PINNACLE WEST CAPITAL CORP, 10-Q filed on 5/4/2023
Quarterly Report
v3.23.1
Cover Page - shares
 3 Months Ended
Mar. 31, 2023
Apr. 27, 2023
Entity Information [Line Items]    
Document Type 10-Q  
Document Quarterly Report true  
Document Period End Date Mar. 31, 2023  
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  
Trading Symbol PNW  
Security Exchange Name NYSE  
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  
Entity Common Stock, Shares Outstanding   113,255,998
Entity Central Index Key 0000764622  
Amendment Flag false  
Current Fiscal Year End Date --12-31  
Document Fiscal Year Focus 2023  
Document Fiscal Period Focus Q1  
Entity Shell Company false  
APS    
Entity Information [Line Items]    
Document Type 10-Q  
Document Period End Date Mar. 31, 2023  
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  
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 Common Stock, Shares Outstanding   71,264,947
Entity Central Index Key 0000007286  
Amendment Flag false  
Current Fiscal Year End Date --12-31  
Document Fiscal Year Focus 2023  
Document Fiscal Period Focus Q1  
Entity Shell Company false  
v3.23.1
CONDENSED CONSOLIDATED STATEMENTS OF INCOME - USD ($)
shares in Thousands, $ in Thousands
 3 Months Ended
Mar. 31, 2023
Mar. 31, 2022
Income Statement [Abstract]    
OPERATING REVENUES $ 944,955 $ 783,531
OPERATING EXPENSES    
Fuel and purchased power 394,504 265,269
Operations and maintenance 250,080 218,342
Depreciation and amortization 191,906 186,605
Taxes other than income taxes 57,138 57,998
Other expenses 610 825
Total 894,238 729,039
OPERATING INCOME 50,717 54,492
OTHER INCOME (DEDUCTIONS)    
Allowance for equity funds used during construction 15,061 9,747
Pension and other postretirement non-service credits - net (Note 5) 9,865 23,809
Other income (Note 9) 6,077 1,704
Other expense (Note 9) (4,131) (3,422)
Total 26,872 31,838
INTEREST EXPENSE    
Interest charges 88,119 65,389
Allowance for borrowed funds used during construction (12,722) (4,482)
Total 75,397 60,907
INCOME BEFORE INCOME TAXES 2,192 25,423
INCOME TAXES 1,183 4,161
NET INCOME 1,009 21,262
Less: Comprehensive income attributable to noncontrolling interests 4,306 4,306
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS $ (3,297) $ 16,956
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — BASIC (in shares) 113,358 113,102
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — DILUTED (in shares) 113,358 113,295
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING    
Net income (loss) attributable to common shareholders - basic (in dollars per share) $ (0.03) $ 0.15
Net income (loss) attributable to common shareholders — diluted (in dollars per share) $ (0.03) $ 0.15
v3.23.1
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($)
$ in Thousands
 3 Months Ended
Mar. 31, 2023
Mar. 31, 2022
Statement of Comprehensive Income [Abstract]    
Net income $ 1,009 $ 21,262
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX    
Derivative instruments net unrealized gain (loss), net of tax benefit (expense) of $202 and $(83) (616) 252
Pension and other postretirement benefit activity, net of tax expense of $169 and $296 515 901
Total other comprehensive income (loss) (101) 1,153
COMPREHENSIVE INCOME 908 22,415
Less: Comprehensive income attributable to noncontrolling interests 4,306 4,306
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS $ (3,398) $ 18,109
v3.23.1
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($)
$ in Thousands
 3 Months Ended
Mar. 31, 2023
Mar. 31, 2022
Statement of Comprehensive Income [Abstract]    
Derivative instruments net unrealized gain, tax benefit (expense) $ 202 $ (83)
Pension and other postretirement benefits activity, tax benefit (expense) $ 169 $ 296
v3.23.1
CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($)
$ in Thousands
Mar. 31, 2023
Dec. 31, 2022
CURRENT ASSETS    
Cash and cash equivalents $ 6,951 $ 4,832
Customer and other receivables 449,096 453,209
Accrued unbilled revenues 143,276 164,764
Allowance for doubtful accounts (Note 2) (22,112) (23,778)
Materials and supplies (at average cost) 425,457 410,481
Income tax receivable 11,699 14,086
Fossil fuel (at average cost) 39,571 40,155
Assets from risk management activities (Note 7) 16,095 87,835
Deferred fuel and purchased power regulatory asset (Note 4) 469,962 460,561
Other regulatory assets (Note 4) 130,840 78,318
Other current assets 77,551 60,091
Total current assets 1,748,386 1,750,554
INVESTMENTS AND OTHER ASSETS    
Nuclear decommissioning trusts (Notes 11 and 12) 1,125,617 1,073,410
Other special use funds (Notes 11 and 12) 352,877 347,231
Assets from risk management activities (Note 7) 17,082 44,394
Other assets 147,430 125,672
Total investments and other assets 1,643,006 1,590,707
PROPERTY, PLANT AND EQUIPMENT    
Plant in service and held for future use 22,624,104 22,452,146
Accumulated depreciation and amortization (8,072,595) (7,929,878)
Net 14,551,509 14,522,268
Construction work in progress 2,101,830 1,882,791
Palo Verde sale leaseback, net of accumulated depreciation (Note 6) 89,329 90,296
Intangible assets, net of accumulated amortization 260,454 258,880
Nuclear fuel, net of accumulated amortization 112,735 100,119
Total property, plant and equipment 17,115,857 16,854,354
DEFERRED DEBITS    
Regulatory assets (Note 4) 1,258,663 1,283,221
Operating lease right-of-use assets 1,361,847 801,688
Assets for pension and other postretirement benefits (Note 5) 405,409 396,599
Other 47,205 46,282
Total deferred debits 3,073,124 2,527,790
TOTAL ASSETS 23,580,373 22,723,405
CURRENT LIABILITIES    
Accounts payable 361,410 430,425
Accrued taxes 214,484 164,440
Accrued interest 72,146 61,217
Common dividends payable 0 97,895
Short-term borrowings (Note 3) 497,550 340,720
Current maturities of long-term debt (Note 3) 60,821 50,685
Customer deposits 41,186 41,769
Liabilities from risk management activities (Note 7) 83,874 37,697
Liabilities for asset retirements 20,321 12,232
Operating lease liabilities 65,130 105,210
Less: current regulatory liabilities 202,266 271,575
Other current liabilities 105,141 148,276
Total current liabilities 1,724,329 1,762,141
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 3) 7,916,554 7,741,286
DEFERRED CREDITS AND OTHER    
Deferred income taxes 2,379,720 2,384,421
Total non-current regulatory liabilities 2,060,273 2,061,776
Liabilities for asset retirements 787,220 785,530
Liabilities for pension benefits (Note 5) 114,290 116,286
Customer advances 532,596 422,103
Coal mine reclamation 180,446 179,255
Deferred investment tax credit 184,427 180,677
Unrecognized tax benefits 38,863 38,658
Operating lease liabilities 1,240,584 639,247
Other 256,620 252,149
Total deferred credits and other 7,775,039 7,060,102
COMMITMENTS AND CONTINGENCIES (Note 8)
EQUITY    
Common stock, no par value; authorized 150,000,000 shares, 113,359,467 and 113,247,189 issued at respective dates 2,730,851 2,724,740
Treasury stock at cost; 106,141 and 73,613 shares at respective dates (7,451) (5,005)
Total common stock 2,723,400 2,719,735
Retained earnings 3,357,052 3,360,347
Accumulated other comprehensive loss (Note 13) (31,536) (31,435)
Total shareholders’ equity 6,048,916 6,048,647
Noncontrolling interests (Note 6) 115,535 111,229
Total equity 6,164,451 6,159,876
TOTAL LIABILITIES AND EQUITY $ 23,580,373 $ 22,723,405
v3.23.1
CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - shares
Mar. 31, 2023
Dec. 31, 2022
EQUITY    
Common stock, authorized shares (in shares) 150,000,000 150,000,000
Common stock, issued shares (in shares) 113,359,467 113,247,189
Treasury stock at cost, shares (in shares) 106,141 73,613
v3.23.1
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)
$ in Thousands
 3 Months Ended
Mar. 31, 2023
Mar. 31, 2022
CASH FLOWS FROM OPERATING ACTIVITIES    
Net income $ 1,009 $ 21,262
Adjustments to reconcile net income to net cash provided by operating activities:    
Depreciation and amortization including nuclear fuel 208,772 203,639
Deferred fuel and purchased power (90,305) (6,110)
Deferred fuel and purchased power amortization 80,904 39,442
Allowance for equity funds used during construction (15,061) (9,747)
Deferred income taxes (5,150) 3,835
Deferred investment tax credit 3,749 (319)
Change in derivative instruments fair value 786 0
Stock compensation 3,635 5,338
Changes in current assets and liabilities:    
Customer and other receivables 2,831 66,146
Accrued unbilled revenues 21,488 1,215
Materials, supplies and fossil fuel (14,392) (11,892)
Income tax receivable 2,387 542
Other current assets (8,110) 13,347
Accounts payable (69,576) (13,873)
Accrued taxes 50,044 53,847
Other current liabilities (84,239) (40,211)
Change in margin and collateral accounts - assets 11 8,600
Change in other long-term assets (58,036) 52,153
Change in operating lease assets (8,920) 324
Change in other long-term liabilities 138,649 (47,883)
Change in operating lease liabilities 51,129 953
Net cash provided by operating activities 211,605 340,608
CASH FLOWS FROM INVESTING ACTIVITIES    
Capital expenditures (445,171) (391,583)
Contributions in aid of construction 25,165 28,262
Allowance for borrowed funds used during construction (12,722) (4,422)
Proceeds from nuclear decommissioning trusts sales and other special use funds 226,626 361,754
Investment in nuclear decommissioning trusts and other special use funds (227,196) (361,809)
Other (19,941) (6,543)
Net cash used for investing activities (453,239) (374,341)
CASH FLOWS FROM FINANCING ACTIVITIES    
Issuance of long-term debt 185,136 312,052
Short-term borrowing and (repayments) - net 156,830 (29,050)
Dividends paid on common stock (96,078) (94,265)
Repayment of long-term debt 0 (150,000)
Common stock equity issuances and (purchases) - net (2,135) (1,005)
Net cash provided by financing activities 243,753 37,732
NET INCREASE IN CASH AND CASH EQUIVALENTS 2,119 3,999
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 4,832 9,969
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 6,951 $ 13,968
v3.23.1
CONDENSED 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, 2021   113,014,528        
Beginning balance at Dec. 31, 2021 $ 6,021,460 $ 2,702,743 $ (6,401) $ 3,264,719 $ (54,861) $ 115,260
Beginning balance (in shares) at Dec. 31, 2021     (87,608)      
Increase (Decrease) in Shareholders' Equity            
Net income 21,262     16,956   4,306
Other comprehensive income (loss) 1,153       1,153  
Dividends on common stock (74)     (74)    
Issuance of common stock (in shares)   33,171        
Issuance of common stock 3,582 $ 3,582        
Purchase of treasury stock (in shares)     (24,885)      
Purchase of treasury stock (1,665)   $ (1,665)      
Reissuance of treasury stock for stock-based compensation and other (in shares)     61,572      
Reissuance of treasury stock for stock-based compensation and other 4,418   $ 4,418      
Ending balance (in shares) at Mar. 31, 2022   113,047,699        
Ending balance at Mar. 31, 2022 $ 6,050,136 $ 2,706,325 $ (3,648) 3,281,601 (53,708) 119,566
Ending balance (in shares) at Mar. 31, 2022     (50,921)      
Beginning balance (in shares) at Dec. 31, 2022 113,247,189 113,247,189        
Beginning balance at Dec. 31, 2022 $ 6,159,876 $ 2,724,740 $ (5,005) 3,360,347 (31,435) 111,229
Beginning balance (in shares) at Dec. 31, 2022 (73,613)   (73,613)      
Increase (Decrease) in Shareholders' Equity            
Net income $ 1,009     (3,297)   4,306
Other comprehensive income (loss) (101)       (101)  
Issuance of common stock (in shares)   112,278        
Issuance of common stock 6,111 $ 6,111        
Purchase of treasury stock (in shares) [1]     (33,154)      
Purchase of treasury stock [1] (2,490)   $ (2,490)      
Reissuance of treasury stock for stock-based compensation and other (in shares)     626      
Reissuance of treasury stock for stock-based compensation and other 44   $ 44      
Other $ 2     2    
Ending balance (in shares) at Mar. 31, 2023 113,359,467 113,359,467        
Ending balance at Mar. 31, 2023 $ 6,164,451 $ 2,730,851 $ (7,451) $ 3,357,052 $ (31,536) $ 115,535
Ending balance (in shares) at Mar. 31, 2023 (106,141)   (106,141)      
[1] Primarily represents shares of common stock withheld from certain stock awards for tax purposes.
v3.23.1
ARIZONA PUBLIC SERVICE COMPANY - CONDENSED CONSOLIDATED STATEMENTS OF INCOME - USD ($)
$ in Thousands
 3 Months Ended
Mar. 31, 2023
Mar. 31, 2022
OPERATING REVENUES $ 944,955 $ 783,531
OPERATING EXPENSES    
Fuel and purchased power 394,504 265,269
Operations and maintenance 250,080 218,342
Depreciation and amortization 191,906 186,605
Taxes other than income taxes 57,138 57,998
Other expenses 610 825
Total 894,238 729,039
OPERATING INCOME 50,717 54,492
OTHER INCOME (DEDUCTIONS)    
Allowance for equity funds used during construction 15,061 9,747
Pension and other postretirement non-service credits - net (Note 5) 9,865 23,809
Other income (Note 9) 6,077 1,704
Other expense (Note 9) (4,131) (3,422)
Total 26,872 31,838
INTEREST EXPENSE    
Interest charges 88,119 65,389
Allowance for borrowed funds used during construction (12,722) (4,482)
Total 75,397 60,907
INCOME BEFORE INCOME TAXES 2,192 25,423
INCOME TAXES 1,183 4,161
NET INCOME 1,009 21,262
Less: Comprehensive income attributable to noncontrolling interests 4,306 4,306
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS (3,297) 16,956
APS    
OPERATING REVENUES 944,955 783,531
OPERATING EXPENSES    
Fuel and purchased power 394,504 265,269
Operations and maintenance 246,179 214,601
Depreciation and amortization 191,884 186,583
Taxes other than income taxes 57,125 57,959
Other expenses 610 825
Total 890,302 725,237
OPERATING INCOME 54,653 58,294
OTHER INCOME (DEDUCTIONS)    
Allowance for equity funds used during construction 15,061 9,747
Pension and other postretirement non-service credits - net (Note 5) 10,106 23,907
Other income (Note 9) 5,075 1,152
Other expense (Note 9) (2,617) (1,849)
Total 27,625 32,957
INTEREST EXPENSE    
Interest charges 75,222 62,309
Allowance for borrowed funds used during construction (11,157) (4,422)
Total 64,065 57,887
INCOME BEFORE INCOME TAXES 18,213 33,364
INCOME TAXES 3,247 4,859
NET INCOME 14,966 28,505
Less: Comprehensive income attributable to noncontrolling interests 4,306 4,306
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS $ 10,660 $ 24,199
v3.23.1
ARIZONA PUBLIC SERVICE COMPANY - CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($)
$ in Thousands
 3 Months Ended
Mar. 31, 2023
Mar. 31, 2022
NET INCOME $ 1,009 $ 21,262
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX    
Pension and other postretirement benefits activity, net of tax expense of $150 and $269 515 901
Total other comprehensive income (loss) (101) 1,153
COMPREHENSIVE INCOME 908 22,415
Less: Comprehensive income attributable to noncontrolling interests 4,306 4,306
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS (3,398) 18,109
APS    
NET INCOME 14,966 28,505
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX    
Pension and other postretirement benefits activity, net of tax expense of $150 and $269 457 820
Total other comprehensive income (loss) 457 820
COMPREHENSIVE INCOME 15,423 29,325
Less: Comprehensive income attributable to noncontrolling interests 4,306 4,306
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS $ 11,117 $ 25,019
v3.23.1
ARIZONA PUBLIC SERVICE COMPANY - CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($)
$ in Thousands
 3 Months Ended
Mar. 31, 2023
Mar. 31, 2022
Pension and other postretirement benefits activity, tax benefit (expense) $ 169 $ 296
APS    
Pension and other postretirement benefits activity, tax benefit (expense) $ 150 $ 269
v3.23.1
ARIZONA PUBLIC SERVICE COMPANY - CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($)
$ in Thousands
Mar. 31, 2023
Dec. 31, 2022
PROPERTY, PLANT AND EQUIPMENT    
Plant in service and held for future use $ 22,624,104 $ 22,452,146
Accumulated depreciation and amortization (8,072,595) (7,929,878)
Net 14,551,509 14,522,268
Construction work in progress 2,101,830 1,882,791
Palo Verde sale leaseback, net of accumulated depreciation (Note 6) 89,329 90,296
Intangible assets, net of accumulated amortization 260,454 258,880
Nuclear fuel, net of accumulated amortization 112,735 100,119
Total property, plant and equipment 17,115,857 16,854,354
INVESTMENTS AND OTHER ASSETS    
Nuclear decommissioning trusts (Notes 11 and 12) 1,125,617 1,073,410
Other special use funds (Notes 11 and 12) 352,877 347,231
Assets from risk management activities (Note 7) 17,082 44,394
Other assets 147,430 125,672
Total investments and other assets 1,643,006 1,590,707
CURRENT ASSETS    
Cash and cash equivalents 6,951 4,832
Customer and other receivables 449,096 453,209
Accrued unbilled revenues 143,276 164,764
Allowance for doubtful accounts (Note 2) (22,112) (23,778)
Materials and supplies (at average cost) 425,457 410,481
Fossil fuel (at average cost) 39,571 40,155
Income tax receivable 11,699 14,086
Assets from risk management activities (Note 7) 16,095 87,835
Deferred fuel and purchased power regulatory asset (Note 4) 469,962 460,561
Other regulatory assets (Note 4) 130,840 78,318
Other current assets 77,551 60,091
Total current assets 1,748,386 1,750,554
DEFERRED DEBITS    
Regulatory assets (Note 4) 1,258,663 1,283,221
Operating lease right-of-use assets 1,361,847 801,688
Assets for pension and other postretirement benefits (Note 5) 405,409 396,599
Other 47,205 46,282
Total deferred debits 3,073,124 2,527,790
TOTAL ASSETS 23,580,373 22,723,405
EQUITY    
Retained earnings 3,357,052 3,360,347
Accumulated other comprehensive loss (Note 13) (31,536) (31,435)
Total shareholders’ equity 6,048,916 6,048,647
Noncontrolling interests (Note 6) 115,535 111,229
Total equity 6,164,451 6,159,876
Long-term debt less current maturities (Note 3) 7,916,554 7,741,286
CURRENT LIABILITIES    
Short-term borrowings (Note 3) 497,550 340,720
Accounts payable 361,410 430,425
Accrued taxes 214,484 164,440
Accrued interest 72,146 61,217
Common dividends payable 0 97,895
Customer deposits 41,186 41,769
Liabilities from risk management activities (Note 7) 83,874 37,697
Liabilities for asset retirements 20,321 12,232
Operating lease liabilities 65,130 105,210
Less: current regulatory liabilities 202,266 271,575
Other current liabilities 105,141 148,276
Total current liabilities 1,724,329 1,762,141
DEFERRED CREDITS AND OTHER    
Deferred income taxes 2,379,720 2,384,421
Total non-current regulatory liabilities 2,060,273 2,061,776
Liabilities for asset retirements 787,220 785,530
Liabilities for pension benefits (Note 5) 114,290 116,286
Customer advances 532,596 422,103
Coal mine reclamation 180,446 179,255
Deferred investment tax credit 184,427 180,677
Unrecognized tax benefits 38,863 38,658
Operating lease liabilities 1,240,584 639,247
Other 256,620 252,149
Total deferred credits and other 7,775,039 7,060,102
COMMITMENTS AND CONTINGENCIES (Note 8)
TOTAL LIABILITIES AND EQUITY 23,580,373 22,723,405
APS    
PROPERTY, PLANT AND EQUIPMENT    
Plant in service and held for future use 22,620,643 22,448,685
Accumulated depreciation and amortization (8,069,288) (7,926,575)
Net 14,551,355 14,522,110
Construction work in progress 2,036,078 1,829,004
Palo Verde sale leaseback, net of accumulated depreciation (Note 6) 89,329 90,296
Intangible assets, net of accumulated amortization 260,299 258,725
Nuclear fuel, net of accumulated amortization 112,735 100,119
Total property, plant and equipment 17,049,796 16,800,254
INVESTMENTS AND OTHER ASSETS    
Nuclear decommissioning trusts (Notes 11 and 12) 1,125,617 1,073,410
Other special use funds (Notes 11 and 12) 352,877 347,231
Assets from risk management activities (Note 7) 17,082 44,394
Other assets 44,165 43,344
Total investments and other assets 1,539,741 1,508,379
CURRENT ASSETS    
Cash and cash equivalents 6,648 4,042
Customer and other receivables 438,251 448,880
Accrued unbilled revenues 143,276 164,764
Allowance for doubtful accounts (Note 2) (22,112) (23,778)
Materials and supplies (at average cost) 425,457 410,481
Fossil fuel (at average cost) 39,571 40,155
Income tax receivable 1,102 1,102
Assets from risk management activities (Note 7) 15,961 87,704
Deferred fuel and purchased power regulatory asset (Note 4) 469,962 460,561
Other regulatory assets (Note 4) 130,840 78,318
Other current assets 70,443 50,043
Total current assets 1,719,399 1,722,272
DEFERRED DEBITS    
Regulatory assets (Note 4) 1,258,663 1,283,221
Operating lease right-of-use assets 1,356,781 796,544
Assets for pension and other postretirement benefits (Note 5) 397,877 389,142
Other 46,401 44,040
Total deferred debits 3,059,722 2,512,947
TOTAL ASSETS 23,368,658 22,543,852
EQUITY    
Common stock 178,162 178,162
Additional paid-in capital 3,321,696 3,171,696
Retained earnings 3,618,125 3,607,464
Accumulated other comprehensive loss (Note 13) (15,139) (15,596)
Total shareholders’ equity 7,102,844 6,941,726
Noncontrolling interests (Note 6) 115,535 111,229
Total equity 7,218,379 7,052,955
Long-term debt less current maturities (Note 3) 6,794,124 6,793,529
Total capitalization 14,012,503 13,846,484
CURRENT LIABILITIES    
Short-term borrowings (Note 3) 463,000 325,000
Accounts payable 349,410 417,732
Accrued taxes 211,940 156,746
Accrued interest 69,816 60,518
Common dividends payable 0 97,900
Customer deposits 41,186 41,769
Liabilities from risk management activities (Note 7) 83,874 37,697
Liabilities for asset retirements 20,321 12,232
Operating lease liabilities 64,593 104,728
Less: current regulatory liabilities 202,266 271,575
Other current liabilities 104,865 144,733
Total current liabilities 1,611,271 1,670,630
DEFERRED CREDITS AND OTHER    
Deferred income taxes 2,384,586 2,385,647
Total non-current regulatory liabilities 2,060,273 2,061,776
Liabilities for asset retirements 787,220 785,530
Liabilities for pension benefits (Note 5) 106,535 108,068
Customer advances 532,596 422,103
Coal mine reclamation 180,446 179,255
Deferred investment tax credit 184,427 180,677
Unrecognized tax benefits 38,863 38,658
Operating lease liabilities 1,235,619 634,199
Other 234,319 230,825
Total deferred credits and other 7,744,884 7,026,738
COMMITMENTS AND CONTINGENCIES (Note 8)
TOTAL LIABILITIES AND EQUITY $ 23,368,658 $ 22,543,852
v3.23.1
ARIZONA PUBLIC SERVICE COMPANY - CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)
$ in Thousands
 3 Months Ended
Mar. 31, 2023
Mar. 31, 2022
CASH FLOWS FROM OPERATING ACTIVITIES    
Net income $ 1,009 $ 21,262
Adjustments to reconcile net income to net cash provided by operating activities:    
Depreciation and amortization including nuclear fuel 208,772 203,639
Deferred fuel and purchased power (90,305) (6,110)
Deferred fuel and purchased power amortization 80,904 39,442
Allowance for equity funds used during construction (15,061) (9,747)
Deferred income taxes (5,150) 3,835
Deferred investment tax credit 3,749 (319)
Changes in current assets and liabilities:    
Customer and other receivables 2,831 66,146
Accrued unbilled revenues 21,488 1,215
Materials, supplies and fossil fuel (14,392) (11,892)
Income tax receivable 2,387 542
Other current assets (8,110) 13,347
Accounts payable (69,576) (13,873)
Accrued taxes 50,044 53,847
Other current liabilities (84,239) (40,211)
Change in margin and collateral accounts - assets 11 8,600
Change in other long-term assets (58,036) 52,153
Change in operating lease assets (8,920) 324
Change in other long-term liabilities 138,649 (47,883)
Change in operating lease liabilities 51,129 953
Net cash provided by operating activities 211,605 340,608
CASH FLOWS FROM INVESTING ACTIVITIES    
Capital expenditures (445,171) (391,583)
Contributions in aid of construction 25,165 28,262
Allowance for borrowed funds used during construction (12,722) (4,422)
Proceeds from nuclear decommissioning trusts sales and other special use funds 226,626 361,754
Investment in nuclear decommissioning trusts and other special use funds (227,196) (361,809)
Other (19,941) (6,543)
Net cash used for investing activities (453,239) (374,341)
CASH FLOWS FROM FINANCING ACTIVITIES    
Short-term borrowing and (repayments) - net 156,830 (29,050)
Dividends paid on common stock (96,078) (94,265)
Net cash provided by financing activities 243,753 37,732
NET INCREASE IN CASH AND CASH EQUIVALENTS 2,119 3,999
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 4,832 9,969
CASH AND CASH EQUIVALENTS AT END OF PERIOD 6,951 13,968
APS    
CASH FLOWS FROM OPERATING ACTIVITIES    
Net income 14,966 28,505
Adjustments to reconcile net income to net cash provided by operating activities:    
Depreciation and amortization including nuclear fuel 208,750 203,617
Deferred fuel and purchased power (90,305) (6,110)
Deferred fuel and purchased power amortization 80,904 39,442
Allowance for equity funds used during construction (15,061) (9,747)
Deferred income taxes (1,693) (106)
Deferred investment tax credit 3,749 (319)
Changes in current assets and liabilities:    
Customer and other receivables 9,347 65,736
Accrued unbilled revenues 21,488 1,215
Materials, supplies and fossil fuel (14,392) (11,892)
Income tax receivable 0 5,207
Other current assets (11,050) 5,261
Accounts payable (64,008) (17,074)
Accrued taxes 55,194 57,718
Other current liabilities (82,658) (37,579)
Change in margin and collateral accounts - assets 11 8,600
Change in other long-term assets (55,909) 53,827
Change in operating lease assets (8,998) 254
Change in other long-term liabilities 138,094 (46,790)
Change in operating lease liabilities 51,212 1,027
Net cash provided by operating activities 239,641 340,792
CASH FLOWS FROM INVESTING ACTIVITIES    
Capital expenditures (439,647) (386,873)
Contributions in aid of construction 25,165 28,262
Allowance for borrowed funds used during construction (11,157) (4,422)
Proceeds from nuclear decommissioning trusts sales and other special use funds 226,626 361,754
Investment in nuclear decommissioning trusts and other special use funds (227,196) (361,809)
Other (926) (258)
Net cash used for investing activities (427,135) (363,346)
CASH FLOWS FROM FINANCING ACTIVITIES    
Short-term borrowing and (repayments) - net 138,000 (28,700)
Equity infusion 150,000 150,000
Dividends paid on common stock (97,900) (96,000)
Net cash provided by financing activities 190,100 25,300
NET INCREASE IN CASH AND CASH EQUIVALENTS 2,606 2,746
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 4,042 9,374
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 6,648 $ 12,120
v3.23.1
ARIZONA PUBLIC SERVICE COMPANY - CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY - USD ($)
$ in Thousands
Total
Common Stock
Retained Earnings
Accumulated Other Comprehensive Income (Loss)
Noncontrolling Interests
APS
APS
Common Stock
APS
Additional Paid-In Capital
APS
Retained Earnings
APS
Accumulated Other Comprehensive Income (Loss)
APS
Noncontrolling Interests
Beginning balance (in shares) at Dec. 31, 2021   113,014,528         71,264,947        
Beginning 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 21,262   16,956   4,306 28,505     24,199   4,306
Other comprehensive income (loss) 1,153     1,153   820       820  
Other           (2)     (2)    
Ending balance (in shares) at Mar. 31, 2022   113,047,699         71,264,947        
Ending balance at Mar. 31, 2022 $ 6,050,136 $ 2,706,325 3,281,601 (53,708) 119,566 6,929,796 $ 178,162 3,171,696 3,494,432 (34,060) 119,566
Beginning balance (in shares) at Dec. 31, 2022 113,247,189 113,247,189         71,264,947        
Beginning 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
Increase (Decrease) in Shareholders' Equity                      
Equity infusion from Pinnacle West 150,000             150,000      
Net income 1,009   (3,297)   4,306 14,966     10,660   4,306
Other comprehensive income (loss) (101)     (101)   457       457  
Other $ 2   2     1     1    
Ending balance (in shares) at Mar. 31, 2023 113,359,467 113,359,467         71,264,947        
Ending balance at Mar. 31, 2023 $ 6,164,451 $ 2,730,851 $ 3,357,052 $ (31,536) $ 115,535 $ 7,218,379 $ 178,162 $ 3,321,696 $ 3,618,125 $ (15,139) $ 115,535
v3.23.1
Consolidation and Nature of Operations
 3 Months Ended
Mar. 31, 2023
Organization, Consolidation and Presentation of Financial Statements [Abstract]  
Consolidation and Nature of Operations Consolidation and Nature of Operations
 
The unaudited condensed consolidated financial statements include the accounts of Pinnacle West and our subsidiaries:  APS, 4C Acquisition, LLC (“4CA”), Bright Canyon Energy Corporation (“BCE”), and El Dorado Investment Company (“El Dorado”).  See Note 8 for more information on 4CA matters. Intercompany accounts and transactions between the consolidated companies have been eliminated.  The unaudited condensed consolidated financial statements for APS include the accounts of APS and the Palo Verde Generating Station (“Palo Verde”) sale leaseback variable interest entities (“VIEs”). See Note 6 for further discussion.  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.

Amounts reported in our interim Condensed Consolidated Statements of Income are not necessarily indicative of amounts expected for the respective annual periods, due to the effects of seasonal temperature variations on energy consumption, timing of maintenance on electric generating units (“EGU”), and other factors.
 
Our condensed 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. Certain information and footnote disclosures normally included in financial statements prepared in conformity with GAAP have been condensed or omitted pursuant to such regulations, although we believe that the disclosures provided are adequate to make the interim information presented not misleading. The accompanying condensed consolidated financial statements and these notes should be read in conjunction with the audited consolidated financial statements and notes included in our 2022 Form 10-K.

On June 30, 2020, the United States Federal Energy Regulatory Commission (“FERC”) issued an order granting a waiver request related to the existing Allowance for Funds Used During Construction (“AFUDC”) rate calculation beginning March 1, 2020, through February 28, 2021.  On February 23, 2021, this waiver was extended until September 30, 2021. On September 21, 2021, it was further extended until March 31, 2022. The order provided a simplified approach that companies may elect to implement in order to minimize the significant distorted effect on the AFUDC formula resulting from increased short-term debt financing during the COVID-19 pandemic.  APS 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 2021 and for the three-month period ended March 31, 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.
Supplemental Cash Flow Information

The following table summarizes supplemental Pinnacle West cash flow information (dollars in thousands):
 Three Months Ended
March 31,
 20232022
Cash paid (received) during the period for:
Income taxes, net of refunds$(12)$— 
Interest, net of amounts capitalized62,241 55,208 
Significant non-cash investing and financing activities:
Accrued capital expenditures$115,559 $131,778 

The following table summarizes supplemental APS cash flow information (dollars in thousands):
Three Months Ended
March 31,
 20232022
Cash paid (received) during the period for:
Income taxes, net of refunds$— $(25)
Interest, net of amounts capitalized53,610 53,982 
Significant non-cash investing and financing activities:
Accrued capital expenditures$112,219 $124,778 
v3.23.1
Revenue
 3 Months Ended
Mar. 31, 2023
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):
Three Months Ended March 31,
20232022
Retail Electric Service
Residential$409,724 $367,346 
Non-Residential406,137 359,516 
Wholesale Energy Sales95,603 28,903 
Transmission Services for Others31,791 25,492 
Other Sources1,700 2,274 
Total operating revenues$944,955 $783,531 

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.

In the electricity business, some contracts to purchase energy are settled by netting against other contracts to sell electricity. This is referred to as a book-out, and usually occurs in contracts that have the same terms (product type, quantities, and delivery points) and for which power does not flow. We net these book-outs, which reduces both wholesale revenues and fuel and purchased power costs.

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 three months ended March 31, 2023 and 2022 were $922 million and $772 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 three months ended March 31, 2023 and 2022, our revenues that do not
qualify as revenue from contracts with customers were $23 million and $12 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 4 for a discussion of our regulatory cost recovery mechanisms.

Contract Assets and Liabilities from Contracts with Customers

There were no material contract assets, contract liabilities, or deferred contract costs recorded on the Condensed Consolidated Balance Sheets as of March 31, 2023, or December 31, 2022.

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):

March 31, 2023December 31, 2022
Allowance for doubtful accounts, balance at beginning of period$23,778 $25,354 
Bad debt expense3,522 17,006 
Actual write-offs(5,188)(18,582)
Allowance for doubtful accounts, balance at end of period$22,112 $23,778 
v3.23.1
Long-Term Debt and Liquidity Matters
 3 Months Ended
Mar. 31, 2023
Debt Disclosure [Abstract]  
Long-Term Debt and Liquidity Matters Long-Term Debt and Liquidity Matters
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.
 
Pinnacle West

On April 10, 2023, Pinnacle West replaced its $200 million revolving credit facility that would have matured on May 28, 2026, with a new $200 million revolving credit facility that matures on April 10, 2028. 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 March 31, 2023, Pinnacle West had no outstanding borrowings under its revolving credit facility, no letters of credit outstanding under the credit facility, and $35 million of outstanding commercial paper borrowings.

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 April 10, 2023, APS replaced its two $500 million revolving credit facilities that would have matured on May 28, 2026, with a new $1.25 billion revolving credit facility that matures on April 10, 2028. APS has the option to increase the amount of the facility up to a maximum of $400 million, for a total of $1.65 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. This facility is available to support APS’s general corporate purposes, including support for APS’s commercial paper program, which was increased from $750 million to $1 billion on April 10, 2023, for bank borrowings or for issuances of letters of credit. At March 31, 2023, APS had no outstanding borrowings under its revolving credit facilities, no letters of credit outstanding under the credit facilities, and $463 million of outstanding commercial paper borrowings.

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 “Financial Assurances” in Note 8 for a discussion of other 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 megawatt (“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 March 31, 2023, $28 million has been drawn from the equity bridge loan and there is a $33 million outstanding balance for the construction facility and $2.5 million letters of credit outstanding under the letter of 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 7.

On April 18, 2023, Pinnacle West issued performance guarantees in connection with BCE’s Kūpono investment project financing. BCE holds an equity method investment relating to the Kūpono project. See Note 8.
 
Debt Fair Value
 
Our long-term debt fair value estimates are classified within Level 2 of the fair value hierarchy. The following table presents the estimated fair value of our long-term debt, including current maturities (dollars in thousands):

 As of March 31, 2023As of December 31, 2022
 Carrying
Amount		Fair ValueCarrying
Amount		Fair Value
Pinnacle West$1,123,101 $1,084,455 $947,892 $905,525 
APS6,794,124 5,898,167 6,793,529 5,629,491 
BCE60,150 60,821 50,550 50,685 
Total$7,977,375 $7,043,443 $7,791,971 $6,585,701 
v3.23.1
Regulatory Matters
 3 Months Ended
Mar. 31, 2023
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

On October 31, 2019, APS filed an application with the ACC for an annual increase in retail base rates (the “2019 Rate Case”). On August 2, 2021, an 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 Power Plant (“Four Corners”) selective catalytic reduction (“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 the Navajo Generating Station (the “Navajo Plant”) regulatory asset recovery related to the closure of the Navajo Plant (see “Navajo Plant” below), (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 Coal Community Transition (“CCT”) plan related to the closure or future closure of coal-fired generation facilities 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, resulted in a total annual revenue decrease for APS of $4.8 million, excluding temporary payments and expenditures, under the CCT plan. 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. On March 6, 2023, the Court issued its opinion in this matter, affirming in part and reversing in part the ACC’s decision in the 2019 Rate Case. The Court vacated the 20-basis-point penalty included in the ACC’s allowed return on equity, as the Court determined the use of customer service metrics to justify the reduction exceeded the ACC’s ratemaking authority. Additionally, the Court vacated the disallowance of $215.5 million of APS’s Four Corners SCR investment because the ACC did not consider APS’s contractual obligations and improperly considered post-investment data in violation of its own rules. The Court remanded the issue to the ACC for further proceedings. The ACC requested an extension of the 30-day deadline to appeal the matter to the Arizona Supreme Court, and the Arizona Supreme Court granted the extension of the deadline to May 8, 2023. 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. 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 2023, APS has completed the following payments that will be recoverable through rates related to the CCT: (i) $6.66 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) $1 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, and on April 17, 2023, the ACC closed the docket. Any further action on CCT issues will take place in utility rate cases, including the currently pending 2022 Rate Case. APS cannot predict the outcome of 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 July 1, 2020, APS filed its 2021 RES Implementation Plan and proposed a budget of approximately $84.7 million.  APS’s budget request supported existing approved projects and commitments and requested 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. The APS Solar Communities program was originally a 3-year program authorizing APS to spend $10 million to $15 million in capital costs each year to install utility-owned distributed renewable energy (“DG”) systems for low to moderate income residential homes, non-profit entities, Title I schools and rural government facilities. 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 continuation of 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 140 MW 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 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 Plan 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 Power Supply Adjustor (“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 2023 and 2022 (dollars in thousands):
 Three Months Ended
March 31,
 20232022
Beginning balance$460,561 $388,148 
Deferred fuel and purchased power costs — current period90,305 6,110 
Amounts charged to customers(80,904)(39,442)
Ending balance$469,962 $354,816 

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 was 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 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 was 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. On February 23, 2023, the ACC approved an overall PSA rate of $0.019074 per kWh, which consisted of a forward component of $(0.005527) per kWh, a historical component of $0.013071 per kWh and a transition component of $0.011530 per kWh, that will continue until further notice of the ACC. The rate became 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 is also required to notify the ACC when the PSA balancing account approaches $0.5 million.

In accordance with the approved PSA Plan of Administration, 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 third-party 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 of the energy storage portion of a third-party solar plus energy storage project through the PSA, 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 the energy storage portion of another third-party solar plus energy storage project, and on February 22, 2023, the ACC approved this application. On March 6, 2023, APS filed an application requesting similar recovery through the PSA for the energy storage portion of another third-party solar plus energy storage project, and on May 2, 2023, the ACC approved this application. The ACC has not yet ruled on the prudency of APS’s acquisition of these projects.

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.  The EIS includes 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. On March 10, 2023, APS filed an amended application requesting an EIS charge of $4.0 million, a decrease of $10.7 million from the
February EIS request and a decrease of $7.5 million from the prior-period charge. The revised 2023 EIS became effective with the first billing cycle in April 2023.
 
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, 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 kWh 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 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 photovoltaic 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.

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 triennial 15-year IRPs which describe how the utility plans to serve customer load in the plan timeframe. The ACC reviews each utility’s IRP to determine if it meets the necessary requirements and whether it should be acknowledged. In February 2022, the ACC acknowledged APS’s 2020 IRP filed on June 26, 2020. 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 on August 1, 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. 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.

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 end 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. 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. As the ACC’s questions pertained to the retail competition law subsequently repealed in April 2022, the Attorney General has not responded to the ACC’s request and the questions are now moot. No action has been taken by the ACC regarding this application since that time.

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.

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 arguments on November 30, 2022. On March 6, 2023, the Court of Appeals issued its order in the matter, vacating the ACC’s disallowance of the SCR investment and remanding the matter back to the ACC for further review in accordance with ACC rules and the order of the Court of Appeals. The parties have until May 8, 2023 to file a petition requesting review by the Arizona Supreme Court. APS cannot predict the outcome of this proceeding. Based on the partial recovery of these investments and cost deferrals in current rates, the favorable Court of Appeals order, and the potential for further appellate review, APS has not recorded an impairment or write-off relating to the SCR plant investments or deferrals as of March 31, 2023. 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. 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 is required to cease burning coal at its remaining Cholla units by April 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, $36.1 million as of March 31, 2023, 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, $50.2 million as of March 31, 2023, 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, $13.1 million as of March 31, 2023. 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): 
 Amortization ThroughMarch 31, 2023December 31, 2022
Pension(a)$628,727 $637,656 
Deferred fuel and purchased power (b) (c)2024469,962 460,561 
Income taxes — allowance for funds used during construction (“AFUDC”) equity2053179,818 179,631 
Ocotillo deferral (e)2031135,766 138,143 
SCR deferral (e)(f)203195,588 97,624 
Retired power plant costs203394,903 98,692 
Deferred fuel and purchased power — mark-to-market (Note 7)
202561,858 — 
Deferred property taxes202738,915 41,057 
Deferred compensation203634,492 33,660 
Income taxes — investment tax credit basis adjustment205624,095 23,977 
Palo Verde VIEs (Note 6)
204620,893 20,933 
Active Union Medical Trust(g)15,010 18,226 
Four Corners cost deferral202413,979 15,999 
Navajo coal reclamation202613,117 13,862 
Loss on reacquired debt20389,238 9,468 
Mead-Phoenix transmission line contributions in aid of construction (“CIAC”)20508,965 9,048 
Tax expense adjustor mechanism (b)20315,681 5,845 
Lost fixed cost recovery (b)2023— 9,547 
OtherVarious8,458 8,171 
Total regulatory assets (d) $1,859,465 $1,822,100 
Less: current regulatory assets$600,802 $538,879 
Total non-current regulatory assets$1,258,663 $1,283,221 

(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 5 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):
 
 Amortization ThroughMarch 31, 2023December 31, 2022
Excess deferred income taxes — ACC - Tax Act (a)2046$970,578 $971,545 
Excess deferred income taxes — FERC - Tax Act (a)2058221,708 221,877 
Asset retirement obligations2057396,107 354,002 
Other postretirement benefits(d)258,955 270,604 
Removal costs(c)106,102 106,889 
Income taxes — change in rates205164,739 64,806 
Four Corners coal reclamation203853,348 52,592 
Income taxes — deferred investment tax credit205649,031 48,035 
Spent nuclear fuel202737,313 39,217 
Renewable energy standard (b)202430,188 35,720 
Sundance maintenance203117,667 16,893 
Property tax deferral (e)202414,353 15,521 
Demand side management (b)202314,207 8,461 
FERC transmission true up (b)202512,597 22,895 
Tax expense adjustor mechanism (b) (e)N/A4,835 4,835 
Deferred fuel and purchased power — mark-to-market (Note 7)
20253,396 96,367 
OtherVarious7,415 3,092 
Total regulatory liabilities $2,262,539 $2,333,351 
Less: current regulatory liabilities$202,266 $271,575 
Total non-current regulatory liabilities$2,060,273 $2,061,776 

(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 guidance, APS accrues removal costs for its regulated assets, even if there is no legal obligation for removal.
(d)See Note 5.
(e)Balance includes amounts for future regulatory consideration and amortization period determination.
v3.23.1
Retirement Plans and Other Postretirement Benefits
 3 Months Ended
Mar. 31, 2023
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, a non-qualified supplemental excess benefit retirement plan, and other postretirement benefit plans for the employees of Pinnacle West and our subsidiaries.  The other postretirement benefit plans include a group life and medical plan and a post-65 retiree health reimbursement arrangement (“HRA”). 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.
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 BenefitsOther Benefits
 Three Months Ended
March 31,		Three Months Ended
March 31,
 2023202220232022
Service cost — benefits earned during the period$10,157 $14,331 $2,120 $4,218 
Non-service costs (credits):
Interest cost on benefit obligation38,362 27,023 5,673 4,463 
Expected return on plan assets(45,561)(46,394)(10,872)(11,510)
  Amortization of:   
  Prior service credit— — (9,447)(9,447)
  Net actuarial loss (gain)9,713 4,768 (2,303)(2,982)
Net periodic cost/(benefit)$12,671 $(272)$(14,829)$(15,258)
Portion of benefit charged to expense$7,227 $(3,290)$(10,737)$(10,895)
 
Contributions
 
We have not made any voluntary contributions to our pension plan year-to-date in 2023. The minimum required contributions for the pension plan are zero for the next three years and we do not expect to make any contributions in 2023, 2024 or 2025. With regard to contributions to our other postretirement benefit plan, we have not made a contribution year-to-date in 2023 and do not expect to make any contributions in 2023, 2024 or 2025.
v3.23.1
Palo Verde Sale Leaseback Variable Interest Entities
 3 Months Ended
Mar. 31, 2023
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.

For regulatory reporting purposes, APS accounts for the three leases as operating leases for income
statement and cash flow statement purposes, and for balance sheet purposes all three leases are classified as finance leases. See Note 14 for a discussion of leases.

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 Nuclear Regulatory Commission (“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 terms.
v3.23.1
Derivative Accounting
 3 Months Ended
Mar. 31, 2023
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 Condensed 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 sheets as an asset or liability and are measured at fair value.  See Note 11 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 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 4.  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 MeasureMarch 31, 2023December 31, 2022
PowerGWh1,664 1,197 
GasBillion cubic feet194 149 
 
Gains and Losses from Energy Derivative Instruments
 
For the three months ended March 31, 2023 and 2022, APS had no energy derivative instruments in designated accounting hedging relationships.
 
The following table provides information about gains and losses from energy derivative instruments not designated as accounting hedging instruments (dollars in thousands):

 Financial Statement LocationThree Months Ended
March 31,
Commodity Contracts20232022
Net Gain (Loss) Recognized in IncomeFuel and purchased power (a)$(188,930)$223,742 
 
(a)Amounts are before the effect of PSA deferrals.
 
Energy Derivative Instruments in the Condensed 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 Condensed Consolidated Balance Sheets.  Transactions that do not allow for offsetting of positive and negative positions are reported gross on the Condensed 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 our risk management activities reported on a gross basis, and the impacts of offsetting.  These amounts relate to commodity contracts and are located in the assets and liabilities from risk management activities lines of APS’s Condensed Consolidated Balance Sheets.
As of March 31, 2023:
(dollars in thousands)
Gross
 Recognized
 Derivatives
 (a)
Amounts
Offset
 (b)
Net
 Recognized
 Derivatives
Other
 (c)
Amount Reported on Balance Sheets
Current assets$22,994 $(7,050)$15,944 $17 $15,961 
Investments and other assets26,746 (9,664)17,082 — 17,082 
Total assets49,740 (16,714)33,026 17 33,043 
Current liabilities(84,853)7,050 (77,803)(6,071)(83,874)
Deferred credits and other(23,349)9,664 (13,685)— (13,685)
Total liabilities(108,202)16,714 (91,488)(6,071)(97,559)
Total$(58,462)$— $(58,462)$(6,054)$(64,516)

(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 or received in excess of the recognized derivative instrument. Includes cash collateral received from counterparties of $6,071 thousand and cash margin provided to counterparties of $17 thousand.

As of December 31, 2022:
(dollars in thousands)
Gross
Recognized
Derivatives
 (a)
Amounts
Offset
(b)
Net
 Recognized
 Derivatives
Other
 (c)
Amount
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.

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 credit agreement for the Los Alamitos project. 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 March 31, 2023, the interest rate swap has a notional value of $32 million with a maturity in 2041. Relating to this derivative, our Condensed Consolidated Balance Sheet as of March 31, 2023, includes approximately $1.7 million reported as a liability within the liabilities from risk management activities line within the deferred credits and other section, and $0.1 million reported as a current asset within the assets from risk management activities line. As of March 31, 2023, the Condensed Consolidated Income Statement includes a pretax loss of approximately $1.6 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 as of March 31, 2023, and we expect $0.1 million of losses 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 counterparties and have risk management contracts with many counterparties. As of March 31, 2023, we have one counterparty for which our exposure represents approximately 20% of Pinnacle West’s $33 million of risk management assets. This exposure relates to a master agreement with the counterparty, and the counterparty is 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 companies 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 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):
 March 31, 2023
Aggregate fair value of derivative instruments in a net liability position$108,202 
Additional cash collateral in the event credit-risk-related contingent features were fully triggered (a)73,886 
(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 have energy-related non-derivative instrument contracts with investment grade credit-related contingent features, which could require us to post additional collateral of approximately $76 million if our debt credit ratings were to fall below investment grade.
v3.23.1
Commitments and Contingencies
 3 Months Ended
Mar. 31, 2023
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, 2025.
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. On March 16, 2023, the DOE approved a payment in the amount of $14.3 million (APS’s share is $4.2 million), and on April 6, 2023, APS received this payment.

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 $22.4 million for each retrospective premium assessment declared by NEIL’s Board of Directors due to losses.  Additionally, at the sole discretion of the NEIL Board of Directors, APS would be liable to provide approximately $62.6 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.

Contractual Obligations

As of March 31, 2023, our fuel and purchased power and purchase obligation commitments have increased from the information provided in our 2022 Form 10-K. The increase is primarily due to new purchased power and energy storage commitments of approximately $1.9 billion. The majority of the changes relate to 2025 and thereafter. This amount includes approximately $1.6 billion of commitments relating to purchased power lease contracts. See Note 14.

Other than the items described above, there have been no material changes, as of March 31, 2023, outside the normal course of business in contractual obligations from the information provided in our 2022 Form 10-K. See Note 3 for discussion regarding changes in our short-term and long-term debt obligations.
Superfund and Other 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 (each a “PRP”).  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 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.

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. On March 6, 2023, the Court of Appeals issued its order in the matter, vacating the ACC’s disallowance of the SCR investment and remanding the matter back to the ACC for further review in accordance with ACC rules and the order of the Court of Appeals. The parties have until May 8, 2023 to file a petition requesting review by the Arizona Supreme Court. APS cannot predict the outcome of this proceeding. Based on the partial recovery of these investments and cost deferrals in current rates, the favorable Court of Appeals order, and the potential for further appellate review, APS has not recorded an impairment or write-off relating to the SCR plant investments or deferrals as of March 31, 2023. 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 greenhouse gases, water quality, wastewater discharges, solid waste, hazardous waste, and coal combustion residuals (“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.
 
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 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. As to Cholla, APS currently estimates that its share of corrective action and monitoring costs at this facility will likely range from $30 million to $35 million, which similarly would be incurred over 30 years. 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 and final remedy selection process, APS cannot predict any ultimate impacts to APS; however, at this time APS does not believe that any potential changes to the cost estimate for Four Corners or Cholla 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 an 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, APS 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 APS’s 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. 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 the 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 included an after-tax loss of $12.8 million relating to this impairment.

BCE and Ameresco, Inc. jointly own a special purpose entity that is sponsoring the Kūpono Solar project. This project is a 42 MW solar and battery storage facility in Oʻahu, Hawaii that will supply clean renewable energy and capacity under a 20-year power purchase agreement with Hawaiian Electric Company, Inc. The Kūpono Solar project is expected to be completed in 2024. On April 18, 2023, the Kūpono Solar special purpose entity entered into a $140 million non-recourse construction financing agreement. The construction financing will convert into a sale leaseback agreement upon commercial operation of the project. The financing agreement requires $40 million of sponsor equity, which has been funded by the project’s equity participants. In connection with the financing, Pinnacle West has issued performance guarantees relating to the project.
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 March 31, 2023, standby letters of credit totaled approximately $10 million and will expire in 2023 and 2024. As of March 31, 2023, surety bonds expiring through 2025 totaled approximately $21 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 March 31, 2023. 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 March 31, 2023 there is approximately $33 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.
On April 18, 2023, Pinnacle West issued performance guarantees in connection with BCE’s Kūpono investment project financing. BCE holds an equity method investment relating to the Kūpono project. See discussion above.
v3.23.1
Other Income and Other Expense
 3 Months Ended
Mar. 31, 2023
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 (dollars in thousands):
Three Months Ended
March 31,
20232022
Other income:
Interest income$6,026 $1,642 
Miscellaneous51 62 
Total other income$6,077 $1,704 
Other expense:
Non-operating costs(2,640)(2,453)
Investment losses — net(1,061)(681)
Miscellaneous(430)(288)
Total other expense$(4,131)$(3,422)
The following table provides detail of APS’s other income and other expense (dollars in thousands):

 Three Months Ended
March 31,
 20232022
Other income:  
Interest income$5,024 $1,099 
Miscellaneous51 53 
Total other income$5,075 $1,152 
Other expense: 
Non-operating costs(2,188)(1,561)
Miscellaneous(429)(288)
Total other expense$(2,617)$(1,849)
v3.23.1
Earnings Per Share
 3 Months Ended
Mar. 31, 2023
Earnings Per Share [Abstract]  
Earnings Per Share Earnings Per Share
The following table presents the calculation of Pinnacle West’s basic and diluted earnings per share (in thousands, except per share amounts):
 Three Months Ended March 31,
 20232022
Net income (loss) attributable to common shareholders$(3,297)$16,956 
Weighted average common shares outstanding — basic
113,358 113,102 
Net effect of dilutive securities:
Contingently issuable performance shares and restricted stock units239 193 
Weighted average common shares outstanding — diluted
113,597 113,295 
Earnings per weighted-average common share outstanding
Net income (loss) attributable to common shareholders — basic$(0.03)$0.15 
Net income (loss) attributable to common shareholders — diluted$(0.03)$0.15 

For the three months ended March 31, 2023, 239 thousand shares were excluded from the calculation of diluted weighted average common shares outstanding, as their inclusion would have been antidilutive. For the three months ended March 31, 2022, no shares were excluded from the calculation of diluted weighted average common shares outstanding.
v3.23.1
Fair Value Measurements
 3 Months Ended
Mar. 31, 2023
Fair Value Disclosures [Abstract]  
Fair Value Measurements Fair Value Measurements
 
We classify our assets and liabilities that are carried at fair value within the fair value hierarchy.  This hierarchy ranks the quality and reliability of the inputs used to determine fair values, which are then classified and disclosed in one of three categories.  The three levels of the fair value hierarchy are:
 
Level 1 — Inputs are unadjusted quoted prices in active markets for identical assets or liabilities at the measurement date.

Level 2 — Other significant observable inputs, including quoted prices in active markets for similar assets or liabilities; quoted prices in markets that are not active, and model-derived valuations whose inputs are observable (such as yield curves). 
 
Level 3 — Valuation models with significant unobservable inputs that are supported by little or no market activity.  Instruments in this category may include long-dated derivative transactions where valuations are unobservable due to the length of the transaction, options, and transactions in locations where observable market data does not exist.  The valuation models we employ utilize spot prices, forward prices, historical market data and other factors to forecast future prices.

 Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  Thus, a valuation may be classified in Level 3 even though the valuation may include significant inputs that are readily observable.  We maximize the use of observable inputs and minimize the use of unobservable inputs.  We rely primarily on the market approach of using prices and other market information for identical and/or comparable assets and liabilities.  If market data is not readily available, inputs
may reflect our own assumptions about the inputs market participants would use.  Our assessment of the inputs and the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities as well as their placement within the fair value hierarchy levels.  We assess whether a market is active by obtaining observable broker quotes, reviewing actual market activity, and assessing the volume of transactions.  We consider broker quotes observable inputs when the quote is binding on the broker, we can validate the quote with market activity, or we can determine that the inputs the broker used to arrive at the quoted price are observable.

Certain instruments have been valued using the concept of Net Asset Value (“NAV”) as a practical expedient. These instruments are typically structured as investment companies offering shares or units to multiple investors for the purpose of providing a return. These instruments are similar to mutual funds; however, their NAV is generally not published and publicly available, nor are these instruments traded on an exchange. Instruments valued using NAV as a practical expedient are included in our fair value disclosures; however, in accordance with GAAP are not classified within the fair value hierarchy levels.

Recurring Fair Value Measurements
 
We apply recurring fair value measurements to cash equivalents, derivative instruments, and investments held in the nuclear decommissioning trusts and other special use funds. On an annual basis, we apply fair value measurements to plan assets held in our retirement and other benefit plans.  See Note 7 in the 2022 Form 10-K 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 12 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 March 31, 2023, of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):
 
 Level 1Level 2Level 3Other Total
ASSETS      
Cash equivalents$14 $— $— $— $14 
Risk management activities — derivative instruments:
Commodity contracts— 28,483 21,257 (16,697)(a)33,043 
Interest rate swaps— 134 — — 134 
Subtotal risk management activities - derivative instruments— 28,617 21,257 (16,697)33,177 
Nuclear decommissioning trust:
Equity securities9,665 — — (1,135)(b)8,530 
U.S. commingled equity funds— — — 507,706 (c)507,706 
U.S. Treasury debt231,003 — — —  231,003 
Corporate debt— 149,541 — —  149,541 
Mortgage-backed securities— 157,330 — —  157,330 
Municipal bonds— 63,950 — —  63,950 
Other fixed income— 7,557 — —  7,557 
Subtotal nuclear decommissioning trust240,668 378,378 — 506,571 1,125,617 
Other special use funds:
Equity securities27,642 — — 1,041 (b)28,683 
U.S. Treasury debt320,196 — — — 320,196 
Municipal bonds— 3,998 — — 3,998 
Subtotal other special use funds347,838 3,998 — 1,041 352,877 
Total assets$588,520 $410,993 $21,257 $490,915 $1,511,685 
LIABILITIES
Risk management activities — derivative instruments:
Commodity contracts$— $(93,567)$(14,635)$10,643 (a)$(97,559)
Interest rate swaps— (1,698)— — (1,698)
Subtotal risk management activities - derivative instruments— (95,265)(14,635)10,643 (99,257)
Total liabilities$— $(95,265)$(14,635)$10,643 $(99,257)
(a)Represents counterparty netting, margin, and collateral. See Note 7.
(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, 2022, of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):
 
 Level 1Level 2Level 3Other Total
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 7.
(b)Represents net pending securities sales and purchases.
(c)Valued using NAV as a practical expedient and, therefore, are not classified in the fair value hierarchy.
Fair Value Measurements Classified as Level 3
 
The significant unobservable inputs used in the fair value measurement of our energy derivative contracts include broker quotes that cannot be validated as an observable input primarily due to the long-term nature of the quote or other characteristics of the product.  Significant changes in these inputs in isolation would result in significantly higher or lower fair value measurements.  Changes in our derivative contract fair values, including changes relating to unobservable inputs, typically will not impact net income due to regulatory accounting treatment. See Note 4.
 
Because our forward commodity contracts classified as Level 3 are currently in a net purchase position, we would expect price increases of the underlying commodity to result in increases in the net fair value of the related contracts.  Conversely, if the price of the underlying commodity decreases, the net fair value of the related contracts would likely decrease.
 
Other unobservable valuation inputs include credit and liquidity reserves which do not have a material impact on our valuations; however, significant changes in these inputs could also result in higher or lower fair value measurements.

The following tables provide information regarding our significant unobservable inputs used to value our risk management derivative Level 3 instruments at March 31, 2023 and December 31, 2022:

March 31, 2023
 Fair Value (thousands)		ValuationSignificantWeighted-Average
Commodity ContractsAssetsLiabilitiesTechniqueUnobservable InputRange (b)
Electricity:
Forward Contracts (a)$21,084 $14,385 Discounted cash flowsElectricity forward price (per MWh)$37.79-$306.34$157.00 
Natural Gas:
Forward Contracts (a)173 250 Discounted cash flowsNatural gas forward price (per MMBtu)$(0.02)-$0.14$0.02 
Total$21,257 $14,635 
(a)Includes swaps and physical and financial contracts.
(b)Unobservable inputs were weighted by the relative fair value of the instrument.

 
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 $31,020 
(a)Includes swaps and physical and financial contracts.
(b)Unobservable inputs were weighted by the relative fair value of the instrument.
The following table shows the changes in fair value for our risk management activities’ assets and liabilities that are measured at fair value on a recurring basis using Level 3 inputs for the three months ended March 31, 2023 and 2022 (dollars in thousands):
 Three Months Ended
March 31,
Commodity Contracts20232022
Net derivative balance at beginning of period$(4,888)$(2,738)
Total net gains (losses) realized/unrealized:
Deferred as a regulatory asset or liability(30,427)16,807 
Settlements41,937 (4,419)
Transfers into Level 3 from Level 2— — 
Transfers from Level 3 into Level 2— — 
Net derivative balance at end of period$6,622 $9,650 
Net unrealized gains included in earnings related to instruments still held at end of period$— $— 

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 3 for our long-term debt fair values.
v3.23.1
Investments in Nuclear Decommissioning Trusts and Other Special Use Funds
 3 Months Ended
Mar. 31, 2023
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 Condensed Consolidated Balance Sheets. See Note 11 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, APS was reimbursed $15 million for prior year active union employee medical claims from the active union employee medical account. The account is invested primarily in fixed income securities. In accordance with the ratemaking treatment, APS has deferred the unrealized gains and losses (including 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):  
March 31, 2023
 Fair ValueTotal
Unrealized
Gains		Total
Unrealized
Losses
Investment Type:Nuclear Decommissioning TrustsOther Special Use FundsTotal
Equity securities$517,371 $27,642 $545,013 $367,791 $(39)
Available for sale-fixed income securities609,381 324,194 933,575 (a)6,728 (54,178)
Other(1,135)1,041 (94)(b)1 (11)
Total$1,125,617 $352,877 $1,478,494 $374,520 $(54,228)

(a)As of March 31, 2023, the amortized cost basis of these available-for-sale investments is $981 million.
(b)Represents net pending securities sales and purchases.

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.
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):
 Three Months Ended March 31,
 Nuclear Decommissioning TrustsOther Special Use FundsTotal
2023
Realized gains$1,210 $— $1,210 
Realized losses(5,694)— (5,694)
Proceeds from the sale of securities (a)136,185 90,441 226,626 
2022
Realized gains$1,023 $— $1,023 
Realized losses(7,235)— (7,235)
Proceeds from the sale of securities (a)319,693 41,545 361,238 

(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 March 31, 2023, is as follows (dollars in thousands):
 Nuclear Decommissioning TrustsCoal Reclamation Escrow AccountActive Union Employee Medical AccountTotal
Less than one year$14,591 $53,718 $74,788 $143,097 
1 year – 5 years174,911 36,821 110,034 321,766 
5 years – 10 years137,708 — 44,835 182,543 
Greater than 10 years282,171 3,998 — 286,169 
Total$609,381 $94,537 $229,657 $933,575 
v3.23.1
Changes in Accumulated Other Comprehensive Loss
 3 Months Ended
Mar. 31, 2023
Comprehensive Income (Loss), Net of Tax, Attributable to Parent [Abstract]  
Changes in Accumulated Other Comprehensive Loss Changes in Accumulated Other Comprehensive Loss
The following tables show the changes in Pinnacle West’s consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component (dollars in thousands):
 Pension and Other Postretirement Benefits Derivative Instruments Total
Three Months Ended March 31
Balance December 31, 2022$(32,332)$897 $(31,435)
OCI (loss) before reclassifications— (616)(616)
Amounts reclassified from accumulated other comprehensive loss515  (a)— 515 
Balance March 31, 2023$(31,817)$281 $(31,536)
Balance December 31, 2021$(53,885)$(976)$(54,861)
OCI (loss) before reclassifications— 252 252 
Amounts reclassified from accumulated other comprehensive loss901  (a)— 901 
Balance March 31, 2022$(52,984)$(724)$(53,708)

(a)    These amounts primarily represent amortization of actuarial loss and are included in the computation of net periodic pension cost.  See Note 5.
The following tables show 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
Three Months Ended March 31
Balance December 31, 2022$(15,596)
OCI (loss) before reclassifications— 
Amounts reclassified from accumulated other comprehensive loss457 (a)
Balance March 31, 2023$(15,139)
Balance December 31, 2021$(34,880)
OCI (loss) before reclassifications— 
Amounts reclassified from accumulated other comprehensive loss820 (a)
Balance March 31, 2022$(34,060)

(a) These amounts primarily represent amortization of actuarial loss and are included in the computation of net periodic pension cost.  See Note 5.
v3.23.1
Leases
 3 Months Ended
Mar. 31, 2023
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 and energy storage agreements that qualify as lease arrangements. Our leases have remaining terms that expire in 2023 through 2073. 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 6 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 the leased assets. APS controls the dispatch of the leased assets during the months of use and is required to pay a fixed monthly capacity payment during these periods of use.  For these types of leased assets APS has elected to combine both the lease and non-lease payment components and accounts for the entire fixed payment as a lease obligation. In addition to the fixed monthly capacity payments, APS must also pay variable charges based on the actual production volume of the assets.  The variable consideration is not included in the measurement of our lease obligation.

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.

The following tables provide information related to our lease costs (dollars in thousands):

Three Months Ended
March 31,
20232022
Operating Lease Cost - Purchased Power Lease Contracts$— $— 
Operating Lease Cost - Land, Property, and Other Equipment4,600 4,572 
Total Operating Lease Cost4,600 4,572 
Variable lease cost (a)16,721 18,695 
Short-term lease cost1,402 1,302 
Total lease cost$22,723 $24,569 

(a) Primarily relates to purchased power lease contracts.
Lease costs are primarily included as a component of operating expenses on our Condensed Consolidated Statements of Income.  Lease costs relating to purchased power lease contracts are recorded in fuel and purchased power on the Condensed Consolidated Statements of Income, and are subject to recovery under the PSA or RES (see Note 4).  The tables above reflect the lease cost amounts before the effect of regulatory deferral under the PSA and RES.  Variable lease costs are recognized in the period the costs are incurred, and primarily relate to renewable purchased power lease contracts.  Payments under most renewable purchased power lease contracts are dependent upon environmental factors, and due to the inherent uncertainty associated with the reliability of the fuel source, the payments are considered variable and are excluded from the measurement of lease liabilities and right-of-use lease assets. Certain of our lease agreements have lease terms with non-consecutive periods of use. For these agreements, we recognize lease costs during the periods of use.  Leases with initial terms of 12 months or less are considered short-term leases and are not recorded on the balance sheet.

The following table provides information related to the maturity of our operating lease liabilities (dollars in thousands):
March 31, 2023
YearPurchased Power Lease ContractsLand, Property & Equipment LeasesTotal
2023 (remaining nine months of 2023)$106,152 $11,981 $118,133 
2024104,315 13,098 117,413 
2025121,082 10,422 131,504 
2026134,806 8,308 143,114 
2027160,727 6,395 167,122 
2028164,524 4,338 168,862 
Thereafter779,792 68,372 848,164 
Total lease commitments1,571,398 122,914 1,694,312 
Less imputed interest342,694 45,904 388,598 
Total lease liabilities$1,228,704 $77,010 $1,305,714 

We recognize lease assets and liabilities upon lease commencement. At March 31, 2023, we have 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 expect 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 $3.5 billion over the terms of the arrangements.
The following tables provide other additional information related to operating lease liabilities (dollars in thousands):
Three Months Ended
March 31, 2023		Three Months Ended March 31, 2022
Cash paid for amounts included in the measurement of lease liabilities — operating cash flows:$3,851 $3,358 
Right-of-use operating lease assets obtained in exchange for operating lease liabilities551,239 (a)4,889 

March 31, 2023December 31, 2022
Weighted average remaining lease term10 years7 years
Weighted average discount rate (b)4.44 %2.21 %

(a) Primarily relates to the two purchased power operating lease agreements that were modified in January 2023.
(b) 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.
v3.23.1
Consolidation and Nature of Operations (Tables)
 3 Months Ended
Mar. 31, 2023
Organization, Consolidation and Presentation of Financial Statements [Abstract]  
Schedule of supplemental cash flow information
The following table summarizes supplemental Pinnacle West cash flow information (dollars in thousands):
 Three Months Ended
March 31,
 20232022
Cash paid (received) during the period for:
Income taxes, net of refunds$(12)$— 
Interest, net of amounts capitalized62,241 55,208 
Significant non-cash investing and financing activities:
Accrued capital expenditures$115,559 $131,778 

The following table summarizes supplemental APS cash flow information (dollars in thousands):
Three Months Ended
March 31,
 20232022
Cash paid (received) during the period for:
Income taxes, net of refunds$— $(25)
Interest, net of amounts capitalized53,610 53,982 
Significant non-cash investing and financing activities:
Accrued capital expenditures$112,219 $124,778 
v3.23.1
Revenue (Tables)
 3 Months Ended
Mar. 31, 2023
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):
Three Months Ended March 31,
20232022
Retail Electric Service
Residential$409,724 $367,346 
Non-Residential406,137 359,516 
Wholesale Energy Sales95,603 28,903 
Transmission Services for Others31,791 25,492 
Other Sources1,700 2,274 
Total operating revenues$944,955 $783,531 
Schedule of Accounts Receivable
The following table provides a rollforward of Pinnacle West’s allowance for doubtful accounts (dollars in thousands):

March 31, 2023December 31, 2022
Allowance for doubtful accounts, balance at beginning of period$23,778 $25,354 
Bad debt expense3,522 17,006 
Actual write-offs(5,188)(18,582)
Allowance for doubtful accounts, balance at end of period$22,112 $23,778 
v3.23.1
Long-Term Debt and Liquidity Matters (Tables)
 3 Months Ended
Mar. 31, 2023
Debt Disclosure [Abstract]  
Schedule of Estimated Fair Value of Long-Term Debt, Including Current Maturities The following table presents the estimated fair value of our long-term debt, including current maturities (dollars in thousands):
 As of March 31, 2023As of December 31, 2022
 Carrying
Amount		Fair ValueCarrying
Amount		Fair Value
Pinnacle West$1,123,101 $1,084,455 $947,892 $905,525 
APS6,794,124 5,898,167 6,793,529 5,629,491 
BCE60,150 60,821 50,550 50,685 
Total$7,977,375 $7,043,443 $7,791,971 $6,585,701 
v3.23.1
Regulatory Matters (Tables)
 3 Months Ended
Mar. 31, 2023
Regulated Operations [Abstract]  
Schedule of Capital Structure and Cost of Capital he 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 %
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 2023 and 2022 (dollars in thousands):
 Three Months Ended
March 31,
 20232022
Beginning balance$460,561 $388,148 
Deferred fuel and purchased power costs — current period90,305 6,110 
Amounts charged to customers(80,904)(39,442)
Ending balance$469,962 $354,816 
Schedule of Regulatory Assets
The detail of regulatory assets is as follows (dollars in thousands): 
 Amortization ThroughMarch 31, 2023December 31, 2022
Pension(a)$628,727 $637,656 
Deferred fuel and purchased power (b) (c)2024469,962 460,561 
Income taxes — allowance for funds used during construction (“AFUDC”) equity2053179,818 179,631 
Ocotillo deferral (e)2031135,766 138,143 
SCR deferral (e)(f)203195,588 97,624 
Retired power plant costs203394,903 98,692 
Deferred fuel and purchased power — mark-to-market (Note 7)
202561,858 — 
Deferred property taxes202738,915 41,057 
Deferred compensation203634,492 33,660 
Income taxes — investment tax credit basis adjustment205624,095 23,977 
Palo Verde VIEs (Note 6)
204620,893 20,933 
Active Union Medical Trust(g)15,010 18,226 
Four Corners cost deferral202413,979 15,999 
Navajo coal reclamation202613,117 13,862 
Loss on reacquired debt20389,238 9,468 
Mead-Phoenix transmission line contributions in aid of construction (“CIAC”)20508,965 9,048 
Tax expense adjustor mechanism (b)20315,681 5,845 
Lost fixed cost recovery (b)2023— 9,547 
OtherVarious8,458 8,171 
Total regulatory assets (d) $1,859,465 $1,822,100 
Less: current regulatory assets$600,802 $538,879 
Total non-current regulatory assets$1,258,663 $1,283,221 

(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 5 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):
 
 Amortization ThroughMarch 31, 2023December 31, 2022
Excess deferred income taxes — ACC - Tax Act (a)2046$970,578 $971,545 
Excess deferred income taxes — FERC - Tax Act (a)2058221,708 221,877 
Asset retirement obligations2057396,107 354,002 
Other postretirement benefits(d)258,955 270,604 
Removal costs(c)106,102 106,889 
Income taxes — change in rates205164,739 64,806 
Four Corners coal reclamation203853,348 52,592 
Income taxes — deferred investment tax credit205649,031 48,035 
Spent nuclear fuel202737,313 39,217 
Renewable energy standard (b)202430,188 35,720 
Sundance maintenance203117,667 16,893 
Property tax deferral (e)202414,353 15,521 
Demand side management (b)202314,207 8,461 
FERC transmission true up (b)202512,597 22,895 
Tax expense adjustor mechanism (b) (e)N/A4,835 4,835 
Deferred fuel and purchased power — mark-to-market (Note 7)
20253,396 96,367 
OtherVarious7,415 3,092 
Total regulatory liabilities $2,262,539 $2,333,351 
Less: current regulatory liabilities$202,266 $271,575 
Total non-current regulatory liabilities$2,060,273 $2,061,776 

(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 guidance, APS accrues removal costs for its regulated assets, even if there is no legal obligation for removal.
(d)See Note 5.
(e)Balance includes amounts for future regulatory consideration and amortization period determination.
v3.23.1
Retirement Plans and Other Postretirement Benefits (Tables)
 3 Months Ended
Mar. 31, 2023
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 BenefitsOther Benefits
 Three Months Ended
March 31,		Three Months Ended
March 31,
 2023202220232022
Service cost — benefits earned during the period$10,157 $14,331 $2,120 $4,218 
Non-service costs (credits):
Interest cost on benefit obligation38,362 27,023 5,673 4,463 
Expected return on plan assets(45,561)(46,394)(10,872)(11,510)
  Amortization of:   
  Prior service credit— — (9,447)(9,447)
  Net actuarial loss (gain)9,713 4,768 (2,303)(2,982)
Net periodic cost/(benefit)$12,671 $(272)$(14,829)$(15,258)
Portion of benefit charged to expense$7,227 $(3,290)$(10,737)$(10,895)
v3.23.1
Derivative Accounting (Tables)
 3 Months Ended
Mar. 31, 2023
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 MeasureMarch 31, 2023December 31, 2022
PowerGWh1,664 1,197 
GasBillion cubic feet194 149 
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 LocationThree Months Ended
March 31,
Commodity Contracts20232022
Net Gain (Loss) Recognized in IncomeFuel and purchased power (a)$(188,930)$223,742 
 
(a)Amounts are before the effect of PSA deferrals.
Schedule of Offsetting Assets
The following tables provide information about the fair value of our risk management activities reported on a gross basis, and the impacts of offsetting.  These amounts relate to commodity contracts and are located in the assets and liabilities from risk management activities lines of APS’s Condensed Consolidated Balance Sheets.
As of March 31, 2023:
(dollars in thousands)
Gross
 Recognized
 Derivatives
 (a)
Amounts
Offset
 (b)
Net
 Recognized
 Derivatives
Other
 (c)
Amount Reported on Balance Sheets
Current assets$22,994 $(7,050)$15,944 $17 $15,961 
Investments and other assets26,746 (9,664)17,082 — 17,082 
Total assets49,740 (16,714)33,026 17 33,043 
Current liabilities(84,853)7,050 (77,803)(6,071)(83,874)
Deferred credits and other(23,349)9,664 (13,685)— (13,685)
Total liabilities(108,202)16,714 (91,488)(6,071)(97,559)
Total$(58,462)$— $(58,462)$(6,054)$(64,516)

(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 or received in excess of the recognized derivative instrument. Includes cash collateral received from counterparties of $6,071 thousand and cash margin provided to counterparties of $17 thousand.

As of December 31, 2022:
(dollars in thousands)
Gross
Recognized
Derivatives
 (a)
Amounts
Offset
(b)
Net
 Recognized
 Derivatives
Other
 (c)
Amount
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.
Schedule of Offsetting Liabilities
The following tables provide information about the fair value of our risk management activities reported on a gross basis, and the impacts of offsetting.  These amounts relate to commodity contracts and are located in the assets and liabilities from risk management activities lines of APS’s Condensed Consolidated Balance Sheets.
As of March 31, 2023:
(dollars in thousands)
Gross
 Recognized
 Derivatives
 (a)
Amounts
Offset
 (b)
Net
 Recognized
 Derivatives
Other
 (c)
Amount Reported on Balance Sheets
Current assets$22,994 $(7,050)$15,944 $17 $15,961 
Investments and other assets26,746 (9,664)17,082 — 17,082 
Total assets49,740 (16,714)33,026 17 33,043 
Current liabilities(84,853)7,050 (77,803)(6,071)(83,874)
Deferred credits and other(23,349)9,664 (13,685)— (13,685)
Total liabilities(108,202)16,714 (91,488)(6,071)(97,559)
Total$(58,462)$— $(58,462)$(6,054)$(64,516)

(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 or received in excess of the recognized derivative instrument. Includes cash collateral received from counterparties of $6,071 thousand and cash margin provided to counterparties of $17 thousand.

As of December 31, 2022:
(dollars in thousands)
Gross
Recognized
Derivatives
 (a)
Amounts
Offset
(b)
Net
 Recognized
 Derivatives
Other
 (c)
Amount
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.
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):
 March 31, 2023
Aggregate fair value of derivative instruments in a net liability position$108,202 
Additional cash collateral in the event credit-risk-related contingent features were fully triggered (a)73,886 
(a)This amount is after counterparty netting and includes those contracts which qualify for scope exceptions, which are excluded from the derivative details above.
v3.23.1
Other Income and Other Expense (Tables)
 3 Months Ended
Mar. 31, 2023
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 (dollars in thousands):
Three Months Ended
March 31,
20232022
Other income:
Interest income$6,026 $1,642 
Miscellaneous51 62 
Total other income$6,077 $1,704 
Other expense:
Non-operating costs(2,640)(2,453)
Investment losses — net(1,061)(681)
Miscellaneous(430)(288)
Total other expense$(4,131)$(3,422)
The following table provides detail of APS’s other income and other expense (dollars in thousands):

 Three Months Ended
March 31,
 20232022
Other income:  
Interest income$5,024 $1,099 
Miscellaneous51 53 
Total other income$5,075 $1,152 
Other expense: 
Non-operating costs(2,188)(1,561)
Miscellaneous(429)(288)
Total other expense$(2,617)$(1,849)
v3.23.1
Earnings Per Share (Tables)
 3 Months Ended
Mar. 31, 2023
Earnings Per Share [Abstract]  
Schedule of Earnings Per Weighted Average Common Share Outstanding The following table presents the calculation of Pinnacle West’s basic and diluted earnings per share (in thousands, except per share amounts):
 Three Months Ended March 31,
 20232022
Net income (loss) attributable to common shareholders$(3,297)$16,956 
Weighted average common shares outstanding — basic
113,358 113,102 
Net effect of dilutive securities:
Contingently issuable performance shares and restricted stock units239 193 
Weighted average common shares outstanding — diluted
113,597 113,295 
Earnings per weighted-average common share outstanding
Net income (loss) attributable to common shareholders — basic$(0.03)$0.15 
Net income (loss) attributable to common shareholders — diluted$(0.03)$0.15 
v3.23.1
Fair Value Measurements (Tables)
 3 Months Ended
Mar. 31, 2023
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 March 31, 2023, of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):
 
 Level 1Level 2Level 3Other Total
ASSETS      
Cash equivalents$14 $— $— $— $14 
Risk management activities — derivative instruments:
Commodity contracts— 28,483 21,257 (16,697)(a)33,043 
Interest rate swaps— 134 — — 134 
Subtotal risk management activities - derivative instruments— 28,617 21,257 (16,697)33,177 
Nuclear decommissioning trust:
Equity securities9,665 — — (1,135)(b)8,530 
U.S. commingled equity funds— — — 507,706 (c)507,706 
U.S. Treasury debt231,003 — — —  231,003 
Corporate debt— 149,541 — —  149,541 
Mortgage-backed securities— 157,330 — —  157,330 
Municipal bonds— 63,950 — —  63,950 
Other fixed income— 7,557 — —  7,557 
Subtotal nuclear decommissioning trust240,668 378,378 — 506,571 1,125,617 
Other special use funds:
Equity securities27,642 — — 1,041 (b)28,683 
U.S. Treasury debt320,196 — — — 320,196 
Municipal bonds— 3,998 — — 3,998 
Subtotal other special use funds347,838 3,998 — 1,041 352,877 
Total assets$588,520 $410,993 $21,257 $490,915 $1,511,685 
LIABILITIES
Risk management activities — derivative instruments:
Commodity contracts$— $(93,567)$(14,635)$10,643 (a)$(97,559)
Interest rate swaps— (1,698)— — (1,698)
Subtotal risk management activities - derivative instruments— (95,265)(14,635)10,643 (99,257)
Total liabilities$— $(95,265)$(14,635)$10,643 $(99,257)
(a)Represents counterparty netting, margin, and collateral. See Note 7.
(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, 2022, of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):
 
 Level 1Level 2Level 3Other Total
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 7.
(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 three months ended March 31, 2023 and 2022 (dollars in thousands):
 Three Months Ended
March 31,
Commodity Contracts20232022
Net derivative balance at beginning of period$(4,888)$(2,738)
Total net gains (losses) realized/unrealized:
Deferred as a regulatory asset or liability(30,427)16,807 
Settlements41,937 (4,419)
Transfers into Level 3 from Level 2— — 
Transfers from Level 3 into Level 2— — 
Net derivative balance at end of period$6,622 $9,650 
Net unrealized gains included in earnings related to instruments still held at end of period$— $— 
Fair Value Measurement Inputs and Valuation Techniques
The following tables provide information regarding our significant unobservable inputs used to value our risk management derivative Level 3 instruments at March 31, 2023 and December 31, 2022:

March 31, 2023
 Fair Value (thousands)		ValuationSignificantWeighted-Average
Commodity ContractsAssetsLiabilitiesTechniqueUnobservable InputRange (b)
Electricity:
Forward Contracts (a)$21,084 $14,385 Discounted cash flowsElectricity forward price (per MWh)$37.79-$306.34$157.00 
Natural Gas:
Forward Contracts (a)173 250 Discounted cash flowsNatural gas forward price (per MMBtu)$(0.02)-$0.14$0.02 
Total$21,257 $14,635 
(a)Includes swaps and physical and financial contracts.
(b)Unobservable inputs were weighted by the relative fair value of the instrument.

 
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.
v3.23.1
Investments in Nuclear Decommissioning Trusts and Other Special Use Funds (Tables)
 3 Months Ended
Mar. 31, 2023
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):  
March 31, 2023
 Fair ValueTotal
Unrealized
Gains		Total
Unrealized
Losses
Investment Type:Nuclear Decommissioning TrustsOther Special Use FundsTotal
Equity securities$517,371 $27,642 $545,013 $367,791 $(39)
Available for sale-fixed income securities609,381 324,194 933,575 (a)6,728 (54,178)
Other(1,135)1,041 (94)(b)1 (11)
Total$1,125,617 $352,877 $1,478,494 $374,520 $(54,228)

(a)As of March 31, 2023, the amortized cost basis of these available-for-sale investments is $981 million.
(b)Represents net pending securities sales and purchases.

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.
Schedule of Realized Gains and Losses and Proceeds from the Sale of Securities by the Nuclear Decommissioning Trust Funds :
 Three Months Ended March 31,
 Nuclear Decommissioning TrustsOther Special Use FundsTotal
2023
Realized gains$1,210 $— $1,210 
Realized losses(5,694)— (5,694)
Proceeds from the sale of securities (a)136,185 90,441 226,626 
2022
Realized gains$1,023 $— $1,023 
Realized losses(7,235)— (7,235)
Proceeds from the sale of securities (a)319,693 41,545 361,238 

(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 March 31, 2023, is as follows (dollars in thousands):
 Nuclear Decommissioning TrustsCoal Reclamation Escrow AccountActive Union Employee Medical AccountTotal
Less than one year$14,591 $53,718 $74,788 $143,097 
1 year – 5 years174,911 36,821 110,034 321,766 
5 years – 10 years137,708 — 44,835 182,543 
Greater than 10 years282,171 3,998 — 286,169 
Total$609,381 $94,537 $229,657 $933,575 
v3.23.1
Changes in Accumulated Other Comprehensive Loss (Tables)
 3 Months Ended
Mar. 31, 2023
Comprehensive Income (Loss), Net of Tax, Attributable to Parent [Abstract]  
Schedule of Changes in Accumulated Other Comprehensive Loss Including Reclassification Adjustments, Net of Tax, by Component
The following tables show the changes in Pinnacle West’s consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component (dollars in thousands):
 Pension and Other Postretirement Benefits Derivative Instruments Total
Three Months Ended March 31
Balance December 31, 2022$(32,332)$897 $(31,435)
OCI (loss) before reclassifications— (616)(616)
Amounts reclassified from accumulated other comprehensive loss515  (a)— 515 
Balance March 31, 2023$(31,817)$281 $(31,536)
Balance December 31, 2021$(53,885)$(976)$(54,861)
OCI (loss) before reclassifications— 252 252 
Amounts reclassified from accumulated other comprehensive loss901  (a)— 901 
Balance March 31, 2022$(52,984)$(724)$(53,708)

(a)    These amounts primarily represent amortization of actuarial loss and are included in the computation of net periodic pension cost.  See Note 5.
The following tables show 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
Three Months Ended March 31
Balance December 31, 2022$(15,596)
OCI (loss) before reclassifications— 
Amounts reclassified from accumulated other comprehensive loss457 (a)
Balance March 31, 2023$(15,139)
Balance December 31, 2021$(34,880)
OCI (loss) before reclassifications— 
Amounts reclassified from accumulated other comprehensive loss820 (a)
Balance March 31, 2022$(34,060)

(a) These amounts primarily represent amortization of actuarial loss and are included in the computation of net periodic pension cost.  See Note 5.
v3.23.1
Leases (Tables)
 3 Months Ended
Mar. 31, 2023
Leases [Abstract]  
Lease cost and additional information
The following tables provide information related to our lease costs (dollars in thousands):

Three Months Ended
March 31,
20232022
Operating Lease Cost - Purchased Power Lease Contracts$— $— 
Operating Lease Cost - Land, Property, and Other Equipment4,600 4,572 
Total Operating Lease Cost4,600 4,572 
Variable lease cost (a)16,721 18,695 
Short-term lease cost1,402 1,302 
Total lease cost$22,723 $24,569 

(a) Primarily relates to purchased power lease contracts.
The following tables provide other additional information related to operating lease liabilities (dollars in thousands):
Three Months Ended
March 31, 2023		Three Months Ended March 31, 2022
Cash paid for amounts included in the measurement of lease liabilities — operating cash flows:$3,851 $3,358 
Right-of-use operating lease assets obtained in exchange for operating lease liabilities551,239 (a)4,889 

March 31, 2023December 31, 2022
Weighted average remaining lease term10 years7 years
Weighted average discount rate (b)4.44 %2.21 %

(a) Primarily relates to the two purchased power operating lease agreements that were modified in January 2023.
(b) 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 future minimum payments
The following table provides information related to the maturity of our operating lease liabilities (dollars in thousands):
March 31, 2023
YearPurchased Power Lease ContractsLand, Property & Equipment LeasesTotal
2023 (remaining nine months of 2023)$106,152 $11,981 $118,133 
2024104,315 13,098 117,413 
2025121,082 10,422 131,504 
2026134,806 8,308 143,114 
2027160,727 6,395 167,122 
2028164,524 4,338 168,862 
Thereafter779,792 68,372 848,164 
Total lease commitments1,571,398 122,914 1,694,312 
Less imputed interest342,694 45,904 388,598 
Total lease liabilities$1,228,704 $77,010 $1,305,714 
v3.23.1
Consolidation and Nature of Operations (Details) - USD ($)
$ in Thousands
 3 Months Ended
Mar. 31, 2023
Mar. 31, 2022
Cash paid (received) during the period for:    
Income taxes, net of refunds $ (12) $ 0
Interest, net of amounts capitalized 62,241 55,208
Significant non-cash investing and financing activities:    
Accrued capital expenditures 115,559 131,778
APS    
Cash paid (received) during the period for:    
Income taxes, net of refunds 0 (25)
Interest, net of amounts capitalized 53,610 53,982
Significant non-cash investing and financing activities:    
Accrued capital expenditures $ 112,219 $ 124,778
v3.23.1
Revenue - Schedule of Disaggregation (Details) - USD ($)
$ in Thousands
 3 Months Ended
Mar. 31, 2023
Mar. 31, 2022
Disaggregation of Revenue [Line Items]    
Total operating revenues $ 944,955 $ 783,531
Regulatory cost recovery revenue 23,000 12,000
Retail Electric Service | Residential    
Disaggregation of Revenue [Line Items]    
Total operating revenues 409,724 367,346
Retail Electric Service | Non-Residential    
Disaggregation of Revenue [Line Items]    
Total operating revenues 406,137 359,516
Wholesale Energy Sales    
Disaggregation of Revenue [Line Items]    
Total operating revenues 95,603 28,903
Transmission Services for Others    
Disaggregation of Revenue [Line Items]    
Total operating revenues 31,791 25,492
Other Sources    
Disaggregation of Revenue [Line Items]    
Total operating revenues 1,700 2,274
Electric and Transmission Service    
Disaggregation of Revenue [Line Items]    
Total operating revenues $ 922,000 $ 772,000
v3.23.1
Revenue - Allowance for Doubtful Accounts (Details) - USD ($)
$ in Thousands
 3 Months Ended 12 Months Ended
Mar. 31, 2023
Dec. 31, 2022
Accounts Receivable, Allowance for Credit Loss [Roll Forward]    
Allowance for doubtful accounts, balance at beginning of period $ 23,778 $ 25,354
Bad debt expense 3,522 17,006
Actual write-offs (5,188) (18,582)
Allowance for doubtful accounts, balance at end of period $ 22,112 $ 23,778
v3.23.1
Long-Term Debt and Liquidity Matters - Narrative (Details)
 3 Months Ended
Jan. 06, 2023
USD ($)
Feb. 11, 2022
USD ($)
MW
Mar. 31, 2023
USD ($)
Mar. 31, 2022
USD ($)
Apr. 10, 2023
USD ($)
creditFacility
Dec. 16, 2022
USD ($)
Long-Term Debt and Liquidity Matters            
Issuance of long-term debt     $ 185,136,000 $ 312,052,000    
Pinnacle West | Term Loan            
Long-Term Debt and Liquidity Matters            
Debt instrument, face amount           $ 175,000,000
Pinnacle West | Revolving Credit Facility | Revolving Credit Facility Maturing April 2028            
Long-Term Debt and Liquidity Matters            
Long-term line of credit     0      
Pinnacle West | Revolving Credit Facility | Revolving Credit Facility Maturing April 2028 | Subsequent Event            
Long-Term Debt and Liquidity Matters            
Current borrowing capacity on credit facility         $ 200,000,000  
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders (up to)         300,000,000  
Pinnacle West | Letter of Credit | Revolving Credit Facility Maturing April 2028            
Long-Term Debt and Liquidity Matters            
Outstanding letters of credit     0      
Pinnacle West | Commercial Paper | Revolving Credit Facility Maturing April 2028            
Long-Term Debt and Liquidity Matters            
Commercial paper     35,000,000      
APS            
Long-Term Debt and Liquidity Matters            
Equity infusion from Pinnacle West $ 150,000,000          
APS | Revolving Credit Facility | Revolving Credit Facility Maturing April 2028 | Subsequent Event            
Long-Term Debt and Liquidity Matters            
Current borrowing capacity on credit facility         1,250,000,000  
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders (up to)         1,650,000,000  
APS | Revolving Credit Facility | Revolving Credit Facility Maturing April 2028, Facility One | Subsequent Event            
Long-Term Debt and Liquidity Matters            
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders (up to)         400,000,000  
APS | Revolving Credit Facility | Revolving Credit Facility Maturing April 2028, Facility Two | Subsequent Event            
Long-Term Debt and Liquidity Matters            
Current borrowing capacity on credit facility         500,000,000  
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders (up to)         $ 400,000,000  
APS | Revolving Credit Facility | Revolving Credit Facility Maturing in 2022 and 2023            
Long-Term Debt and Liquidity Matters            
Long-term line of credit     0      
APS | Revolving Credit Facility | Revolving Credit Facility Maturing in 2022 and 2023 | Subsequent Event            
Long-Term Debt and Liquidity Matters            
Number of line of credit facilities | creditFacility         2  
APS | Letter of Credit            
Long-Term Debt and Liquidity Matters            
Outstanding letters of credit     10,000,000      
APS | Letter of Credit | Revolving Credit Facility Maturing April 2028            
Long-Term Debt and Liquidity Matters            
Outstanding letters of credit     0      
APS | Commercial Paper            
Long-Term Debt and Liquidity Matters            
Maximum commercial paper support available under credit facility     750,000,000      
APS | Commercial Paper | Subsequent Event            
Long-Term Debt and Liquidity Matters            
Maximum commercial paper support available under credit facility         $ 1,000,000,000  
APS | Commercial Paper | Revolving Credit Facility Maturing April 2028            
Long-Term Debt and Liquidity Matters            
Commercial paper     463,000,000      
BCE            
Long-Term Debt and Liquidity Matters            
Solar and battery storage capacity (in MW) | MW   31        
BCE | Term Loan | Non-Recourse Construction Term Loan Facility            
Long-Term Debt and Liquidity Matters            
Long-term line of credit     33,000,000      
Debt instrument, face amount   $ 42,000,000        
BCE | Letter of Credit            
Long-Term Debt and Liquidity Matters            
Debt instrument, face amount   5,000,000        
BCE | Letter of Credit | Revolving Credit Facility Maturing April 2028            
Long-Term Debt and Liquidity Matters            
Outstanding letters of credit     2,500,000      
BCE | Bridge Loan | Equity Bridge Loan Facility            
Long-Term Debt and Liquidity Matters            
Debt instrument, face amount   33,000,000        
Issuance of long-term debt     $ 28,000,000      
BCE | Pinnacle West | Bridge Loan            
Long-Term Debt and Liquidity Matters            
Debt guarantee   $ 42,000,000        
v3.23.1
Long-Term Debt and Liquidity Matters - Estimated Fair Value of Long-Term Debt (Details) - USD ($)
$ in Thousands
Mar. 31, 2023
Dec. 31, 2022
Estimated fair value of long-term debt, including current maturities    
Carrying Amount $ 7,977,375 $ 7,791,971
Fair Value 7,043,443 6,585,701
APS    
Estimated fair value of long-term debt, including current maturities    
Carrying Amount 6,794,124 6,793,529
Fair Value 5,898,167 5,629,491
BCE    
Estimated fair value of long-term debt, including current maturities    
Carrying Amount 60,150 50,550
Fair Value 60,821 50,685
Pinnacle West    
Estimated fair value of long-term debt, including current maturities    
Carrying Amount 1,123,101 947,892
Fair Value $ 1,084,455 $ 905,525
v3.23.1
Regulatory Matters - Retail Rate Case Filing (Details)
 12 Months Ended
Mar. 06, 2023
USD ($)
Oct. 28, 2022
USD ($)
$ / kWh
Sep. 23, 2022
MW
Jul. 12, 2022
USD ($)
Jun. 30, 2022
USD ($)
Mar. 31, 2022
MW
Dec. 17, 2021
USD ($)
Oct. 27, 2021
USD ($)
Aug. 02, 2021
USD ($)
Jun. 07, 2021
USD ($)
Jul. 01, 2020
USD ($)
Aug. 13, 2018
USD ($)
Mar. 27, 2017
USD ($)
Dec. 31, 2020
Jul. 01, 2022
USD ($)
Apr. 30, 2022
USD ($)
Dec. 09, 2021
USD ($)
Jul. 01, 2021
USD ($)
ACC | APS                                    
Public Utilities, General Disclosures [Line Items]                                    
Total revenue deficiency   $ 772,000,000                                
Proposed annual revenue increase                       $ (86,500,000)            
Regulatory matters, no of basis penalty point 0.0020                                  
Program term                           18 years        
Retail Rate Case Filing with Arizona Corporation Commission | ACC | APS                                    
Public Utilities, General Disclosures [Line Items]                                    
Approximate percentage of increase in average residential customer bill   13.60%                                
Rate matter, cost base rate         $ 10,500,000,000                          
Base fuel rate (in dollars per kWh) | $ / kWh   0.038321                                
Revenue 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%                  
Net retail base rate, increase                         $ 94,600,000          
Non-fuel and non-depreciation base rate, increase                         87,200,000          
Fuel-related base rate decrease                         53,600,000          
Base rate increase, changes in depreciation schedules                         $ 61,000,000          
Commercial customers, market pricing, threshold | MW     140     280                        
RES 2018 | ACC | APS                                    
Public Utilities, General Disclosures [Line Items]                                    
Amount of proposed budget                     $ 84,700,000       $ 86,200,000   $ 100,500,000 $ 93,100,000
Revenue requirements                     $ 4,500,000              
Authorized amount to be collected                   $ 68,300,000                
Coal Community Transition Plan | ACC | Navajo Nation, Electrification Projects                                    
Public Utilities, General Disclosures [Line Items]                                    
Amount funded by shareholders                               $ 1,000,000    
Coal Community Transition Plan | ACC | Navajo Nation, Hopi Tribe                                    
Public Utilities, General Disclosures [Line Items]                                    
Amount recoverable through rates related to the CCT                               1,000,000    
Coal Community Transition Plan | ACC | Navajo Nation                                    
Public Utilities, General Disclosures [Line Items]                                    
Amount recoverable through rates related to the CCT                               6,660,000    
Coal Community Transition Plan | ACC | Navajo Nation, Hopi Reservation                                    
Public Utilities, General Disclosures [Line Items]                                    
Amount recoverable through rates related to the CCT                               1,250,000    
Coal Community Transition Plan | ACC | Navajo County Communities                                    
Public Utilities, General Disclosures [Line Items]                                    
Amount recoverable through rates related to the CCT                               500,000    
Coal Community Transition Plan | ACC | Navajo County Communities, CCT and Economic Development                                    
Public Utilities, General Disclosures [Line Items]                                    
Amount funded by shareholders                               1,100,000    
Coal Community Transition Plan | ACC | Navajo Nation, Hopi Tribe for CCT and Economic Development                                    
Public Utilities, General Disclosures [Line Items]                                    
Amount funded by shareholders                               $ 1,250,000    
Coal Community Transition Plan | Retail Rate Case Filing with Arizona Corporation Commission | ACC | APS | Navajo Nation, Economic Development Organization                                    
Public Utilities, General Disclosures [Line Items]                                    
Disallowance of annual amortization percentage                 15.00%                  
Amount funded by customers                 $ 50,000,000                  
Amount funded by customers, term                 10 years                  
Coal Community Transition Plan | Retail Rate Case Filing with Arizona Corporation Commission | ACC | APS | Navajo County Communities                                    
Public Utilities, General Disclosures [Line Items]                                    
Amount funded by shareholders               $ 500,000 $ 5,000,000                  
Amount funded by shareholders, term               60 days 5 years                  
Coal Community Transition Plan | Retail Rate Case Filing with Arizona Corporation Commission | ACC | APS | Navajo Nation, Hopi Tribe                                    
Public Utilities, General Disclosures [Line Items]                                    
Amount funded by shareholders               $ 1,000,000 $ 1,675,000                  
Amount funded by shareholders, term               60 days                    
Amount not recoverable               $ 215,500,000                    
Coal Community Transition Plan | Retail Rate Case Filing with Arizona Corporation Commission | ACC | APS | Navajo Nation                                    
Public Utilities, General Disclosures [Line Items]                                    
Amount funded by shareholders               $ 10,000,000                    
Amount funded by shareholders, term               3 years                    
Coal Community Transition Plan | Retail Rate Case Filing with Arizona Corporation Commission | ACC | APS | Navajo Nation, Hopi Reservation                                    
Public Utilities, General Disclosures [Line Items]                                    
Amount funded by shareholders               $ 1,250,000                    
Coal Community Transition Plan | Retail Rate Case Filing with Arizona Corporation Commission | ACC | APS | Navajo Nation Reservation                                    
Public Utilities, General Disclosures [Line Items]                                    
Revenue decrease               4,800,000                    
Amount funded by shareholders               $ 1,250,000                    
Disallowance of plant investments $ 215,500,000           $ 215,500,000                      
Solar Communities | RES 2018 | ACC | APS                                    
Public Utilities, General Disclosures [Line Items]                                    
Program term       3 years             3 years              
Minimum | ACC | APS                                    
Public Utilities, General Disclosures [Line Items]                                    
Annual increase in retail base rates   $ 460,000,000                                
Minimum | RES 2018 | ACC | APS                                    
Public Utilities, General Disclosures [Line Items]                                    
Authorized spending       $ 20,000,000                            
Minimum | Solar Communities | RES 2018 | ACC | APS                                    
Public Utilities, General Disclosures [Line Items]                                    
Required annual capital investment                     $ 10,000,000              
Maximum | RES 2018 | ACC | APS                                    
Public Utilities, General Disclosures [Line Items]                                    
Authorized spending       $ 30,000,000                            
Maximum | Solar Communities | RES 2018 | ACC | APS                                    
Public Utilities, General Disclosures [Line Items]                                    
Required annual capital investment                     $ 15,000,000              
v3.23.1
Regulatory Matters - Capital Structure and Costs of Capital (Details) - APS
Oct. 28, 2022
Cost of Capital  
Public Utilities, Requested Long-Term Debt Cost Of Capital, Percentage 3.85%
Common stock equity 10.25%
Weighted-average cost of capital 7.17%
Retail Rate Case Filing with Arizona Corporation Commission  
Capital Structure  
Common stock equity 51.93%
Retail Rate Case Filing with Arizona Corporation Commission | ACC  
Capital Structure  
Long-term debt 48.07%
v3.23.1
Regulatory Matters - Cost Recovery Mechanisms (Details)
 1 Months Ended 3 Months Ended 12 Months Ended
Mar. 10, 2023
USD ($)
Feb. 23, 2023
USD ($)
$ / kWh
Feb. 01, 2023
USD ($)
$ / kWh
Sep. 23, 2022
MW
Jul. 12, 2022
USD ($)
$ / kWh
Jun. 01, 2022
USD ($)
Mar. 31, 2022
USD ($)
MW
Feb. 15, 2022
USD ($)
Feb. 01, 2022
USD ($)
$ / kWh
$ / KWH_Kilowatt_hour
Nov. 01, 2021
$ / kWh
Oct. 01, 2021
$ / kWh
Jun. 07, 2021
USD ($)
Jun. 01, 2021
USD ($)
Apr. 01, 2021
$ / kWh
Feb. 15, 2021
USD ($)
Feb. 01, 2021
USD ($)
$ / kWh
Aug. 20, 2020
USD ($)
customer
Jul. 01, 2020
USD ($)
May 01, 2020
$ / kWh
Feb. 01, 2020
$ / kWh
Nov. 14, 2019
USD ($)
customer
Oct. 31, 2019
$ / KWH_Kilowatt_hour
Oct. 29, 2019
USD ($)
May 01, 2019
$ / kWh
Apr. 10, 2019
Aug. 13, 2018
USD ($)
Sep. 01, 2017
Mar. 31, 2021
Mar. 31, 2023
USD ($)
Mar. 31, 2022
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 ($)
Dec. 31, 2021
USD ($)
Dec. 17, 2021
USD ($)
Dec. 09, 2021
USD ($)
Oct. 28, 2021
agreement
Jul. 01, 2021
USD ($)
May 15, 2020
USD ($)
May 05, 2020
USD ($)
Dec. 31, 2019
USD ($)
Mar. 15, 2019
agreement
Change in regulatory asset                                                                                          
Deferred fuel and purchased power costs — current period                                                         $ 90,305,000 $ 6,110,000                              
Amounts charged to customers                                                         (80,904,000) (39,442,000)                              
Rate plan comparison tool, number of customers | customer                                 3,800       13,000                                                
Rate plan comparison tool, inconvenience payment                                 $ 25       $ 25                                                
APS                                                                                          
Settlement Agreement                                                                                          
Demand side management funds                                                                                     $ 36,000,000    
Customer credits                                                                         $ 43,000,000                
Customer credits, additional funds                                                                         $ 7,000,000                
Change in regulatory asset                                                                                          
Deferred fuel and purchased power costs — current period                                                         90,305,000 6,110,000                              
Amounts charged to customers                                                         $ (80,904,000) (39,442,000)                              
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%                                  
Lost Fixed Cost Recovery Mechanisms | APS                                                                                          
Change in regulatory asset                                                                                          
Fixed cost recoverable per power lost (in dollars per kWh)                                                               0.025 2.56                        
Percentage of retail revenues                                                         1.00%                                
Amount of adjustment representing prorated sales losses pending approval               $ 59,100,000             $ 38,500,000                                                            
Increase (decrease) in amount of adjustment representing prorated sales losses               $ 32,500,000             $ 11,800,000                                                            
ACC | APS                                                                                          
Settlement Agreement                                                                                          
Program term                                                             18 years                            
Change in regulatory asset                                                                                          
Amount requested to be returned in form of tax savings to customers                                                   $ 86,500,000                                      
Deferred taxes amortization, period                                                 28 years 6 months                                        
Public Utilities, one-time bill credit                                             $ 64,000,000                                            
Public Utilities, one-time bill credit, additional benefit                                             $ 39,500,000                                            
Number of programs | program                                                             2                            
Solar capacity (in MW) | MW                                                             80                            
ACC | RES | APS                                                                                          
Settlement Agreement                                                                                          
Plan term                                                         5 years                                
ACC | RES 2018 | APS                                                                                          
Settlement Agreement                                                                                          
Amount of proposed budget                                   $ 84,700,000                                 $ 86,200,000       $ 100,500,000   $ 93,100,000        
Revenue requirements                                   $ 4,500,000                                                      
Authorized amount to be collected                       $ 68,300,000                                                                  
ACC | RES 2018 | APS | Solar Communities                                                                                          
Settlement Agreement                                                                                          
Program term         3 years                         3 years                                                      
ACC | Retail Rate Case Filing with Arizona Corporation Commission | APS                                                                                          
Settlement Agreement                                                                                          
Commercial customers, market pricing, threshold | MW       140     280                                                                            
ACC | Demand Side Management Adjustor Charge 2020 | APS                                                                                          
Settlement Agreement                                                                                          
Amount of proposed budget                                                                                   $ 51,900,000   $ 51,900,000  
ACC | Net Metering | APS                                                                                          
Change in regulatory asset                                                                                          
Cost of service, resource comparison proxy method, maximum annual percentage decrease         10.00%                                           10.00%                                    
Cost of service for interconnected DG system customers, grandfathered period                                                     20 years                                    
Cost of service for new customers, guaranteed export price period                                                     10 years                                    
Second-year export energy price (in dollars per kWh) | $ / kWh         0.0846           0.094               0.094         0.105                                          
ACC | Demand Side Management Adjustor Charge 2021 | APS                                                                                          
Settlement Agreement                                                                                          
Amount of proposed budget                                                             $ 63,700,000                            
ACC | Demand Side Management Adjustor Charge 2022 | APS                                                                                          
Settlement Agreement                                                                                          
Amount of proposed budget                                                                           $ 78,400,000              
Increase in proposed budget                                                                           $ 14,000,000              
ACC | Power Supply Adjustor (PSA) | APS                                                                                          
Change in regulatory asset                                                                                          
Beginning balance                                                         $ 460,561,000 388,148,000                              
Deferred fuel and purchased power costs — current period                                                         90,305,000 6,110,000                              
Amounts charged to customers                                                         (80,904,000) (39,442,000)                              
Ending balance             $ 354,816,000                                           $ 469,962,000 $ 354,816,000                              
PSA rate (in dollars per kWh) | $ / kWh   0.019074 0.006           0.007544 0.003544       0.001544   0.003544                                                          
PSA rate for prior year (in dollars per kWh) | $ / kWh   (0.005527)             0.004842 (0.004444)       (0.004444)   0.003434                                                          
Forward component of increase in PSA (in dollars per kWh) | $ / kWh   0.013071             0.012386 0.007988       0.005988   0.000110                                                          
Fuel and purchased power costs above annual cap                               $ 215,900,000                                                          
Transition Component Of PSA Rate1 | $ / kWh   0.011530                                                                                      
Regulatory Clause, Deferred Fuel And Purchased Power Costs, Balancing Account, Depletion Period   24 months                                                                                      
Regulatory Clause, Deferred Fuel And Purchased Power Costs, Balancing Account, Reporting Threshold Amount   $ 500,000                                                                                      
ACC | Demand Side Management Adjustor Charge 2023 | APS                                                                                          
Settlement Agreement                                                                                          
Amount of proposed budget                                                                   $ 88,000,000                      
FERC | Environmental Improvement Surcharge | APS                                                                                          
Change in regulatory asset                                                                                          
Rate matter, environmental surcharge cap rate (in dollars per kWh) | $ / KWH_Kilowatt_hour                 0.0005                                                                        
Rate matter, environmental surcharge cap rate amount $ 4,000,000                                                                                        
Increase (decrease) in annual wholesale transmission rates (10,700,000)   $ 14,700,000                                                                                    
Rate matters, increase (decrease) in cost recovery, excess of annual amount $ (7,500,000)   $ 3,300,000                                                                                    
FERC | Open Access Transmission Tariff | APS                                                                                          
Change in regulatory asset                                                                                          
Increase (decrease) in annual wholesale transmission rates           $ 33,000,000             $ 4,000,000                                                                
Decrease in wholesale customer rates           6,400,000             3,200,000                                                                
Increase (decrease) in retail customer rates           (26,600,000)             7,200,000                                                                
Increase (decrease) in retail revenue requirements           $ (2,400,000)             $ (28,400,000)                                                                
Cost Recovery Mechanisms | ACC | Power Supply Adjustor (PSA) | APS                                                                                          
Settlement Agreement                                                                                          
Maximum increase decrease in PSA rate | $ / kWh                                       0.004                                                  
Change in regulatory asset                                                                                          
Historical component of increase in PSA (in dollars per kWh) | $ / kWh                 0.004             0.004                                                          
Cost recovery, number of agreements | agreement                                                                               3         2
Minimum | ACC | RES 2018 | APS                                                                                          
Settlement Agreement                                                                                          
Authorized spending         $ 20,000,000                                                                                
Minimum | ACC | RES 2018 | APS | Solar Communities                                                                                          
Settlement Agreement                                                                                          
Required annual capital investment                                   $ 10,000,000                                                      
Minimum | FERC | Environmental Improvement Surcharge | APS                                                                                          
Change in regulatory asset                                                                                          
Rate matter, environmental surcharge cap rate amount                 $ 13,000,000                                                                        
Maximum | Retail Rate Case Filing with Arizona Corporation Commission | APS                                                                                          
Change in regulatory asset                                                                                          
Fixed cost recoverable per power lost (in dollars per kWh) | $ / KWH_Kilowatt_hour                                           2.68                                              
Maximum | ACC | RES 2018 | APS                                                                                          
Settlement Agreement                                                                                          
Authorized spending         $ 30,000,000                                                                                
Maximum | ACC | RES 2018 | APS | Solar Communities                                                                                          
Settlement Agreement                                                                                          
Required annual capital investment                                   $ 15,000,000                                                      
Maximum | FERC | Environmental Improvement Surcharge | APS                                                                                          
Change in regulatory asset                                                                                          
Rate matter, environmental surcharge cap rate amount                 $ 15,000,000                                                                        
Damage from Fire, Explosion or Other Hazard | APS                                                                                          
Change in regulatory asset                                                                                          
Past due balance threshold qualifying for payment extension                                                                       $ 75                  
v3.23.1
Regulatory Matters - Four Corners, Cholla and Navajo Plant (Details) - APS - USD ($)
$ in Millions
 1 Months Ended 3 Months Ended
Nov. 02, 2021
Sep. 30, 2018
Apr. 30, 2018
Mar. 31, 2023
Aug. 02, 2021
Navajo Nation, Economic Development Organization | Coal Community Transition Plan | Retail Rate Case Filing with Arizona Corporation Commission | ACC          
Business Acquisition [Line Items]          
Disallowance of annual amortization percentage         15.00%
SCE | Four Corners Units 4 and 5          
Business Acquisition [Line Items]          
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  
Retired power plant costs          
Business Acquisition [Line Items]          
Net book value       36.1  
Navajo Plant          
Business Acquisition [Line Items]          
Net book value       50.2  
Navajo Plant, Coal Reclamation Regulatory Asset          
Business Acquisition [Line Items]          
Net book value       $ 13.1  
v3.23.1
Regulatory Matters - Schedule of Regulatory Assets (Details) - USD ($)
$ in Thousands
Mar. 31, 2023
Dec. 31, 2022
Detail of regulatory assets    
Regulatory asset including deferred fuel and purchased power regulatory asset current $ 1,859,465 $ 1,822,100
Less: current regulatory assets 600,802 538,879
Total non-current regulatory assets 1,258,663 1,283,221
Pension    
Detail of regulatory assets    
Regulatory asset including deferred fuel and purchased power regulatory asset current 628,727 637,656
Deferred fuel and purchased power    
Detail of regulatory assets    
Regulatory asset including deferred fuel and purchased power regulatory asset current 469,962 460,561
Income taxes — allowance for funds used during construction (“AFUDC”) equity    
Detail of regulatory assets    
Regulatory asset including deferred fuel and purchased power regulatory asset current 179,818 179,631
Ocotillo Deferral    
Detail of regulatory assets    
Regulatory asset including deferred fuel and purchased power regulatory asset current 135,766 138,143
SCR Deferral    
Detail of regulatory assets    
Regulatory asset including deferred fuel and purchased power regulatory asset current 95,588 97,624
Retired power plant costs    
Detail of regulatory assets    
Regulatory asset including deferred fuel and purchased power regulatory asset current 94,903 98,692
Deferred fuel and purchased power — mark-to-market (Note 7)    
Detail of regulatory assets    
Regulatory asset including deferred fuel and purchased power regulatory asset current 61,858 0
Deferred property taxes    
Detail of regulatory assets    
Regulatory asset including deferred fuel and purchased power regulatory asset current 38,915 41,057
Deferred compensation    
Detail of regulatory assets    
Regulatory asset including deferred fuel and purchased power regulatory asset current 34,492 33,660
Income taxes — investment tax credit basis adjustment    
Detail of regulatory assets    
Regulatory asset including deferred fuel and purchased power regulatory asset current 24,095 23,977
Palo Verde VIEs (Note 6)    
Detail of regulatory assets    
Regulatory asset including deferred fuel and purchased power regulatory asset current 20,893 20,933
Active Union Medical Trust    
Detail of regulatory assets    
Regulatory asset including deferred fuel and purchased power regulatory asset current 15,010 18,226
Four Corners cost deferral    
Detail of regulatory assets    
Regulatory asset including deferred fuel and purchased power regulatory asset current 13,979 15,999
Navajo coal reclamation    
Detail of regulatory assets    
Regulatory asset including deferred fuel and purchased power regulatory asset current 13,117 13,862
Loss on reacquired debt    
Detail of regulatory assets    
Regulatory asset including deferred fuel and purchased power regulatory asset current 9,238 9,468
Mead-Phoenix transmission line contributions in aid of construction (“CIAC”)    
Detail of regulatory assets    
Regulatory asset including deferred fuel and purchased power regulatory asset current 8,965 9,048
Tax expense adjustor mechanism (b) (e)    
Detail of regulatory assets    
Regulatory asset including deferred fuel and purchased power regulatory asset current 5,681 5,845
Lost fixed cost recovery    
Detail of regulatory assets    
Regulatory asset including deferred fuel and purchased power regulatory asset current 0 9,547
Other    
Detail of regulatory assets    
Regulatory asset including deferred fuel and purchased power regulatory asset current $ 8,458 $ 8,171
v3.23.1
Regulatory Matters - Schedule of Regulatory Liabilities (Details) - USD ($)
$ in Thousands
Mar. 31, 2023
Dec. 31, 2022
Detail of regulatory liabilities    
Regulatory liability, including deferred fuel and purchased power regulatory liability current $ 2,262,539 $ 2,333,351
Less: current regulatory liabilities 202,266 271,575
Total non-current regulatory liabilities 2,060,273 2,061,776
Asset retirement obligations    
Detail of regulatory liabilities    
Regulatory liability, including deferred fuel and purchased power regulatory liability current 396,107 354,002
Other postretirement benefits    
Detail of regulatory liabilities    
Regulatory liability, including deferred fuel and purchased power regulatory liability current 258,955 270,604
Removal costs    
Detail of regulatory liabilities    
Regulatory liability, including deferred fuel and purchased power regulatory liability current 106,102 106,889
Income taxes — change in rates    
Detail of regulatory liabilities    
Regulatory liability, including deferred fuel and purchased power regulatory liability current 64,739 64,806
Four Corners coal reclamation    
Detail of regulatory liabilities    
Regulatory liability, including deferred fuel and purchased power regulatory liability current 53,348 52,592
Income taxes — deferred investment tax credit    
Detail of regulatory liabilities    
Regulatory liability, including deferred fuel and purchased power regulatory liability current 49,031 48,035
Spent nuclear fuel    
Detail of regulatory liabilities    
Regulatory liability, including deferred fuel and purchased power regulatory liability current 37,313 39,217
Renewable energy standard (b)    
Detail of regulatory liabilities    
Regulatory liability, including deferred fuel and purchased power regulatory liability current 30,188 35,720
Sundance maintenance    
Detail of regulatory liabilities    
Regulatory liability, including deferred fuel and purchased power regulatory liability current 17,667 16,893
Property tax deferral (e)    
Detail of regulatory liabilities    
Regulatory liability, including deferred fuel and purchased power regulatory liability current 14,353 15,521
Demand side management (b)    
Detail of regulatory liabilities    
Regulatory liability, including deferred fuel and purchased power regulatory liability current 14,207 8,461
FERC transmission true up (b)    
Detail of regulatory liabilities    
Regulatory liability, including deferred fuel and purchased power regulatory liability current 12,597 22,895
Tax expense adjustor mechanism (b) (e)    
Detail of regulatory liabilities    
Regulatory liability, including deferred fuel and purchased power regulatory liability current 4,835 4,835
Deferred fuel and purchased power — mark-to-market (Note 7)    
Detail of regulatory liabilities    
Regulatory liability, including deferred fuel and purchased power regulatory liability current 3,396 96,367
Other    
Detail of regulatory liabilities    
Regulatory liability, including deferred fuel and purchased power regulatory liability current 7,415 3,092
ACC | Excess deferred income taxes - Tax Act    
Detail of regulatory liabilities    
Regulatory liability, including deferred fuel and purchased power regulatory liability current 970,578 971,545
FERC | Excess deferred income taxes - Tax Act    
Detail of regulatory liabilities    
Regulatory liability, including deferred fuel and purchased power regulatory liability current $ 221,708 $ 221,877
v3.23.1
Retirement Plans and Other Postretirement Benefits - Narrative (Details)
$ in Millions
 3 Months Ended
Mar. 31, 2023
USD ($)
Pension Benefits  
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]  
Minimum employer contributions for the next three years $ 0
v3.23.1
Retirement Plans and Other Postretirement Benefits - Schedule of Net Benefit Cost (Details) - USD ($)
$ in Thousands
 3 Months Ended
Mar. 31, 2023
Mar. 31, 2022
Amortization of:    
Portion of benefit charged to expense $ (9,865) $ (23,809)
Pension Benefits    
Retirement Plans and Other Benefits    
Service cost — benefits earned during the period 10,157 14,331
Interest cost on benefit obligation 38,362 27,023
Expected return on plan assets (45,561) (46,394)
Amortization of:    
Prior service credit 0 0
Net actuarial loss (gain) 9,713 4,768
Net periodic cost/(benefit) 12,671 (272)
Portion of benefit charged to expense 7,227 (3,290)
Other Benefits    
Retirement Plans and Other Benefits    
Service cost — benefits earned during the period 2,120 4,218
Interest cost on benefit obligation 5,673 4,463
Expected return on plan assets (10,872) (11,510)
Amortization of:    
Prior service credit (9,447) (9,447)
Net actuarial loss (gain) (2,303) (2,982)
Net periodic cost/(benefit) (14,829) (15,258)
Portion of benefit charged to expense $ (10,737) $ (10,895)
v3.23.1
Palo Verde Sale Leaseback Variable Interest Entities - Narrative (Details)
 3 Months Ended
Mar. 31, 2023
USD ($)
lease
Mar. 31, 2022
USD ($)
Dec. 31, 1986
trust
Palo Verde Sale Leaseback Variable Interest Entities      
Net income attributable to noncontrolling interest $ 4,306,000 $ 4,306,000  
APS      
Palo Verde Sale Leaseback Variable Interest Entities      
Number of VIE lessor trusts | trust     3
Net income attributable to noncontrolling interest 4,306,000 $ 4,306,000  
Palo Verde VIE | APS      
Palo Verde Sale Leaseback Variable Interest Entities      
Initial loss exposure to the VIE's noncontrolling equity participants during lease extension period 324,000,000    
Palo Verde VIE | APS | Maximum      
Palo Verde Sale Leaseback Variable Interest Entities      
Maximum loss exposure to the VIE's noncontrolling equity participants during lease extension period (up to) $ 501,000,000    
Palo Verde VIE | APS | Period Through 2033      
Palo Verde Sale Leaseback Variable Interest Entities      
Number of leases under which assets are retained | lease 3    
Annual lease payments $ 21,000,000    
Palo Verde VIE | APS | Period Through 2033 | Maximum      
Palo Verde Sale Leaseback Variable Interest Entities      
Lease period (up to) 2 years    
v3.23.1
Derivative Accounting - Narrative (Details)
$ in Thousands
 3 Months Ended
Mar. 31, 2023
USD ($)
Mar. 31, 2023
USD ($)
Commodity Contracts    
Derivative Accounting    
Aggregate fair value of derivative instruments in a net liability position $ 108,202 $ 108,202
Additional collateral to counterparties for energy related non-derivative instrument contracts 76,000 76,000
Interest Rate Contract    
Derivative Accounting    
Derivative, Notional Amount 32,000 32,000
Derivative, Loss on Derivative   1,700
Gain (Loss) from Price Risk Management Activity   100
Loss on Derivative Instruments, Pretax   1,600
Amounts reclassified from accumulated other comprehensive income in next twelve months   100
Risk Management Assets | Credit Concentration Risk    
Derivative Accounting    
Aggregate fair value of derivative instruments in a net liability position $ 33,000 $ 33,000
Risk Management Assets | Credit Concentration Risk | One Counterparties    
Derivative Accounting    
Concentration risk 20.00%  
APS    
Derivative Accounting    
Percentage of unrealized gains and losses on certain derivatives deferred for future rate treatment 100.00% 100.00%
v3.23.1
Derivative Accounting - Schedule of Gross Notional Amounts Outstanding (Details) - Commodity Contracts
GWh in Thousands, Bcf in Thousands
 3 Months Ended 12 Months Ended
Mar. 31, 2023
GWh
Bcf
Dec. 31, 2022
GWh
Bcf
Outstanding gross notional amount of derivatives    
Power | GWh 1,664 1,197
Gas | Bcf 194 149
v3.23.1
Derivative Accounting - Gains and Losses from Derivative Instruments (Details) - USD ($)
$ in Thousands
 3 Months Ended
Mar. 31, 2023
Mar. 31, 2022
Not Designated as Hedging Instruments | Commodity Contracts | Fuel and Purchased Power    
Gains and losses from derivative instruments    
Net Gain (Loss) Recognized in Income $ (188,930) $ 223,742
v3.23.1
Derivative Accounting - Derivative Instruments in the Balance Sheets (Details) - USD ($)
Mar. 31, 2023
Dec. 31, 2022
Assets    
Gross recognized derivatives $ 33,177,000 $ 132,229,000
Liabilities    
Amount Reported on Balance Sheets (99,257,000) (42,446,000)
Commodity Contracts    
Assets    
Gross recognized derivatives 49,740,000 153,261,000
Amounts offset (16,714,000) (21,191,000)
Net Recognized Derivatives 33,026,000 132,070,000
Other 17,000 28,000
Amount Reported on Balance Sheets 33,043,000 132,098,000
Liabilities    
Gross recognized derivatives (108,202,000) (56,893,000)
Amounts offset 16,714,000 21,191,000
Net Recognized Derivatives (91,488,000) (35,702,000)
Other (6,071,000) (5,835,000)
Amount Reported on Balance Sheets (97,559,000) (41,537,000)
Assets and Liabilities    
Gross recognized derivatives (58,462,000) 96,368,000
Amounts offset 0 0
Net Recognized Derivatives (58,462,000) 96,368,000
Other (6,054,000) (5,807,000)
Amount Reported on Balance Sheets (64,516,000) 90,561,000
Cash collateral received subject to offsetting 0  
Cash collateral received from counterparties 6,071,000 5,835,000
Commodity Contracts | Current assets    
Assets    
Gross recognized derivatives 22,994,000 103,484,000
Amounts offset (7,050,000) (15,808,000)
Net Recognized Derivatives 15,944,000 87,676,000
Other 17,000 28,000
Amount Reported on Balance Sheets 15,961,000 87,704,000
Commodity Contracts | Investments and other assets    
Assets    
Gross recognized derivatives 26,746,000 49,777,000
Amounts offset (9,664,000) (5,383,000)
Net Recognized Derivatives 17,082,000 44,394,000
Other 0 0
Amount Reported on Balance Sheets 17,082,000 44,394,000
Commodity Contracts | Current liabilities    
Liabilities    
Gross recognized derivatives (84,853,000) (47,670,000)
Amounts offset 7,050,000 15,808,000
Net Recognized Derivatives (77,803,000) (31,862,000)
Other (6,071,000) (5,835,000)
Amount Reported on Balance Sheets (83,874,000) (37,697,000)
Assets and Liabilities    
Cash collateral received from counterparties 6,071,000 5,835,000
Commodity Contracts | Deferred credits and other    
Liabilities    
Gross recognized derivatives (23,349,000) (9,223,000)
Amounts offset 9,664,000 5,383,000
Net Recognized Derivatives (13,685,000) (3,840,000)
Other 0 0
Amount Reported on Balance Sheets (13,685,000) (3,840,000)
Assets and Liabilities    
Cash collateral received from counterparties $ 0 $ 0
v3.23.1
Derivative Accounting - Credit Risk and Credit Related Contingent Features (Details) - Commodity Contracts
$ in Thousands
Mar. 31, 2023
USD ($)
Credit Risk and Credit-Related Contingent Features  
Aggregate fair value of derivative instruments in a net liability position $ 108,202
Additional cash collateral in the event credit-risk-related contingent features were fully triggered (a) $ 73,886
v3.23.1
Commitments and Contingencies (Details)
$ in Millions
 3 Months Ended 12 Months Ended 120 Months Ended
Sep. 30, 2022
USD ($)
Nov. 02, 2021
USD ($)
Nov. 01, 2021
USD ($)
Jul. 03, 2018
USD ($)
Apr. 05, 2018
plaintiff
defendant
Dec. 16, 2016
plaintiff
Jul. 06, 2016
Aug. 06, 2013
defendant
Mar. 31, 2023
USD ($)
Trust
MW
Dec. 31, 2022
USD ($)
Jun. 30, 2021
USD ($)
claim
Apr. 18, 2023
USD ($)
Commitments and Contingencies                        
Increase in contractual obligations                 $ 1,900.0      
Production tax credit guarantees                 33.0      
Subsequent Event                        
Commitments and Contingencies                        
Non recourse construction financing agreement                       $ 140.0
Financing agreement of sponsor equity                       $ 40.0
Purchase Power Lease Contracts                        
Commitments and Contingencies                        
Increase in contractual obligations                 $ 1,600.0      
Kūpono Solar                        
Commitments and Contingencies                        
Project plant capacity (in MW's) | MW                 42      
Asset purchase agreement                 20 years      
APS                        
Commitments and Contingencies                        
Maximum insurance against public liability per occurrence for a nuclear incident (up to)                 $ 13,700.0      
Maximum available nuclear liability insurance (up to)                 450.0      
Remaining nuclear liability insurance through mandatory industry wide retrospective assessment program                 13,200.0      
Maximum retrospective premium assessment per reactor for each nuclear liability incident                 137.6      
Annual limit per incident with respect to maximum retrospective premium assessment                 $ 20.5      
Number of VIE lessor trusts | Trust                 3      
Maximum potential retrospective assessment per incident of APS                 $ 120.1      
Annual payment limitation with respect to maximum potential retrospective premium assessment                 17.9      
Amount of "all risk" (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde                 2,800.0      
Maximum amount that could be incurred under retrospective assessment of NEIL policies                 22.4      
Collateral assurance provided based on rating triggers                 $ 62.6      
Period to provide collateral assurance based on rating triggers                 20 days      
APS | Contaminated groundwater wells                        
Commitments and Contingencies                        
Costs related to investigation and study under Superfund site                 $ 3.0      
Number of defendants against whom Roosevelt Irrigation District (RID) filed lawsuit | defendant         28     24        
Number of plaintiffs | plaintiff           2            
Costs claimed                   $ 21.0    
APS | Contaminated groundwater wells | Settled Litigation                        
Commitments and Contingencies                        
Number of plaintiffs | plaintiff         2              
APS | Contaminated groundwater wells | Pending Litigation                        
Commitments and Contingencies                        
Settlement amount $ 20.7                      
APS | Letter of Credit                        
Commitments and Contingencies                        
Outstanding letters of credit                 10.0      
APS | Surety Bonds Expiring in 2025                        
Commitments and Contingencies                        
Surety bonds expiring, amount                 21.0      
APS | Coal Combustion Waste | Four Corners                        
Commitments and Contingencies                        
Site contingency increase in loss exposure not accrued, best estimate                 30.0      
APS | Coal Combustion Waste | Four Corners | Minimum                        
Commitments and Contingencies                        
Site contingency increase in loss exposure not accrued, best estimate                 10.0      
APS | Coal Combustion Waste | Four Corners | Maximum                        
Commitments and Contingencies                        
Site contingency increase in loss exposure not accrued, best estimate                 15.0      
APS | Coal Combustion Waste | Cholla                        
Commitments and Contingencies                        
Site contingency increase in loss exposure not accrued, best estimate                 16.0      
APS | Coal Combustion Waste | Cholla | Minimum                        
Commitments and Contingencies                        
Site contingency increase in loss exposure not accrued, best estimate                 30.0      
APS | Coal Combustion Waste | Cholla | Maximum                        
Commitments and Contingencies                        
Site contingency increase in loss exposure not accrued, best estimate                 35.0      
APS | Coal Combustion Waste | Navajo Plant                        
Commitments and Contingencies                        
Site contingency increase in loss exposure not accrued, best estimate                 1.0      
APS | SCE | Four Corners Units 4 and 5                        
Commitments and Contingencies                        
Disallowance of plant investments   $ 194.0                    
Cost deferrals   $ 215.5                    
Amount not recoverable                 $ 154.4      
4C Acquisition, LLC | Four Corners                        
Commitments and Contingencies                        
Percentage of share of cost of control             7.00%          
BCE | Clear Creek Wind Farm                        
Commitments and Contingencies                        
Equity method investments $ 17.1                 0.0    
Impairment of equity method investments                   $ 12.8    
NTEC | Four Corners                        
Commitments and Contingencies                        
Option to purchase ownership interest (as a percent)       7.00%     7.00%          
Proceeds from operating and maintenance cost reimbursement       $ 70.0                
Asset purchase agreement, option to purchase, ownership interest, percentage       7.00%                
Breach of Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste                        
Commitments and Contingencies                        
Amount awarded from other party     $ 14.3               $ 123.9  
Breach of Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste | APS                        
Commitments and Contingencies                        
Number of claims submitted | claim                     8  
Amount awarded from other party     $ 4.2               $ 36.0  
v3.23.1
Other Income and Other Expense (Details) - USD ($)
$ in Thousands
 3 Months Ended
Mar. 31, 2023
Mar. 31, 2022
Other income:    
Interest income $ 6,026 $ 1,642
Miscellaneous 51 62
Total other income 6,077 1,704
Other expense:    
Non-operating costs (2,640) (2,453)
Investment losses — net (1,061) (681)
Miscellaneous (430) (288)
Total other expense (4,131) (3,422)
APS    
Other income:    
Interest income 5,024 1,099
Miscellaneous 51 53
Total other income 5,075 1,152
Other expense:    
Non-operating costs (2,188) (1,561)
Miscellaneous (429) (288)
Total other expense $ (2,617) $ (1,849)
v3.23.1
Earnings Per Share (Details) - USD ($)
$ / shares in Units, shares in Thousands, $ in Thousands
 3 Months Ended
Mar. 31, 2023
Mar. 31, 2022
Earnings Per Share [Abstract]    
Net income (loss) attributable to common shareholders $ (3,297) $ 16,956
Weighted average common shares outstanding - basic (in shares) 113,358 113,102
Net effect of dilutive securities:    
Contingently issuable performance shares and restricted stock units (in shares) 239 193
Weighted average common shares outstanding — diluted (in shares) 113,597 113,295
Earnings per weighted-average common share outstanding    
Net income (loss) attributable to common shareholders - basic (in dollars per share) $ (0.03) $ 0.15
Net income (loss) attributable to common shareholders - diluted (in dollars per share) $ (0.03) $ 0.15
Antidilutive securities excluded from computation of EPS 239 0
v3.23.1
Fair Value Measurements - Assets and Liabilities Measured on a Recurring Basis (Details) - USD ($)
$ in Thousands
 3 Months Ended 12 Months Ended
Mar. 31, 2023
Dec. 31, 2022
ASSETS    
Cash equivalents $ 14  
Commodity contracts, assets 33,177 $ 132,229
Commodity contracts assets, other (16,697) (21,163)
Nuclear decommissioning trust: 1,125,617 1,073,410
Nuclear decommissioning trust, other 506,571 476,409
Other special use funds 352,877 347,231
Other special use funds, other 1,041 963
Total assets 1,511,685 1,552,870
Total assets, other 490,915 456,209
LIABILITIES    
Gross derivative liability, other 10,643 15,357
Interest rate swaps (99,257) (42,446)
Total liabilities (99,257) (42,446)
Total liabilities, other $ 10,643 $ 15,357
Derivative Liability Statement Of Financial Position Extensible Enumeration Not Disclosed Flag Subtotal risk management activities - derivative instruments Subtotal risk management activities - derivative instruments
Equity securities    
ASSETS    
Nuclear decommissioning trust: $ 8,530 $ 18,485
Nuclear decommissioning trust, other (1,135) 3,827
Other special use funds 28,683 67,937
Other special use funds, other 1,041 963
U.S. commingled equity funds    
ASSETS    
Nuclear decommissioning trust: 507,706 472,582
U.S. Treasury debt    
ASSETS    
Nuclear decommissioning trust: 231,003 211,923
Other special use funds 320,196 275,267
Corporate debt    
ASSETS    
Nuclear decommissioning trust: 149,541 149,226
Mortgage-backed securities    
ASSETS    
Nuclear decommissioning trust: 157,330 147,938
Municipal bonds    
ASSETS    
Nuclear decommissioning trust: 63,950 64,881
Other special use funds 3,998 4,027
Other fixed income    
ASSETS    
Nuclear decommissioning trust: 7,557 8,375
Commodity Option    
ASSETS    
Commodity contracts, assets 33,043 132,098
Commodity contracts assets, other (16,697) (21,163)
LIABILITIES    
Gross derivative liability, other 10,643 15,357
Interest rate swaps (97,559) (41,537)
Interest Rate Swap    
ASSETS    
Commodity contracts, assets 134 131
Commodity contracts assets, other 0 0
LIABILITIES    
Gross derivative liability, other 0 0
Interest rate swaps (1,698) (909)
Level 1    
ASSETS    
Cash equivalents 14  
Commodity contracts, assets 0 0
Nuclear decommissioning trust: 240,668 226,581
Other special use funds 347,838 342,241
Total assets 588,520 568,822
LIABILITIES    
Gross derivative liability 0 0
Total liabilities 0 0
Level 1 | Equity securities    
ASSETS    
Nuclear decommissioning trust: 9,665 14,658
Other special use funds 27,642 66,974
Level 1 | U.S. commingled equity funds    
ASSETS    
Nuclear decommissioning trust: 0 0
Level 1 | U.S. Treasury debt    
ASSETS    
Nuclear decommissioning trust: 231,003 211,923
Other special use funds 320,196 275,267
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 funds 0 0
Level 1 | Other fixed income    
ASSETS    
Nuclear decommissioning trust: 0 0
Level 1 | Commodity Option    
ASSETS    
Commodity contracts, assets 0 0
LIABILITIES    
Gross derivative liability 0 0
Level 1 | Interest Rate Swap    
ASSETS    
Commodity contracts, assets 0 0
LIABILITIES    
Gross derivative liability 0 0
Level 2    
ASSETS    
Cash equivalents 0  
Commodity contracts, assets 28,617 127,260
Nuclear decommissioning trust: 378,378 370,420
Other special use funds 3,998 4,027
Total assets 410,993 501,707
LIABILITIES    
Gross derivative liability (95,265) (26,783)
Total liabilities (95,265) (26,783)
Level 2 | Equity securities    
ASSETS    
Nuclear decommissioning trust: 0 0
Other special use funds 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 funds 0 0
Level 2 | Corporate debt    
ASSETS    
Nuclear decommissioning trust: 149,541 149,226
Level 2 | Mortgage-backed securities    
ASSETS    
Nuclear decommissioning trust: 157,330 147,938
Level 2 | Municipal bonds    
ASSETS    
Nuclear decommissioning trust: 63,950 64,881
Other special use funds 3,998 4,027
Level 2 | Other fixed income    
ASSETS    
Nuclear decommissioning trust: 7,557 8,375
Level 2 | Commodity Option    
ASSETS    
Commodity contracts, assets 28,483 127,129
LIABILITIES    
Gross derivative liability (93,567) (25,874)
Level 2 | Interest Rate Swap    
ASSETS    
Commodity contracts, assets 134 131
LIABILITIES    
Gross derivative liability (1,698) (909)
Level 3    
ASSETS    
Cash equivalents 0  
Commodity contracts, assets 21,257 26,132
Nuclear decommissioning trust: 0 0
Other special use funds 0 0
Total assets 21,257 26,132
LIABILITIES    
Gross derivative liability (14,635) (31,020)
Total liabilities (14,635) (31,020)
Level 3 | Equity securities    
ASSETS    
Nuclear decommissioning trust: 0 0
Other special use funds 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 funds 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 funds 0 0
Level 3 | Other fixed income    
ASSETS    
Nuclear decommissioning trust: 0 0
Level 3 | Commodity Option    
ASSETS    
Commodity contracts, assets 21,257 26,132
LIABILITIES    
Gross derivative liability (14,635) (31,020)
Level 3 | Interest Rate Swap    
ASSETS    
Commodity contracts, assets 0 0
LIABILITIES    
Gross derivative liability 0 0
Fair Value Measured at Net Asset Value Per Share | U.S. commingled equity funds    
ASSETS    
Nuclear decommissioning trust: $ 507,706 $ 472,582
v3.23.1
Fair Value Measurements - Significant Unobservable Inputs Used to Value Level 3 Instruments (Details 2)
$ in Thousands
 3 Months Ended 12 Months Ended
Mar. 31, 2023
USD ($)
$ / MWh
$ / MMBTU
Dec. 31, 2022
USD ($)
$ / MWh
$ / MMBTU
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments    
Assets $ 1,511,685 $ 1,552,870
Liabilities 99,257 42,446
Level 3    
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments    
Assets 21,257 26,132
Liabilities 14,635 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 21,257 26,132
Liabilities $ 14,635 $ 31,020
Level 3 | Forward Contracts | Valuation Technique, Discounted Cash Flow | 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 37.79
Natural gas forward price (in usd per MMBTu) | $ / MMBTU (0.02) (11.81)
Level 3 | Forward Contracts | Valuation Technique, Discounted Cash Flow | 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 306.34 310.69
Natural gas forward price (in usd per MMBTu) | $ / MMBTU 0.14 0.00
Level 3 | Forward Contracts | Valuation Technique, Discounted Cash Flow | 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 157.00 163.92
Natural gas forward price (in usd per MMBTu) | $ / MMBTU 0.02 (5.08)
Level 3 | Forward Contracts | Valuation Technique, Discounted Cash Flow | Electricity | Commodity Contracts    
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments    
Assets $ 21,084 $ 26,132
Liabilities 14,385 1,759
Level 3 | Forward Contracts | Valuation Technique, Discounted Cash Flow | Natural Gas | Commodity Contracts    
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments    
Assets 173 0
Liabilities $ 250 $ 29,261
v3.23.1
Fair Value Measurements - Fair Value For Our Risk Management Activities (Details) - Commodity Contracts - Level 3 - USD ($)
$ in Thousands
 3 Months Ended
Mar. 31, 2023
Mar. 31, 2022
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]    
Net derivative balance at beginning of period $ (4,888) $ (2,738)
Deferred as a regulatory asset or liability (30,427) 16,807
Settlements 41,937 (4,419)
Transfers into Level 3 from Level 2 0 0
Transfers from Level 3 into Level 2 0 0
Net derivative balance at end of period 6,622 9,650
Net unrealized gains included in earnings related to instruments still held at end of period $ 0 $ 0
v3.23.1
Investments in Nuclear Decommissioning Trusts and Other Special Use Funds - Narrative (Details)
$ in Millions
 12 Months Ended
Dec. 31, 2021
USD ($)
APS  
Schedule of Equity Method Investments [Line Items]  
Employee medical claims amount $ 15
v3.23.1
Investments in Nuclear Decommissioning Trusts and Other Special Use Funds (Details) - APS - USD ($)
$ in Thousands
 3 Months Ended 12 Months Ended
Mar. 31, 2023
Mar. 31, 2022
Dec. 31, 2022
Nuclear decommissioning trust fund assets      
Fair Value $ 1,478,494   $ 1,420,641
Total Unrealized Gains 374,520   337,994
Total Unrealized Losses (54,228)   (69,091)
Amortized cost 981,000   927,000
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds      
Realized gains 1,210 $ 1,023  
Realized losses (5,694) (7,235)  
Proceeds from the sale of securities 226,626 361,238  
Nuclear Decommissioning Trusts      
Nuclear decommissioning trust fund assets      
Fair Value 1,125,617   1,073,410
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds      
Realized gains 1,210 1,023  
Realized losses (5,694) (7,235)  
Proceeds from the sale of securities 136,185 319,693  
Other Special Use Funds      
Nuclear decommissioning trust fund assets      
Fair Value 352,877   347,231
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds      
Realized gains 0 0  
Realized losses 0 0  
Proceeds from the sale of securities 90,441 $ 41,545  
Equity securities      
Nuclear decommissioning trust fund assets      
Equity securities 545,013   554,214
Total Unrealized Gains 367,791   334,817
Total Unrealized Losses (39)   (267)
Equity securities | Nuclear Decommissioning Trusts      
Nuclear decommissioning trust fund assets      
Equity securities 517,371   487,240
Equity securities | Other Special Use Funds      
Nuclear decommissioning trust fund assets      
Equity securities 27,642   66,974
Available for sale-fixed income securities      
Nuclear decommissioning trust fund assets      
Fair Value 933,575   861,637
Total Unrealized Gains 6,728   3,177
Total Unrealized Losses (54,178)   (68,795)
Fair value of fixed income securities, summarized by contractual maturities      
Less than one year 143,097    
1 year – 5 years 321,766    
5 years – 10 years 182,543    
Greater than 10 years 286,169    
Total 933,575    
Available for sale-fixed income securities | Nuclear Decommissioning Trusts      
Nuclear decommissioning trust fund assets      
Fair Value 609,381   582,343
Fair value of fixed income securities, summarized by contractual maturities      
Less than one year 14,591    
1 year – 5 years 174,911    
5 years – 10 years 137,708    
Greater than 10 years 282,171    
Total 609,381    
Available for sale-fixed income securities | Other Special Use Funds      
Nuclear decommissioning trust fund assets      
Fair Value 324,194   279,294
Available for sale-fixed income securities | Coal Reclamation Escrow Account      
Fair value of fixed income securities, summarized by contractual maturities      
Less than one year 53,718    
1 year – 5 years 36,821    
5 years – 10 years 0    
Greater than 10 years 3,998    
Total 94,537    
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 74,788    
1 year – 5 years 110,034    
5 years – 10 years 44,835    
Greater than 10 years 0    
Total 229,657    
Other      
Nuclear decommissioning trust fund assets      
Fair Value (94)   4,790
Total Unrealized Gains 1   0
Total Unrealized Losses (11)   (29)
Other | Nuclear Decommissioning Trusts      
Nuclear decommissioning trust fund assets      
Fair Value (1,135)   3,827
Other | Other Special Use Funds      
Nuclear decommissioning trust fund assets      
Fair Value $ 1,041   $ 963
v3.23.1
Changes in Accumulated Other Comprehensive Loss (Details) - USD ($)
$ in Thousands
 3 Months Ended
Mar. 31, 2023
Mar. 31, 2022
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]    
Beginning balance $ 6,159,876 $ 6,021,460
OCI (loss) before reclassifications (616) 252
Amounts reclassified from accumulated other comprehensive loss 515 901
Ending balance 6,164,451 6,050,136
APS    
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]    
Beginning balance 7,052,955 6,750,473
Ending balance 7,218,379 6,929,796
Pension and Other Postretirement Benefits    
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]    
Beginning balance (32,332) (53,885)
OCI (loss) before reclassifications 0 0
Amounts reclassified from accumulated other comprehensive loss 515 901
Ending balance (31,817) (52,984)
Pension and Other Postretirement Benefits | APS    
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]    
Beginning balance (15,596) (34,880)
OCI (loss) before reclassifications 0 0
Amounts reclassified from accumulated other comprehensive loss 457 820
Ending balance (15,139) (34,060)
Derivative Instruments    
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]    
Beginning balance 897 (976)
OCI (loss) before reclassifications (616) 252
Amounts reclassified from accumulated other comprehensive loss 0 0
Ending balance 281 (724)
Accumulated Other Comprehensive Loss    
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]    
Beginning balance (31,435) (54,861)
Ending balance (31,536) (53,708)
Accumulated Other Comprehensive Loss | APS    
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]    
Beginning balance (15,596) (34,880)
Ending balance $ (15,139) $ (34,060)
v3.23.1
Leases - Narrative (Details)
$ in Millions
Mar. 31, 2023
USD ($)
lease
Jan. 31, 2023
agreement
Leases [Abstract]    
Number of lease agreements, lease and sell back | lease 3  
Number of purchase power operating lease agreements | agreement   2
Lease not yet commenced | $ $ 3,500  
v3.23.1
Leases - Lease Costs (Details) - USD ($)
$ in Thousands
 3 Months Ended
Mar. 31, 2023
Mar. 31, 2022
Operating Leased Assets [Line Items]    
Operating Lease Cost - Purchased Power Lease Contracts $ 4,600 $ 4,572
Variable lease, cost 16,721 18,695
Short-term lease cost 1,402 1,302
Purchased Power Lease Contracts    
Operating Leased Assets [Line Items]    
Operating Lease Cost - Purchased Power Lease Contracts 0 0
Land, Property and Equipment Leases    
Operating Leased Assets [Line Items]    
Operating Lease Cost - Purchased Power Lease Contracts 4,600 4,572
Total lease cost $ 22,723 $ 24,569
v3.23.1
Leases - Maturity of Operating Lease Liabilities (Details)
$ in Thousands
Mar. 31, 2023
USD ($)
Lessee, Lease, Description [Line Items]  
2023 (remaining nine months of 2023) $ 118,133
2024 117,413
2025 131,504
2026 143,114
2027 167,122
2028 168,862
Thereafter 848,164
Total lease commitments 1,694,312
Less imputed interest 388,598
Estimated lease and nonlease payments 1,305,714
Purchased Power Lease Contracts  
Lessee, Lease, Description [Line Items]  
2023 (remaining nine months of 2023) 106,152
2024 104,315
2025 121,082
2026 134,806
2027 160,727
2028 164,524
Thereafter 779,792
Total lease commitments 1,571,398
Less imputed interest 342,694
Estimated lease and nonlease payments 1,228,704
Land, Property and Equipment Leases  
Lessee, Lease, Description [Line Items]  
2023 (remaining nine months of 2023) 11,981
2024 13,098
2025 10,422
2026 8,308
2027 6,395
2028 4,338
Thereafter 68,372
Total lease commitments 122,914
Less imputed interest 45,904
Estimated lease and nonlease payments $ 77,010
v3.23.1
Leases - Other Additional Information Related to Operating Lease Liabilities (Details)
$ in Thousands
 3 Months Ended
Mar. 31, 2023
USD ($)
Mar. 31, 2022
USD ($)
Jan. 31, 2023
agreement
Dec. 31, 2022
Leases [Abstract]        
Cash paid for amounts included in the measurement of lease liabilities — operating cash flows: $ 3,851 $ 3,358    
Right-of-use operating lease assets obtained in exchange for operating lease liabilities $ 551,239 $ 4,889    
Weighted average remaining lease term 10 years     7 years
Weighted average discount rate 4.44%     2.21%
Number of purchase power operating lease agreements | agreement     2