PINNACLE WEST CAPITAL CORP, 10-Q filed on 5/2/2024
Quarterly Report
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Cover Page - shares
 3 Months Ended
Mar. 31, 2024
Apr. 25, 2024
Entity Information [Line Items]    
Document Type 10-Q  
Document Quarterly Report true  
Document Period End Date Mar. 31, 2024  
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 Shell Company false  
Entity Common Stock, Shares Outstanding   113,558,885
Entity Central Index Key 0000764622  
Amendment Flag false  
Current Fiscal Year End Date --12-31  
Document Fiscal Year Focus 2024  
Document Fiscal Period Focus Q1  
APS    
Entity Information [Line Items]    
Document Type 10-Q  
Document Period End Date Mar. 31, 2024  
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 Shell 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 2024  
Document Fiscal Period Focus Q1  
v3.24.1.u1
CONDENSED CONSOLIDATED STATEMENTS OF INCOME - USD ($)
shares in Thousands, $ in Thousands
 3 Months Ended
Mar. 31, 2024
Mar. 31, 2023
Income Statement [Abstract]    
OPERATING REVENUES (Note 2) $ 951,712 $ 944,955
OPERATING EXPENSES    
Fuel and purchased power 357,864 394,504
Operations and maintenance 257,578 250,080
Depreciation and amortization 210,294 191,906
Taxes other than income taxes 59,164 57,138
Other expense 20 610
Total 884,920 894,238
OPERATING INCOME 66,792 50,717
OTHER INCOME (DEDUCTIONS)    
Allowance for equity funds used during construction 10,292 15,061
Pension and other postretirement non-service credits - net (Note 5) 11,568 9,865
Other income (Note 9) 30,607 6,077
Other expense (Note 9) (7,567) (4,131)
Total 44,900 26,872
INTEREST EXPENSE    
Interest charges 99,774 88,119
Allowance for borrowed funds used during construction (13,141) (12,722)
Total 86,633 75,397
Income Before Income Taxes 25,059 2,192
Income Taxes 3,891 1,183
Net Income 21,168 1,009
Less: Net income attributable to noncontrolling interests (Note 6) 4,306 4,306
Net Income (Loss) Attributable to Common Shareholders $ 16,862 $ (3,297)
Weighted-average common shares outstanding - basic (in shares) 113,621 113,358
Weighted-average common shares outstanding - diluted (in shares) 114,227 113,358
Earnings Per Weighted-Average Common Share Outstanding    
Net income (loss) attributable to common shareholders - basic (in dollars per share) $ 0.15 $ (0.03)
Net income (loss) attributable to common shareholders - diluted (in dollars per share) $ 0.15 $ (0.03)
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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($)
$ in Thousands
 3 Months Ended
Mar. 31, 2024
Mar. 31, 2023
Statement of Comprehensive Income [Abstract]    
NET INCOME $ 21,168 $ 1,009
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX    
Derivative instruments net unrealized loss, net of tax benefit of $— and $202 0 (616)
Pension and other postretirement benefit activity, net of tax expense of $185 and $169 562 515
Total other comprehensive income (loss) 562 (101)
COMPREHENSIVE INCOME 21,730 908
Less: Comprehensive income attributable to noncontrolling interests 4,306 4,306
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS $ 17,424 $ (3,398)
v3.24.1.u1
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($)
$ in Thousands
 3 Months Ended
Mar. 31, 2024
Mar. 31, 2023
Statement of Comprehensive Income [Abstract]    
Derivative instruments net unrealized loss, net of tax benefit $ 0 $ 202
Pension and other postretirement benefits activity, net of tax expense $ 185 $ 169
v3.24.1.u1
CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($)
$ in Thousands
Mar. 31, 2024
Dec. 31, 2023
CURRENT ASSETS    
Cash and cash equivalents $ 9,634 $ 4,955
Customer and other receivables 425,716 513,892
Accrued unbilled revenues 166,479 167,553
Allowance for doubtful accounts (Note 2) (19,224) (22,433)
Materials and supplies (at average cost) 438,943 444,344
Income tax receivable 0 332
Fossil fuel (at average cost) 50,230 49,203
Assets from risk management activities (Note 7) 78 6,808
Assets held for sale (Note 14) 0 35,139
Deferred fuel and purchased power regulatory asset (Note 4) 387,737 463,195
Other regulatory assets (Note 4) 191,132 162,562
Other current assets 131,257 101,417
Total current assets 1,781,982 1,926,967
INVESTMENTS AND OTHER ASSETS    
Nuclear decommissioning trusts (Notes 11 and 12) 1,239,024 1,201,246
Other special use funds (Notes 11 and 12) 364,225 362,781
Other assets 106,830 102,845
Total investments and other assets 1,710,079 1,666,872
PROPERTY, PLANT AND EQUIPMENT    
Plant in service and held for future use 24,461,914 24,211,167
Accumulated depreciation and amortization (8,594,795) (8,408,040)
Net 15,867,119 15,803,127
Construction work in progress 1,685,365 1,724,004
Palo Verde sale leaseback, net of accumulated depreciation (Note 6) 85,459 86,426
Intangible assets, net of accumulated amortization 512,874 267,110
Nuclear fuel, net of accumulated amortization 113,825 99,490
Total property, plant and equipment 18,264,642 17,980,157
DEFERRED DEBITS    
Regulatory assets (Note 4) 1,371,260 1,390,279
Operating lease right-of-use assets 1,325,138 1,309,975
Assets for pension and other postretirement benefits (Note 5) 334,765 323,438
Other 59,847 63,465
Total deferred debits 3,091,010 3,087,157
TOTAL ASSETS 24,847,713 24,661,153
CURRENT LIABILITIES    
Accounts payable 476,629 442,455
Accrued taxes 224,851 166,833
Accrued interest 74,001 72,916
Common dividends payable 0 99,813
Short-term borrowings (Note 3) 793,500 609,500
Current maturities of long-term debt (Note 3) 875,000 875,000
Customer deposits 42,059 42,037
Liabilities from risk management activities (Note 7) 113,530 80,913
Liabilities for asset retirements 33,048 28,550
Operating lease liabilities 69,102 67,883
Regulatory liabilities (Note 4) 221,552 209,923
Other current liabilities 132,597 193,524
Total current liabilities 3,055,869 2,889,347
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 3) 7,541,871 7,540,622
DEFERRED CREDITS AND OTHER    
Deferred income taxes 2,396,743 2,416,480
Regulatory liabilities (Note 4) 1,966,120 1,965,865
Liabilities for asset retirements 946,457 937,451
Liabilities for pension benefits (Note 5) 110,597 112,702
Liabilities from risk management activities (Note 7) 34,872 42,975
Customer advances 533,180 533,580
Coal mine reclamation 185,229 184,007
Deferred investment tax credit 257,448 257,743
Unrecognized tax benefits 34,511 33,861
Operating lease liabilities 1,225,468 1,210,189
Other 248,815 251,469
Total deferred credits and other 7,939,440 7,946,322
COMMITMENTS AND CONTINGENCIES (Note 8)
EQUITY    
Common stock, no par value; authorized 150,000,000 shares, 113,686,849 and 113,537,689 issued at respective dates 2,757,506 2,752,676
Treasury stock at cost; 128,234 and 113,272 shares at respective dates (9,073) (8,185)
Total common stock 2,748,433 2,744,491
Retained earnings 3,483,178 3,466,317
Accumulated other comprehensive loss (Note 13) (32,582) (33,144)
Total shareholder equity 6,199,029 6,177,664
Noncontrolling interests (Note 6) 111,504 107,198
Total equity 6,310,533 6,284,862
TOTAL LIABILITIES AND EQUITY $ 24,847,713 $ 24,661,153
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CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - shares
Mar. 31, 2024
Dec. 31, 2023
EQUITY    
Common stock, authorized shares (in shares) 150,000,000 150,000,000
Common stock, issued shares (in shares) 113,686,849 113,537,689
Treasury stock at cost, shares (in shares) 128,234 113,272
v3.24.1.u1
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)
$ in Thousands
 3 Months Ended
Mar. 31, 2024
Mar. 31, 2023
CASH FLOWS FROM OPERATING ACTIVITIES    
Net income $ 21,168 $ 1,009
Adjustments to reconcile net income to net cash provided by operating activities:    
Gain on sale relating to BCE (22,988) 0
Depreciation and amortization including nuclear fuel 226,413 208,772
Deferred fuel and purchased power (33,094) (90,305)
Deferred fuel and purchased power amortization 108,552 80,904
Allowance for equity funds used during construction (10,292) (15,061)
Deferred income taxes (23,297) (5,150)
Deferred investment tax credit (294) 3,749
Change in derivative instruments fair value 0 786
Stock compensation 5,935 3,635
Changes in current assets and liabilities:    
Customer and other receivables 84,888 2,831
Accrued unbilled revenues 1,074 21,488
Materials, supplies and fossil fuel 4,374 (14,392)
Income tax receivable 332 2,387
Other current assets (32,306) (8,099)
Accounts payable 23,799 (69,576)
Accrued taxes 58,018 50,044
Other current liabilities (55,343) (84,003)
Change in long-term regulatory assets 9,850 14,557
Change in long-term regulatory liabilities 16,493 33,555
Change in other long-term assets (19,571) (72,593)
Change in operating lease assets (8,416) (8,920)
Change in other long-term liabilities (17,489) 104,858
Change in operating lease liabilities 9,547 51,129
Net cash provided by operating activities 347,353 211,605
CASH FLOWS FROM INVESTING ACTIVITIES    
Capital expenditures (517,756) (445,171)
Contributions in aid of construction 69,047 25,165
Proceeds from sale relating to BCE 38,681 0
Allowance for borrowed funds used during construction (13,141) (12,722)
Proceeds from nuclear decommissioning trust sales and other special use funds 443,870 226,626
Investment in nuclear decommissioning trust and other special use funds (443,854) (227,196)
Other (939) (19,941)
Net cash used for investing activities (424,092) (453,239)
CASH FLOWS FROM FINANCING ACTIVITIES    
Issuance of long-term debt 0 185,136
Short-term borrowing and (repayments) - net 184,000 156,830
Dividends paid on common stock (98,082) (96,078)
Common stock equity issuance and (purchases) - net (4,500) (2,135)
Net cash provided by financing activities 81,418 243,753
NET INCREASE IN CASH AND CASH EQUIVALENTS 4,679 2,119
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 4,955 4,832
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 9,634 $ 6,951
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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, 2022   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)      
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        
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)      
Beginning balance (in shares) at Dec. 31, 2023 113,537,689 113,537,689        
Beginning balance at Dec. 31, 2023 $ 6,284,862 $ 2,752,676 $ (8,185) 3,466,317 (33,144) 107,198
Beginning balance (in shares) at Dec. 31, 2023 (113,272)   (113,272)      
Increase (Decrease) in Shareholders' Equity            
Net income $ 21,168     16,862   4,306
Other comprehensive income (loss) 562       562  
Issuance of common stock (in shares) [2]   149,160        
Issuance of common stock [2] 4,830 $ 4,830        
Purchase of treasury stock (in shares) [1]     (71,008)      
Purchase of treasury stock [1] (4,907)   $ (4,907)      
Reissuance of treasury stock for stock-based compensation and other (in shares)     56,046      
Reissuance of treasury stock for stock-based compensation and other 4,018   $ 4,018      
Other $ 0   1 (1)    
Ending balance (in shares) at Mar. 31, 2024 113,686,849 113,686,849        
Ending balance at Mar. 31, 2024 $ 6,310,533 $ 2,757,506 $ (9,073) $ 3,483,178 $ (32,582) $ 111,504
Ending balance (in shares) at Mar. 31, 2024 (128,234)   (128,234)      
[1] Primarily represents shares of common stock withheld from certain stock awards for tax purposes.
[2] See Note 10 for information related to our equity forward sale agreements that were executed in February 2024. As of March 31, 2024, no common shares have been issued as part of this agreement.
v3.24.1.u1
ARIZONA PUBLIC SERVICE COMPANY - CONDENSED CONSOLIDATED STATEMENTS OF INCOME - USD ($)
$ in Thousands
 3 Months Ended
Mar. 31, 2024
Mar. 31, 2023
OPERATING REVENUES (Note 2) $ 951,712 $ 944,955
OPERATING EXPENSES    
Fuel and purchased power 357,864 394,504
Operations and maintenance 257,578 250,080
Depreciation and amortization 210,294 191,906
Taxes other than income taxes 59,164 57,138
Other expense 20 610
Total 884,920 894,238
OPERATING INCOME 66,792 50,717
OTHER INCOME (DEDUCTIONS)    
Allowance for equity funds used during construction 10,292 15,061
Pension and other postretirement non-service credits - net (Note 5) 11,568 9,865
Other income (Note 9) 30,607 6,077
Other expense (Note 9) (7,567) (4,131)
Total 44,900 26,872
INTEREST EXPENSE    
Interest charges 99,774 88,119
Allowance for borrowed funds used during construction (13,141) (12,722)
Total 86,633 75,397
Income Before Income Taxes 25,059 2,192
INCOME TAXES 3,891 1,183
Net Income 21,168 1,009
Less: Net income attributable to noncontrolling interests (Note 6) 4,306 4,306
Net Income (Loss) Attributable to Common Shareholders 16,862 (3,297)
APS    
OPERATING REVENUES (Note 2) 951,712 944,955
OPERATING EXPENSES    
Fuel and purchased power 357,864 394,504
Operations and maintenance 253,593 246,179
Depreciation and amortization 210,273 191,884
Taxes other than income taxes 59,078 57,125
Other expense 20 610
Total 880,828 890,302
OPERATING INCOME 70,884 54,653
OTHER INCOME (DEDUCTIONS)    
Allowance for equity funds used during construction 10,292 15,061
Pension and other postretirement non-service credits - net (Note 5) 11,773 10,106
Other income (Note 9) 6,855 5,075
Other expense (Note 9) (2,894) (2,617)
Total 26,026 27,625
INTEREST EXPENSE    
Interest charges 86,979 75,222
Allowance for borrowed funds used during construction (13,141) (11,157)
Total 73,838 64,065
Income Before Income Taxes 23,072 18,213
INCOME TAXES 3,649 3,247
Net Income 19,423 14,966
Less: Net income attributable to noncontrolling interests (Note 6) 4,306 4,306
Net Income (Loss) Attributable to Common Shareholders $ 15,117 $ 10,660
v3.24.1.u1
ARIZONA PUBLIC SERVICE COMPANY - CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($)
$ in Thousands
 3 Months Ended
Mar. 31, 2024
Mar. 31, 2023
NET INCOME $ 21,168 $ 1,009
OTHER COMPREHENSIVE INCOME, NET OF TAX    
Pension and other postretirement benefits activity, net of tax expense of $161 and $150 562 515
Total other comprehensive income (loss) 562 (101)
COMPREHENSIVE INCOME 21,730 908
Less: Comprehensive income attributable to noncontrolling interests 4,306 4,306
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS 17,424 (3,398)
APS    
NET INCOME 19,423 14,966
OTHER COMPREHENSIVE INCOME, NET OF TAX    
Pension and other postretirement benefits activity, net of tax expense of $161 and $150 490 457
Total other comprehensive income (loss) 490 457
COMPREHENSIVE INCOME 19,913 15,423
Less: Comprehensive income attributable to noncontrolling interests 4,306 4,306
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS $ 15,607 $ 11,117
v3.24.1.u1
ARIZONA PUBLIC SERVICE COMPANY - CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($)
$ in Thousands
 3 Months Ended
Mar. 31, 2024
Mar. 31, 2023
Pension and other postretirement benefits activity, net of tax expense $ 185 $ 169
APS    
Pension and other postretirement benefits activity, net of tax expense $ 161 $ 150
v3.24.1.u1
ARIZONA PUBLIC SERVICE COMPANY - CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($)
$ in Thousands
Mar. 31, 2024
Dec. 31, 2023
PROPERTY, PLANT AND EQUIPMENT    
Plant in service and held for future use $ 24,461,914 $ 24,211,167
Accumulated depreciation and amortization (8,594,795) (8,408,040)
Net 15,867,119 15,803,127
Construction work in progress 1,685,365 1,724,004
Palo Verde sale leaseback, net of accumulated depreciation (Note 6) 85,459 86,426
Intangible assets, net of accumulated amortization 512,874 267,110
Nuclear fuel, net of accumulated amortization 113,825 99,490
Total property, plant and equipment 18,264,642 17,980,157
INVESTMENTS AND OTHER ASSETS    
Nuclear decommissioning trusts (Notes 11 and 12) 1,239,024 1,201,246
Other special use funds (Notes 11 and 12) 364,225 362,781
Other assets 106,830 102,845
Total investments and other assets 1,710,079 1,666,872
CURRENT ASSETS    
Cash and cash equivalents 9,634 4,955
Customer and other receivables 425,716 513,892
Accrued unbilled revenues 166,479 167,553
Allowance for doubtful accounts (Note 2) (19,224) (22,433)
Materials and supplies (at average cost) 438,943 444,344
Fossil fuel (at average cost) 50,230 49,203
Assets from risk management activities (Note 7) 78 6,808
Deferred fuel and purchased power regulatory asset (Note 4) 387,737 463,195
Other regulatory assets (Note 4) 191,132 162,562
Other current assets 131,257 101,417
Total current assets 1,781,982 1,926,967
DEFERRED DEBITS    
Regulatory assets (Note 4) 1,371,260 1,390,279
Operating lease right-of-use assets 1,325,138 1,309,975
Assets for pension and other postretirement benefits (Note 5) 334,765 323,438
Other 59,847 63,465
Total deferred debits 3,091,010 3,087,157
TOTAL ASSETS 24,847,713 24,661,153
CAPITALIZATION    
Retained earnings 3,483,178 3,466,317
Accumulated other comprehensive loss (Note 13) (32,582) (33,144)
Total shareholder equity 6,199,029 6,177,664
Noncontrolling interests (Note 6) 111,504 107,198
Total equity 6,310,533 6,284,862
Long-term debt less current maturities (Note 3) 7,541,871 7,540,622
CURRENT LIABILITIES    
Short-term borrowings (Note 3) 793,500 609,500
Accounts payable 476,629 442,455
Accrued taxes 224,851 166,833
Accrued interest 74,001 72,916
Common dividends payable 0 99,813
Customer deposits 42,059 42,037
Liabilities from risk management activities (Note 7) 113,530 80,913
Liabilities for asset retirements 33,048 28,550
Operating lease liabilities 69,102 67,883
Regulatory liabilities (Note 4) 221,552 209,923
Other current liabilities 132,597 193,524
Total current liabilities 3,055,869 2,889,347
DEFERRED CREDITS AND OTHER    
Deferred income taxes 2,396,743 2,416,480
Regulatory liabilities (Note 4) 1,966,120 1,965,865
Liabilities for asset retirements 946,457 937,451
Liabilities for pension benefits (Note 5) 110,597 112,702
Liabilities from risk management activities (Note 7) 34,872 42,975
Customer advances 533,180 533,580
Coal mine reclamation 185,229 184,007
Deferred investment tax credit 257,448 257,743
Unrecognized tax benefits 34,511 33,861
Operating lease liabilities 1,225,468 1,210,189
Other 248,815 251,469
Total deferred credits and other 7,939,440 7,946,322
COMMITMENTS AND CONTINGENCIES (Note 8)
TOTAL LIABILITIES AND EQUITY 24,847,713 24,661,153
APS    
PROPERTY, PLANT AND EQUIPMENT    
Plant in service and held for future use 24,458,518 24,207,706
Accumulated depreciation and amortization (8,591,536) (8,404,721)
Net 15,866,982 15,802,985
Construction work in progress 1,685,365 1,724,004
Palo Verde sale leaseback, net of accumulated depreciation (Note 6) 85,459 86,426
Intangible assets, net of accumulated amortization 512,719 266,955
Nuclear fuel, net of accumulated amortization 113,825 99,490
Total property, plant and equipment 18,264,350 17,979,860
INVESTMENTS AND OTHER ASSETS    
Nuclear decommissioning trusts (Notes 11 and 12) 1,239,024 1,201,246
Other special use funds (Notes 11 and 12) 364,225 362,781
Other assets 43,676 43,625
Total investments and other assets 1,646,925 1,607,652
CURRENT ASSETS    
Cash and cash equivalents 9,494 4,549
Customer and other receivables 422,651 510,296
Accrued unbilled revenues 166,479 167,553
Allowance for doubtful accounts (Note 2) (19,224) (22,433)
Materials and supplies (at average cost) 438,943 444,344
Fossil fuel (at average cost) 50,230 49,203
Assets from risk management activities (Note 7) 78 6,808
Deferred fuel and purchased power regulatory asset (Note 4) 387,737 463,195
Other regulatory assets (Note 4) 191,132 162,562
Other current assets 76,154 64,311
Total current assets 1,723,674 1,850,388
DEFERRED DEBITS    
Regulatory assets (Note 4) 1,371,260 1,390,279
Operating lease right-of-use assets 1,323,837 1,308,611
Assets for pension and other postretirement benefits (Note 5) 327,836 316,606
Other 59,447 63,059
Total deferred debits 3,082,380 3,078,555
TOTAL ASSETS 24,717,329 24,516,455
CAPITALIZATION    
Common stock 178,162 178,162
Additional paid-in capital 3,321,696 3,321,696
Retained earnings 3,774,414 3,759,299
Accumulated other comprehensive loss (Note 13) (16,729) (17,219)
Total shareholder equity 7,257,543 7,241,938
Noncontrolling interests (Note 6) 111,504 107,198
Total equity 7,369,047 7,349,136
Long-term debt less current maturities (Note 3) 7,042,930 7,041,891
Total capitalization 14,411,977 14,391,027
CURRENT LIABILITIES    
Short-term borrowings (Note 3) 733,500 532,850
Current maturities of long-term debt (Note 3) 250,000 250,000
Accounts payable 470,973 433,229
Accrued taxes 222,033 162,288
Accrued interest 71,988 72,548
Common dividends payable 0 99,800
Customer deposits 42,059 42,037
Liabilities from risk management activities (Note 7) 113,530 80,913
Liabilities for asset retirements 33,048 28,550
Operating lease liabilities 68,878 67,608
Regulatory liabilities (Note 4) 221,552 209,923
Other current liabilities 125,305 211,773
Total current liabilities 2,352,866 2,191,519
DEFERRED CREDITS AND OTHER    
Deferred income taxes 2,434,844 2,431,697
Regulatory liabilities (Note 4) 1,966,120 1,965,865
Liabilities for asset retirements 946,457 937,451
Liabilities for pension benefits (Note 5) 104,669 106,215
Liabilities from risk management activities (Note 7) 34,872 42,975
Customer advances 533,180 533,580
Coal mine reclamation 185,229 184,007
Deferred investment tax credit 257,448 257,743
Unrecognized tax benefits 37,007 33,861
Operating lease liabilities 1,224,170 1,208,857
Other 228,490 231,658
Total deferred credits and other 7,952,486 7,933,909
COMMITMENTS AND CONTINGENCIES (Note 8)
TOTAL LIABILITIES AND EQUITY $ 24,717,329 $ 24,516,455
v3.24.1.u1
ARIZONA PUBLIC SERVICE COMPANY - CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)
$ in Thousands
 3 Months Ended
Mar. 31, 2024
Mar. 31, 2023
CASH FLOWS FROM OPERATING ACTIVITIES    
Net income $ 21,168 $ 1,009
Adjustments to reconcile net income to net cash provided by operating activities:    
Depreciation and amortization including nuclear fuel 226,413 208,772
Deferred fuel and purchased power (33,094) (90,305)
Deferred fuel and purchased power amortization 108,552 80,904
Allowance for equity funds used during construction (10,292) (15,061)
Deferred income taxes (23,297) (5,150)
Deferred investment tax credit (294) 3,749
Changes in current assets and liabilities:    
Customer and other receivables 84,888 2,831
Accrued unbilled revenues 1,074 21,488
Materials, supplies and fossil fuel 4,374 (14,392)
Other current assets (32,306) (8,099)
Accounts payable 23,799 (69,576)
Accrued taxes 58,018 50,044
Other current liabilities (55,343) (84,003)
Change in long-term regulatory assets 9,850 14,557
Change in long-term regulatory liabilities 16,493 33,555
Change in other long-term assets (19,571) (72,593)
Change in operating lease assets (8,416) (8,920)
Change in other long-term liabilities (17,489) 104,858
Change in operating lease liabilities 9,547 51,129
Net cash provided by operating activities 347,353 211,605
CASH FLOWS FROM INVESTING ACTIVITIES    
Capital expenditures (517,756) (445,171)
Contributions in aid of construction 69,047 25,165
Allowance for borrowed funds used during construction (13,141) (12,722)
Proceeds from nuclear decommissioning trust sales and other special use funds 443,870 226,626
Investment in nuclear decommissioning trust and other special use funds (443,854) (227,196)
Other (939) (19,941)
Net cash used for investing activities (424,092) (453,239)
CASH FLOWS FROM FINANCING ACTIVITIES    
Short-term borrowing and (repayments) - net 184,000 156,830
Dividends paid on common stock (98,082) (96,078)
Net cash provided by financing activities 81,418 243,753
NET INCREASE IN CASH AND CASH EQUIVALENTS 4,679 2,119
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 4,955 4,832
CASH AND CASH EQUIVALENTS AT END OF PERIOD 9,634 6,951
APS    
CASH FLOWS FROM OPERATING ACTIVITIES    
Net income 19,423 14,966
Adjustments to reconcile net income to net cash provided by operating activities:    
Depreciation and amortization including nuclear fuel 226,392 208,750
Deferred fuel and purchased power (33,094) (90,305)
Deferred fuel and purchased power amortization 108,552 80,904
Allowance for equity funds used during construction (10,292) (15,061)
Deferred income taxes 2,071 (1,693)
Deferred investment tax credit (294) 3,749
Changes in current assets and liabilities:    
Customer and other receivables 84,357 9,347
Accrued unbilled revenues 1,074 21,488
Materials, supplies and fossil fuel 4,374 (14,392)
Other current assets 3,516 (11,039)
Accounts payable 26,328 (64,008)
Accrued taxes 59,745 55,194
Other current liabilities (82,478) (82,422)
Change in long-term regulatory assets 9,850 14,557
Change in long-term regulatory liabilities 16,493 33,555
Change in other long-term assets (51,555) (70,466)
Change in operating lease assets (8,479) (8,998)
Change in other long-term liabilities (19,584) 104,303
Change in operating lease liabilities 9,581 51,212
Net cash provided by operating activities 365,980 239,641
CASH FLOWS FROM INVESTING ACTIVITIES    
Capital expenditures (517,756) (439,647)
Contributions in aid of construction 69,047 25,165
Allowance for borrowed funds used during construction (13,141) (11,157)
Proceeds from nuclear decommissioning trust sales and other special use funds 443,870 226,626
Investment in nuclear decommissioning trust and other special use funds (443,854) (227,196)
Other (51) (926)
Net cash used for investing activities (461,885) (427,135)
CASH FLOWS FROM FINANCING ACTIVITIES    
Short-term borrowing and (repayments) - net 200,650 138,000
Equity infusion 0 150,000
Dividends paid on common stock (99,800) (97,900)
Net cash provided by financing activities 100,850 190,100
NET INCREASE IN CASH AND CASH EQUIVALENTS 4,945 2,606
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 4,549 4,042
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 9,494 $ 6,648
v3.24.1.u1
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, 2022   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         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
Beginning balance (in shares) at Dec. 31, 2023 113,537,689 113,537,689         71,264,947        
Beginning balance at Dec. 31, 2023 $ 6,284,862 $ 2,752,676 3,466,317 (33,144) 107,198 7,349,136 $ 178,162 3,321,696 3,759,299 (17,219) 107,198
Increase (Decrease) in Shareholders' Equity                      
Net income 21,168   16,862   4,306 19,423     15,117   4,306
Other comprehensive income (loss) 562     562   490       490  
Other $ 0   (1)     (2)     (2)    
Ending balance (in shares) at Mar. 31, 2024 113,686,849 113,686,849         71,264,947        
Ending balance at Mar. 31, 2024 $ 6,310,533 $ 2,757,506 $ 3,483,178 $ (32,582) $ 111,504 $ 7,369,047 $ 178,162 $ 3,321,696 $ 3,774,414 $ (16,729) $ 111,504
v3.24.1.u1
Consolidation and Nature of Operations
 3 Months Ended
Mar. 31, 2024
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, El Dorado Investment Company (“El Dorado”), and Pinnacle West Power, LLC (“PNW Power”). 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.  PNW Power is a wholly-owned subsidiary that was created in September 2023 to hold certain investments in wind and transmission joint projects that were previously held in Bright Canyon Energy Corporation (“BCE”). See Note 14 for additional information. 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.

BCE was a Pinnacle West subsidiary that was formed in 2014. On August 4, 2023, Pinnacle West entered into a purchase and sale agreement pursuant to which all of our equity interest in BCE was sold. The sale was completed on January 12, 2024. See Note 14 for more information relating to the sale of BCE.

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, 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 2023 Form 10-K.
Supplemental Cash Flow Information

The following table summarizes supplemental Pinnacle West cash flow information (dollars in thousands):
 Three Months Ended
March 31,
 20242023
Cash paid (received) during the period for:
Income taxes, net of refunds$20,970 $(12)
Interest, net of amounts capitalized83,974 62,241 
Significant non-cash investing and financing activities:
Accrued capital expenditures$217,684 $115,559 
Cash paid for amounts included in the measurement of lease liabilities — operating cash flows:3,544 3,851 
Right-of-use operating lease assets obtained in exchange for operating lease liabilities6,747 551,239 
BCE Sale non-cash consideration (Note 14)
45,608 — 


The following table summarizes supplemental APS cash flow information (dollars in thousands):
Three Months Ended
March 31,
 20242023
Cash paid during the period for:
Interest, net of amounts capitalized$73,035 $53,610 
Significant non-cash investing and financing activities:
Accrued capital expenditures$217,684 $112,219 
Cash paid for amounts included in the measurement of lease liabilities — operating cash flows:3,544 3,851 
Right-of-use operating lease assets obtained in exchange for operating lease liabilities6,747 551,239 
v3.24.1.u1
Revenue
 3 Months Ended
Mar. 31, 2024
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,
20242023
Retail Electric Service
Residential$432,692 $409,724 
Non-Residential461,483 406,137 
Wholesale Energy Sales26,864 95,603 
Transmission Services for Others27,712 31,791 
Other Sources2,961 1,700 
Total Operating Revenues$951,712 $944,955 

Retail Electric Revenue. All of Pinnacle West’s retail electric revenue is generated by APS. Retail electric revenue is generated by the 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 the U.S. Federal Energy Regulatory Commission (“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, 2024 and 2023 were $943 million and $922 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, 2024 and 2023, our revenues that do not qualify as revenue from contracts with customers were $9 million and $23 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, 2024 or December 31, 2023.

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, 2024December 31, 2023
Allowance for doubtful accounts, balance at beginning of period$22,433 $23,778 
Bad debt expense4,769 23,399 
Actual write-offs(7,978)(24,744)
Allowance for doubtful accounts, balance at end of period$19,224 $22,433 
v3.24.1.u1
Long-Term Debt and Liquidity Matters
 3 Months Ended
Mar. 31, 2024
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 total 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, 2024, Pinnacle West had no outstanding borrowings under its revolving credit facility, no letters of credit outstanding under the credit facility, and $60 million of outstanding commercial paper borrowings. The weighted-average interest rate for the outstanding borrowings on March 31, 2024, was 5.47%.

On February 28, 2024, Pinnacle West entered into various equity forward sale agreements (the “Equity Forward Sale Agreements”), which may be settled with Pinnacle West common stock or cash. At March 31, 2024, Pinnacle West could have settled the Equity Forward Sale Agreements with the issuance of 11,240,601 shares of common stock, which would have provided cash liquidity to Pinnacle West of $728 million. See Note 10.

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 by 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 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 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, 2024, APS had no outstanding borrowings under its revolving credit facility, no letters of credit outstanding under the credit facility, and $384 million of outstanding commercial paper borrowings. The weighted-average interest rate for the outstanding borrowings on March 31, 2024, was 5.42%.

APS is currently authorized to receive up to $150 million annually in equity infusions from Pinnacle West without seeking ACC approval. On October 27, 2023, APS sought approval from the ACC to receive from Pinnacle West in 2024 up to an additional $500 million in equity infusions above the authorized limit of $150 million, and on January 9, 2024, the ACC approved the increased equity infusion limit for 2024.

On December 15, 2022, the ACC issued a financing order reaffirming the previous short-term debt authorization equal to the sum of (i) 7% of APS’s capitalization, and (ii) $500 million (which is required to be used for costs relating to purchases of natural gas and power) and approving APS’s application filed April 6, 2022 requesting to increase the long-term debt limit from $7.5 billion to $8.0 billion and to exclude financing lease power purchase agreements (“PPAs”) from the definition of long-term debt for purposes of the ACC financing orders.

On April 19, 2024, APS submitted an application to the ACC requesting to further increase the long-term debt limit from $8.0 billion to $9.5 billion and to increase Pinnacle West’s permitted yearly equity infusions to equal up to 2.5% of Pinnacle West’s consolidated assets each calendar year on a three-year rolling average basis. APS cannot predict the outcome of this matter.

On December 12, 2023, APS entered into an agreement for a new 364-day $350 million term loan facility that matures on December 10, 2024. Borrowings under the facility bear interest at SOFR plus 1.0% per annum. On February 9, 2024, APS drew the full amount of $350 million.
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 the development of a 31 megawatt (“MW”) solar and 20 megawatt hour (“MWh”) battery storage project in Los Alamitos, California (“Los Alamitos”). The credit agreement consisted of an equity bridge loan facility, a non-recourse construction facility, a letter of credit facility, and a related interest rate swap. On August 4, 2023, Pinnacle West entered into a purchase and sale agreement with Ameresco, Inc. (“Ameresco”), pursuant to which we agreed to sell all our equity interest in BCE to Ameresco (the “BCE Sale”). See Note 14. As a part of the BCE Sale closing, the $36 million construction facility, the letter of credit facility, and the interest rate swap were transferred to Ameresco. On August 4, 2023, concurrent with the BCE Sale, Pinnacle West paid in full the outstanding $31 million equity bridge loan balance. As of March 31, 2024, and December 31, 2023, there was no outstanding balance on our Condensed Consolidated Balance Sheets relating to this credit agreement.

Pinnacle West has issued performance guarantees relating to BCE’s Kūpono solar project (the “Kūpono Solar Project”). BCE held an equity method investment in the Kūpono Solar Project. As a result of the BCE Sale that closed on January 12, 2024, Pinnacle West no longer holds an equity or ownership interest in BCE or the Kūpono Solar Project. The performance guarantees did not transfer in the BCE Sale, and Pinnacle West continues to retain these guarantees. 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, 2024As of December 31, 2023
 Carrying
Amount		Fair ValueCarrying
Amount		Fair Value
Pinnacle West$1,123,941 $1,099,455 $1,123,731 $1,095,935 
APS7,292,930 6,368,753 7,291,891 6,459,718 
Total$8,416,871 $7,468,208 $8,415,622 $7,555,653 
v3.24.1.u1
Regulatory Matters
 3 Months Ended
Mar. 31, 2024
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 would have represented 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 would have been an increase of 13.6%.
The principal provisions of APS’s application were:

•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 (“EIS”) and collect costs through base rates,
▪eliminate the Lost Fixed Cost Recovery (“LFCR”) mechanism and collect costs through base rates and the Demand Side Management (“DSM”) Adjustment Charge (“DSMAC”),
▪maintain as inactive the Tax Expense Adjustor Mechanism (“TEAM”),
▪maintain the Transmission Cost Adjustment (“TCA”) mechanism,
▪modify the performance incentive in the DSMAC, and
▪modify the Renewable Energy Adjustment Charge (“REAC”) 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.

On June 5, 2023, and June 15, 2023, the ACC Staff, the Residential Utility Consumer Office (“RUCO”) and other intervenors filed their initial written testimony with the ACC. The ACC Staff recommended, among other things, (i) a $251 million revenue increase or, as an alternative, a $312 million revenue increase, (ii) a 9.6% return on equity, (iii) a 0.0% fair value increment or, as an alternative, a 0.75% fair value increment, and (iv) a continuation of a 12-month post-test year plant. RUCO recommended, among other things, (i) an $84.9 million revenue increase, (ii) an 8.2% return on equity or, as an alternative, an 8.7% return on equity if the ACC imputes a hypothetical capital structure with a 46% equity layer, (iii) a fair value increment of 0.0%, and (iv) a reduction of post-test year plant to six months.

On July 12, 2023, APS filed rebuttal testimony addressing the ACC Staff and intervenors’ direct testimonies. The principal provisions of APS’s rebuttal testimony were:

•reducing the revenue requirement increase to $383.1 million, which reduced the average annual customer bill impact to an increase of 11.3%;
•maintaining a return on equity request of 10.25%;
•reducing the increment of fair value rate base return to 0.5% from 1.0%;
•maintaining a post-test year plant request of 12 months, plus the Four Corners Power Plant (“Four Corners”) Effluent Limitation Guidelines (“ELG”) project;
•withdrawing the Payment Fee Removal Proposal (net reduction) which was originally requested in APS’s initial application;
•maintaining the LFCR mechanism and DSMAC as separate adjustors;
•increasing the Power Supply Adjustment (“PSA”) annual rate change limit from $0.004/kWh to $0.006/kWh;
•proposing a new System Reliability Benefit (“SRB”) recovery mechanism;
•maintaining the REAC in its current state;
•maintaining adjustor base transfers and elimination of EIS; and
•maintaining the request to recover Coal Community Transition (“CCT”) funding.

On July 26, 2023, the ACC Staff, RUCO and other intervenors filed their surrebuttal testimony with the ACC. The ACC Staff adjusted their initial recommendations to, among other things, (i) a $281.9 million revenue increase, (ii) a 9.68% return on equity, (iii) a 0.5% fair value increment, (iv) a continuation of a 12-month post-test year plant that includes the Four Corners ELG project, and (v) support of an increase to the annual PSA increase limit to $0.006/kWh. RUCO maintained their direct position and also recommended further review of the PSA in a second phase of the 2022 Rate Case.

On August 4, 2023, APS filed rejoinder testimony addressing the ACC Staff and intervenors’ surrebuttal testimonies. APS’s rejoinder testimony included final post-test year plant values, reducing the revenue requirement increase to $377.7 million from $383.1 million, which reduced the average annual customer bill impact to an increase of 11.2%. All other major provisions from APS’s rebuttal testimony were maintained in its rejoinder testimony.

On November 6, 2023, and November 21, 2023, APS and stakeholders filed briefs in the 2022 Rate Case. APS’s briefs included the reduction of the total revenue requirement increase to $376.2 million and a resulting average annual customer bill impact increase of 11.1%. All other major provisions from APS’s rejoinder testimony were maintained in its briefs. ACC Staff’s briefs included a proposed total revenue requirement increase from $281.9 million to $282.7 million and also included their support of APS’s SRB mechanism, contingent on increased stakeholder outreach.

On January 25, 2024, an Administrative Law Judge issued a Recommended Opinion and Order in the 2022 Rate Case, as corrected on February 6, 2024 (the “2022 Rate Case ROO”). The 2022 Rate Case ROO recommended, among other things, (i) a $523.1 million increase in the annual base rate revenue requirement, (ii) a 9.55% return on equity, (iii) a 0.25% return on the increment of fair value rate base greater than original cost, (iv) an effective fair value rate of return of 4.36%, (v) 12 months of post-test year plant and the inclusion of the Four Corners ELG project, (vi) the approval of APS’s SRB proposal with certain procedural and other modifications, (vii) no additional CCT funding, (viii) a 5.0% return on the prepaid pension asset and a return of 5.35% on the OPEB liability, and (ix) no disallowances on APS’s coal contracts.

The 2022 Rate Case ROO also recommended a number of changes to existing adjustors, including (i) the approval of modified DSM performance incentives and the requested DSM transfer to base rates, (ii) the retention of $1.9 million of REAC in the adjustor rather than base rates, (iii) a partial transfer of $27.1 million of LFCR funds to base rates, and (iv) the adoption of an increase in the annual PSA cap to $0.006/kWh.

On February 22, 2024, the ACC approved a number of amendments to the 2022 Rate Case ROO that resulted in, among other things, (i) an approximately $491.7 million increase in the annual base revenue requirement, (ii) a 9.55% return on equity, (iii) a 0.25% return on the increment of fair value rate base greater than original cost, (iv) an effective fair value rate of return of 4.39%, (v) a return set at the Company’s weighted average cost of capital on the net prepaid pension asset and net other post-employment benefit
liability in rate base, (vi) an adjustment to generation maintenance and outage expense to reflect a more reasonable level of test year costs, (vii) approval of the SRB mechanism with modifications to customer notifications, procedural timelines and the inclusion of any qualifying technology and fuel source bid received through an all-source request for proposal (“RFP”), and (viii) recovery of all DSM costs through the DSMAC rather than through base rates.

The ACC’s decision results in an expected total net annual revenue increase for APS of approximately $253.4 million and a roughly 8% increase to the typical residential customer’s bill. The ACC issued the final order for the 2022 Rate Case on March 5, 2024, with the new rates becoming effective for all service rendered on or after March 8, 2024.

Six intervenors and the Attorney General of Arizona requested rehearing on various issues included in the ACC’s decision, such as the grid access charge (“GAC”) for solar customers, the SRB, and CCT funding. On April 15, 2024, the ACC granted, in part, the rehearing applications of the Attorney General, Arizona Solar Energy Industries Association, Solar Energy Industries Association, and Vote Solar for the limited purpose of reviewing arguments concerning the GAC. Specifically, rehearing is ordered as to whether the GAC rate is just and reasonable, including whether it should be higher or lower, whether the GAC rate constitutes a discriminatory fee to solar customers, and whether omission of a GAC charge is discriminatory to non-solar customers. All other applications for rehearing were denied. The parties seeking rehearing have 30 days after the denial or granting of a request for rehearing to file a notice of appeal to the Arizona Court of Appeals. A procedural conference was held on April 26, 2024 for the purpose of discussing the procedural schedule for the matter. APS cannot predict the outcome of any subsequent proceedings.

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.

On November 2, 2021, the ACC approved the 2019 Rate Case ROO, with various amendments, that resulted in, among other things, (i) a return on equity of 8.70%, which included a 20-basis point penalty; (ii) the recovery of the deferral and rate base effects of the operating costs and construction of the Four Corners selective catalytic reduction (“SCR”) project, with the exception of $215.5 million (see “Four Corners SCR Cost Recovery” below); (iii) the CCT plan including 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; 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.

Consistent with the 2019 Rate Case decision, as of April 2024, APS has completed the following payments that will be recoverable through rates related to the CCT: (i) $10 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) $1.5 million to the Navajo Nation for CCT; (ii) $1.1 million to the Navajo County communities for CCT and economic
development; and (iii) $1.25 million to the Hopi Tribe for CCT and economic development. The ACC has also authorized $1.25 million to be recovered through rates for electrification of homes and businesses on both the Navajo Nation and Hopi reservation. Expenditure of the recoverable funds for electrification of homes and businesses on the Navajo Nation and the Hopi reservations is contingent upon completion of a census of the unelectrified homes and businesses in each that are also within APS service territory. The census work was completed in November 2022 and disbursement of the $1.25 million for electrification of homes and businesses is planned to be finalized after discussions with the Navajo Nation and the Hopi Tribe are completed. On February 22, 2024, the ACC voted to not approve any further CCT funding.

APS filed a Notice of Direct Appeal to the Arizona Court of Appeals on December 17, 2021 requesting review of certain aspects of the 2019 Rate Case. 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. The Court remanded the issue to the ACC for further proceedings.

On June 14, 2023, APS and the ACC Legal Division filed a joint resolution with the ACC to allow recovery of the $215.5 million in costs related to the installation of the Four Corners SCR, a reversal of the 20-basis point reduction to APS’s return on equity from 8.9% to 8.7% as a result of the 2019 Rate Case decision, and recovery of $59.6 million in revenue lost by APS between December of 2021 and June 20, 2023. On June 21, 2023, the ACC approved the joint resolution and proposals therein for recovery through the Court Resolution Surcharge (“CRS”) mechanism, which became effective on July 1, 2023. See “Court Resolution Surcharge” below for more information.

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. On February 22, 2024, the ACC voted to not approve any further CCT funding.

Regulatory Lag Docket

On January 5, 2023, the ACC opened a new docket to explore the possibility of modifications to the ACC’s historical test year rules. The ACC requested comments from utilities and interested parties on ways to reduce regulatory lag, including alternative ratemaking structures such as future test years and hybrid test years. APS filed comments on June 1, 2023. On March 19, 2024, the ACC held a workshop to discuss modifying the state’s rate case test year rules. Utilities, including APS, spoke about alternatives to the current rules that could reduce regulatory lag. The ACC plans to hold another workshop on this topic and has invited further comments from stakeholders. On April 19, 2024, a letter was filed to the docket by an ACC commissioner discussing the potential benefits of modifying test year rules, including the potentiality of
offering utilities to choose the type of test year that best suits them. The letter also recommended that this issue be discussed at the next possible open meeting. APS cannot predict the outcome of this matter.

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 modifications of adjustment mechanisms in the 2022 Rate Case.
 
Renewable Energy Standard.  In 2006, the ACC approved the renewable energy standard (“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.

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 Integrated Resource Plan (“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 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 included 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 supported existing approved projects and commitments and requested 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 ACC’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 proposed 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. On March 23, 2023, the ACC approved a policy statement that included information on how statewide community solar and storage programs should be structured, their location, and inclusion in RFPs. The remainder of the community solar program policy components were 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. On March 5, 2024, the ACC ordered APS to not expand or extend the
APS Solar Communities program. Consistent with that decision, the Solar Communities program has been discontinued and APS stopped enrolling new customers. APS will continue work on projects that were in the queue prior to that decision.

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 contained funding for programs to comply with ACC-approved initiatives, including the 2019 Rate Case decision. APS’s budget proposal supported existing approved projects and commitments and requested 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.

On June 30, 2023, APS filed its 2024 RES Implementation Plan and proposed a budget of approximately $95.1 million. APS’s budget proposal supports existing approved projects and commitments and requests a waiver of the RES renewable energy credit requirements to demonstrate compliance with the Annual Renewable Energy Requirement for 2023. The ACC has not yet ruled on the 2024 RES Implementation Plan.

Demand Side Management Adjustor Charge.  The ACC Electric Energy Efficiency Standards require APS to submit a DSM Implementation Plan annually for review and approval by the ACC. Verified energy savings from APS’s resource savings projects can be counted toward compliance with the Electric Energy Efficiency Standards; however, APS is not allowed to count savings from systems savings projects toward determination of the achievement of performance incentives, nor may APS include savings from these system savings projects in the calculation of its LFCR mechanism. See below for discussion of the LFCR.

On 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 June 1, 2022, APS filed its 2023 Transportation Electrification Plan (“2023 TE Plan”). The 2023 TE Plan detailed APS’s efforts to support transportation electrification in Arizona, including the Take Charge AZ Pilot Program and customer education and outreach related to transportation electrification. Subsequently, APS filed an amended 2023 TE Plan on November 30, 2022, that included a request for a $5 million budget. On December 12, 2023, the ACC approved the 2023 TE Plan without including the Take Charge AZ Program and its budget going forward, but allowed APS to complete projects already underway. Additionally, the ACC discontinued the residential EV SmartCharger rebate and approved modifications to the EV rate plan.

On November 30, 2022, APS filed its 2023 DSM Implementation Plan, which requested a budget of $88 million. On May 31, 2023, APS filed an amended 2023 DSM Implementation Plan. The amended plan maintained the originally proposed budget of $88 million. Subsequent to filing the amended 2023 DSM Implementation Plan and prior to the ACC approving it, on November 30, 2023, APS filed its 2024 DSM Implementation Plan. The 2024 DSM Implementation Plan requested a total budget of $91.5 million and incorporated all elements of the amended 2023 DSM Implementation Plan as well as the 2024 TE Implementation Plan. On April 26, 2024, APS filed an amendment to the 2024 DSM Implementation Plan. The amended 2024 DSM Implementation Plan includes an updated budget to reflect removal of all incentive funds for the EV Charging Demand Management Pilot, an update on the performance incentive calculation, and the withdrawal of tranches two and three of the residential battery pilot. The ACC has not yet ruled on the amended 2024 DSM Implementation Plan. APS cannot predict the outcome of this proceeding.
Power Supply Adjustor Mechanism and Balance.  The PSA provides for the adjustment of retail rates to reflect variations primarily in retail fuel and purchased power costs.  The PSA is subject to specified parameters and procedures, including the following:

•APS records deferrals for recovery or refund to the extent actual retail fuel and purchased power costs vary from the Base Fuel Rate;
•an adjustment to the PSA rate is made annually each February 1 (unless otherwise approved by the ACC) and goes into effect automatically unless suspended by the ACC;
•the PSA uses a forward-looking estimate of fuel and purchased power costs to set the annual PSA rate, which is reconciled to actual costs experienced for each PSA Year (February 1 through January 31) (see the following bullet point);
•the PSA rate includes (a) a “forward component,” under which APS recovers or refunds differences between expected fuel and purchased power costs for the upcoming calendar year and those embedded in the Base Fuel Rate; (b) a “historical component,” under which differences between actual fuel and purchased power costs and those recovered or refunded through the combination of the Base Fuel Rate and the forward component are recovered during the next PSA Year; and (c) a “transition component,” under which APS may seek mid-year PSA changes due to large variances between actual fuel and purchased power costs and the combination of the Base Fuel Rate and the forward component; and
•the PSA rate may not be increased or decreased more than $0.006 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 2024 and 2023 (dollars in thousands):
 Three Months Ended
March 31,
 20242023
Beginning balance$463,195 $460,561 
Deferred fuel and purchased power costs — current period33,094 90,305 
Amounts charged to customers(108,552)(80,904)
Ending balance$387,737 $469,962 

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 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 contained 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 found that APS’s fuel processing accounting practices, dispatching procedures, and procedures for hedging activity were reasonable and appropriate. The report included 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, 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. On November 30, 2023, APS notified the ACC that it will be maintaining the current PSA rate of $0.019074 per kWh and an updated PSA adjustment schedule would not be filed at that time. In Decision No. 79293 in the 2022 Rate Case, the ACC approved a permanent increase in the annual PSA adjustor rate cap from $0.004 per kWh to $0.006 per kWh and a requirement that APS report to the ACC for possible action when the overall PSA balance reaches $100 million. As part of the 2022 Rate Case decision, the ACC also approved an overall PSA rate of $0.011977 per kWh, which consisted of a forward component of $(0.012624) per kWh, a historical component of $0.013071 per kWh, and a transition component of $0.011530 per kWh. The rate became effective on March 8, 2024.

In accordance with the PSA Plan of Administration, APS is required to seek ACC approval to recover costs related to third-party energy storage systems through its PSA adjustment mechanism. In 2023, nine energy storage PPAs and their respective costs have been approved for recovery through the PSA. In 2022, one energy storage PPA and its costs was approved for recovery through the PSA. In 2021, four energy storage PPAs and their respective costs were approved for recovery through the PSA. However, one energy storage PPA that was approved in 2021 was later terminated by APS due to project delays.

Environmental Improvement Surcharge. On March 5, 2024, the ACC approved the elimination of the EIS, and the surcharge is no longer in effect. The EIS permitted 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.  APS’s February 1, 2023 EIS 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; however, with the elimination of the surcharge, it is no longer in effect.
 
Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters.  In July 2008, FERC approved a modification to APS’s Open Access Transmission Tariff to allow APS to move from fixed rates to a formula rate-setting methodology in order to more accurately reflect and recover the costs that APS incurs in providing transmission services.  A large portion of the rate represents charges for transmission services to serve APS’s retail customers (“Retail Transmission Charges”).  In order to recover the Retail Transmission Charges, APS was previously required to file an application with, and obtain approval from, the ACC to reflect changes in Retail Transmission Charges through the TCA.  Under the terms of the settlement agreement entered into in 2012 regarding APS’s rate case, 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 submitted 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, 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.

Effective June 1, 2023, APS’s annual wholesale transmission revenue requirement for all users of its transmission system increased by approximately $34.7 million for the 12-month period beginning June 1, 2023, in accordance with the FERC-approved formula. Of this net amount, wholesale customer rates increased by approximately $20.7 million and retail customer rates would have increased by approximately $14 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 $10 million, resulting in reductions to the residential and commercial rates. An adjustment to APS’s retail rates to recover FERC-approved transmission charges went into effect automatically on June 1, 2023.

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 distributed generation (“DG”) such as rooftop solar arrays. The adjustment to the LFCR 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.
 
As a result of the 2019 Rate Case decision, the fixed costs recoverable by the LFCR mechanism were set at 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. APS’s annual LFCR adjustor rate is dependent on an annual earnings test filing, which compares 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. As a result of certain changes made to the LFCR mechanism in the 2019 Rate Case decision, the mechanism no longer qualifies for alternative revenue program accounting treatment.

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 a $11.8 million balance from APS’s 2021 LFCR 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. On September 5, 2023, APS filed an updated LFCR Plan of Administration, which was approved by ACC Staff on December 8, 2023. On July 31, 2023, APS filed its 2023 annual LFCR adjustment, requesting that the annual LFCR recovery amount be increased to $68.7 million (a $9.6 million increase from previous levels). On October 19, 2023, a request for intervention was filed, which was granted. Consistent with an October 25, 2023, Procedural Order, the parties met and conferred and conducted limited discovery. As a result of Decision No. 79293 in the 2022 Rate Case, APS transferred $27.1 million from the LFCR to base rates.

On March 8, 2024, APS filed conforming LFCR schedules to incorporate changes required as a result of Decision No. 79293 in the 2022 Rate Case. On April 9, 2024, the ACC approved the 2023 annual LFCR adjustment, with new rates effective in the first billing cycle of May 2024.

Tax Expense Adjustor Mechanism.  The TEAM helps 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. As part of the 2019 Rate Case decision, the TEAM rates were reset to zero beginning December 31, 2021. The TEAM was retained in the 2022 Rate Case to address potential changes in tax law that may be enacted prior to a decision in a subsequent APS rate case.

Court Resolution Surcharge. The CRS mechanism permits APS to recover certain costs associated with investments and expenses for APS’s purchase and installation of SCR technology for Four Corners Units 4 and 5 and a change in APS’s allowable return on equity as required by the Arizona Court of Appeals and approved by the ACC in Decision No. 78979. The CRS went into effect on July 1, 2023 at a rate of $0.00175 per kWh. The rate is designed to recover $59.6 million in revenue lost by APS between December of 2021 and June 20, 2023, and the prospective recovery of ongoing costs related to the SCR investments and expense and the allowable return on equity difference in current base rates. The portion of the CRS representing the recovery of the $59.6 million of lost revenue between December of 2021 and June 20, 2023, $12.7 million of which has been collected as of March 31, 2024, will cease upon full collection of the lost revenue. Additionally, the CRS tariff was updated to remove the return on equity component and account for SCR-
related depreciation and deferral adjustments approved in Decision No. 79293 in the 2022 Rate Case. See “2019 Retail Rate Case” above for more information.

Net Metering

The ACC’s decision from APS’s 2017 rate case (the “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 Resource Comparison Proxy (“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.

On April 29, 2022, APS filed an application to decrease the RCP price from 9.4 cents per kWh, which had been in effect since October 1, 2021, 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.

On May 1, 2023, APS filed an application for revisions to the RCP. This application would decrease the RCP price to 7.619 cents per kWh, reflecting a 10% annual reduction, to become effective September 1, 2023. On August 25, 2023, the ACC approved the RCP as filed.

On October 11, 2023, the ACC voted to open a new general docket to hold a hearing to explore potential future changes to the 10% annual reduction cap in the solar export rate paid by utilities to distributed solar customers for exports to the grid and the 10-year rate lock period for those customers that were approved in the ACC’s Value and Cost of Distributed Generation Docket. A procedural conference was held on November 1, 2023, to discuss the process going forward. As a result of the procedural conference, ACC Staff issued a request for information to investigate the issues related to this matter. A status conference was held on March 20, 2024, to determine if ACC Staff is prepared to present a recommendation on this matter at that time. Stakeholders provided responses to the ACC Staff’s request for information on March 21, 2024. Another status conference has been scheduled for May 20, 2024 to discuss next steps. The amounts APS pays
customers for solar exports under its RCP rate rider could be affected by this docket. APS cannot predict the outcome of this matter.

Energy Modernization Plan

On May 26, 2023, the ACC opened a new docket to review articles within the Arizona Administrative Code related to Resource Planning, the Renewable Energy Standard and Tariff, and Electric Energy Efficiency Standards. On January 9, 2024, the ACC approved a rulemaking process for this matter. During the ACC Open Meeting on February 6, 2024, the ACC approved motions to direct ACC Staff to include recommendations to repeal the current Electric Energy Efficiency and Renewable Energy Standard rules during the rulemaking process. 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 time frame. 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.

On May 1, 2023, APS, Tucson Electric Power Company, and UNS Electric, Inc. filed a joint request for an extension to file the IRPs from August 1, 2023, to November 1, 2023. On June 21, 2023, the ACC granted the extension. As a result, APS filed its 2023 IRP on November 1, 2023. On January 31, 2024, stakeholders filed comments regarding the IRP and APS has until May 31, 2024 to respond to the stakeholders’ comments. APS cannot predict the outcome of this matter. See “Energy Modernization Plan” above for information regarding proposed changes to the IRP filings.

Equity Infusions

On October 27, 2023, APS filed a notice of intent to increase Pinnacle West’s equity in APS in 2024. APS is currently authorized to receive up to $150 million annually in equity infusions from Pinnacle West without seeking ACC approval. APS sought approval under Arizona Administrative Code provision R14-2-803 to receive from Pinnacle West in 2024 up to $500 million in additional equity infusions above the currently authorized limit of $150 million annually. On January 9, 2024, the ACC approved the increased equity infusion limit for 2024.

On April 19, 2024, APS submitted a request to the ACC to permanently modify Pinnacle West’s permitted yearly equity infusions to equal up to 2.5% of Pinnacle West’s consolidated assets each calendar year on a three-year rolling average basis. APS cannot predict the outcome of this matter.

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 19, 2023, the agreements for these two PPAs were terminated due to project delays.

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 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. However, on May 17, 2023, the Retail Energy Supply Association filed a motion with the ACC requesting it to re-open the generic docket to re-examine the ACC’s electric competition rules. No action has been taken by the ACC regarding this motion. APS cannot predict the outcome of these matters.

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.

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. On June 21, 2023, the ACC approved a joint settlement filed by APS and the ACC’s Legal Division that resolved all issues relating to the 2019 Rate Case decision, including recovery of the cost of the Four Corners SCRs. 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 U.S. 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. APS is allowed continued recovery of the net book value of the unit and the unit’s decommissioning and other retirement-related costs, $31.5 million as of March 31, 2024, 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, $40.6 million as of March 31, 2024, 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, $10.1 million as of March 31, 2024. 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, 2024December 31, 2023
Pension(a)$686,379 $696,476 
Deferred fuel and purchased power (b) (c)2025387,737 463,195 
Income taxes — allowance for funds used during construction (“AFUDC”) equity2054189,211 189,058 
Deferred fuel and purchased power — mark-to-market (Note 7)
2026154,658 120,214 
Ocotillo deferral2034125,908 128,636 
SCR deferral (e)203887,576 89,477 
Retired power plant costs203379,747 83,536 
Lease incentives(g)54,543 46,615 
Income taxes — investment tax credit basis adjustment205636,017 34,230 
Deferred compensation203633,923 33,972 
Deferred property taxes202730,345 32,488 
Palo Verde VIEs (Note 6)
204620,732 20,772 
Active Union Medical Trust(f)13,809 12,747 
Navajo coal reclamation202610,139 10,883 
Mead-Phoenix transmission line contributions in aid of construction (“CIAC”)20508,633 8,716 
Loss on reacquired debt20387,644 7,965 
Four Corners cost deferral20245,903 7,922 
Tax expense adjustor mechanism (b)20315,026 5,190 
FERC Transmission true up20264,313 616 
Power supply adjustor - interest20253,105 19,416 
OtherVarious4,781 3,912 
Total regulatory assets (d) $1,950,129 $2,016,036 
Less: current regulatory assets$578,869 $625,757 
Total non-current regulatory assets$1,371,260 $1,390,279 

(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. The 2022 Rate Case decision allows for the full return on the pension asset in rate base. 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)See “Four Corners SCR Cost Recovery” discussion above.
(f)Collected in retail rates.
(g)Amortization periods vary based on specific terms of lease contract.
The detail of regulatory liabilities is as follows (dollars in thousands):
 Amortization ThroughMarch 31, 2024December 31, 2023
Excess deferred income taxes - ACC — Tax Cuts and Jobs Act (a)2046$929,197 $930,344 
Excess deferred income taxes - FERC — Tax Cuts and Jobs Act (a)2058214,466 214,667 
Asset retirement obligations2057411,393 392,383 
Other postretirement benefits(c)215,298 226,726 
Removal costs(d)90,082 94,368 
Income taxes — deferred investment tax credit205668,442 68,521 
Income taxes — change in rates205360,589 60,667 
Four Corners coal reclamation203856,557 55,917 
Renewable energy standard (b)202451,001 43,251 
Spent nuclear fuel202731,552 33,154 
Demand side management (b)202420,905 14,374 
Sundance maintenance203120,763 19,989 
Property tax deferral20279,541 10,850 
Tax expense adjustor mechanism (b)20324,796 4,835 
FERC transmission true up (b)2026— 1,869 
OtherVarious3,090 3,873 
Total regulatory liabilities $2,187,672 $2,175,788 
Less: current regulatory liabilities$221,552 $209,923 
Total non-current regulatory liabilities$1,966,120 $1,965,865 

(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)See Note 5.
(d)In accordance with regulatory accounting, APS accrues removal costs for its regulated assets, even if there is no legal obligation for removal.
v3.24.1.u1
Retirement Plans and Other Postretirement Benefits
 3 Months Ended
Mar. 31, 2024
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,
 2024202320242023
Service cost — benefits earned during the period$10,631 $10,157 $2,459 $2,120 
Non-service costs (credits):
Interest cost on benefit obligation37,236 38,362 5,613 5,673 
Expected return on plan assets(46,983)(45,561)(11,709)(10,872)
  Amortization of:   
  Prior service credit (a)— — (9,447)(9,447)
  Net actuarial loss/(gain)10,944 9,713 (2,080)(2,303)
Net periodic cost/(benefit)$11,828 $12,671 $(15,164)$(14,829)
Portion of cost/(benefit) charged to expense$6,337 $7,227 $(11,306)$(10,737)
 
(a)Prior-service costs or credits reflect the impact of modifications to the pension or postretirement plan benefits. The impact of these modifications is amortized over a period which reflects the demographics of the impacted population. In 2014, Pinnacle West made changes to the postretirement benefits offered to Medicare eligible retirees, which resulted in prior-service credits. We have been amortizing these prior-serviced credits since 2015 with the last full-year amortization occurring in 2024.

Contributions
 
We have not made any voluntary contributions to our pension plan year-to-date in 2024. 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 2024, 2025 or 2026. With regard to contributions to our other postretirement benefit plan, we have not made a contribution year-to-date in 2024 and do not expect to make any contributions in 2024, 2025 or 2026.
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Palo Verde Sale Leaseback Variable Interest Entities
 3 Months Ended
Mar. 31, 2024
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 variable interest entities (“VIEs”) 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 2024 through 2033. At the end of the lease period, APS will have the option to purchase the leased assets at their fair market value, extend the leases for up to two years, or return the assets to the lessors.

The leases’ terms give APS the ability to utilize the assets for a significant portion of the assets’ economic life, and therefore provide APS with the power to direct activities of the VIEs that most significantly impact the VIEs’ economic performance.  Predominantly due to the lease terms, APS has been deemed the primary beneficiary of these VIEs and therefore consolidates the VIEs.

As a result of consolidation, we eliminate lease accounting and instead recognize depreciation expense, resulting in an increase in net income of $4 million for both the three months ended March 31, 2024 and 2023.
The increase in net income is entirely attributable to the noncontrolling interests. Income attributable to Pinnacle West shareholders is not impacted by the consolidation.

Our Condensed Consolidated Balance Sheets include the following amounts relating to the VIEs (dollars in thousands):
 March 31, 2024December 31, 2023
Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation$85,459 $86,426 
Equity — Noncontrolling interests111,504 107,198 
 
Assets of the VIEs are restricted and may only be used for payment to the noncontrolling interest holders. These assets are reported on our condensed consolidated financial statements.

APS is exposed to losses relating to these VIEs upon the occurrence of certain events that APS does not consider to be reasonably likely to occur. Under certain circumstances (for example, the 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 $334 million beginning in 2024, and up to $501 million over the lease extension terms.

For regulatory ratemaking purposes, the agreements continue to be treated as operating leases and, as a result, we have recorded a regulatory asset relating to the arrangements.
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Derivative Accounting
 3 Months Ended
Mar. 31, 2024
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.
See Note 10 for details relating to Pinnacle West’s Equity Forward Sale Agreements that are classified as equity transactions. These equity transactions are indexed to Pinnacle West common stock and qualify for a derivative scope exception. These equity transactions are not subject to mark-to-market accounting and are excluded from the derivative disclosures below.
 
Energy Derivatives

For its regulated operations, APS defers for future rate treatment 100% of the unrealized gains and losses on energy derivatives pursuant to the PSA mechanism that would otherwise be recognized in income.  Realized gains and losses on energy derivatives are deferred in accordance with the PSA to the extent the amounts are above or below the Base Fuel Rate. See Note 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, 2024December 31, 2023
PowerGWh2,097 1,212 
GasBillion cubic feet235 200 
 
Gains and Losses from Energy Derivative Instruments
 
For the three months ended March 31, 2024 and 2023, 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 Contracts20242023
Net Loss Recognized in IncomeFuel and purchased power (a)$(55,942)$(188,930)
 
(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 APS’s risk management activities reported on a gross basis and the impacts of offsetting.  These amounts relate to commodity contracts and are located in the assets and liabilities from risk management activities lines of APS’s Condensed Consolidated Balance Sheets.
As of March 31, 2024:
(dollars in thousands)
Gross
 Recognized
 Derivatives
 (a)
Amounts
Offset
 (b)
Net
 Recognized
 Derivatives
Other
 (c)
Amounts Reported on Balance Sheets
Current assets$73 $— $73 $5 $78 
Investments and other assets— — — — — 
Total assets73 — 73 5 78 
Current liabilities(119,859)13,100 (106,759)(6,771)(113,530)
Deferred credits and other(34,872)— (34,872)— (34,872)
Total liabilities(154,731)13,100 (141,631)(6,771)(148,402)
Total$(154,658)$13,100 $(141,558)$(6,766)$(148,324)

(a)All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)Includes cash collateral provided to counterparties of $13,100 thousand 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 $6,771 thousand and cash margin provided to counterparties of $5 thousand.
As of December 31, 2023:
(dollars in thousands)
Gross
Recognized
Derivatives
 (a)
Amounts
Offset
(b)
Net
 Recognized
 Derivatives
Other
 (c)
Amounts
Reported on
Balance Sheets
Current assets$8,497 $(1,694)$6,803 $5 $6,808 
Investments and other assets— — — — — 
Total assets8,497 (1,694)6,803 5 6,808 
Current liabilities(85,736)10,894 (74,842)(6,071)(80,913)
Deferred credits and other(42,975)— (42,975)— (42,975)
Total liabilities(128,711)10,894 (117,817)(6,071)(123,888)
Total$(120,214)$9,200 $(111,014)$(6,066)$(117,080)

(a)All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)Includes cash collateral provided to counterparties of $9,200 thousand 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 $6,071 thousand and cash margin provided to counterparties of $5 thousand.

Credit Risk and Credit Related Contingent Features
 
We are exposed to losses in the event of nonperformance or nonpayment by energy derivative counterparties and have risk management contracts with many energy derivative counterparties. As of March 31, 2024, we have no counterparties with positive exposures of greater than 10% of Pinnacle West’s risk management assets. Our risk management process assesses and monitors the financial exposure of all counterparties.  Despite the fact that the great majority of our trading counterparties’ debt is rated as investment grade by the credit rating agencies, there is still a possibility that one or more of these counterparties could default, resulting in a material impact on consolidated earnings for a given period. Counterparties in the portfolio consist principally of financial institutions, major energy companies, municipalities and local distribution companies.  We maintain credit policies that we believe minimize overall credit risk to within acceptable limits.  Determination of the credit quality of our counterparties is based upon a number of factors, including credit ratings and our evaluation of their financial condition.  To manage credit risk, we employ collateral requirements and standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty.  Valuation adjustments are established representing our estimated credit losses on our overall exposure to counterparties.
 
Certain of our energy derivative instrument contracts contain credit-risk-related contingent features including, among other things, investment grade credit rating provisions, credit-related cross-default provisions, and adequate assurance provisions.  Adequate assurance provisions allow a counterparty with reasonable grounds for uncertainty to demand additional collateral based on subjective events and/or conditions.  For those energy derivative instruments in a net liability position, with investment grade credit contingencies, the counterparties could demand additional collateral if our debt credit rating were to fall below investment grade (below BBB- for Standard & Poor’s or Fitch or Baa3 for Moody’s).
 
The following table provides information about our energy derivative instruments that have credit-risk-related contingent features (dollars in thousands):
 March 31, 2024
Aggregate fair value of derivative instruments in a net liability position$154,731 
Cash collateral posted13,100 
Additional cash collateral in the event credit-risk-related contingent features were fully triggered (a)127,607 
(a)This amount is after counterparty netting and includes those contracts which qualify for scope exceptions, which are excluded from the derivative details above.

We also have energy-related non-derivative instrument contracts with investment grade credit-related contingent features, which could also require us to post additional collateral of approximately $206 million if our debt credit ratings were to fall below investment grade.
v3.24.1.u1
Commitments and Contingencies
 3 Months Ended
Mar. 31, 2024
Commitments and Contingencies Disclosure [Abstract]  
Commitments and Contingencies Commitments and Contingencies
 
Palo Verde Generating Station
 
Spent Nuclear Fuel and Waste Disposal
 
On December 19, 2012, APS, acting on behalf of itself and the participant owners of Palo Verde, filed a second breach of contract lawsuit against the U.S. Department of Energy (“DOE”) in the U.S. 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 nine claims pursuant to the terms of the August 18, 2014 settlement agreement, for nine separate time periods during July 1, 2011 through October 31, 2022. The DOE has approved and paid $138.2 million for these claims (APS’s share is $40.2 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, 2023, APS filed its tenth claim pursuant to the terms of the August 18, 2014, settlement agreement in the amount of $18.46 million (APS’s share is $5.4 million). On March 21, 2024, the DOE approved a payment in the amount of $18.39 million (APS’s share is $5.4 million), and payment is anticipated in the second quarter of 2024.

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.  This insurance limit is subject to an adjustment every five years based upon the aggregate percentage change in the Consumer Price Index. The most recent adjustment took effect on January 1, 2024. As of that
date, in accordance with the Price-Anderson Act, the Palo Verde participants are insured against public liability for a nuclear incident up to approximately $16.3 billion per occurrence. Palo Verde maintains the maximum available nuclear liability insurance in the amount of $500 million, which is provided by American Nuclear Insurers.  The remaining balance of approximately $15.8 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 $165.9 million, subject to a maximum annual premium of approximately $24.7 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 $144.9 million, with a maximum annual retrospective premium of approximately $21.6 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 $23.1 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 $64.1 million in deposit premium within 20 days of request as assurance to satisfy any site obligation of retrospective premium assessment.  The insurance coverage discussed in this, and the previous paragraph, is subject to certain policy conditions, sublimits, and exclusions.

Fuel and Purchased Power Commitments and Purchase Obligations

As of March 31, 2024, our fuel and purchased power and purchase obligation commitments have increased by $295 million from the information provided in our 2023 Form 10-K. The change is primarily due to new purchased power commitments. The majority of the changes relate to 2026 and thereafter.

At March 31, 2024, we have various lease arrangements that have been executed but have not yet commenced. These arrangements primarily relate to energy storage assets, with expected lease commencement dates ranging from June 2024 through June 2025, with terms expiring through May 2045. We expect the total fixed consideration paid for these arrangements, which includes both lease and nonlease payments, will approximate $7.1 billion over the term of the arrangements. The lease commencement dates for these leased assets have experienced delays. APS continues to work with the lessors to determine the revised commencement dates that will be achieved. For additional information regarding our lease commitments, see our 2023 Form 10-K.

Other than the items described above, there have been no material changes, as of March 31, 2024, outside the normal course of business in contractual obligations from the information provided in our 2023 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.

In connection with APS’s status as a PRP for OU3, since 2013 APS and at least two dozen other parties have been defendants in various CERCLA lawsuits stemming from allegations that contamination from OU3 and elsewhere has impacted groundwater wells operated by the Roosevelt Irrigation District (“RID”). At this time, only one active lawsuit remains pending, which is on appeal to the U.S. Court of Appeals for the Ninth Circuit based on a U.S. District Court order dismissing cost recovery claims of approximately $20.7 million by a service provider for RID. APS is unable to predict the outcome of any further litigation related to this claim or APS’s share of liability related to that claim; however, APS does 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. APS estimates that its costs to oversee and participate in the remedial investigation work will be approximately $1.7 million. At the present time, we are unable to predict the outcome of this matter and any further expenditures related to necessary remediation, if any, or further investigations cannot be reasonably estimated.

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 could 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 the 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 the Arizona Department of Environmental Quality (“ADEQ”) has taken steps to develop a CCR permitting program, and new state legislation has been adopted 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, which would impact facilities like Four Corners located on the Navajo Nation. 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 2024.

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 our financial condition, results of operations, or cash flows.

On April 25, 2024, EPA took final action on a proposal to expand the scope of federal CCR regulations to address the impacts from historical CCR disposal activities that would have ceased prior to 2015. This new class of CCR management units (“CCRMUs”), which contain at least 1,000 tons of CCR, broadly encompass any location at an operating coal-fired power plant where CCR would have been placed on land. As proposed, this would include not only historically closed landfills and surface impoundments but also prior applications
of CCR beneficial use (with exceptions for historical roadbed and embankment applications). Existing CCR regulatory requirements for groundwater monitoring, corrective action, closure, post-closure care, and other requirements will be imposed on such CCRMUs. At this time, APS is still evaluating the impacts of this final regulation on its business, with initial CCRMU site surveys due to be completed within 21 months following publication of this final regulation in the Federal Register. Depending on the outcome of that evaluation, the costs associated with APS’s management of CCR could materially increase, which could affect our financial condition, results of operations, or cash flows.

APS currently disposes of CCR in ash ponds and dry storage areas at Cholla and Four Corners. The Navajo Plant disposed of CCR only in a dry landfill storage area. 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. APS’s estimates for its share of corrective action and monitoring costs at Four Corners and Cholla are captured within the Asset Retirement Obligations. 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 condition, results of operations, or cash flows.

EPA Power Plant Carbon Regulations. EPA’s regulation of carbon dioxide emissions from electric utility power plants has proceeded in fits and starts over most of the last decade. Starting on August 3, 2015, EPA finalized the Clean Power Plan, which was the Agency’s first effort at such regulation through system-wide generation dispatch shifting. Those regulations were subsequently repealed by the EPA on June 19, 2019 and replaced by the Affordable Clean Energy (“ACE”) regulations, which were a far narrower set of rules. While the U.S. Court of Appeals for the D.C. Circuit subsequently vacated the ACE regulations on January 19, 2021, and ordered a remand for EPA to develop replacement regulations consistent with the original 2015 Clean Power Plan, the U.S. Supreme Court subsequently reversed that decision on June 30, 2022, holding that the Clean Power Plan exceeded EPA’s authority under the Clean Air Act.

In the final regulations governing power plant carbon dioxide emissions, released April 25, 2024, EPA issued emission standards and guidelines for various subcategories of new and existing power plants. Unlike EPA’s Clean Power Plan regulations from 2015, which took a broad, system-wide approach to regulating carbon emissions from electric utility fossil-fuel burning power plants, these new federal regulations are limited to measures that can be installed at individual power plants to limit planet-warming carbon-dioxide emissions.

As such, for new natural gas-fired combustion turbine power plants, EPA is proposing that carbon emission performance standards apply based on the annual capacity factors. For the highest utilization combustion turbines, EPA is therefore proposing that such facilities be retrofitted for carbon capture and sequestration or utilization controls (“CCS”) by 2032. For intermediate or low-load natural gas fired combustion turbines, those with 40% or less capacity factors, EPA’s regulations would not require add-on pollution controls. Instead, natural gas-fired combustion turbines with capacity factors of up to 20% would be effectively unregulated, while such turbines with capacity factors over 20% and up to 40% would be subject to
carbon dioxide emission rate limitations. EPA did not finalize standards for existing natural gas-fired combustion turbines but has indicated that it will propose a new set of standards, initiating a separate rulemaking, for these existing gas-fired power plants within the next year.

For coal-fired power plants, instead of imposing regulations based on capacity and utilization, EPA has finalized subcategories based on planned retirement dates. This means that facilities retiring before 2032 are effectively exempt from regulation, those that retire between 2032 and 2038 must co-fire with natural gas starting in 2030, and those that retire in 2039 or later must install CCS controls by 2032.

At this time, APS continues to assess the recently finalized EPA carbon emission standards and cannot yet predict their potential impact on APS’s operations. The costs associated with APS’s operation of its current thermal plants and construction and operation of future facilities could materially increase, which could affect our financial condition, results of operations, or cash flows.

Effluent Limitation Guidelines. EPA published effluent limitation guidelines (“ELG”) on October 13, 2020, and, based off those guidelines, APS completed a National Pollutant Discharge Elimination System (“NPDES”) permit modification for Four Corners on December 1, 2023. The ELG standards finalized in October of 2020 relaxed the “zero discharge” standard for bottom ash transport waters EPA finalized in September of 2015. However, on April 25, 2024, EPA finalized new ELG regulations that once again require “zero discharge” standards for flows of bottom ash transport water at power plants like Four Corners. Nonetheless, for power plants that permanently cease operations by December 31, 2034, such facilities can continue to comply with the 2020 ELG standards. APS is currently evaluating its compliance options for Four Corners based on the ELG regulations finalized in April 2024 and is assessing what impacts the new standards will have on our financial condition, results of operations, or cash flows.

EPA Good Neighbor Proposal for Arizona. On March 15, 2023, EPA issued its final Good Neighbor Plan for 23 states in order to ensure that the cross-state transport of ozone forming emissions does not interfere with downwind state compliance with the National Ambient Air Quality Standards (“NAAQS”). Thermal power plant emission limitations are a key aspect of these regulations, which involve emission allowance trading for nitrogen oxide (“NOx”) emissions. While Arizona was not among the 23 states subject to EPA’s March 2023 final action, EPA announced on January 23, 2024 that it was proposing to add Arizona and New Mexico (along with two other additional states) to EPA’s NOx emission allowance trading program finalized last year. Since APS operates thermal power plants within Arizona and those portions of the Navajo Nation within New Mexico, APS’s power plants would be subject to EPA’s Good Neighbor Plan upon finalization of this proposal. APS cannot predict the outcome of EPA’s proposal or the extent to which such regulations, if finalized, could materially impact our financial condition, results of operations, or cash flows.

Revised Mercury and Air Toxics Standard (“MATS”) Proposal. On April 25, 2024, EPA finalized revisions to the existing MATS regulations governing emissions of toxic air pollution from existing coal-fired power plants. The final regulations increase the stringency of filterable particulate matter limits used to demonstrate compliance with MATS and require the use of continuous emissions monitoring systems to ensure compliance (as opposed to periodic performance testing). These final regulations will take effect for existing coal-fired power plants, such as Four Corners, within three years of publication in the Federal Register. APS continues to evaluate this new regulation and its impact on Four Corners. Depending on the outcome of that assessment, the costs associated with APS’s controls for filterable particulate matter could materially increase, which could affect APS’s financial position, results of operations, or cash flows.

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 APS does not expect the outcome to have a material impact on our financial condition, results of operations, or cash flows.

BCE Kūpono Solar

BCE and Ameresco jointly owned 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. In connection with the financing, Pinnacle West has issued performance guarantees relating to the project. Investments in the Kūpono Solar Project are included in the BCE Sale which closed on January 12, 2024. As a result of the BCE Sale, on March 31, 2024, Pinnacle West holds no equity or ownership interest in the Kūpono Solar Project. Subsequent to the BCE Sale, Pinnacle West continues to maintain the performance guarantees relating to the Kūpono Solar Project financing (see additional information below regarding these guarantees). See Note 14 for information relating to the BCE Sale.

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, 2024, standby letters of credit totaled approximately $35 million and surety bonds totaled approximately $21 million; both will expire through 2025. 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, 2024. In connection with the sale of 4C Acquisition, LLC’s 7% interest to Navajo Transitional Energy Corporation (“NTEC”), Pinnacle West is guaranteeing certain obligations that NTEC will have to the other owners of Four Corners. 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 PNW Power’s investments in minority ownership positions in the Clear Creek wind farm in Missouri and Nobles 2 wind farm in Minnesota, Pinnacle West has guaranteed the obligations of PNW Power 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, 2024, there is approximately $31 million of remaining guarantees relating to these PTC Guarantees that are expected to terminate by 2030.

Pinnacle West has issued various performance guarantees in connection with the Kūpono Solar Project investment financing and is exposed to losses relating to these guarantees upon the occurrence of certain events that we do not consider to be reasonably likely to occur. Subsequent to the BCE Sale, Pinnacle West continues to maintain these performance guarantees. See Note 14. Pinnacle West has not needed to perform under these guarantees. Maximum obligations are not explicitly stated in the guarantees and cannot be reasonably estimated. We consider the fair value of these guarantees, including expected credit losses, to be immaterial. The details of the guarantees are as follows:

•Upon the BCE Sale closing, on January 12, 2024, Pinnacle West committed to certain performance guarantees tied to the Kūpono project achieving certain construction and operation milestones. These performance guarantees will expire when the Kūpono project achieves commercial operation, which is expected in May 2024. If the Kūpono project is unable to achieve commercial operation, Pinnacle West may incur losses relating to these guarantees. The guarantees provide support relating to the $140 million Kūpono construction financing agreements, described above. As of March 31, 2024, we cannot reasonably estimate the range of loss that may occur; however, the likelihood of any payment under these guarantees is considered remote.
•When the Kūpono financing converts to a sale leaseback agreement, which is expected to occur upon commercial operation of the project, Pinnacle West has committed to certain performance guarantees that may apply upon the occurrence of specified events (such as uninsured loss events). Ameresco has agreed to make efforts to refinance the project and eliminate these guarantees prior to 2030.

•Ameresco is obligated to reimburse Pinnacle West for any payments made by Pinnacle West under such guarantees.
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Other Income and Other Expense
 3 Months Ended
Mar. 31, 2024
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,
20242023
Other income:
Interest income (a)$7,560 $6,026 
Gain on sale of BCE (Note 14)
22,988 — 
Miscellaneous59 51 
Total other income$30,607 $6,077 
Other expense:
Non-operating costs$(6,150)$(2,640)
Investment losses — net(777)(1,061)
Miscellaneous(640)(430)
Total other expense$(7,567)$(4,131)

(a)     The 2023 and 2024 Interest income is primarily related to PSA Interest. See Note 4.
The following table provides detail of APS’s other income and other expense (dollars in thousands):

 Three Months Ended
March 31,
 20242023
Other income:  
Interest income (a)$6,796 $5,024 
Miscellaneous59 51 
Total other income$6,855 $5,075 
Other expense: 
Non-operating costs$(2,255)$(2,188)
Miscellaneous(639)(429)
Total other expense$(2,894)$(2,617)

(a)     The 2023 and 2024 Interest income is primarily related to PSA Interest. See Note 4.
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Earnings Per Share and Equity Forward Sale Agreements
 3 Months Ended
Mar. 31, 2024
Earnings Per Share [Abstract]  
Earnings Per Share and Equity Forward Sale Agreements Earnings Per Share and Equity Forward Sale Agreements
On February 28, 2024, Pinnacle West executed the Equity Forward Sale Agreements, which allow Pinnacle West to issue a fixed number of Pinnacle West common shares to be settled in the future. The Equity Forward Sale Agreements relate to an aggregate of 11,240,601 shares of Pinnacle West common stock that may be settled at our discretion no later than September 4, 2025. The forward sale price was initially $64.51 per share and is subject to certain adjustments in accordance with the terms of the Equity Forward Sale Agreements through the date of settlements. On a settlement date, Pinnacle West will issue shares of common stock and receive cash at the then-applicable forward sale price.

As of March 31, 2024, the Equity Forward Sale Agreements have not been settled. At March 31, 2024, Pinnacle West could have settled the Equity Forward Sale Agreements with the issuance of 11,240,601 shares of common stock in exchange for cash of $728 million. We will not receive any proceeds from the Equity Forward Sale Agreements until the settlement with shares occurs, and upon settlement, we will record the proceeds, if any, in equity. The terms of the Equity Forward Sale Agreements also allow Pinnacle West, at our option, to settle the Equity Forward Sale Agreements with the counterparties by delivering cash, in lieu of shares.

We have classified the Equity Forward Sale Agreements as an equity transaction. As a result, no amounts have been recorded on the Condensed Consolidated Balance Sheets relating to the Equity Forward Sale Agreements as of March 31, 2024. Delivery of shares to settle the Equity Forward Sale Agreements will eventually result in dilution to basic earnings per share (“EPS”) upon settlement. Prior to settlement, the potentially issuable shares are reflected in our diluted EPS calculations using the treasury stock method. Under this method, the number of shares of Pinnacle West common stock used in calculating diluted EPS for a reporting period is increased by the number of shares, if any, that would be issued upon settlement less that number of shares that could be purchased by Pinnacle West in the market with the proceeds received from issuance (based on the average market price during that reporting period). Share dilution occurs when the average market price of our stock during the reporting period is higher than the adjusted forward sale price as of the end of the reporting period.
The following table presents the calculation of Pinnacle West’s basic and diluted EPS (in thousands, except per share amounts):
 Three Months Ended March 31,
 20242023
Net income (loss) attributable to common shareholders$16,862 $(3,297)
Weighted average common shares outstanding — basic
113,621 113,358 
Net effect of dilutive securities:
Contingently issuable performance shares and restricted stock units327 239 
Dilutive shares related to equity forward sale agreements279 — 
Total contingently issuable shares606 239 
Weighted average common shares outstanding — diluted
114,227 113,597 
Earnings per weighted-average common share outstanding:
Net income (loss) attributable to common shareholders — basic$0.15 $(0.03)
Net income (loss) attributable to common shareholders — diluted$0.15 $(0.03)

For the three months ended March 31, 2023, 239,000 shares were excluded from the calculation of diluted weighted average common shares outstanding, as their inclusion would have been antidilutive. The net income attributable to common shareholders was calculated using the weighted average number of common shares outstanding of 113,537,689. For the three months ended March 31, 2024, no shares were excluded from the calculation of diluted weighted average common shares outstanding.
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Fair Value Measurements
 3 Months Ended
Mar. 31, 2024
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 2023 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.  Long-dated energy transactions may consist of observable valuations for the near-term portion and unobservable valuations for the long-term portions of the transaction.  We rely primarily on broker quotes to value these instruments.  When our valuations utilize broker quotes, we perform various control procedures to ensure the quote has been developed consistent with fair value accounting guidance.  These controls include assessing the quote for reasonableness by comparison against other broker quotes, reviewing historical price relationships, and assessing market activity.  When broker quotes are not available, the primary valuation technique used to
calculate the fair value is the extrapolation of forward pricing curves using observable market data for more liquid delivery points in the same region and actual transactions at more illiquid delivery points.
 
When the unobservable portion is significant to the overall valuation of the transaction, the entire transaction is classified as Level 3. 
 
Investments Held in Nuclear Decommissioning Trusts and Other Special Use Funds

The nuclear decommissioning trusts and other special use funds invest in fixed income and equity securities. Other special use funds include the coal reclamation escrow account and the active union employee medical account. See Note 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, 2024, 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$15 $— $— $— $15 
Risk management activities — derivative instruments:
Commodity contracts— — 73 5 (a)78 
Nuclear decommissioning trust:
Equity securities9,590 — — 2,129 (b)11,719 
U.S. commingled equity funds— — — 384,687 (c)384,687 
U.S. Treasury debt343,985 — — —  343,985 
Corporate debt— 218,595 — —  218,595 
Mortgage-backed securities— 214,514 — —  214,514 
Municipal bonds— 52,053 — —  52,053 
Other fixed income— 13,471 — —  13,471 
Subtotal nuclear decommissioning trust353,575 498,633 — 386,816 1,239,024 
Other special use funds:
Equity securities46,665 — — 1,423 (b)48,088 
U.S. Treasury debt316,137 — — — 316,137 
Subtotal other special use funds362,802 — — 1,423 364,225 
Total assets$716,392 $498,633 $73 $388,244 $1,603,342 
LIABILITIES
Risk management activities — derivative instruments:
Commodity contracts$— $(138,687)$(16,044)$6,329 (a)$(148,402)

(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, 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$10 $— $— $— $10 
Risk management activities — derivative instruments:
Commodity contracts— 1,881 6,616 (1,689)(a)6,808 
Nuclear decommissioning trust:
Equity securities11,064 — — (767)(b)10,297 
U.S. commingled equity funds— — — 409,616 (c)409,616 
U.S. Treasury debt319,734 — — — 319,734 
Corporate debt— 188,317 — — 188,317 
Mortgage-backed securities— 208,306 — — 208,306 
Municipal bonds— 59,323 — — 59,323 
Other fixed income— 5,653 — — 5,653 
Subtotal nuclear decommissioning trust330,798 461,599 — 408,849 1,201,246 
Other special use funds:
Equity securities40,991 — — 2,196 (b)43,187 
U.S. Treasury debt319,594 — — — 319,594 
Subtotal other special use funds360,585 — — 2,196 362,781 
Total assets$691,393 $463,480 $6,616 $409,356 $1,570,845 
LIABILITIES
Risk management activities — derivative instruments:
Commodity contracts$— $(127,016)$(1,695)$4,823 (a)$(123,888)

(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, 2024, and December 31, 2023:

March 31, 2024
 Fair Value (thousands)		ValuationSignificantWeighted-Average
Commodity ContractsAssetsLiabilitiesTechniqueUnobservable InputRange(c)
Electricity:
Forward Contracts (a)$73 $13,206 Discounted cash flowsElectricity forward price (per MWh)$25.27-$247.22$135.29 
Option Contracts (b)— 801 Option modelElectricity forward price (per MWh)$42.75-$103.25$66.67 
Electricity price volatilities154 %-285 %203 %
Natural gas forward price (per MMBtu)$2.08-$4.83$3.11 
Natural gas price volatilities56 %-78 %69 %
Natural Gas:
Forward Contracts (a)— 2,037 Discounted cash flowsNatural gas forward price (per MMBtu)$(0.14)-$0.02$(0.01)
Total$73 $16,044 

(a)Includes swaps and physical and financial contracts.
(b)Option contracts classified as Level 3 relate to purchase power heat rate options. Electricity and natural gas price volatilities are estimated based on historical forward price movements due to lack of market quotes for implied volatilities.
(c)Unobservable inputs were weighted by the relative fair value of the instrument.

December 31, 2023
 Fair Value (thousands) 		ValuationSignificantWeighted-Average
Commodity ContractsAssetsLiabilitiesTechniqueUnobservable InputRange (b)
Electricity:
Forward Contracts (a)$6,587 $658 Discounted cash flowsElectricity forward price (per MWh)$37.79-$259.04$158.08 
Natural Gas:
Forward Contracts (a)29 1,037 Discounted cash flowsNatural gas forward price (per MMBtu)$0.00-$0.08$0.03 
Total$6,616 $1,695 
(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 (dollars in thousands):

 Three Months Ended March 31,
Commodity Contracts20242023
Net derivative balance at beginning of period$4,921 $(4,888)
Total net losses realized/unrealized:
Deferred as a regulatory asset or liability(23,600)(30,427)
Settlements2,708 41,937 
Net derivative balance at end of period$(15,971)$6,622 

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.

Non-recurring Financial Instruments Measured at Fair Value
As of March 31, 2024, the fair value of certain Pinnacle West guarantees issued relating to BCE that have been measured at fair value on a nonrecurring basis was $2 million, which was valued using unobservable inputs (Level 3). See Notes 8 and 14.
v3.24.1.u1
Investments in Nuclear Decommissioning Trusts and Other Special Use Funds
 3 Months Ended
Mar. 31, 2024
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 2023, APS was reimbursed $14 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 assets. 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, 2024
 Fair ValueTotal
Unrealized
Gains		Total
Unrealized
Losses
Investment Type:Nuclear Decommissioning TrustsOther Special Use FundsTotal
Equity securities$394,277 $46,665 $440,942 $325,101 $— 
Available for sale-fixed income securities842,618 316,137 1,158,755 (a)12,056 (48,075)
Other2,129 1,423 3,552 (b)164 — 
Total$1,239,024 $364,225 $1,603,249 $337,321 $(48,075)

(a)As of March 31, 2024, the amortized cost basis of these available-for-sale investments is $1,194,000 thousand.
(b)Represents net pending securities sales and purchases.

December 31, 2023
 Fair ValueTotal
Unrealized
Gains		Total
Unrealized
Losses
Investment Type:Nuclear Decommissioning TrustsOther Special Use FundsTotal
Equity securities$420,680 $40,991 $461,671 $336,555 $— 
Available for sale-fixed income securities781,333 319,594 1,100,927 (a)21,518 (40,868)
Other(767)2,196 1,429 (b)39 — 
Total$1,201,246 $362,781 $1,564,027 $358,112 $(40,868)

(a)As of December 31, 2023, the amortized cost basis of these available-for-sale investments is $1,120,000 thousand.
(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
2024
Realized gains$54,492 $80 $54,572 
Realized losses$(2,815)$— $(2,815)
Proceeds from the sale of securities (a)$377,822 $66,048 $443,870 
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 

(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, 2024, is as follows (dollars in thousands):

 Nuclear Decommissioning TrustsCoal Reclamation Escrow AccountActive Union Employee Medical AccountTotal
Less than one year$24,043 $59,198 $37,081 $120,322 
1 year – 5 years254,711 43,219 151,844 449,774 
5 years – 10 years193,975 — 24,795 218,770 
Greater than 10 years369,889 — — 369,889 
Total$842,618 $102,417 $213,720 $1,158,755 
v3.24.1.u1
Changes in Accumulated Other Comprehensive Loss
 3 Months Ended
Mar. 31, 2024
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, 2023$(34,754)$1,610 $(33,144)
OCI (loss) before reclassifications— — — 
Amounts reclassified from accumulated other comprehensive loss562  (a)— 562 
Balance March 31, 2024$(34,192)$1,610 $(32,582)
Balance December 31, 2022$(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)

(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, 2023$(17,219)
OCI (loss) before reclassifications— 
Amounts reclassified from accumulated other comprehensive loss490 (a)
Balance March 31, 2024$(16,729)
Balance December 31, 2022$(15,596)
OCI (loss) before reclassifications— 
Amounts reclassified from accumulated other comprehensive loss457 (a)
Balance March 31, 2023$(15,139)

(a) These amounts primarily represent amortization of actuarial loss and are included in the computation of net periodic pension cost.  See Note 5.
v3.24.1.u1
Sale of Bright Canyon Energy
 3 Months Ended
Mar. 31, 2024
Discontinued Operations and Disposal Groups [Abstract]  
Sale of Bright Canyon Energy Sale of Bright Canyon Energy
On August 4, 2023, Pinnacle West entered into a purchase and sale agreement pursuant to which we agreed to sell all of our equity interest in our wholly-owned subsidiary, BCE, to Ameresco. The transaction is accounted for as the sale of a business and was structured to close in multiple stages that were completed on January 12, 2024. Certain investments and assets that BCE previously held, including the TransCanyon joint venture and holdings in the two Tenaska wind farm investments, were not included in the BCE Sale and were instead transferred to PNW Power, a wholly-owned subsidiary of Pinnacle West. The BCE Sale did not include a $31 million equity bridge loan relating to BCE’s Los Alamitos project, which was paid in full by Pinnacle West on August 4, 2023. Other than these retained investments and the debt instrument, all BCE assets and liabilities were included in the BCE Sale and were transferred to Ameresco.

The total carrying value of net assets transferred to Ameresco as a result of the BCE Sale totaled $79 million, with total consideration received by Pinnacle West of $108 million, resulting in a total pre-tax gain of $29 million, which was recognized between August 4, 2023 and January 12, 2024. The net assets transferred includes $41 million of liabilities that have been assumed by Ameresco. The consideration received by Pinnacle West includes both cash and interest-bearing promissory notes. The stages of the BCE Sale and timing of net assets transferring to Ameresco and related gain recognition are as follows:

•The first stage of the BCE Sale was completed on August 4, 2023. In the first stage, the net assets transferred to Ameresco totaled $44 million, which included a $36 million construction term loan. See Note 3. The assets and liabilities transferred in the first stage related to the BCE Los Alamitos project and were previously primarily classified as construction work in progress and current maturities of long-term debt, respectively. A gain of $6 million was recognized on our Consolidated Statements of Income for the year ended December 31, 2023, relating to the first stage of the BCE Sale.

•The final stage of the BCE Sale was completed on January 12, 2024. In the final stage, the net assets transferred to Ameresco totaled $35 million. The assets transferred in the final stage related primarily to equity method investments in the Kūpono Solar Project and other development stage projects. These assets were previously classified as assets held for sale on our December 31, 2023, Consolidated Balance Sheets. Our Condensed Consolidated Statements of Income for the three months ended March 31, 2024, include a $23 million gain relating to the final stage of the BCE Sale.

As of January 12, 2024, all stages of the BCE Sale have been completed. As partial consideration for the BCE Sale, Pinnacle West received $46 million of interest-bearing promissory notes from Ameresco. The notes require Ameresco to make cash payments to Pinnacle West throughout 2024. We expect to receive full payment, and interest, on the notes no later than August 4, 2024. Our March 31, 2024 Condensed Consolidated Balance Sheets include $46 million of notes receivable and a $2 million estimated credit reserve.

 On January 30, 2024, Pinnacle West entered into a tax credit transfer agreement to purchase from Ameresco $23.3 million of investment tax credits from the BCE Los Alamitos project for $21 million. See Note 15.
Additionally, Pinnacle West continues to maintain certain guarantees relating to the Kūpono Solar Project financing, which were not transferred in the BCE Sale transaction. See Note 8.
v3.24.1.u1
Income Taxes
 3 Months Ended
Mar. 31, 2024
Income Tax Disclosure [Abstract]  
Income Taxes Income Taxes
 On January 30, 2024, Pinnacle West entered into a tax credit transfer agreement to purchase from Ameresco $23.3 million of investment tax credits from the BCE Los Alamitos project for $21 million. See Note 14 for more information about the BCE Sale.

As a part of the Inflation Reduction Act of 2022 (“IRA”), a new PTC for nuclear energy produced by existing nuclear energy plants was enacted, available from 2024 through 2032. The Nuclear PTC can be increased by five times if certain IRS prevailing wages rules are met. The Company continues to await guidance from the U.S. Treasury Department related to the definition of “gross receipts” from nuclear sales for purposes of the credit phase-out applicable to the nuclear PTC. Without such guidance, the Company is unable to make a reasonable estimate of the potential benefit the nuclear PTC may provide. As a result, no income tax benefits have been recorded related to the nuclear PTC as of March 31, 2024.
v3.24.1.u1
Insider Trading Arrangements
 3 Months Ended
Mar. 31, 2024
Trading Arrangements, by Individual  
Rule 10b5-1 Arrangement Adopted false
Non-Rule 10b5-1 Arrangement Adopted false
Rule 10b5-1 Arrangement Terminated false
Non-Rule 10b5-1 Arrangement Terminated false
v3.24.1.u1
Consolidation and Nature of Operations (Tables)
 3 Months Ended
Mar. 31, 2024
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,
 20242023
Cash paid (received) during the period for:
Income taxes, net of refunds$20,970 $(12)
Interest, net of amounts capitalized83,974 62,241 
Significant non-cash investing and financing activities:
Accrued capital expenditures$217,684 $115,559 
Cash paid for amounts included in the measurement of lease liabilities — operating cash flows:3,544 3,851 
Right-of-use operating lease assets obtained in exchange for operating lease liabilities6,747 551,239 
BCE Sale non-cash consideration (Note 14)
45,608 — 


The following table summarizes supplemental APS cash flow information (dollars in thousands):
Three Months Ended
March 31,
 20242023
Cash paid during the period for:
Interest, net of amounts capitalized$73,035 $53,610 
Significant non-cash investing and financing activities:
Accrued capital expenditures$217,684 $112,219 
Cash paid for amounts included in the measurement of lease liabilities — operating cash flows:3,544 3,851 
Right-of-use operating lease assets obtained in exchange for operating lease liabilities6,747 551,239 
v3.24.1.u1
Revenue (Tables)
 3 Months Ended
Mar. 31, 2024
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,
20242023
Retail Electric Service
Residential$432,692 $409,724 
Non-Residential461,483 406,137 
Wholesale Energy Sales26,864 95,603 
Transmission Services for Others27,712 31,791 
Other Sources2,961 1,700 
Total Operating Revenues$951,712 $944,955 
Schedule of Accounts Receivable
The following table provides a rollforward of Pinnacle West’s allowance for doubtful accounts (dollars in thousands):

March 31, 2024December 31, 2023
Allowance for doubtful accounts, balance at beginning of period$22,433 $23,778 
Bad debt expense4,769 23,399 
Actual write-offs(7,978)(24,744)
Allowance for doubtful accounts, balance at end of period$19,224 $22,433 
v3.24.1.u1
Long-Term Debt and Liquidity Matters (Tables)
 3 Months Ended
Mar. 31, 2024
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, 2024As of December 31, 2023
 Carrying
Amount		Fair ValueCarrying
Amount		Fair Value
Pinnacle West$1,123,941 $1,099,455 $1,123,731 $1,095,935 
APS7,292,930 6,368,753 7,291,891 6,459,718 
Total$8,416,871 $7,468,208 $8,415,622 $7,555,653 
v3.24.1.u1
Regulatory Matters (Tables)
 3 Months Ended
Mar. 31, 2024
Regulated Operations [Abstract]  
Schedule of Capital Structure and Cost of Capital 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 %
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 2024 and 2023 (dollars in thousands):
 Three Months Ended
March 31,
 20242023
Beginning balance$463,195 $460,561 
Deferred fuel and purchased power costs — current period33,094 90,305 
Amounts charged to customers(108,552)(80,904)
Ending balance$387,737 $469,962 
Schedule of Regulatory Assets
The detail of regulatory assets is as follows (dollars in thousands): 
 Amortization ThroughMarch 31, 2024December 31, 2023
Pension(a)$686,379 $696,476 
Deferred fuel and purchased power (b) (c)2025387,737 463,195 
Income taxes — allowance for funds used during construction (“AFUDC”) equity2054189,211 189,058 
Deferred fuel and purchased power — mark-to-market (Note 7)
2026154,658 120,214 
Ocotillo deferral2034125,908 128,636 
SCR deferral (e)203887,576 89,477 
Retired power plant costs203379,747 83,536 
Lease incentives(g)54,543 46,615 
Income taxes — investment tax credit basis adjustment205636,017 34,230 
Deferred compensation203633,923 33,972 
Deferred property taxes202730,345 32,488 
Palo Verde VIEs (Note 6)
204620,732 20,772 
Active Union Medical Trust(f)13,809 12,747 
Navajo coal reclamation202610,139 10,883 
Mead-Phoenix transmission line contributions in aid of construction (“CIAC”)20508,633 8,716 
Loss on reacquired debt20387,644 7,965 
Four Corners cost deferral20245,903 7,922 
Tax expense adjustor mechanism (b)20315,026 5,190 
FERC Transmission true up20264,313 616 
Power supply adjustor - interest20253,105 19,416 
OtherVarious4,781 3,912 
Total regulatory assets (d) $1,950,129 $2,016,036 
Less: current regulatory assets$578,869 $625,757 
Total non-current regulatory assets$1,371,260 $1,390,279 

(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. The 2022 Rate Case decision allows for the full return on the pension asset in rate base. 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)See “Four Corners SCR Cost Recovery” discussion above.
(f)Collected in retail rates.
(g)Amortization periods vary based on specific terms of lease contract.
Schedule of Regulatory Liabilities
The detail of regulatory liabilities is as follows (dollars in thousands):
 Amortization ThroughMarch 31, 2024December 31, 2023
Excess deferred income taxes - ACC — Tax Cuts and Jobs Act (a)2046$929,197 $930,344 
Excess deferred income taxes - FERC — Tax Cuts and Jobs Act (a)2058214,466 214,667 
Asset retirement obligations2057411,393 392,383 
Other postretirement benefits(c)215,298 226,726 
Removal costs(d)90,082 94,368 
Income taxes — deferred investment tax credit205668,442 68,521 
Income taxes — change in rates205360,589 60,667 
Four Corners coal reclamation203856,557 55,917 
Renewable energy standard (b)202451,001 43,251 
Spent nuclear fuel202731,552 33,154 
Demand side management (b)202420,905 14,374 
Sundance maintenance203120,763 19,989 
Property tax deferral20279,541 10,850 
Tax expense adjustor mechanism (b)20324,796 4,835 
FERC transmission true up (b)2026— 1,869 
OtherVarious3,090 3,873 
Total regulatory liabilities $2,187,672 $2,175,788 
Less: current regulatory liabilities$221,552 $209,923 
Total non-current regulatory liabilities$1,966,120 $1,965,865 

(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)See Note 5.
(d)In accordance with regulatory accounting, APS accrues removal costs for its regulated assets, even if there is no legal obligation for removal.
v3.24.1.u1
Retirement Plans and Other Postretirement Benefits (Tables)
 3 Months Ended
Mar. 31, 2024
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)
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,
 2024202320242023
Service cost — benefits earned during the period$10,631 $10,157 $2,459 $2,120 
Non-service costs (credits):
Interest cost on benefit obligation37,236 38,362 5,613 5,673 
Expected return on plan assets(46,983)(45,561)(11,709)(10,872)
  Amortization of:   
  Prior service credit (a)— — (9,447)(9,447)
  Net actuarial loss/(gain)10,944 9,713 (2,080)(2,303)
Net periodic cost/(benefit)$11,828 $12,671 $(15,164)$(14,829)
Portion of cost/(benefit) charged to expense$6,337 $7,227 $(11,306)$(10,737)
 
(a)Prior-service costs or credits reflect the impact of modifications to the pension or postretirement plan benefits. The impact of these modifications is amortized over a period which reflects the demographics of the impacted population. In 2014, Pinnacle West made changes to the postretirement benefits offered to Medicare eligible retirees, which resulted in prior-service credits. We have been amortizing these prior-serviced credits since 2015 with the last full-year amortization occurring in 2024.
v3.24.1.u1
Palo Verde Sale Leaseback Variable Interest Entities (Tables)
 3 Months Ended
Mar. 31, 2024
Variable Interest Entities [Abstract]  
Schedule of Amounts Relating to The VIEs included in Condensed Consolidated Balance Sheets
Our Condensed Consolidated Balance Sheets include the following amounts relating to the VIEs (dollars in thousands):
 March 31, 2024December 31, 2023
Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation$85,459 $86,426 
Equity — Noncontrolling interests111,504 107,198 
v3.24.1.u1
Derivative Accounting (Tables)
 3 Months Ended
Mar. 31, 2024
Derivative Instruments and Hedging Activities Disclosure [Abstract]  
Schedule of Outstanding Gross Notional Amount of Derivatives, Which Represents Both Purchases and Sales (Does Not Reflect Net Position)
The following table shows the outstanding gross notional volume of energy derivatives, which represent both purchases and sales (does not reflect net position): 
Quantity
CommodityUnit of MeasureMarch 31, 2024December 31, 2023
PowerGWh2,097 1,212 
GasBillion cubic feet235 200 
Schedule of Gains and Losses From Derivative Instruments Not Designated as Accounting Hedges Instruments
The following table provides information about gains and losses from energy derivative instruments not designated as accounting hedging instruments (dollars in thousands):
 Financial Statement LocationThree Months Ended
March 31,
Commodity Contracts20242023
Net Loss Recognized in IncomeFuel and purchased power (a)$(55,942)$(188,930)
 
(a)Amounts are before the effect of PSA deferrals.
Schedule of Offsetting Assets
The following tables provide information about the fair value of APS’s risk management activities reported on a gross basis and the impacts of offsetting.  These amounts relate to commodity contracts and are located in the assets and liabilities from risk management activities lines of APS’s Condensed Consolidated Balance Sheets.
As of March 31, 2024:
(dollars in thousands)
Gross
 Recognized
 Derivatives
 (a)
Amounts
Offset
 (b)
Net
 Recognized
 Derivatives
Other
 (c)
Amounts Reported on Balance Sheets
Current assets$73 $— $73 $5 $78 
Investments and other assets— — — — — 
Total assets73 — 73 5 78 
Current liabilities(119,859)13,100 (106,759)(6,771)(113,530)
Deferred credits and other(34,872)— (34,872)— (34,872)
Total liabilities(154,731)13,100 (141,631)(6,771)(148,402)
Total$(154,658)$13,100 $(141,558)$(6,766)$(148,324)

(a)All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)Includes cash collateral provided to counterparties of $13,100 thousand 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 $6,771 thousand and cash margin provided to counterparties of $5 thousand.
As of December 31, 2023:
(dollars in thousands)
Gross
Recognized
Derivatives
 (a)
Amounts
Offset
(b)
Net
 Recognized
 Derivatives
Other
 (c)
Amounts
Reported on
Balance Sheets
Current assets$8,497 $(1,694)$6,803 $5 $6,808 
Investments and other assets— — — — — 
Total assets8,497 (1,694)6,803 5 6,808 
Current liabilities(85,736)10,894 (74,842)(6,071)(80,913)
Deferred credits and other(42,975)— (42,975)— (42,975)
Total liabilities(128,711)10,894 (117,817)(6,071)(123,888)
Total$(120,214)$9,200 $(111,014)$(6,066)$(117,080)

(a)All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)Includes cash collateral provided to counterparties of $9,200 thousand 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 $6,071 thousand and cash margin provided to counterparties of $5 thousand.
Schedule of Offsetting Liabilities
The following tables provide information about the fair value of APS’s risk management activities reported on a gross basis and the impacts of offsetting.  These amounts relate to commodity contracts and are located in the assets and liabilities from risk management activities lines of APS’s Condensed Consolidated Balance Sheets.
As of March 31, 2024:
(dollars in thousands)
Gross
 Recognized
 Derivatives
 (a)
Amounts
Offset
 (b)
Net
 Recognized
 Derivatives
Other
 (c)
Amounts Reported on Balance Sheets
Current assets$73 $— $73 $5 $78 
Investments and other assets— — — — — 
Total assets73 — 73 5 78 
Current liabilities(119,859)13,100 (106,759)(6,771)(113,530)
Deferred credits and other(34,872)— (34,872)— (34,872)
Total liabilities(154,731)13,100 (141,631)(6,771)(148,402)
Total$(154,658)$13,100 $(141,558)$(6,766)$(148,324)

(a)All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)Includes cash collateral provided to counterparties of $13,100 thousand 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 $6,771 thousand and cash margin provided to counterparties of $5 thousand.
As of December 31, 2023:
(dollars in thousands)
Gross
Recognized
Derivatives
 (a)
Amounts
Offset
(b)
Net
 Recognized
 Derivatives
Other
 (c)
Amounts
Reported on
Balance Sheets
Current assets$8,497 $(1,694)$6,803 $5 $6,808 
Investments and other assets— — — — — 
Total assets8,497 (1,694)6,803 5 6,808 
Current liabilities(85,736)10,894 (74,842)(6,071)(80,913)
Deferred credits and other(42,975)— (42,975)— (42,975)
Total liabilities(128,711)10,894 (117,817)(6,071)(123,888)
Total$(120,214)$9,200 $(111,014)$(6,066)$(117,080)

(a)All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)Includes cash collateral provided to counterparties of $9,200 thousand 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 $6,071 thousand and cash margin provided to counterparties of $5 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, 2024
Aggregate fair value of derivative instruments in a net liability position$154,731 
Cash collateral posted13,100 
Additional cash collateral in the event credit-risk-related contingent features were fully triggered (a)127,607 
(a)This amount is after counterparty netting and includes those contracts which qualify for scope exceptions, which are excluded from the derivative details above.
v3.24.1.u1
Other Income and Other Expense (Tables)
 3 Months Ended
Mar. 31, 2024
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,
20242023
Other income:
Interest income (a)$7,560 $6,026 
Gain on sale of BCE (Note 14)
22,988 — 
Miscellaneous59 51 
Total other income$30,607 $6,077 
Other expense:
Non-operating costs$(6,150)$(2,640)
Investment losses — net(777)(1,061)
Miscellaneous(640)(430)
Total other expense$(7,567)$(4,131)

(a)     The 2023 and 2024 Interest income is primarily related to PSA Interest. See Note 4.
The following table provides detail of APS’s other income and other expense (dollars in thousands):

 Three Months Ended
March 31,
 20242023
Other income:  
Interest income (a)$6,796 $5,024 
Miscellaneous59 51 
Total other income$6,855 $5,075 
Other expense: 
Non-operating costs$(2,255)$(2,188)
Miscellaneous(639)(429)
Total other expense$(2,894)$(2,617)

(a)     The 2023 and 2024 Interest income is primarily related to PSA Interest. See Note 4.
v3.24.1.u1
Earnings Per Share and Equity Forward Sale Agreements (Tables)
 3 Months Ended
Mar. 31, 2024
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 EPS (in thousands, except per share amounts):
 Three Months Ended March 31,
 20242023
Net income (loss) attributable to common shareholders$16,862 $(3,297)
Weighted average common shares outstanding — basic
113,621 113,358 
Net effect of dilutive securities:
Contingently issuable performance shares and restricted stock units327 239 
Dilutive shares related to equity forward sale agreements279 — 
Total contingently issuable shares606 239 
Weighted average common shares outstanding — diluted
114,227 113,597 
Earnings per weighted-average common share outstanding:
Net income (loss) attributable to common shareholders — basic$0.15 $(0.03)
Net income (loss) attributable to common shareholders — diluted$0.15 $(0.03)
v3.24.1.u1
Fair Value Measurements (Tables)
 3 Months Ended
Mar. 31, 2024
Fair Value Disclosures [Abstract]  
Schedule of Fair Value of Assets and Liabilities Measured at Fair Value on a Recurring Basis
The following table presents the fair value at March 31, 2024, 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$15 $— $— $— $15 
Risk management activities — derivative instruments:
Commodity contracts— — 73 5 (a)78 
Nuclear decommissioning trust:
Equity securities9,590 — — 2,129 (b)11,719 
U.S. commingled equity funds— — — 384,687 (c)384,687 
U.S. Treasury debt343,985 — — —  343,985 
Corporate debt— 218,595 — —  218,595 
Mortgage-backed securities— 214,514 — —  214,514 
Municipal bonds— 52,053 — —  52,053 
Other fixed income— 13,471 — —  13,471 
Subtotal nuclear decommissioning trust353,575 498,633 — 386,816 1,239,024 
Other special use funds:
Equity securities46,665 — — 1,423 (b)48,088 
U.S. Treasury debt316,137 — — — 316,137 
Subtotal other special use funds362,802 — — 1,423 364,225 
Total assets$716,392 $498,633 $73 $388,244 $1,603,342 
LIABILITIES
Risk management activities — derivative instruments:
Commodity contracts$— $(138,687)$(16,044)$6,329 (a)$(148,402)

(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, 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$10 $— $— $— $10 
Risk management activities — derivative instruments:
Commodity contracts— 1,881 6,616 (1,689)(a)6,808 
Nuclear decommissioning trust:
Equity securities11,064 — — (767)(b)10,297 
U.S. commingled equity funds— — — 409,616 (c)409,616 
U.S. Treasury debt319,734 — — — 319,734 
Corporate debt— 188,317 — — 188,317 
Mortgage-backed securities— 208,306 — — 208,306 
Municipal bonds— 59,323 — — 59,323 
Other fixed income— 5,653 — — 5,653 
Subtotal nuclear decommissioning trust330,798 461,599 — 408,849 1,201,246 
Other special use funds:
Equity securities40,991 — — 2,196 (b)43,187 
U.S. Treasury debt319,594 — — — 319,594 
Subtotal other special use funds360,585 — — 2,196 362,781 
Total assets$691,393 $463,480 $6,616 $409,356 $1,570,845 
LIABILITIES
Risk management activities — derivative instruments:
Commodity contracts$— $(127,016)$(1,695)$4,823 (a)$(123,888)

(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 (dollars in thousands):

 Three Months Ended March 31,
Commodity Contracts20242023
Net derivative balance at beginning of period$4,921 $(4,888)
Total net losses realized/unrealized:
Deferred as a regulatory asset or liability(23,600)(30,427)
Settlements2,708 41,937 
Net derivative balance at end of period$(15,971)$6,622 
Schedule of 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, 2024, and December 31, 2023:

March 31, 2024
 Fair Value (thousands)		ValuationSignificantWeighted-Average
Commodity ContractsAssetsLiabilitiesTechniqueUnobservable InputRange(c)
Electricity:
Forward Contracts (a)$73 $13,206 Discounted cash flowsElectricity forward price (per MWh)$25.27-$247.22$135.29 
Option Contracts (b)— 801 Option modelElectricity forward price (per MWh)$42.75-$103.25$66.67 
Electricity price volatilities154 %-285 %203 %
Natural gas forward price (per MMBtu)$2.08-$4.83$3.11 
Natural gas price volatilities56 %-78 %69 %
Natural Gas:
Forward Contracts (a)— 2,037 Discounted cash flowsNatural gas forward price (per MMBtu)$(0.14)-$0.02$(0.01)
Total$73 $16,044 

(a)Includes swaps and physical and financial contracts.
(b)Option contracts classified as Level 3 relate to purchase power heat rate options. Electricity and natural gas price volatilities are estimated based on historical forward price movements due to lack of market quotes for implied volatilities.
(c)Unobservable inputs were weighted by the relative fair value of the instrument.

December 31, 2023
 Fair Value (thousands) 		ValuationSignificantWeighted-Average
Commodity ContractsAssetsLiabilitiesTechniqueUnobservable InputRange (b)
Electricity:
Forward Contracts (a)$6,587 $658 Discounted cash flowsElectricity forward price (per MWh)$37.79-$259.04$158.08 
Natural Gas:
Forward Contracts (a)29 1,037 Discounted cash flowsNatural gas forward price (per MMBtu)$0.00-$0.08$0.03 
Total$6,616 $1,695 
(a)Includes swaps and physical and financial contracts.
(b)Unobservable inputs were weighted by the relative fair value of the instrument.
v3.24.1.u1
Investments in Nuclear Decommissioning Trusts and Other Special Use Funds (Tables)
 3 Months Ended
Mar. 31, 2024
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, 2024
 Fair ValueTotal
Unrealized
Gains		Total
Unrealized
Losses
Investment Type:Nuclear Decommissioning TrustsOther Special Use FundsTotal
Equity securities$394,277 $46,665 $440,942 $325,101 $— 
Available for sale-fixed income securities842,618 316,137 1,158,755 (a)12,056 (48,075)
Other2,129 1,423 3,552 (b)164 — 
Total$1,239,024 $364,225 $1,603,249 $337,321 $(48,075)

(a)As of March 31, 2024, the amortized cost basis of these available-for-sale investments is $1,194,000 thousand.
(b)Represents net pending securities sales and purchases.

December 31, 2023
 Fair ValueTotal
Unrealized
Gains		Total
Unrealized
Losses
Investment Type:Nuclear Decommissioning TrustsOther Special Use FundsTotal
Equity securities$420,680 $40,991 $461,671 $336,555 $— 
Available for sale-fixed income securities781,333 319,594 1,100,927 (a)21,518 (40,868)
Other(767)2,196 1,429 (b)39 — 
Total$1,201,246 $362,781 $1,564,027 $358,112 $(40,868)

(a)As of December 31, 2023, the amortized cost basis of these available-for-sale investments is $1,120,000 thousand.
(b)Represents net pending securities sales and purchases.
Schedule of Realized Gains and Losses and Proceeds from the Sale of Securities by the Nuclear Decommissioning Trust Funds
The following table sets forth APS’s realized gains and losses relating to the sale and maturity of available-for-sale debt securities and equity securities, and the proceeds from the sale and maturity of these investment securities (dollars in thousands):
 Three Months Ended March 31,
 Nuclear Decommissioning TrustsOther Special Use FundsTotal
2024
Realized gains$54,492 $80 $54,572 
Realized losses$(2,815)$— $(2,815)
Proceeds from the sale of securities (a)$377,822 $66,048 $443,870 
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 

(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, 2024, is as follows (dollars in thousands):

 Nuclear Decommissioning TrustsCoal Reclamation Escrow AccountActive Union Employee Medical AccountTotal
Less than one year$24,043 $59,198 $37,081 $120,322 
1 year – 5 years254,711 43,219 151,844 449,774 
5 years – 10 years193,975 — 24,795 218,770 
Greater than 10 years369,889 — — 369,889 
Total$842,618 $102,417 $213,720 $1,158,755 
v3.24.1.u1
Changes in Accumulated Other Comprehensive Loss (Tables)
 3 Months Ended
Mar. 31, 2024
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, 2023$(34,754)$1,610 $(33,144)
OCI (loss) before reclassifications— — — 
Amounts reclassified from accumulated other comprehensive loss562  (a)— 562 
Balance March 31, 2024$(34,192)$1,610 $(32,582)
Balance December 31, 2022$(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)

(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, 2023$(17,219)
OCI (loss) before reclassifications— 
Amounts reclassified from accumulated other comprehensive loss490 (a)
Balance March 31, 2024$(16,729)
Balance December 31, 2022$(15,596)
OCI (loss) before reclassifications— 
Amounts reclassified from accumulated other comprehensive loss457 (a)
Balance March 31, 2023$(15,139)

(a) These amounts primarily represent amortization of actuarial loss and are included in the computation of net periodic pension cost.  See Note 5.
v3.24.1.u1
Consolidation and Nature of Operations (Details) - USD ($)
$ in Thousands
 3 Months Ended
Mar. 31, 2024
Mar. 31, 2023
Cash paid (received) during the period for:    
Income taxes, net of refunds $ 20,970 $ (12)
Interest, net of amounts capitalized 83,974 62,241
Significant non-cash investing and financing activities:    
Accrued capital expenditures 217,684 115,559
Cash paid for amounts included in the measurement of lease liabilities — operating cash flows: 3,544 3,851
Right-of-use operating lease assets obtained in exchange for operating lease liabilities 6,747 551,239
BCE Sale non-cash consideration (Note 14) 45,608 0
APS    
Cash paid (received) during the period for:    
Interest, net of amounts capitalized 73,035 53,610
Significant non-cash investing and financing activities:    
Accrued capital expenditures 217,684 112,219
Cash paid for amounts included in the measurement of lease liabilities — operating cash flows: 3,544 3,851
Right-of-use operating lease assets obtained in exchange for operating lease liabilities $ 6,747 $ 551,239
v3.24.1.u1
Revenue - Schedule of Disaggregation (Details) - USD ($)
$ in Thousands
 3 Months Ended
Mar. 31, 2024
Mar. 31, 2023
Disaggregation of Revenue [Line Items]    
Total operating revenues $ 951,712 $ 944,955
Wholesale Energy Sales    
Disaggregation of Revenue [Line Items]    
Total operating revenues 26,864 95,603
Transmission Services for Others    
Disaggregation of Revenue [Line Items]    
Total operating revenues 27,712 31,791
Other Sources    
Disaggregation of Revenue [Line Items]    
Total operating revenues 2,961 1,700
Residential | Retail Electric Service    
Disaggregation of Revenue [Line Items]    
Total operating revenues 432,692 409,724
Non-Residential | Retail Electric Service    
Disaggregation of Revenue [Line Items]    
Total operating revenues $ 461,483 $ 406,137
v3.24.1.u1
Revenue - Additional Information (Details) - USD ($)
$ in Thousands
 3 Months Ended
Mar. 31, 2024
Mar. 31, 2023
Disaggregation of Revenue [Line Items]    
Total operating revenues $ 951,712 $ 944,955
Regulatory cost recovery revenue 9,000 23,000
Electric and Transmission Service    
Disaggregation of Revenue [Line Items]    
Total operating revenues $ 943,000 $ 922,000
v3.24.1.u1
Revenue - Allowance for Doubtful Accounts (Details) - USD ($)
$ in Thousands
 3 Months Ended 12 Months Ended
Mar. 31, 2024
Dec. 31, 2023
Accounts Receivable, Allowance for Credit Loss [Roll Forward]    
Allowance for doubtful accounts, balance at beginning of period $ 22,433 $ 23,778
Bad debt expense 4,769 23,399
Actual write-offs (7,978) (24,744)
Allowance for doubtful accounts, balance at end of period $ 19,224 $ 22,433
v3.24.1.u1
Long-Term Debt and Liquidity Matters - Narrative (Details)
 3 Months Ended
Apr. 19, 2024
USD ($)
Feb. 09, 2024
USD ($)
Dec. 12, 2023
USD ($)
Feb. 11, 2022
USD ($)
MW
Mar. 31, 2024
USD ($)
shares
Oct. 27, 2023
USD ($)
Aug. 04, 2023
USD ($)
Apr. 10, 2023
USD ($)
creditFacility
Apr. 09, 2023
USD ($)
Dec. 15, 2022
USD ($)
Dec. 14, 2022
USD ($)
APS                      
Long-Term Debt and Liquidity Matters                      
Annual amount of approved equity infusions         $ 150,000,000            
Increased in equity contributions           $ 500,000,000          
APS | Subsequent Event                      
Long-Term Debt and Liquidity Matters                      
Public utilities, request to permanently modify permitted yearly equity infusions 2.50%                    
APS | ACC                      
Long-Term Debt and Liquidity Matters                      
Public utility order short term debt authorization as percentage of capitalization                   7.00%  
Public utility order short term debt authorization, fixed amount                   $ 500,000,000  
Public utility order long term debt, authorization         $ 8,000,000,000         $ 8,000,000,000 $ 7,500,000,000
APS | ACC | Subsequent Event                      
Long-Term Debt and Liquidity Matters                      
Public utility order long term debt, increase in authorization limit $ 9,500,000,000                    
BCE                      
Long-Term Debt and Liquidity Matters                      
Solar plant capacity (in MW) | MW       31              
Battery storage capacity (in MW) | MW       20              
Equity Forward Sale Agreements | Pinnacle West                      
Long-Term Debt and Liquidity Matters                      
Sale of stock, settlement terms (in shares) | shares         11,240,601            
Sale of stock, settlement proceeds from issuance of common stock         $ 728,000,000            
Term Loan | APS                      
Long-Term Debt and Liquidity Matters                      
Debt instrument, term     364 days                
Debt instrument, face amount     $ 350,000,000                
Proceeds from short-term debt   $ 350,000,000                  
Term Loan | APS | Secured Overnight Financing Rate (SOFR) Overnight Index Swap Rate                      
Long-Term Debt and Liquidity Matters                      
Variable rate     1.00%                
Revolving Credit Facility | Revolving Credit Facility Maturing May 2026 | APS                      
Long-Term Debt and Liquidity Matters                      
Current borrowing capacity on credit facility               $ 500,000,000      
Number of line of credit facilities | creditFacility               2      
Revolving Credit Facility | Revolving Credit Facility Maturing April 2028 | APS                      
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      
Revolving Credit Facility | Revolving Credit Facility Maturing April 2028, Facility Two | APS                      
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      
Revolving Credit Facility | Revolving Credit Facility Maturing April 2028, Facility One | APS                      
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      
Revolving Credit Facility | Revolving Credit Facility Maturing in 2022 and 2023 | APS                      
Long-Term Debt and Liquidity Matters                      
Long-term line of credit         $ 0            
Debt, weighted average interest rate         5.42%            
Letter of Credit | APS                      
Long-Term Debt and Liquidity Matters                      
Outstanding letters of credit         $ 35,000,000            
Letter of Credit | Revolving Credit Facility Maturing April 2028 | APS                      
Long-Term Debt and Liquidity Matters                      
Outstanding letters of credit         0            
Commercial Paper | APS                      
Long-Term Debt and Liquidity Matters                      
Maximum commercial paper support available under credit facility               1,000,000,000 $ 750,000,000    
Commercial Paper | Revolving Credit Facility Maturing April 2028 | APS                      
Long-Term Debt and Liquidity Matters                      
Commercial paper         384,000,000            
Term Loan | Non-Recourse Construction Term Loan Facility | BCE                      
Long-Term Debt and Liquidity Matters                      
Debt instrument, face amount       $ 36,000,000              
Bridge Loan | Equity Bridge Loan Facility | BCE                      
Long-Term Debt and Liquidity Matters                      
Debt instrument, face amount       $ 31,000,000     $ 31,000,000        
Pinnacle West | Revolving Credit Facility | Revolving Credit Facility Maturing May 2026                      
Long-Term Debt and Liquidity Matters                      
Current borrowing capacity on credit facility                 $ 200,000,000    
Pinnacle West | Revolving Credit Facility | Revolving Credit Facility Maturing April 2028                      
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      
Long-term line of credit         0            
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         $ 60,000,000            
Debt, weighted average interest rate         5.47%            
v3.24.1.u1
Long-Term Debt and Liquidity Matters - Estimated Fair Value of Long-term Debt, Including Current Maturities (Details) - USD ($)
$ in Thousands
Mar. 31, 2024
Dec. 31, 2023
Estimated fair value of long-term debt, including current maturities    
Carrying Amount $ 8,416,871 $ 8,415,622
Fair Value 7,468,208 7,555,653
APS    
Estimated fair value of long-term debt, including current maturities    
Carrying Amount 7,292,930 7,291,891
Fair Value 6,368,753 6,459,718
Pinnacle West    
Estimated fair value of long-term debt, including current maturities    
Carrying Amount 1,123,941 1,123,731
Fair Value $ 1,099,455 $ 1,095,935
v3.24.1.u1
Regulatory Matters - Retail Rate Case Filing (Details)
$ in Thousands
Feb. 22, 2024
USD ($)
Jan. 25, 2024
USD ($)
$ / MWh
Jul. 26, 2023
USD ($)
$ / kWh
Jul. 12, 2023
USD ($)
$ / kWh
Jul. 11, 2023
$ / kWh
Jun. 14, 2023
USD ($)
Oct. 28, 2022
USD ($)
$ / kWh
Jun. 30, 2022
USD ($)
Dec. 17, 2021
USD ($)
Nov. 02, 2021
USD ($)
Apr. 30, 2024
USD ($)
Nov. 06, 2023
USD ($)
Nov. 05, 2023
USD ($)
Aug. 04, 2023
USD ($)
Aug. 03, 2023
USD ($)
Jun. 15, 2023
USD ($)
Mar. 06, 2023
Nov. 30, 2022
USD ($)
Public Utilities, General Disclosures [Line Items]                                    
Revenue increase (decrease) $ 491,700 $ 523,100                                
ACC                                    
Public Utilities, General Disclosures [Line Items]                                    
Base fuel rate (in dollars per kWh) | $ / kWh     0.006 0.006 0.004                          
Revenue increase (decrease)     $ 281,900 $ 383,100               $ 282,700 $ 281,900     $ 251,000    
Alternative revenue increase (decrease)                               $ 312,000    
Recommended return on equity, percentage 9.55% 9.55% 9.68% 10.25%                       9.60%    
Increment of fair value rate, percentage 0.25% 0.25% 0.50% 0.50%                       0.00%    
Alternative increment of fair value rate percentage                               0.0075    
Hypothetical capital structure of equity layer percentage                               0.46    
ACC | Navajo Nation, Hopi Tribe | Coal Community Transition Plan | Subsequent Event                                    
Public Utilities, General Disclosures [Line Items]                                    
Amount recoverable through rates related to the CCT                     $ 1,000              
ACC | Navajo Nation | Coal Community Transition Plan | Subsequent Event                                    
Public Utilities, General Disclosures [Line Items]                                    
Amount funded by shareholders                     1,500              
Amount recoverable through rates related to the CCT                     10,000              
ACC | Navajo Nation, Hopi Reservation | Coal Community Transition Plan | Subsequent Event                                    
Public Utilities, General Disclosures [Line Items]                                    
Amount recoverable through rates related to the CCT                     1,250              
ACC | Navajo County Communities | Coal Community Transition Plan | Subsequent Event                                    
Public Utilities, General Disclosures [Line Items]                                    
Amount recoverable through rates related to the CCT                     500              
ACC | Navajo County Communities, CCT and Economic Development | Coal Community Transition Plan | Subsequent Event                                    
Public Utilities, General Disclosures [Line Items]                                    
Amount funded by shareholders                     1,100              
ACC | Navajo Nation, Hopi Tribe for CCT and Economic Development | Coal Community Transition Plan | Subsequent Event                                    
Public Utilities, General Disclosures [Line Items]                                    
Amount funded by shareholders                     $ 1,250              
ACC | Navajo and Hopi Tribes | Coal Community Transition Plan                                    
Public Utilities, General Disclosures [Line Items]                                    
Disbursement                                   $ 1,250
ACC | APS                                    
Public Utilities, General Disclosures [Line Items]                                    
Total revenue deficiency             $ 772,000                      
Revenue increase (decrease)                       $ 376,200   $ 377,700 $ 383,100      
Regulatory matters, customer bill impact rate       11.30%               11.10%   11.20%        
Regulatory matters, no of basis penalty point                   0.0020             20  
Reversal of basis point penalty           0.0020                        
ACC | APS | Retail Rate Case Filing with Arizona Corporation Commission                                    
Public Utilities, General Disclosures [Line Items]                                    
Approximate percentage of increase in average residential customer bill             13.60%                      
Rate matter, cost base rate               $ 10,500,000                    
Base fuel rate (in dollars per kWh)   0.006         0.038321                      
Recommended return on equity, percentage                 8.90% 8.70%                
Effective fair value percentage 4.39% 4.36%                                
Public utilities, effective prepaid pension asset, rate   5.00%                                
Public utilities, effective other postretirement benefit plan liability rate   5.35%                                
Public utilities, retention of renewable energy adjustment charge   $ 1,900                                
Public utilities, recommended transfer of funds to base rates   $ 27,100                                
Increases in annual revenue $ 253,400                                  
Increase to the typical residential customer’s bill 8.00%                                  
ACC | APS | Retail Rate Case Filing with Arizona Corporation Commission | Navajo Nation, Hopi Tribe | Coal Community Transition Plan                                    
Public Utilities, General Disclosures [Line Items]                                    
Amount not recoverable                   $ 215,500                
Amount funded by shareholders                   $ 1,000                
Amount funded by shareholders, term                   60 days                
ACC | APS | Retail Rate Case Filing with Arizona Corporation Commission | Navajo Nation | Coal Community Transition Plan                                    
Public Utilities, General Disclosures [Line Items]                                    
Amount funded by shareholders                   $ 10,000                
Amount funded by shareholders, term                   3 years                
ACC | APS | Retail Rate Case Filing with Arizona Corporation Commission | Navajo County Communities | Coal Community Transition Plan                                    
Public Utilities, General Disclosures [Line Items]                                    
Amount funded by shareholders                   $ 500                
Amount funded by shareholders, term                   60 days                
ACC | APS | Retail Rate Case Filing with Arizona Corporation Commission | Navajo Nation, Hopi Reservation | Coal Community Transition Plan                                    
Public Utilities, General Disclosures [Line Items]                                    
Amount funded by shareholders                   $ 1,250                
ACC | APS | Retail Rate Case Filing with Arizona Corporation Commission | Navajo Nation Reservation | Coal Community Transition Plan                                    
Public Utilities, General Disclosures [Line Items]                                    
Revenue increase (decrease)                   (4,800)                
Recommended return on equity, percentage           8.70%                        
Amount funded by shareholders                   $ 1,250                
Disallowance of plant investments                 $ 215,500                  
Requested reversal of rate adjustment           $ 215,500                        
Lost revenue recovery           $ 59,600                        
Residential Utility Consumer Office | ACC                                    
Public Utilities, General Disclosures [Line Items]                                    
Revenue increase (decrease)                               $ 84,900    
Recommended return on equity, percentage                               8.20%    
Increment of fair value rate, percentage                               0.00%    
Alternate recommended return on equity percentage                               0.087    
Minimum | ACC | APS                                    
Public Utilities, General Disclosures [Line Items]                                    
Annual increase in retail base rates             $ 460,000                      
Maximum | ACC                                    
Public Utilities, General Disclosures [Line Items]                                    
Increment of fair value rate, percentage         1.00%                          
v3.24.1.u1
Regulatory Matters - Capital Structure and Costs of Capital (Details) - APS
Oct. 28, 2022
Cost of Capital  
Requested Long-term debt cost of capital, percentage 3.85%
Requested equity cost of capital, percentage 10.25%
Requested weighted average cost of capital, percentage 7.17%
Retail Rate Case Filing with Arizona Corporation Commission  
Capital Structure  
Requested equity capital structure, percentage 51.93%
Retail Rate Case Filing with Arizona Corporation Commission | ACC  
Capital Structure  
Requested debt capital structure, percentage 48.07%
v3.24.1.u1
Regulatory Matters - Cost Recovery Mechanisms (Details)
 3 Months Ended 12 Months Ended
Apr. 19, 2024
Nov. 30, 2023
USD ($)
$ / kWh
Oct. 25, 2023
USD ($)
Oct. 11, 2023
Jul. 31, 2023
USD ($)
Jul. 01, 2023
USD ($)
$ / KWH_Kilowatt_hour
Jun. 01, 2023
USD ($)
May 01, 2023
$ / kWh
Mar. 10, 2023
USD ($)
Feb. 23, 2023
$ / kWh
Feb. 01, 2023
USD ($)
$ / kWh
Sep. 23, 2022
MW
Jul. 12, 2022
USD ($)
$ / kWh
Jun. 01, 2022
USD ($)
Feb. 15, 2022
USD ($)
Feb. 01, 2022
$ / kWh
Oct. 01, 2021
$ / kWh
Jun. 01, 2021
USD ($)
Feb. 15, 2021
USD ($)
Feb. 01, 2020
$ / kWh
Oct. 31, 2019
$ / KWH_Kilowatt_hour
Sep. 01, 2017
Mar. 31, 2024
USD ($)
Dec. 31, 2023
storage
Dec. 31, 2022
storage
Dec. 31, 2021
storage
Dec. 31, 2020
program
MW
Oct. 27, 2023
USD ($)
Jun. 30, 2023
USD ($)
May 31, 2023
USD ($)
Nov. 30, 2022
USD ($)
Jul. 01, 2022
USD ($)
Apr. 18, 2022
USD ($)
Dec. 17, 2021
USD ($)
Dec. 09, 2021
USD ($)
Jul. 01, 2021
USD ($)
APS                                                                        
Public Utilities, General Disclosures [Line Items]                                                                        
Number of energy storage PPA | storage                                               9 1 4                    
Number of energy storage PPA, terminated | storage                                                   1                    
Annual amount of approved equity infusions                                             $ 150,000,000                          
Increased in equity contributions                                                       $ 500,000,000                
APS | Damage from Fire, Explosion or Other Hazard                                                                        
Public Utilities, General Disclosures [Line Items]                                                                        
Past due balance threshold qualifying for payment extension                                                                 $ 75      
APS | Subsequent Event                                                                        
Public Utilities, General Disclosures [Line Items]                                                                        
Public utilities, request to permanently modify permitted yearly equity infusions 2.50%                                                                      
ACC | APS                                                                        
Public Utilities, General Disclosures [Line Items]                                                                        
Program term                                                     18 years                  
Number of programs | program                                                     2                  
Solar capacity (in MW) | MW                                                     80                  
RES | ACC | APS                                                                        
Public Utilities, General Disclosures [Line Items]                                                                        
Plan term                                             5 years                          
RES 2018 | ACC | APS                                                                        
Public Utilities, General Disclosures [Line Items]                                                                        
Amount of proposed budget                                                         $ 95,100,000     $ 86,200,000     $ 100,500,000 $ 93,100,000
RES 2018 | ACC | APS | Solar Communities                                                                        
Public Utilities, General Disclosures [Line Items]                                                                        
Program term                         3 years                                              
RES 2018 | ACC | APS | Minimum                                                                        
Public Utilities, General Disclosures [Line Items]                                                                        
Authorized spending                         $ 20,000,000                                              
RES 2018 | ACC | APS | Maximum                                                                        
Public Utilities, General Disclosures [Line Items]                                                                        
Authorized spending                         $ 30,000,000                                              
Retail Rate Case Filing with Arizona Corporation Commission | APS | Maximum                                                                        
Public Utilities, General Disclosures [Line Items]                                                                        
Fixed cost recoverable per power lost (in dollars per kWh) | $ / KWH_Kilowatt_hour                                         2.68                              
Retail Rate Case Filing with Arizona Corporation Commission | ACC | APS                                                                        
Public Utilities, General Disclosures [Line Items]                                                                        
Commercial customers, market pricing, threshold | MW                       140                                                
Demand Side Management Adjustor Charge 2022 | ACC | APS                                                                        
Public Utilities, General Disclosures [Line Items]                                                                        
Amount of proposed budget                                                                   $ 78,400,000    
Increase in proposed budget                                                                   $ 14,000,000    
2023 Transportation Electrification Plan | ACC | APS                                                                        
Public Utilities, General Disclosures [Line Items]                                                                        
Amount of proposed budget                                                             $ 5,000,000          
Demand Side Management Adjustor Charge 2023 | ACC | APS                                                                        
Public Utilities, General Disclosures [Line Items]                                                                        
Amount of proposed budget                                                           $ 88,000,000 $ 88,000,000          
Demand Side Management Adjustor Charge 2024 | ACC | APS                                                                        
Public Utilities, General Disclosures [Line Items]                                                                        
Amount of proposed budget   $ 91,500,000                                                                    
Power Supply Adjustor (PSA) | ACC | APS                                                                        
Public Utilities, General Disclosures [Line Items]                                                                        
PSA rate (in dollars per kWh) | $ / kWh   0.019074               0.019074 0.006         0.007544                                        
PSA rate for prior year (in dollars per kWh) | $ / kWh   (0.012624)               (0.005527)           0.004842                                        
Forward component of increase in PSA (in dollars per kWh) | $ / kWh   0.013071               0.013071           0.012386                                        
Transition component of PSA rate | $ / kWh   0.011530               0.011530                                                    
Depletion period                   24 months                                                    
Reporting threshold amount of balancing account   $ 100,000,000                                                                    
Approved PSA rate | $ / kWh   0.011977                                                                    
Power Supply Adjustor (PSA) | ACC | APS | Cost Recovery Mechanisms                                                                        
Public Utilities, General Disclosures [Line Items]                                                                        
Maximum increase decrease in PSA rate | $ / kWh                                       0.006                                
Historical component of increase in PSA (in dollars per kWh) | $ / kWh                               0.004                                        
Environmental Improvement Surcharge | FERC | APS                                                                        
Public Utilities, General Disclosures [Line Items]                                                                        
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                                                  
Rate matter, environmental surcharge cap rate amount                 $ 4,000,000                                                      
Open Access Transmission Tariff | FERC | APS                                                                        
Public Utilities, General Disclosures [Line Items]                                                                        
Increase (decrease) in annual wholesale transmission rates             $ 34,700,000             $ (33,000,000)       $ 4,000,000                                    
Rate matters, increase (decrease) in cost recovery, wholesale customer rates             20,700,000             6,400,000       3,200,000                                    
Increase (decrease) in retail customer rates             14,000,000             (26,600,000)       7,200,000                                    
Rate matters, increase (decrease) in retail revenue requirements             $ 10,000,000             $ 2,400,000       $ 28,400,000                                    
Lost Fixed Cost Recovery Mechanisms | APS                                                                        
Public Utilities, General Disclosures [Line Items]                                                                        
Percentage of retail revenues                                             1.00%                          
Fixed cost recoverable per power lost (in dollars per kWh) | $ / KWH_Kilowatt_hour                                         2.56                              
Amount of adjustment representing prorated sales losses pending approval         $ 68,700,000                   $ 59,100,000                                          
Increase (decrease) in amount of adjustment representing prorated sales losses                             $ 32,500,000       $ 11,800,000                                  
Amount of adjustment representing annual recovery         $ 9,600,000                                                              
Lost Fixed Cost Recovery Mechanisms | ACC                                                                        
Public Utilities, General Disclosures [Line Items]                                                                        
Amount of adjustment approved to transfer     $ 27,100,000                                                                  
Court Resolution Surcharge | ACC | APS                                                                        
Public Utilities, General Disclosures [Line Items]                                                                        
Court resolution surcharge (in dollars per kWh) | $ / KWH_Kilowatt_hour           0.00175                                                            
Lost revenue recovery           $ 59,600,000                                                            
Navajo Nation Reservation | Coal Community Transition Plan | APS | Coal Community Transition Plan                                                                        
Public Utilities, General Disclosures [Line Items]                                                                        
Lost revenue recovery collected                                             $ 12,700,000                          
Net Metering | ACC | APS                                                                        
Public Utilities, General Disclosures [Line Items]                                                                        
Cost of service, resource comparison proxy method, maximum annual percentage decrease       10.00%       10.00%         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                                      
Third-year export energy price (in dollars per kWh) | $ / kWh               0.07619                                                        
v3.24.1.u1
Regulatory Matters - Schedule of Changes in The Deferred Fuel and Purchased Power Regulatory Asset (Details) - USD ($)
$ in Thousands
 3 Months Ended
Mar. 31, 2024
Mar. 31, 2023
Change in regulatory asset    
Deferred fuel and purchased power costs — current period $ 33,094 $ 90,305
Amounts charged to customers (108,552) (80,904)
APS    
Change in regulatory asset    
Deferred fuel and purchased power costs — current period 33,094 90,305
Amounts charged to customers (108,552) (80,904)
Power Supply Adjustor (PSA) | ACC | APS    
Change in regulatory asset    
Beginning balance 463,195 460,561
Deferred fuel and purchased power costs — current period 33,094 90,305
Amounts charged to customers (108,552) (80,904)
Ending balance $ 387,737 $ 469,962
v3.24.1.u1
Regulatory Matters - Four Corners, Cholla and Navajo Plant (Details) - APS - USD ($)
$ in Millions
 1 Months Ended
Nov. 02, 2021
Sep. 30, 2018
Apr. 30, 2018
Mar. 31, 2024
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%
Retired power plant costs          
Business Acquisition [Line Items]          
Net book value       $ 31.5  
Navajo Plant          
Business Acquisition [Line Items]          
Net book value       40.6  
Navajo Plant, Coal Reclamation Regulatory Asset          
Business Acquisition [Line Items]          
Net book value       $ 10.1  
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        
v3.24.1.u1
Regulatory Matters - Schedule of Regulatory Assets (Details) - USD ($)
$ in Thousands
Mar. 31, 2024
Dec. 31, 2023
Detail of regulatory assets    
Total regulatory assets $ 1,950,129 $ 2,016,036
Less: current regulatory assets 578,869 625,757
Total non-current regulatory assets 1,371,260 1,390,279
Pension    
Detail of regulatory assets    
Total regulatory assets 686,379 696,476
Deferred fuel and purchased power    
Detail of regulatory assets    
Total regulatory assets 387,737 463,195
Income taxes — allowance for funds used during construction (“AFUDC”) equity    
Detail of regulatory assets    
Total regulatory assets 189,211 189,058
Deferred fuel and purchased power — mark-to-market (Note 7)    
Detail of regulatory assets    
Total regulatory assets 154,658 120,214
Ocotillo deferral    
Detail of regulatory assets    
Total regulatory assets 125,908 128,636
SCR deferral    
Detail of regulatory assets    
Total regulatory assets 87,576 89,477
Retired power plant costs    
Detail of regulatory assets    
Total regulatory assets 79,747 83,536
Lease incentives    
Detail of regulatory assets    
Total regulatory assets 54,543 46,615
Income taxes — investment tax credit basis adjustment    
Detail of regulatory assets    
Total regulatory assets 36,017 34,230
Deferred compensation    
Detail of regulatory assets    
Total regulatory assets 33,923 33,972
Deferred property taxes    
Detail of regulatory assets    
Total regulatory assets 30,345 32,488
Palo Verde VIEs (Note 6)    
Detail of regulatory assets    
Total regulatory assets 20,732 20,772
Active Union Medical Trust    
Detail of regulatory assets    
Total regulatory assets 13,809 12,747
Navajo coal reclamation    
Detail of regulatory assets    
Total regulatory assets 10,139 10,883
Mead-Phoenix transmission line contributions in aid of construction (“CIAC”)    
Detail of regulatory assets    
Total regulatory assets 8,633 8,716
Loss on reacquired debt    
Detail of regulatory assets    
Total regulatory assets 7,644 7,965
Four Corners cost deferral    
Detail of regulatory assets    
Total regulatory assets 5,903 7,922
Tax expense adjustor mechanism    
Detail of regulatory assets    
Total regulatory assets 5,026 5,190
FERC Transmission true up    
Detail of regulatory assets    
Total regulatory assets 4,313 616
Power supply adjustor - interest    
Detail of regulatory assets    
Total regulatory assets 3,105 19,416
Other    
Detail of regulatory assets    
Total regulatory assets $ 4,781 $ 3,912
v3.24.1.u1
Regulatory Matters - Schedule of Regulatory Liabilities (Details) - USD ($)
$ in Thousands
Mar. 31, 2024
Dec. 31, 2023
Detail of regulatory liabilities    
Total regulatory liabilities $ 2,187,672 $ 2,175,788
Less: current regulatory liabilities 221,552 209,923
Total non-current regulatory liabilities 1,966,120 1,965,865
Asset retirement obligations    
Detail of regulatory liabilities    
Total regulatory liabilities 411,393 392,383
Other postretirement benefits    
Detail of regulatory liabilities    
Total regulatory liabilities 215,298 226,726
Removal costs    
Detail of regulatory liabilities    
Total regulatory liabilities 90,082 94,368
Income taxes — deferred investment tax credit    
Detail of regulatory liabilities    
Total regulatory liabilities 68,442 68,521
Income taxes — change in rates    
Detail of regulatory liabilities    
Total regulatory liabilities 60,589 60,667
Four Corners coal reclamation    
Detail of regulatory liabilities    
Total regulatory liabilities 56,557 55,917
Renewable energy standard    
Detail of regulatory liabilities    
Total regulatory liabilities 51,001 43,251
Spent nuclear fuel    
Detail of regulatory liabilities    
Total regulatory liabilities 31,552 33,154
Demand side management    
Detail of regulatory liabilities    
Total regulatory liabilities 20,905 14,374
Sundance maintenance    
Detail of regulatory liabilities    
Total regulatory liabilities 20,763 19,989
Property tax deferral    
Detail of regulatory liabilities    
Total regulatory liabilities 9,541 10,850
Tax expense adjustor mechanism    
Detail of regulatory liabilities    
Total regulatory liabilities 4,796 4,835
FERC Transmission true up    
Detail of regulatory liabilities    
Total regulatory liabilities 0 1,869
Other    
Detail of regulatory liabilities    
Total regulatory liabilities 3,090 3,873
ACC | Excess deferred income taxes - Tax Act    
Detail of regulatory liabilities    
Total regulatory liabilities 929,197 930,344
FERC | Excess deferred income taxes - Tax Act    
Detail of regulatory liabilities    
Total regulatory liabilities $ 214,466 $ 214,667
v3.24.1.u1
Retirement Plans and Other Postretirement Benefits - Schedule of Net Benefit Cost (Details) - USD ($)
$ in Thousands
 3 Months Ended
Mar. 31, 2024
Mar. 31, 2023
Amortization of:    
Portion of cost/(benefit) charged to expense $ (11,568) $ (9,865)
Pension Benefits    
Retirement Plans and Other Benefits    
Service cost — benefits earned during the period 10,631 10,157
Interest cost on benefit obligation 37,236 38,362
Expected return on plan assets (46,983) (45,561)
Amortization of:    
Prior service credit (a) 0 0
Net actuarial loss/(gain) 10,944 9,713
Net periodic cost/(benefit) 11,828 12,671
Portion of cost/(benefit) charged to expense 6,337 7,227
Other Benefits    
Retirement Plans and Other Benefits    
Service cost — benefits earned during the period 2,459 2,120
Interest cost on benefit obligation 5,613 5,673
Expected return on plan assets (11,709) (10,872)
Amortization of:    
Prior service credit (a) (9,447) (9,447)
Net actuarial loss/(gain) (2,080) (2,303)
Net periodic cost/(benefit) (15,164) (14,829)
Portion of cost/(benefit) charged to expense $ (11,306) $ (10,737)
v3.24.1.u1
Retirement Plans and Other Postretirement Benefits - Narrative (Details)
 3 Months Ended
Mar. 31, 2024
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
v3.24.1.u1
Palo Verde Sale Leaseback Variable Interest Entities - Narrative (Details)
$ in Thousands
 3 Months Ended
Mar. 31, 2024
USD ($)
lease
Mar. 31, 2023
USD ($)
Dec. 31, 1986
numberOfTrust
Palo Verde Sale Leaseback Variable Interest Entities      
Less: Net income attributable to noncontrolling interests (Note 6) $ 4,306 $ 4,306  
APS      
Palo Verde Sale Leaseback Variable Interest Entities      
Less: Net income attributable to noncontrolling interests (Note 6) 4,306 4,306  
Palo Verde VIE | APS      
Palo Verde Sale Leaseback Variable Interest Entities      
Number of VIE lessor trusts | numberOfTrust     3
Less: Net income attributable to noncontrolling interests (Note 6) 4,000 $ 4,000  
Initial loss exposure to the VIE's noncontrolling equity participants during lease extension period 334,000    
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    
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    
Palo Verde VIE | APS | Period Through 2033 | Maximum      
Palo Verde Sale Leaseback Variable Interest Entities      
Lease period (up to) 2 years    
v3.24.1.u1
Palo Verde Sale Leaseback Variable Interest Entities - Schedule of VIEs (Details) - USD ($)
$ in Thousands
Mar. 31, 2024
Dec. 31, 2023
Palo Verde Sale Leaseback Variable Interest Entities    
Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation $ 18,264,642 $ 17,980,157
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets    
Equity — Noncontrolling interests 111,504 107,198
APS    
Palo Verde Sale Leaseback Variable Interest Entities    
Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation 18,264,350 17,979,860
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets    
Equity — Noncontrolling interests 111,504 107,198
Palo Verde VIE | APS    
Palo Verde Sale Leaseback Variable Interest Entities    
Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation 85,459 86,426
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets    
Equity — Noncontrolling interests $ 111,504 $ 107,198
v3.24.1.u1
Derivative Accounting - Narrative (Details)
$ in Millions
Mar. 31, 2024
USD ($)
Commodity Contracts  
Derivative Accounting  
Additional collateral to counterparties for energy related non-derivative instrument contracts $ 206
APS  
Derivative Accounting  
Percentage of unrealized gains and losses on certain derivatives deferred for future rate treatment 100.00%
v3.24.1.u1
Derivative Accounting - Schedule of Gross Notional Amounts Outstanding (Details) - Commodity Contracts
MWh in Thousands
 3 Months Ended 12 Months Ended
Mar. 31, 2024
MWh
Bcf
Dec. 31, 2023
MWh
Bcf
Outstanding gross notional amount of derivatives    
Power | MWh 2,097 1,212
Gas | Bcf 235,000 200,000
v3.24.1.u1
Derivative Accounting - Gains and Losses from Derivative Instruments (Details) - USD ($)
$ in Thousands
 3 Months Ended
Mar. 31, 2024
Mar. 31, 2023
Commodity Contracts | Not Designated as Hedging Instruments | Fuel and Purchased Power    
Gains and losses from derivative instruments    
Net Loss Recognized in Income $ (55,942) $ (188,930)
v3.24.1.u1
Derivative Accounting - Derivative Instruments in the Balance Sheets (Details) - Commodity Contracts - USD ($)
$ in Thousands
Mar. 31, 2024
Dec. 31, 2023
Assets    
Gross recognized derivatives $ 73 $ 8,497
Amounts offset 0 (1,694)
Net Recognized Derivatives 73 6,803
Other 5 5
Amounts Reported on Balance Sheets 78 6,808
Liabilities    
Gross recognized derivatives (154,731) (128,711)
Amounts offset 13,100 10,894
Net Recognized Derivatives (141,631) (117,817)
Other (6,771) (6,071)
Amounts Reported on Balance Sheets (148,402) (123,888)
Assets and Liabilities    
Gross recognized derivatives (154,658) (120,214)
Amounts offset 13,100 9,200
Net Recognized Derivatives (141,558) (111,014)
Other (6,766) (6,066)
Amounts Reported on Balance Sheets (148,324) (117,080)
Cash collateral received subject to offsetting 13,100  
Cash collateral received from counterparties 6,771 6,071
Current assets    
Assets    
Gross recognized derivatives 73 8,497
Amounts offset 0 (1,694)
Net Recognized Derivatives 73 6,803
Other 5 5
Amounts Reported on Balance Sheets 78 6,808
Investments and other assets    
Assets    
Gross recognized derivatives 0 0
Amounts offset 0 0
Net Recognized Derivatives 0 0
Other 0 0
Amounts Reported on Balance Sheets 0 0
Current liabilities    
Liabilities    
Gross recognized derivatives (119,859) (85,736)
Amounts offset 13,100 10,894
Net Recognized Derivatives (106,759) (74,842)
Other (6,771) (6,071)
Amounts Reported on Balance Sheets (113,530) (80,913)
Assets and Liabilities    
Cash collateral received from counterparties 6,771 6,071
Deferred credits and other    
Liabilities    
Gross recognized derivatives (34,872) (42,975)
Amounts offset 0 0
Net Recognized Derivatives (34,872) (42,975)
Other 0 0
Amounts Reported on Balance Sheets (34,872) (42,975)
Assets and Liabilities    
Cash collateral received from counterparties $ 0 $ 0
v3.24.1.u1
Derivative Accounting - Credit Risk and Credit Related Contingent Features (Details) - Commodity Contracts
$ in Thousands
Mar. 31, 2024
USD ($)
Credit Risk and Credit-Related Contingent Features  
Aggregate fair value of derivative instruments in a net liability position $ 154,731
Cash collateral posted 13,100
Additional cash collateral in the event credit-risk-related contingent features were fully triggered $ 127,607
v3.24.1.u1
Commitments and Contingencies (Details)
$ in Thousands
 3 Months Ended 136 Months Ended
Mar. 21, 2024
USD ($)
Jan. 01, 2024
USD ($)
trust
Oct. 31, 2023
claim
Jan. 17, 2023
USD ($)
Sep. 30, 2022
USD ($)
Jul. 03, 2018
Aug. 18, 2014
USD ($)
Mar. 31, 2024
USD ($)
trust
MW
Oct. 31, 2022
timePeriod
claim
Apr. 18, 2023
USD ($)
Schedule of Commitments and Contingencies [Line Items]                    
Production tax credit guarantees               $ 31,000    
Kūpono Solar                    
Schedule of Commitments and Contingencies [Line Items]                    
Non recourse construction financing agreement               $ 140,000   $ 140,000
Kūpono Solar                    
Schedule of Commitments and Contingencies [Line Items]                    
Project plant capacity (in MW's) | MW               42    
Asset purchase agreement               20 years    
APS                    
Schedule of Commitments and Contingencies [Line Items]                    
Maximum insurance against public liability per occurrence for a nuclear incident (up to)   $ 16,300,000                
Maximum available nuclear liability insurance (up to)   500,000                
Remaining nuclear liability insurance through mandatory industry wide retrospective assessment program   15,800,000                
Maximum retrospective premium assessment per reactor for each nuclear liability incident   165,900                
Annual limit per incident with respect to maximum retrospective premium assessment   $ 24,700                
Number of VIE lessor trusts | trust   3           3    
Maximum potential retrospective assessment per incident of APS   $ 144,900                
Annual payment limitation with respect to maximum potential retrospective premium assessment   $ 21,600                
Amount of "all risk" (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde               $ 2,800,000    
Maximum amount that could be incurred under retrospective assessment of NEIL policies               23,100    
Collateral assurance provided based on rating triggers               $ 64,100    
Period to provide collateral assurance based on rating triggers               20 days    
Increase in contractual obligations               $ 295,000    
Amount of leases not yet commenced               7,100,000    
APS | Surety Bonds Expiring in 2025                    
Schedule of Commitments and Contingencies [Line Items]                    
Surety bonds expiring, amount               21,000    
APS | Letter of Credit                    
Schedule of Commitments and Contingencies [Line Items]                    
Outstanding letters of credit               35,000    
APS | Contaminated groundwater wells                    
Schedule of Commitments and Contingencies [Line Items]                    
Costs related to investigation and study under Superfund site               3,000    
Costs related to oversight and remedial investigation of superfund site       $ 1,700            
APS | Contaminated groundwater wells | Pending Litigation                    
Schedule of Commitments and Contingencies [Line Items]                    
Settlement amount         $ 20,700          
NTEC | Four Corners                    
Schedule of Commitments and Contingencies [Line Items]                    
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                    
Schedule of Commitments and Contingencies [Line Items]                    
Amount awarded from other party $ 18,390           $ 18,460 138,200    
Breach of Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste | APS                    
Schedule of Commitments and Contingencies [Line Items]                    
Number of claims submitted | claim     10           9  
Gain contingency, number of settlement agreement time periods | timePeriod                 9  
Amount awarded from other party             $ 5,400 $ 40,200    
v3.24.1.u1
Other Income and Other Expense (Details) - USD ($)
$ in Thousands
 3 Months Ended
Mar. 31, 2024
Mar. 31, 2023
Other income:    
Interest income $ 7,560 $ 6,026
Gain on sale of BCE (Note 14) 22,988 0
Miscellaneous 59 51
Total other income 30,607 6,077
Other expense:    
Non-operating costs (6,150) (2,640)
Investment losses — net (777) (1,061)
Miscellaneous (640) (430)
Total other expense (7,567) (4,131)
APS    
Other income:    
Interest income 6,796 5,024
Miscellaneous 59 51
Total other income 6,855 5,075
Other expense:    
Non-operating costs (2,255) (2,188)
Miscellaneous (639) (429)
Total other expense $ (2,894) $ (2,617)
v3.24.1.u1
Earnings Per Share and Equity Forward Sale Agreements - Narrative (Details) - USD ($)
$ / shares in Units, $ in Millions
 3 Months Ended
Feb. 28, 2024
Mar. 31, 2024
Mar. 31, 2023
Dec. 31, 2023
Subsidiary, Sale of Stock [Line Items]        
Antidilutive securities excluded from computation of EPS (in shares)   0 239,000  
Common stock, issued shares (in shares)   113,686,849   113,537,689
Forward Sale Agreements        
Subsidiary, Sale of Stock [Line Items]        
Sale of stock, issued in transaction (in shares) 11,240,601      
Forward Sale Agreements | Pinnacle West        
Subsidiary, Sale of Stock [Line Items]        
Sale of stock (in dollars per share) $ 64.51      
Sale of stock, settlement terms (in shares)   11,240,601    
Sale of stock, settlement proceeds from issuance of common stock   $ 728    
v3.24.1.u1
Earnings Per Share and Equity Forward Sale Agreements - Schedule of Earnings Per Weighted Average Common Share Outstanding (Details) - USD ($)
$ / shares in Units, shares in Thousands, $ in Thousands
 3 Months Ended
Mar. 31, 2024
Mar. 31, 2023
Earnings Per Share [Abstract]    
Net income (loss) attributable to common shareholders $ 16,862 $ (3,297)
Weighted average common shares outstanding - basic (in shares) 113,621 113,358
Net effect of dilutive securities:    
Contingently issuable shares (in shares) 327 239
Dilutive shares related to equity forward sale agreements (in shares) 279 0
Total contingently issuable shares (in shares) 606 239
Weighted average common shares outstanding — diluted (in shares) 114,227 113,597
Earnings per weighted-average common share outstanding:    
Net income (loss) attributable to common shareholders — basic (in dollars per share) $ 0.15 $ (0.03)
Net income (loss) attributable to common shareholders — diluted (in dollars per share) $ 0.15 $ (0.03)
v3.24.1.u1
Fair Value Measurements - Assets and Liabilities Measured on a Recurring Basis (Details) - USD ($)
$ in Thousands
Mar. 31, 2024
Dec. 31, 2023
ASSETS    
Cash equivalents $ 15 $ 10
Nuclear decommissioning trust: 1,239,024 1,201,246
Nuclear decommissioning trust, other 386,816 408,849
Other special use funds 364,225 362,781
Other special use funds, other 1,423 2,196
Total assets 1,603,342 1,570,845
Total assets, other 388,244 409,356
Commodity contracts    
ASSETS    
Commodity contracts, assets 78 6,808
Commodity contracts assets, other 5 (1,689)
LIABILITIES    
Gross derivative liability, other 6,329 4,823
Interest rate swaps (148,402) (123,888)
Equity securities    
ASSETS    
Nuclear decommissioning trust: 11,719 10,297
Nuclear decommissioning trust, other 2,129 (767)
Other special use funds 48,088 43,187
Other special use funds, other 1,423 2,196
U.S. commingled equity funds    
ASSETS    
Nuclear decommissioning trust: 384,687 409,616
U.S. Treasury debt    
ASSETS    
Nuclear decommissioning trust: 343,985 319,734
Other special use funds 316,137 319,594
Corporate debt    
ASSETS    
Nuclear decommissioning trust: 218,595 188,317
Mortgage-backed securities    
ASSETS    
Nuclear decommissioning trust: 214,514 208,306
Municipal bonds    
ASSETS    
Nuclear decommissioning trust: 52,053 59,323
Other fixed income    
ASSETS    
Nuclear decommissioning trust: 13,471 5,653
Level 1    
ASSETS    
Cash equivalents 15 10
Nuclear decommissioning trust: 353,575 330,798
Other special use funds 362,802 360,585
Total assets 716,392 691,393
Level 1 | Commodity contracts    
ASSETS    
Commodity contracts, assets 0 0
LIABILITIES    
Gross derivative liability 0 0
Level 1 | Equity securities    
ASSETS    
Nuclear decommissioning trust: 9,590 11,064
Other special use funds 46,665 40,991
Level 1 | U.S. commingled equity funds    
ASSETS    
Nuclear decommissioning trust: 0 0
Level 1 | U.S. Treasury debt    
ASSETS    
Nuclear decommissioning trust: 343,985 319,734
Other special use funds 316,137 319,594
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
Level 1 | Other fixed income    
ASSETS    
Nuclear decommissioning trust: 0 0
Level 2    
ASSETS    
Cash equivalents 0 0
Nuclear decommissioning trust: 498,633 461,599
Other special use funds 0 0
Total assets 498,633 463,480
Level 2 | Commodity contracts    
ASSETS    
Commodity contracts, assets 0 1,881
LIABILITIES    
Gross derivative liability (138,687) (127,016)
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: 218,595 188,317
Level 2 | Mortgage-backed securities    
ASSETS    
Nuclear decommissioning trust: 214,514 208,306
Level 2 | Municipal bonds    
ASSETS    
Nuclear decommissioning trust: 52,053 59,323
Level 2 | Other fixed income    
ASSETS    
Nuclear decommissioning trust: 13,471 5,653
Level 3    
ASSETS    
Cash equivalents 0 0
Nuclear decommissioning trust: 0 0
Other special use funds 0 0
Total assets 73 6,616
Level 3 | Commodity contracts    
ASSETS    
Commodity contracts, assets 73 6,616
LIABILITIES    
Gross derivative liability (16,044) (1,695)
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
Level 3 | Other fixed income    
ASSETS    
Nuclear decommissioning trust: 0 0
Fair Value Measured at Net Asset Value Per Share | U.S. commingled equity funds    
ASSETS    
Nuclear decommissioning trust: $ 384,687 $ 409,616
v3.24.1.u1
Fair Value Measurements - Significant Unobservable Inputs Used to Value Level 3 Instruments (Details)
$ in Thousands
 3 Months Ended 12 Months Ended
Mar. 31, 2024
USD ($)
$ / MWh
$ / MMBTU
Dec. 31, 2023
USD ($)
$ / MMBTU
$ / MWh
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments    
Assets $ 1,603,342 $ 1,570,845
Level 3    
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments    
Assets 73 6,616
Commodity Contracts | Level 3 | Forward Contracts    
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments    
Assets 73 6,616
Liabilities $ 16,044 $ 1,695
Commodity Contracts | Level 3 | Forward Contracts | Valuation Technique, Discounted Cash Flow | 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 25.27 37.79
Natural gas forward price (in usd per MMBTu) | $ / MMBTU 0.14 0.00
Commodity Contracts | Level 3 | Forward Contracts | Valuation Technique, Discounted Cash Flow | 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 247.22 259.04
Natural gas forward price (in usd per MMBTu) | $ / MMBTU 0.02 0.08
Commodity Contracts | Level 3 | Forward Contracts | Valuation Technique, Discounted Cash Flow | 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 135.29 158.08
Natural gas forward price (in usd per MMBTu) | $ / MMBTU (0.01) 0.03
Commodity Option | Level 3 | Forward Contracts | Valuation Technique, Discounted Cash Flow | 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 42.75  
Electricity price volatilities 1.54  
Natural gas forward price (in usd per MMBTu) | $ / MMBTU 2.08  
Natural gas price volatilities 0.56  
Commodity Option | Level 3 | Forward Contracts | Valuation Technique, Discounted Cash Flow | 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 103.25  
Electricity price volatilities 2.85  
Natural gas forward price (in usd per MMBTu) | $ / MMBTU 4.83  
Natural gas price volatilities 0.78  
Commodity Option | Level 3 | Forward Contracts | Valuation Technique, Discounted Cash Flow | 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 66.67  
Electricity price volatilities 2.03  
Natural gas forward price (in usd per MMBTu) | $ / MMBTU 3.11  
Natural gas price volatilities 0.69  
Electricity | Commodity Contracts | Level 3 | Forward Contracts | Valuation Technique, Discounted Cash Flow    
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments    
Assets $ 73 $ 6,587
Liabilities 13,206 658
Electricity | Commodity Option | Level 3 | Forward Contracts | Valuation Technique, Discounted Cash Flow    
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments    
Assets 0  
Liabilities 801  
Natural Gas | Commodity Contracts | Level 3 | Forward Contracts | Valuation Technique, Discounted Cash Flow    
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments    
Assets 0 29
Liabilities $ 2,037 $ 1,037
v3.24.1.u1
Fair Value Measurements - Fair Value For Our Risk Management Activities (Details) - Commodity Contracts - Level 3 - USD ($)
$ in Thousands
 3 Months Ended
Mar. 31, 2024
Mar. 31, 2023
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]    
Net derivative balance at beginning of period $ 4,921 $ (4,888)
Deferred as a regulatory asset or liability (23,600) (30,427)
Settlements 2,708 41,937
Net derivative balance at end of period $ (15,971) $ 6,622
v3.24.1.u1
Fair Value Measurements - Narrative (Details)
$ in Millions
Mar. 31, 2024
USD ($)
Variable Interest Entity, Not Primary Beneficiary | BCE | Level 3 | Fair Value, Nonrecurring  
Fair value of assets and liabilities that are measured at fair value on a recurring basis  
Fair value of performance obligations $ 2
v3.24.1.u1
Investments in Nuclear Decommissioning Trusts and Other Special Use Funds - Narrative (Details)
$ in Millions
 12 Months Ended
Dec. 31, 2023
USD ($)
APS  
Schedule of Equity Method Investments [Line Items]  
Employee medical claims amount $ 14
v3.24.1.u1
Investments in Nuclear Decommissioning Trusts and Other Special Use Funds (Details) - APS - USD ($)
$ in Thousands
 3 Months Ended 12 Months Ended
Mar. 31, 2024
Mar. 31, 2023
Dec. 31, 2022
Dec. 31, 2023
Nuclear decommissioning trust fund assets        
Fair Value $ 1,603,249     $ 1,564,027
Total Unrealized Gains 337,321   $ 358,112  
Total Unrealized Losses (48,075)   (40,868)  
Amortized cost 1,194,000     1,120,000
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds        
Realized gains 54,572 $ 1,210    
Realized losses (2,815) (5,694)    
Proceeds from the sale of securities 443,870 226,626    
Nuclear Decommissioning Trusts        
Nuclear decommissioning trust fund assets        
Fair Value 1,239,024     1,201,246
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds        
Realized gains 54,492 1,210    
Realized losses (2,815) (5,694)    
Proceeds from the sale of securities 377,822 136,185    
Other Special Use Funds        
Nuclear decommissioning trust fund assets        
Fair Value 364,225     362,781
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds        
Realized gains 80 0    
Realized losses 0 0    
Proceeds from the sale of securities 66,048 $ 90,441    
Equity securities        
Nuclear decommissioning trust fund assets        
Equity securities 440,942     461,671
Total Unrealized Gains 325,101   336,555  
Total Unrealized Losses 0   0  
Equity securities | Nuclear Decommissioning Trusts        
Nuclear decommissioning trust fund assets        
Equity securities 394,277     420,680
Equity securities | Other Special Use Funds        
Nuclear decommissioning trust fund assets        
Equity securities 46,665     40,991
Available for sale-fixed income securities        
Nuclear decommissioning trust fund assets        
Fair Value 1,158,755     1,100,927
Total Unrealized Gains 12,056   21,518  
Total Unrealized Losses (48,075)   (40,868)  
Fair value of fixed income securities, summarized by contractual maturities        
Less than one year 120,322      
1 year – 5 years 449,774      
5 years – 10 years 218,770      
Greater than 10 years 369,889      
Total 1,158,755      
Available for sale-fixed income securities | Nuclear Decommissioning Trusts        
Nuclear decommissioning trust fund assets        
Fair Value 842,618     781,333
Fair value of fixed income securities, summarized by contractual maturities        
Less than one year 24,043      
1 year – 5 years 254,711      
5 years – 10 years 193,975      
Greater than 10 years 369,889      
Total 842,618      
Available for sale-fixed income securities | Other Special Use Funds        
Nuclear decommissioning trust fund assets        
Fair Value 316,137     319,594
Available for sale-fixed income securities | Coal Reclamation Escrow Account        
Fair value of fixed income securities, summarized by contractual maturities        
Less than one year 59,198      
1 year – 5 years 43,219      
5 years – 10 years 0      
Greater than 10 years 0      
Total 102,417      
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 37,081      
1 year – 5 years 151,844      
5 years – 10 years 24,795      
Greater than 10 years 0      
Total 213,720      
Other        
Nuclear decommissioning trust fund assets        
Fair Value 3,552     1,429
Total Unrealized Gains 164   39  
Total Unrealized Losses 0   $ 0  
Other | Nuclear Decommissioning Trusts        
Nuclear decommissioning trust fund assets        
Fair Value 2,129     (767)
Other | Other Special Use Funds        
Nuclear decommissioning trust fund assets        
Fair Value $ 1,423     $ 2,196
v3.24.1.u1
Changes in Accumulated Other Comprehensive Loss (Details) - USD ($)
$ in Thousands
 3 Months Ended
Mar. 31, 2024
Mar. 31, 2023
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]    
Beginning balance $ 6,284,862 $ 6,159,876
OCI (loss) before reclassifications 0 (616)
Amounts reclassified from accumulated other comprehensive loss 562 515
Ending balance 6,310,533 6,164,451
APS    
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]    
Beginning balance 7,349,136 7,052,955
Ending balance 7,369,047 7,218,379
Accumulated Other Comprehensive Loss    
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]    
Beginning balance (33,144) (31,435)
Ending balance (32,582) (31,536)
Accumulated Other Comprehensive Loss | APS    
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]    
Beginning balance (17,219) (15,596)
Ending balance (16,729) (15,139)
Pension and Other Postretirement Benefits    
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]    
Beginning balance (34,754) (32,332)
OCI (loss) before reclassifications 0 0
Amounts reclassified from accumulated other comprehensive loss 562 515
Ending balance (34,192) (31,817)
Pension and Other Postretirement Benefits | APS    
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]    
Beginning balance (17,219) (15,596)
OCI (loss) before reclassifications 0 0
Amounts reclassified from accumulated other comprehensive loss 490 457
Ending balance (16,729) (15,139)
Derivative Instruments    
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]    
Beginning balance 1,610 897
OCI (loss) before reclassifications 0 (616)
Amounts reclassified from accumulated other comprehensive loss 0 0
Ending balance $ 1,610 $ 281
v3.24.1.u1
Sale of Bright Canyon Energy (Details) - USD ($)
$ in Thousands
 3 Months Ended 5 Months Ended 12 Months Ended
Jan. 30, 2024
Mar. 31, 2024
Mar. 31, 2023
Jan. 12, 2024
Dec. 31, 2023
Aug. 04, 2023
Feb. 11, 2022
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]              
Gain on sale relating to BCE   $ 22,988 $ 0        
Discontinued Operations, Disposed of by Sale | BCE              
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]              
Assets held-for-sale   46,000   $ 35,000      
Consideration received       108,000   $ 44,000  
Gain on sale relating to BCE   23,000   29,000 $ 6,000    
Promissory notes received       46,000      
Credit reserve   $ 2,000          
Discontinued Operations, Disposed of by Sale | Bright Canyou Energy Corportion              
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]              
Investment tax credits $ 23,300            
Payments to acquire investment tax credits $ 21,000            
Ameresco, Inc. | Discontinued Operations, Disposed of by Sale | BCE              
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]              
Assets held-for-sale       79,000      
Liabilities transferred       $ 41,000      
Bridge Loan | Equity Bridge Loan Facility | BCE              
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]              
Debt instrument, face amount           $ 31,000 $ 31,000
Term Loan | Non-Recourse Construction Term Loan Facility | BCE              
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]              
Debt instrument, face amount             $ 36,000
v3.24.1.u1
Income Taxes (Details) - Discontinued Operations, Disposed of by Sale - Bright Canyou Energy Corportion
$ in Millions
Jan. 30, 2024
USD ($)
Income Tax Contingency [Line Items]  
Investment tax credits $ 23.3
Payments to acquire investment tax credits $ 21.0