2022
USD ($)
Credit Risk and Credit-Related Contingent Features  
Aggregate fair value of derivative instruments in a net liability position $ 56,893
Cash collateral posted 0
Additional cash collateral in the event credit-risk related contingent features were fully triggered $ 32,884
v3.22.4
Other Income and Other Expense (Details) - USD ($)
 12 Months Ended
Dec. 31, 2022
Dec. 31, 2021
Dec. 31, 2020
Apr. 30, 2022
Nov. 06, 2020
Other income:          
Interest income $ 7,326,000 $ 6,726,000 $ 12,210,000    
Investment gains (losses) — net 0 0 2,358,000    
Miscellaneous 590,000 53,000 149,000    
Total other income 7,916,000 45,100,000 56,703,000    
Other expense:          
Non-operating costs (18,619,000) (13,008,000) (12,400,000)    
Investment gains (losses) - net (20,537,000) (1,367,000)      
Miscellaneous (13,229,000) (11,021,000) (45,376,000)    
Total other expense (52,385,000) (25,396,000) (57,776,000)    
Arizona Public Service Company          
Other income:          
Interest income 5,332,000 4,692,000 9,621,000    
Miscellaneous 556,000 40,000 148,000    
Total other income 5,888,000 43,053,000 51,755,000    
Other expense:          
Non-operating costs (15,579,000) (10,080,000) (10,659,000)    
Miscellaneous (10,529,000) (8,817,000) (43,035,000)    
Total other expense (26,108,000) (18,897,000) (53,694,000)    
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 7,000,000   10,000,000 $ 500,000 $ 10,000,000
SCR deferral          
Other income:          
Debt return   14,955,000 15,865,000    
SCR deferral | Arizona Public Service Company          
Other income:          
Debt return 0 14,955,000 15,865,000    
Octotillo modernization project          
Other income:          
Debt return   23,366,000 26,121,000    
Octotillo modernization project | Arizona Public Service Company          
Other income:          
Debt return $ 0 $ 23,366,000 $ 26,121,000    
v3.22.4
Palo Verde Sale Leaseback Variable Interest Entities - Additional Information (Details)
$ in Thousands
 12 Months Ended
Dec. 31, 2022
USD ($)
lease
Trust
Dec. 31, 2021
USD ($)
Dec. 31, 2020
USD ($)
Dec. 31, 1986
Trust
Palo Verde Sale Leaseback Variable Interest Entities        
Net income attributable to noncontrolling interest $ 17,224 $ 17,224 $ 19,493  
Arizona Public Service Company        
Palo Verde Sale Leaseback Variable Interest Entities        
Number of VIE lessor trusts | Trust 3      
Net income attributable to noncontrolling interest $ 17,224 17,224 19,493  
Arizona Public Service Company | Variable Interest Entity        
Palo Verde Sale Leaseback Variable Interest Entities        
Number of VIE lessor trusts | Trust       3
Net income attributable to noncontrolling interest 17,000 $ 17,000 $ 19,000  
Initial loss exposure to the VIEs noncontrolling equity participants during lease extension period 324,000      
Maximum loss exposure to the VIE's noncontrolling equity participants during lease extension period $ 501,000      
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      
v3.22.4
Palo Verde Sale Leaseback Variable Interest Entities - Schedule of VIEs (Details) - USD ($)
$ in Thousands
Dec. 31, 2022
Dec. 31, 2021
Palo Verde Sale Leaseback Variable Interest Entities    
Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation $ 16,854,354 $ 15,987,434
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets    
Equity-Noncontrolling interests 111,229 115,260
Arizona Public Service Company    
Palo Verde Sale Leaseback Variable Interest Entities    
Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation 16,800,254 15,985,346
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets    
Equity-Noncontrolling interests 111,229 115,260
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 90,296 94,166
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets    
Equity-Noncontrolling interests $ 111,229 $ 115,260
v3.22.4
Investments in Nuclear Decommissioning Trusts and Other Special Use Funds - Additional Information (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2022
Dec. 31, 2021
Arizona Public Service Company    
Schedule of Equity Method Investments [Line Items]    
Employee medical claims amount $ 15 $ 15
v3.22.4
Investments in Nuclear Decommissioning Trusts and Other Special Use Funds (Details) - Arizona Public Service Company - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2022
Dec. 31, 2021
Dec. 31, 2020
Nuclear decommissioning trust fund assets      
Fair Value $ 1,420,641 $ 1,653,167  
Total Unrealized Gains 337,994 475,670  
Total Unrealized Losses (69,091) (4,063)  
Amortized cost 927,000 972,000  
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds      
Realized gains 9,437 134,659 $ 12,370
Realized losses (40,239) (8,438) (5,568)
Proceeds from the sale of securities 1,207,197 1,720,966 819,519
Nuclear Decommissioning Trusts      
Nuclear decommissioning trust fund assets      
Fair Value 1,073,410 1,294,757  
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds      
Realized gains 9,017 134,610 12,194
Realized losses (40,239) (8,431) (5,553)
Proceeds from the sale of securities 979,639 1,457,305 675,035
Other Special Use Funds      
Nuclear decommissioning trust fund assets      
Fair Value 347,231 358,410  
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds      
Realized gains 420 49 176
Realized losses 0 (7) (15)
Proceeds from the sale of securities 227,558 263,661 $ 144,484
Equity securities      
Nuclear decommissioning trust fund assets      
Equity securities 554,214 687,882  
Total Unrealized Gains 334,817 451,387  
Total Unrealized Losses (267) 0  
Equity securities | Nuclear Decommissioning Trusts      
Nuclear decommissioning trust fund assets      
Equity securities 487,240 640,312  
Equity securities | Other Special Use Funds      
Nuclear decommissioning trust fund assets      
Equity securities 66,974 47,570  
Available for sale-fixed income securities      
Nuclear decommissioning trust fund assets      
Fair Value 861,637 992,131  
Total Unrealized Gains 3,177 24,283  
Total Unrealized Losses (68,795) (4,063)  
Fair value of fixed income securities, summarized by contractual maturities      
Less than one year 97,496    
1 year – 5 years 362,002    
5 years – 10 years 129,171    
Greater than 10 years 272,968    
Total 861,637    
Available for sale-fixed income securities | Nuclear Decommissioning Trusts      
Nuclear decommissioning trust fund assets      
Fair Value 582,343 682,227  
Fair value of fixed income securities, summarized by contractual maturities      
Less than one year 9,422    
1 year – 5 years 181,640    
5 years – 10 years 122,340    
Greater than 10 years 268,941    
Total 582,343    
Available for sale-fixed income securities | Other Special Use Funds      
Nuclear decommissioning trust fund assets      
Fair Value 279,294 309,904  
Available for sale-fixed income securities | Coal Reclamation Escrow Account      
Fair value of fixed income securities, summarized by contractual maturities      
Less than one year 49,917    
1 year – 5 years 36,484    
5 years – 10 years 0    
Greater than 10 years 4,027    
Total 90,428    
Available for sale-fixed income securities | Active Union Employee Medical Account      
Fair value of fixed income securities, summarized by contractual maturities      
Less than one year 38,157    
1 year – 5 years 143,878    
5 years – 10 years 6,831    
Greater than 10 years 0    
Total 188,866    
Other      
Nuclear decommissioning trust fund assets      
Fair Value 4,790 (26,846)  
Total Unrealized Gains 0 0  
Total Unrealized Losses (29) 0  
Other | Nuclear Decommissioning Trusts      
Nuclear decommissioning trust fund assets      
Fair Value 3,827 (27,782)  
Other | Other Special Use Funds      
Nuclear decommissioning trust fund assets      
Fair Value $ 963 $ 936  
v3.22.4
Changes in Accumulated Other Comprehensive Loss (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2022
Dec. 31, 2021
Changes in accumulated other comprehensive income (loss) by component    
Beginning balance $ 6,021,460 $ 5,752,793
Ending balance 6,159,876 6,021,460
Pension and Other Postretirement Benefits    
Changes in accumulated other comprehensive income (loss) by component    
Beginning balance (53,885) (60,725)
OCI (loss) before reclassifications 17,550 2,439
Amounts reclassified from accumulated other comprehensive loss 4,003 4,401
Ending balance (32,332) (53,885)
Derivative Instruments    
Changes in accumulated other comprehensive income (loss) by component    
Beginning balance (976) (2,071)
OCI (loss) before reclassifications 1,873 1,077
Amounts reclassified from accumulated other comprehensive loss 0 18
Ending balance 897 (976)
Accumulated Other Comprehensive Income (Loss)    
Changes in accumulated other comprehensive income (loss) by component    
Beginning balance (54,861) (62,796)
OCI (loss) before reclassifications 19,423 3,516
Amounts reclassified from accumulated other comprehensive loss 4,003 4,419
Ending balance (31,435) (54,861)
Arizona Public Service Company    
Changes in accumulated other comprehensive income (loss) by component    
Beginning balance 6,750,473 6,345,185
Ending balance 7,052,955 6,750,473
Arizona Public Service Company | Pension and Other Postretirement Benefits    
Changes in accumulated other comprehensive income (loss) by component    
Beginning balance (34,880) (40,918)
OCI (loss) before reclassifications 15,646 2,043
Amounts reclassified from accumulated other comprehensive loss 3,638 3,995
Ending balance (15,596) (34,880)
Arizona Public Service Company | Derivative Instruments    
Changes in accumulated other comprehensive income (loss) by component    
Beginning balance 0 0
OCI (loss) before reclassifications 0 (18)
Amounts reclassified from accumulated other comprehensive loss 0 18
Ending balance 0 0
Arizona Public Service Company | Accumulated Other Comprehensive Income (Loss)    
Changes in accumulated other comprehensive income (loss) by component    
Beginning balance (34,880) (40,918)
OCI (loss) before reclassifications 15,646 2,025
Amounts reclassified from accumulated other comprehensive loss 3,638 4,013
Ending balance $ (15,596) $ (34,880)
v3.22.4
Schedule I - Condensed Financial Information of Registrant - Comprehensive Income (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2022
Dec. 31, 2021
Dec. 31, 2020
CONDENSED FINANCIAL STATEMENTS      
Operating expenses $ 3,592,474 $ 2,998,525 $ 2,798,830
Other      
Total 99,281 173,982 89,044
Interest expense 283,569 254,314 247,501
Income tax benefit 74,827 110,086 78,173
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS 483,602 618,720 550,559
Other comprehensive income (loss) — attributable to common shareholders 23,426 7,935 (5,700)
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS 507,028 626,655 544,859
Pinnacle West      
CONDENSED FINANCIAL STATEMENTS      
Operating expenses 8,850 10,245 7,901
Other      
Equity in earnings of subsidiaries 500,042 628,916 566,147
Other expense (4,725) (4,919) (4,586)
Total 495,317 623,997 561,561
Interest expense 18,861 10,672 14,021
Income before income taxes 467,606 603,080 539,639
Income tax benefit (15,996) (15,640) (10,920)
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS 483,602 618,720 550,559
Other comprehensive income (loss) — attributable to common shareholders 23,426 7,935 (5,700)
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS $ 507,028 $ 626,655 $ 544,859
v3.22.4
Schedule I - Condensed Financial Information of Registrant - Balance Sheets (Details) - USD ($)
$ in Thousands
Dec. 31, 2022
Dec. 31, 2021
Dec. 31, 2020
Dec. 31, 2019
Current assets        
Cash and cash equivalents $ 4,832 $ 9,969    
Accounts receivable 453,209 391,923    
Income tax receivable 14,086 7,514    
Other current assets 60,091 83,896    
Total current assets 1,750,554 1,551,100    
Investments and other assets        
Other assets 125,672 97,884    
Total investments and other assets 1,590,707 1,797,959    
TOTAL ASSETS 22,723,405 22,003,222    
Current liabilities        
Accounts payable 430,425 393,083    
Accrued taxes 164,440 168,645    
Common dividends payable 97,895 95,988    
Short-term borrowings 340,720 292,000    
Current maturities of long-term debt 50,685 150,000    
Operating lease liabilities 105,210 100,443    
Other current liabilities 148,276 151,968    
Total current liabilities 1,762,141 1,756,869    
Deferred credits and other        
Long-term debt less current maturities (Note 6) 7,741,286 6,913,735    
Operating lease liabilities 639,247 728,401    
Other 252,149 232,914    
Total deferred credits and other 7,060,102 7,311,158    
COMMITMENTS AND CONTINGENCIES (SEE NOTES)    
Common stock equity        
Common stock 2,724,740 2,702,743    
Accumulated other comprehensive loss (Note 19) (31,435) (54,861)    
Retained earnings 3,360,347 3,264,719    
Total shareholders’ equity 6,048,647 5,906,200    
Noncontrolling interests 111,229 115,260    
Total equity 6,159,876 6,021,460 $ 5,752,793 $ 5,553,188
TOTAL LIABILITIES AND EQUITY 22,723,405 22,003,222    
Pinnacle West        
Current assets        
Cash and cash equivalents 0 594    
Accounts receivable 132,061 125,457    
Income tax receivable 14,494 1,498    
Other current assets 288 13    
Total current assets 146,843 127,562    
Investments and other assets        
Investments in subsidiaries 7,105,789 6,797,528    
Deferred income taxes 1,521 19,520    
Other assets 23,153 57,608    
Total investments and other assets 7,130,463 6,874,656    
TOTAL ASSETS 7,277,306 7,002,218    
Current liabilities        
Accounts payable 6,499 3,071    
Accrued taxes 7,694 19,855    
Common dividends payable 97,895 95,988    
Short-term borrowings 15,720 13,300    
Current maturities of long-term debt 0 150,000    
Operating lease liabilities 117 107    
Other current liabilities 14,637 14,684    
Total current liabilities 142,562 297,005    
Deferred credits and other        
Long-term debt less current maturities (Note 6) 947,892 647,139    
Pension liabilities 8,218 14,537    
Operating lease liabilities 1,459 1,576    
Other 17,299 20,501    
Total deferred credits and other 26,976 36,614    
COMMITMENTS AND CONTINGENCIES (SEE NOTES)    
Common stock equity        
Common stock 2,719,735 2,696,342    
Accumulated other comprehensive loss (Note 19) (31,435) (54,861)    
Retained earnings 3,360,347 3,264,719    
Total shareholders’ equity 6,048,647 5,906,200    
Noncontrolling interests 111,229 115,260    
Total equity 6,159,876 6,021,460    
TOTAL LIABILITIES AND EQUITY $ 7,277,306 $ 7,002,218    
v3.22.4
Schedule I - Condensed Financial Information of Registrant - Cash Flows (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2022
Dec. 31, 2021
Dec. 31, 2020
Cash flows from operating activities      
Net income $ 500,826 $ 635,944 $ 570,052
Adjustments to reconcile net income to net cash provided by operating activities:      
Depreciation and amortization 817,814 719,141 686,253
Deferred income taxes 43,202 117,471 69,469
Accounts receivable (63,869) (72,559) (18,191)
Accounts payable 90,076 20,267 (6,059)
Net cash provided by operating activities 1,241,441 860,014 966,365
Cash flows from investing activities      
Net cash used for investing activities (1,618,046) (1,386,929) (1,277,818)
Cash flows from financing activities      
Issuance of long-term debt 875,537 746,999 1,596,672
Short-term debt borrowings under revolving credit facility 0 0 751,690
Short-term debt repayments under revolving credit facility 0 (19,000) (770,690)
Short-term borrowings and (repayments) — net 48,720 142,000 73,325
Dividends paid on common stock (378,881) (369,478) (350,577)
Repayment of long-term debt (150,000) 0 (915,150)
Common stock equity issuance and purchases — net (2,653) (2,350) (1,389)
Net cash provided by financing activities 371,468 476,916 361,138
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (5,137) (49,999) 49,685
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 9,969 59,968 10,283
CASH AND CASH EQUIVALENTS AT END OF YEAR 4,832 9,969 59,968
Pinnacle West      
Cash flows from operating activities      
Net income 483,602 618,720 550,559
Adjustments to reconcile net income to net cash provided by operating activities:      
Equity in earnings of subsidiaries — net (500,042) (628,916) (566,147)
Depreciation and amortization 76 93 76
Deferred income taxes 17,256 (11,381) 33,007
Accounts receivable (8,535) 8,897 (7,903)
Accounts payable 3,431 (2,598) (1,964)
Accrued taxes and income tax receivables — net (25,157) 16,079 9,610
Dividends received from subsidiaries 385,800 376,500 357,500
Other 47,719 4,214 20,163
Net cash provided by operating activities 404,150 381,608 394,901
Cash flows from investing activities      
Investments in subsidiaries (186,630) (145,266) (137,881)
Repayments of loans from subsidiaries 14,308 4,017 932
Advances of loans to subsidiaries (3,308) (12,256) (7,261)
Net cash used for investing activities (175,630) (153,505) (144,210)
Cash flows from financing activities      
Issuance of long-term debt 300,000 300,000 496,950
Short-term debt borrowings under revolving credit facility 0 0 211,690
Short-term debt repayments under revolving credit facility 0 (19,000) (230,690)
Short-term borrowings and (repayments) — net 2,420 (136,700) 73,325
Dividends paid on common stock (378,881) (369,478) (350,577)
Repayment of long-term debt (150,000) 0 (450,000)
Common stock equity issuance and purchases — net (2,653) (2,350) (1,389)
Net cash provided by financing activities (229,114) (227,528) (250,691)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (594) 575 0
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 594 19 19
CASH AND CASH EQUIVALENTS AT END OF YEAR $ 0 $ 594 $ 19