PINNACLE WEST CAPITAL CORP, 10-Q filed on 5/1/2025
Quarterly Report
v3.25.1
Cover Page - shares
 3 Months Ended
Mar. 31, 2025
Apr. 24, 2025
Entity Information [Line Items]    
Document Type 10-Q  
Document Quarterly Report true  
Document Period End Date Mar. 31, 2025  
Current Fiscal Year End Date --12-31  
Document Transition Report false  
Entity File Number 1-8962  
Entity Registrant Name PINNACLE WEST CAPITAL CORPORATION  
Entity Tax Identification Number 86-0512431  
Entity Incorporation, State or Country Code AZ  
Entity Address, Address Line One 400 North Fifth Street, P.O. Box 53999  
Entity Address, City or Town Phoenix  
Entity Address, State or Province AZ  
Entity Address, Postal Zip Code 85072-3999  
City Area Code (602)  
Local Phone Number 250-1000  
Title of 12(b) Security Common Stock, no par value  
Trading Symbol PNW  
Security Exchange Name NYSE  
Entity 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   119,399,009
Entity Central Index Key 0000764622  
Amendment Flag false  
Document Fiscal Year Focus 2025  
Document Fiscal Period Focus Q1  
APS    
Entity Information [Line Items]    
Document Type 10-Q  
Document Period End Date Mar. 31, 2025  
Current Fiscal Year End Date --12-31  
Entity File Number 1-4473  
Entity Registrant Name ARIZONA PUBLIC SERVICE COMPANY  
Entity Tax Identification Number 86-0011170  
Entity Address, Address Line One 400 North Fifth Street, P.O. Box 53999  
Entity Address, City or Town Phoenix  
Entity Address, State or Province AZ  
Entity Address, Postal Zip Code 85072-3999  
City Area Code (602)  
Local Phone Number 250-1000  
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  
Document Fiscal Year Focus 2025  
Document Fiscal Period Focus Q1  
v3.25.1
CONDENSED CONSOLIDATED STATEMENTS OF INCOME - USD ($)
shares in Thousands, $ in Thousands
 3 Months Ended
Mar. 31, 2025
Mar. 31, 2024
Income Statement [Abstract]    
OPERATING REVENUES (Note 4) $ 1,032,280 $ 951,712
OPERATING EXPENSES    
Fuel and purchased power 380,071 357,864
Operations and maintenance 300,109 257,578
Depreciation and amortization 234,940 210,294
Taxes other than income taxes 59,354 59,164
Other expense 584 20
Total 975,058 884,920
OPERATING INCOME 57,222 66,792
OTHER INCOME (DEDUCTIONS)    
Allowance for equity funds used during construction 13,249 10,292
Pension and other postretirement non-service credits - net (Note 7) 2,958 11,568
Other income (Note 11) 17,461 30,607
Other expense (Note 11) (2,570) (7,567)
Total 31,098 44,900
INTEREST EXPENSE    
Interest charges 104,943 99,774
Allowance for borrowed funds used during construction (10,102) (13,141)
Total 94,841 86,633
Income (Loss) Before Income Taxes (6,521) 25,059
Income taxes (benefit) (6,183) 3,891
Net Income (Loss) (338) 21,168
Less: Net income attributable to noncontrolling interests (Note 8) 4,306 4,306
Net Income (Loss) Attributable to Common Shareholders $ (4,644) $ 16,862
Weighted-average common shares outstanding - basic (in shares) 119,594 113,621
Weighted-average common shares outstanding - diluted (in shares) 119,594 114,227
Earnings Per Weighted-Average Common Share Outstanding    
Net income (loss) attributable to common shareholders - basic (in dollars per share) $ (0.04) $ 0.15
Net income (loss) attributable to common shareholders - diluted (in dollars per share) $ (0.04) $ 0.15
v3.25.1
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($)
$ in Thousands
 3 Months Ended
Mar. 31, 2025
Mar. 31, 2024
Statement of Comprehensive Income [Abstract]    
NET INCOME (LOSS) $ (338) $ 21,168
Derivative instruments:    
Net unrealized gain (loss), net of tax benefit (expense) of $—, and $— 350 0
Pension and other postretirement benefit activity, net of tax expense of $(164) and $(185) 498 562
Total other comprehensive income 848 562
Total other comprehensive income 510 21,730
Less: Comprehensive income attributable to noncontrolling interests 4,306 4,306
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS $ (3,796) $ 17,424
v3.25.1
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($)
$ in Thousands
 3 Months Ended
Mar. 31, 2025
Mar. 31, 2024
Statement of Comprehensive Income [Abstract]    
Net unrealized gain (loss), net of tax benefit (expense) $ 0 $ 0
Pension and other postretirement benefits activity, tax benefit (expense) $ (164) $ (185)
v3.25.1
CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($)
$ in Thousands
Mar. 31, 2025
Dec. 31, 2024
CURRENT ASSETS    
Cash and cash equivalents $ 10,047 $ 3,838
Customer and other receivables 430,726 525,608
Accrued unbilled revenues (Note 4) 176,769 176,903
Allowance for doubtful accounts (Note 4) (23,039) (24,849)
Materials and supplies (at average cost) 488,009 469,022
Fossil fuel (at average cost) 16,203 32,420
Assets from risk management activities (Note 9) 77,550 10,578
Deferred fuel and purchased power regulatory asset (Note 6) 228,036 287,597
Other regulatory assets (Note 6) 94,034 133,372
Other current assets 90,995 74,915
Total current assets 1,589,330 1,689,404
INVESTMENTS AND OTHER ASSETS    
Nuclear decommissioning trusts (Notes 13 and 14) 1,286,101 1,282,845
Other special use funds (Notes 13 and 14) 415,401 408,357
Assets from risk management activities (Note 9) 31,375 5,980
Other assets 133,136 115,095
Total investments and other assets 1,866,013 1,812,277
PROPERTY, PLANT AND EQUIPMENT    
Plant in service and held for future use 26,326,246 25,860,950
Accumulated depreciation and amortization (9,327,761) (9,027,426)
Net 16,998,485 16,833,524
Construction work in progress 1,858,894 1,592,659
Palo Verde sale leaseback, net of accumulated depreciation (Note 8) 81,589 82,556
Intangible assets, net of accumulated amortization 555,462 591,310
Nuclear fuel, net of accumulated amortization 112,207 97,850
Total property, plant and equipment 19,606,637 19,197,899
DEFERRED DEBITS    
Regulatory assets (Note 6) 1,372,760 1,389,489
Operating lease right-of-use assets (Note 16) 2,373,880 1,605,463
Assets for pension and other postretirement benefits (Note 7) 353,910 342,102
Other 73,948 66,126
Total deferred debits 4,174,498 3,403,180
TOTAL ASSETS 27,236,478 26,102,760
CURRENT LIABILITIES    
Accounts payable 599,239 485,426
Accrued taxes 232,383 175,863
Accrued interest 82,819 81,799
Common dividends payable 0 106,592
Short-term borrowings (Note 5) 870,197 568,450
Current maturities of long-term debt (Note 5) 800,000 800,000
Customer deposits 45,600 44,345
Liabilities from risk management activities (Note 9) 18,208 52,340
Liabilities for asset retirements 47,344 50,009
Operating lease liabilities (Note 16) 122,929 100,367
Regulatory liabilities (Note 6) 225,332 206,955
Other current liabilities 123,955 171,651
Total current liabilities 3,168,006 2,843,797
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 5) 8,060,736 8,058,648
DEFERRED CREDITS AND OTHER    
Deferred income taxes 2,445,213 2,444,473
Regulatory liabilities (Note 6) 1,910,764 1,855,278
Liabilities for asset retirements 1,112,434 1,096,577
Liabilities for pension benefits (Note 7) 140,437 139,317
Liabilities from risk management activities (Note 9) 9,368 9,446
Customer advances 569,290 569,343
Coal mine reclamation 153,606 171,483
Deferred investment tax credit 249,525 249,490
Unrecognized tax benefits 45,013 44,233
Operating lease liabilities (Note 16) 2,278,493 1,520,877
Other 247,611 242,320
Total deferred credits and other 9,161,754 8,342,837
COMMITMENTS AND CONTINGENCIES (Note 10)
EQUITY    
Common stock, no par value; authorized 150,000,000 shares, 119,445,299 and 119,143,782 issued at respective dates 3,109,612 3,121,617
Treasury stock at cost; 46,968 and 46,968 shares at respective dates (3,323) (3,323)
Total common stock 3,106,289 3,118,294
Retained earnings 3,662,313 3,666,959
Accumulated other comprehensive loss (Note 15) (30,094) (30,942)
Total shareholder equity 6,738,508 6,754,311
Noncontrolling interests (Note 8) 107,474 103,167
Total equity 6,845,982 6,857,478
TOTAL LIABILITIES AND EQUITY $ 27,236,478 $ 26,102,760
v3.25.1
CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - shares
Mar. 31, 2025
Dec. 31, 2024
Statement of Financial Position [Abstract]    
Common stock, authorized (in shares) 150,000,000 150,000,000
Common stock, issued (in shares) 119,445,299 119,143,782
Treasury stock at cost (in shares) 46,968 46,968
v3.25.1
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)
$ in Thousands
 3 Months Ended
Mar. 31, 2025
Mar. 31, 2024
CASH FLOWS FROM OPERATING ACTIVITIES    
Net income (loss) $ (338) $ 21,168
Adjustments to reconcile net income to net cash provided by operating activities:    
Gain on sale relating to BCE 0 (22,988)
Depreciation and amortization including nuclear fuel 250,651 226,413
Deferred fuel and purchased power (25,228) (33,094)
Deferred fuel and purchased power amortization 84,789 108,552
Allowance for equity funds used during construction (13,249) (10,292)
Deferred income taxes 795 (23,297)
Deferred investment tax credit 36 (294)
Stock compensation 7,160 5,935
Changes in current assets and liabilities:    
Customer and other receivables 93,800 84,888
Accrued unbilled revenues 134 1,074
Materials, supplies and fossil fuel (2,770) 4,374
Income tax receivable 0 332
Other current assets (15,008) (32,306)
Accounts payable 56,010 23,799
Accrued taxes 56,520 58,018
Other current liabilities (41,391) (55,343)
Change in long-term regulatory assets 17,614 9,850
Change in long-term regulatory liabilities 12,033 16,493
Change in other long-term assets (45,413) (19,571)
Change in operating lease assets 3,889 (8,416)
Change in other long-term liabilities (40,427) (17,489)
Change in operating lease liabilities 2,288 9,547
Net cash provided by operating activities 401,895 347,353
CASH FLOWS FROM INVESTING ACTIVITIES    
Capital expenditures (622,552) (517,756)
Contributions in aid of construction 51,244 69,047
Proceeds from sale relating to BCE 0 38,681
Allowance for borrowed funds used during construction (10,102) (13,141)
Proceeds from nuclear decommissioning trusts sales and other special use funds 485,814 443,870
Investment in nuclear decommissioning trusts and other special use funds (486,385) (443,854)
Other (4,134) (939)
Net cash used for investing activities (586,115) (424,092)
CASH FLOWS FROM FINANCING ACTIVITIES    
Short-term borrowing and (repayments) - net 301,747 184,000
Dividends paid on common stock (104,934) (98,082)
Common stock equity issuance and (purchases) - net (6,381) (4,500)
Other (3) 0
Net cash provided by financing activities 190,429 81,418
NET INCREASE IN CASH AND CASH EQUIVALENTS 6,209 4,679
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 3,838 4,955
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 10,047 $ 9,634
v3.25.1
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY - USD ($)
$ in Thousands
Total
Common Stock
Treasury Stock
Retained Earnings
Accumulated Other Comprehensive Income (Loss)
Noncontrolling Interests
Beginning balance (in shares) at Dec. 31, 2023   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)      
Increase (Decrease) in Shareholders' Equity            
Net income (loss) 21,168     16,862   4,306
Other comprehensive income 562       562  
Issuance of common stock (in shares) [1]   149,160        
Issuance of common stock [1] 4,830 $ 4,830        
Purchase of treasury stock (in shares) [2]     (71,008)      
Purchase of treasury stock [2] (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        
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)      
Beginning balance (in shares) at Dec. 31, 2024 119,143,782 119,143,782        
Beginning balance at Dec. 31, 2024 $ 6,857,478 $ 3,121,617 $ (3,323) 3,666,959 (30,942) 103,167
Beginning balance (in shares) at Dec. 31, 2024 (46,968)   (46,968)      
Increase (Decrease) in Shareholders' Equity            
Net income (loss) $ (338)     (4,644)   4,306
Other comprehensive income 848       848  
Issuance of common stock (in shares) [1]   301,517        
Issuance of common stock [1] (12,005) $ (12,005)        
Other $ (1)     (2)   1
Ending balance (in shares) at Mar. 31, 2025 119,445,299 119,445,299        
Ending balance at Mar. 31, 2025 $ 6,845,982 $ 3,109,612 $ (3,323) $ 3,662,313 $ (30,094) $ 107,474
Ending balance (in shares) at Mar. 31, 2025 (46,968)   (46,968)      
[1] See Note 12 for information related to our equity forward sale agreements.
[2] Primarily represents shares of common stock withheld from certain stock awards for tax purposes.
v3.25.1
ARIZONA PUBLIC SERVICE COMPANY - CONDENSED CONSOLIDATED STATEMENTS OF INCOME - USD ($)
$ in Thousands
 3 Months Ended
Mar. 31, 2025
Mar. 31, 2024
OPERATING REVENUES (Note 4) $ 1,032,280 $ 951,712
OPERATING EXPENSES    
Fuel and purchased power 380,071 357,864
Operations and maintenance 300,109 257,578
Depreciation and amortization 234,940 210,294
Taxes other than income taxes 59,354 59,164
Other expense 584 20
Total 975,058 884,920
OPERATING INCOME 57,222 66,792
OTHER INCOME (DEDUCTIONS)    
Allowance for equity funds used during construction 13,249 10,292
Pension and other postretirement non-service credits - net (Note 7) 2,958 11,568
Other income (Note 11) 17,461 30,607
Other expense (Note 11) (2,570) (7,567)
Total 31,098 44,900
INTEREST EXPENSE    
Interest charges 104,943 99,774
Allowance for borrowed funds used during construction (10,102) (13,141)
Total 94,841 86,633
Income (Loss) Before Income Taxes (6,521) 25,059
Income taxes (benefit) (6,183) 3,891
Net Income (Loss) (338) 21,168
Less: Net income attributable to noncontrolling interests (Note 8) 4,306 4,306
Net Income (Loss) Attributable to Common Shareholders (4,644) 16,862
APS    
OPERATING REVENUES (Note 4) 1,032,280 951,712
OPERATING EXPENSES    
Fuel and purchased power 380,071 357,864
Operations and maintenance 296,651 253,593
Depreciation and amortization 234,923 210,273
Taxes other than income taxes 59,336 59,078
Other expense 584 20
Total 971,565 880,828
OPERATING INCOME 60,715 70,884
OTHER INCOME (DEDUCTIONS)    
Allowance for equity funds used during construction 13,249 10,292
Pension and other postretirement non-service credits - net (Note 7) 3,200 11,773
Other income (Note 11) 5,722 6,855
Other expense (Note 11) (2,333) (2,894)
Total 19,838 26,026
INTEREST EXPENSE    
Interest charges 88,771 86,979
Allowance for borrowed funds used during construction (10,102) (13,141)
Total 78,669 73,838
Income (Loss) Before Income Taxes 1,884 23,072
Income taxes (benefit) (2,701) 3,649
Net Income (Loss) 4,585 19,423
Less: Net income attributable to noncontrolling interests (Note 8) 4,306 4,306
Net Income (Loss) Attributable to Common Shareholders $ 279 $ 15,117
v3.25.1
ARIZONA PUBLIC SERVICE COMPANY - CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($)
$ in Thousands
 3 Months Ended
Mar. 31, 2025
Mar. 31, 2024
NET INCOME (LOSS) $ (338) $ 21,168
OTHER COMPREHENSIVE INCOME, NET OF TAX    
Pension and other postretirement benefits activity, net of tax expense of $(133) and $(161) 498 562
Total other comprehensive income 848 562
Total other comprehensive income 510 21,730
Less: Comprehensive income attributable to noncontrolling interests 4,306 4,306
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS (3,796) 17,424
APS    
NET INCOME (LOSS) 4,585 19,423
OTHER COMPREHENSIVE INCOME, NET OF TAX    
Pension and other postretirement benefits activity, net of tax expense of $(133) and $(161) 406 490
Total other comprehensive income 406 490
Total other comprehensive income 4,991 19,913
Less: Comprehensive income attributable to noncontrolling interests 4,306 4,306
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS $ 685 $ 15,607
v3.25.1
ARIZONA PUBLIC SERVICE COMPANY - CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($)
$ in Thousands
 3 Months Ended
Mar. 31, 2025
Mar. 31, 2024
Pension and other postretirement benefits activity, net of tax benefit (expense) $ (164) $ (185)
APS    
Pension and other postretirement benefits activity, net of tax benefit (expense) $ (133) $ (161)
v3.25.1
ARIZONA PUBLIC SERVICE COMPANY - CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($)
$ in Thousands
Mar. 31, 2025
Dec. 31, 2024
PROPERTY, PLANT AND EQUIPMENT    
Plant in service and held for future use $ 26,326,246 $ 25,860,950
Accumulated depreciation and amortization (9,327,761) (9,027,426)
Net 16,998,485 16,833,524
Construction work in progress 1,858,894 1,592,659
Palo Verde sale leaseback, net of accumulated depreciation (Note 8) 81,589 82,556
Intangible assets, net of accumulated amortization 555,462 591,310
Nuclear fuel, net of accumulated amortization 112,207 97,850
Total property, plant and equipment 19,606,637 19,197,899
INVESTMENTS AND OTHER ASSETS    
Nuclear decommissioning trusts (Notes 13 and 14) 1,286,101 1,282,845
Other special use funds (Notes 13 and 14) 415,401 408,357
Assets from risk management activities (Note 9) 31,375 5,980
Other assets 133,136 115,095
Total investments and other assets 1,866,013 1,812,277
CURRENT ASSETS    
Cash and cash equivalents 10,047 3,838
Customer and other receivables 430,726 525,608
Accrued unbilled revenues (Note 4) 176,769 176,903
Allowance for doubtful accounts (Note 4) (23,039) (24,849)
Materials and supplies (at average cost) 488,009 469,022
Fossil fuel (at average cost) 16,203 32,420
Assets from risk management activities (Note 9) 77,550 10,578
Deferred fuel and purchased power regulatory asset (Note 6) 228,036 287,597
Other regulatory assets (Note 6) 94,034 133,372
Other current assets 90,995 74,915
Total current assets 1,589,330 1,689,404
DEFERRED DEBITS    
Regulatory assets (Note 6) 1,372,760 1,389,489
Operating lease right-of-use assets (Note 16) 2,373,880 1,605,463
Assets for pension and other postretirement benefits (Note 7) 353,910 342,102
Other 73,948 66,126
Total deferred debits 4,174,498 3,403,180
TOTAL ASSETS 27,236,478 26,102,760
CAPITALIZATION    
Retained earnings 3,662,313 3,666,959
Accumulated other comprehensive loss (Note 15) (30,094) (30,942)
Total shareholder equity 6,738,508 6,754,311
Noncontrolling interests (Note 8) 107,474 103,167
Total equity 6,845,982 6,857,478
Long-term debt less current maturities (Note NA) 8,060,736 8,058,648
CURRENT LIABILITIES    
Short-term borrowings (Note 5) 870,197 568,450
Current maturities of long-term debt (Note 5) 800,000 800,000
Accounts payable 599,239 485,426
Accrued taxes 232,383 175,863
Accrued interest 82,819 81,799
Common dividends payable 0 106,592
Customer deposits 45,600 44,345
Liabilities from risk management activities (Note 9) 18,208 52,340
Liabilities for asset retirements 47,344 50,009
Operating lease liabilities (Note 16) 122,929 100,367
Less: current regulatory liabilities 225,332 206,955
Other current liabilities 123,955 171,651
Total current liabilities 3,168,006 2,843,797
DEFERRED CREDITS AND OTHER    
Deferred income taxes 2,445,213 2,444,473
Regulatory liabilities (Note 6) 1,910,764 1,855,278
Liabilities for asset retirements 1,112,434 1,096,577
Liabilities for pension benefits (Note 7) 140,437 139,317
Liabilities from risk management activities (Note 9) 9,368 9,446
Customer advances 569,290 569,343
Coal mine reclamation 153,606 171,483
Deferred investment tax credit 249,525 249,490
Unrecognized tax benefits 45,013 44,233
Operating lease liabilities (Note 16) 2,278,493 1,520,877
Other 247,611 242,320
Total deferred credits and other 9,161,754 8,342,837
COMMITMENTS AND CONTINGENCIES (Note 10)
TOTAL LIABILITIES AND EQUITY 27,236,478 26,102,760
APS    
PROPERTY, PLANT AND EQUIPMENT    
Plant in service and held for future use 26,325,364 25,860,068
Accumulated depreciation and amortization (9,326,879) (9,026,544)
Net 16,998,485 16,833,524
Construction work in progress 1,858,894 1,592,659
Palo Verde sale leaseback, net of accumulated depreciation (Note 8) 81,589 82,556
Intangible assets, net of accumulated amortization 555,306 591,154
Nuclear fuel, net of accumulated amortization 112,207 97,850
Total property, plant and equipment 19,606,481 19,197,743
INVESTMENTS AND OTHER ASSETS    
Nuclear decommissioning trusts (Notes 13 and 14) 1,286,101 1,282,845
Other special use funds (Notes 13 and 14) 380,257 374,156
Assets from risk management activities (Note 9) 31,375 5,980
Other assets 50,921 49,673
Total investments and other assets 1,748,654 1,712,654
CURRENT ASSETS    
Cash and cash equivalents 8,541 3,815
Customer and other receivables 427,753 522,886
Accrued unbilled revenues (Note 4) 176,769 176,903
Allowance for doubtful accounts (Note 4) (23,039) (24,849)
Materials and supplies (at average cost) 488,009 469,022
Fossil fuel (at average cost) 16,203 32,420
Income tax receivable 42 5,463
Assets from risk management activities (Note 9) 77,550 10,578
Deferred fuel and purchased power regulatory asset (Note 6) 228,036 287,597
Other regulatory assets (Note 6) 94,034 133,372
Other current assets 81,854 65,754
Total current assets 1,575,752 1,682,961
DEFERRED DEBITS    
Regulatory assets (Note 6) 1,372,760 1,389,489
Operating lease right-of-use assets (Note 16) 2,372,772 1,604,324
Assets for pension and other postretirement benefits (Note 7) 347,185 335,458
Other 73,415 65,606
Total deferred debits 4,166,132 3,394,877
TOTAL ASSETS 27,097,019 25,988,235
CAPITALIZATION    
Common stock 178,162 178,162
Additional paid-in capital 4,116,696 4,116,696
Retained earnings 3,992,700 3,992,423
Accumulated other comprehensive loss (Note 15) (13,710) (14,116)
Total shareholder equity 8,273,848 8,273,165
Noncontrolling interests (Note 8) 107,474 103,167
Total equity 8,381,322 8,376,332
Long-term debt less current maturities (Note NA) 7,191,990 7,190,878
Total capitalization 15,573,312 15,567,210
CURRENT LIABILITIES    
Short-term borrowings (Note 5) 626,600 339,900
Current maturities of long-term debt (Note 5) 300,000 300,000
Accounts payable 592,109 481,955
Accrued taxes 237,738 181,698
Accrued interest 72,498 79,308
Common dividends payable 0 107,200
Customer deposits 45,600 44,345
Liabilities from risk management activities (Note 9) 18,208 52,340
Liabilities for asset retirements 47,344 50,009
Operating lease liabilities (Note 16) 122,788 100,229
Less: current regulatory liabilities 225,332 206,955
Other current liabilities 116,655 177,019
Total current liabilities 2,404,872 2,120,958
DEFERRED CREDITS AND OTHER    
Deferred income taxes 2,419,729 2,419,937
Regulatory liabilities (Note 6) 1,910,764 1,855,278
Liabilities for asset retirements 1,112,434 1,096,577
Liabilities for pension benefits (Note 7) 136,534 134,855
Liabilities from risk management activities (Note 9) 9,368 9,446
Customer advances 569,290 569,343
Coal mine reclamation 153,606 171,483
Deferred investment tax credit 249,525 249,490
Unrecognized tax benefits 49,505 48,725
Operating lease liabilities (Note 16) 2,277,336 1,519,683
Other 230,744 225,250
Total deferred credits and other 9,118,835 8,300,067
COMMITMENTS AND CONTINGENCIES (Note 10)
TOTAL LIABILITIES AND EQUITY $ 27,097,019 $ 25,988,235
v3.25.1
ARIZONA PUBLIC SERVICE COMPANY - CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)
$ in Thousands
 3 Months Ended
Mar. 31, 2025
Mar. 31, 2024
CASH FLOWS FROM OPERATING ACTIVITIES    
Net income (loss) $ (338) $ 21,168
Adjustments to reconcile net income to net cash provided by operating activities:    
Depreciation and amortization including nuclear fuel 250,651 226,413
Deferred fuel and purchased power (25,228) (33,094)
Deferred fuel and purchased power amortization 84,789 108,552
Allowance for equity funds used during construction (13,249) (10,292)
Deferred income taxes 795 (23,297)
Deferred investment tax credit 36 (294)
Changes in current assets and liabilities:    
Customer and other receivables 93,800 84,888
Accrued unbilled revenues 134 1,074
Materials, supplies and fossil fuel (2,770) 4,374
Income tax receivable 0 332
Other current assets (15,008) (32,306)
Accounts payable 56,010 23,799
Accrued taxes 56,520 58,018
Other current liabilities (41,391) (55,343)
Change in long-term regulatory assets 17,614 9,850
Change in long-term regulatory liabilities 12,033 16,493
Change in other long-term assets (45,413) (19,571)
Change in operating lease assets 3,889 (8,416)
Change in other long-term liabilities (40,427) (17,489)
Change in operating lease liabilities 2,288 9,547
Net cash provided by operating activities 401,895 347,353
CASH FLOWS FROM INVESTING ACTIVITIES    
Capital expenditures (622,552) (517,756)
Contributions in aid of construction 51,244 69,047
Allowance for borrowed funds used during construction (10,102) (13,141)
Proceeds from nuclear decommissioning trusts sales and other special use funds 485,814 443,870
Investment in nuclear decommissioning trusts and other special use funds (486,385) (443,854)
Other (4,134) (939)
Net cash used for investing activities (586,115) (424,092)
CASH FLOWS FROM FINANCING ACTIVITIES    
Short-term borrowing and (repayments) - net 301,747 184,000
Dividends paid on common stock (104,934) (98,082)
Net cash provided by financing activities 190,429 81,418
NET INCREASE IN CASH AND CASH EQUIVALENTS 6,209 4,679
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 3,838 4,955
CASH AND CASH EQUIVALENTS AT END OF PERIOD 10,047 9,634
APS    
CASH FLOWS FROM OPERATING ACTIVITIES    
Net income (loss) 4,585 19,423
Adjustments to reconcile net income to net cash provided by operating activities:    
Depreciation and amortization including nuclear fuel 250,634 226,392
Deferred fuel and purchased power (25,228) (33,094)
Deferred fuel and purchased power amortization 84,789 108,552
Allowance for equity funds used during construction (13,249) (10,292)
Deferred income taxes (123) 2,071
Deferred investment tax credit 36 (294)
Changes in current assets and liabilities:    
Customer and other receivables 94,051 84,357
Accrued unbilled revenues 134 1,074
Materials, supplies and fossil fuel (2,770) 4,374
Income tax receivable 5,421 0
Other current assets (15,028) 3,516
Accounts payable 52,351 26,328
Accrued taxes 56,040 59,745
Other current liabilities (61,892) (82,478)
Change in long-term regulatory assets 17,614 9,850
Change in long-term regulatory liabilities 12,033 16,493
Change in other long-term assets (30,585) (51,555)
Change in operating lease assets 3,858 (8,479)
Change in other long-term liabilities (26,322) (19,584)
Change in operating lease liabilities 2,325 9,581
Net cash provided by operating activities 408,674 365,980
CASH FLOWS FROM INVESTING ACTIVITIES    
Capital expenditures (622,552) (517,756)
Contributions in aid of construction 51,244 69,047
Allowance for borrowed funds used during construction (10,102) (13,141)
Proceeds from nuclear decommissioning trusts sales and other special use funds 460,538 443,870
Investment in nuclear decommissioning trusts and other special use funds (461,109) (443,854)
Other (1,467) (51)
Net cash used for investing activities (583,448) (461,885)
CASH FLOWS FROM FINANCING ACTIVITIES    
Short-term borrowing and (repayments) - net 286,700 200,650
Dividends paid on common stock (107,200) (99,800)
Net cash provided by financing activities 179,500 100,850
NET INCREASE IN CASH AND CASH EQUIVALENTS 4,726 4,945
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 3,815 4,549
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 8,541 $ 9,494
v3.25.1
ARIZONA PUBLIC SERVICE COMPANY - CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY - USD ($)
$ in Thousands
Total
Common Stock
Retained Earnings
Accumulated Other Comprehensive Income (Loss)
Noncontrolling Interests
APS
APS
Common Stock
APS
Additional Paid-In Capital
APS
Retained Earnings
APS
Accumulated Other Comprehensive Income (Loss)
APS
Noncontrolling Interests
Beginning balance (in shares) at Dec. 31, 2023   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 (loss) 21,168   16,862   4,306 19,423     15,117   4,306
Other comprehensive income 562     562   490       490  
Other 0   (1)     (2)     (2)    
Ending balance (in shares) at Mar. 31, 2024   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
Beginning balance (in shares) at Dec. 31, 2024 119,143,782 119,143,782         71,264,947        
Beginning balance at Dec. 31, 2024 $ 6,857,478 $ 3,121,617 3,666,959 (30,942) 103,167 8,376,332 $ 178,162 4,116,696 3,992,423 (14,116) 103,167
Increase (Decrease) in Shareholders' Equity                      
Net income (loss) (338)   (4,644)   4,306 4,585     279   4,306
Other comprehensive income 848     848   406       406  
Other $ (1)   (2)   1 (1)     (2)   1
Ending balance (in shares) at Mar. 31, 2025 119,445,299 119,445,299         71,264,947        
Ending balance at Mar. 31, 2025 $ 6,845,982 $ 3,109,612 $ 3,662,313 $ (30,094) $ 107,474 $ 8,381,322 $ 178,162 $ 4,116,696 $ 3,992,700 $ (13,710) $ 107,474
v3.25.1
Consolidation and Nature of Operations
 3 Months Ended
Mar. 31, 2025
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, including 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 Pinnacle West include the accounts of Pinnacle West and its subsidiaries as well as a variable interest entity (“VIE”) related to a Captive Insurance Cell (“Captive”). The unaudited Condensed Consolidated Financial Statements for APS include the accounts of APS and the Palo Verde Generating Station (“Palo Verde”) VIEs. See Note 8 for further discussion on Pinnacle West’s VIEs. El Dorado is a wholly-owned subsidiary that invests in energy-related and Arizona community-based ventures. PNW Power is a wholly-owned subsidiary that holds certain investments in wind and transmission joint venture projects that were previously held by Bright Canyon Energy Corporation (“BCE”). 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 18 for more information relating to the sale of BCE.

Amounts reported in our unaudited 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, 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 2024 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,
20252024
Cash paid (received) during the period for:
Income taxes, net of refunds$(10,799)$20,970 
Interest, net of amounts capitalized91,475 83,974 
Significant non-cash investing and financing activities:
Accrued capital expenditures$315,297 $217,684 
BCE Sale non-cash consideration (Note 18)
— 45,608 

The following table summarizes supplemental APS cash flow information (dollars in thousands):
Three Months Ended March 31,
20252024
Cash paid (received) during the period for:
Income taxes, net of refunds$(5,392)$— 
Interest, net of amounts capitalized84,110 73,035 
Significant non-cash investing and financing activities:
Accrued capital expenditures$315,297 $217,684 
v3.25.1
Business Segments
 3 Months Ended
Mar. 31, 2025
Segment Reporting [Abstract]  
Business Segments Business Segments
 
Pinnacle West’s reportable business segment is our regulated electricity segment, which consists of retail and wholesale sales supplied under traditional cost-based regulation and related activities and includes electricity generation, transmission, and distribution. Our reportable segment activities are conducted through our wholly-owned subsidiary, APS. All other operating segment activities are insignificant to Pinnacle West.

For segment reporting purposes, Pinnacle West’s Chief Executive Officer performs the function of chief operating decision maker (“CODM”). Our CODM uses net income to measure an operating segment’s profitability. When assessing the performance of an operating segment, and making decisions about allocating resources, our CODM evaluates net income actual results compared to budget. Net income is also used when implementing strategic initiatives and selecting projects to meet business objectives. Our reportable segment’s revenue streams are dependent upon regulated rate recovery, which is a primary factor in how we identify operating segments.
For information on our reportable business segment’s revenues, significant expenses, net income, assets, and other reportable segment items, see the APS Condensed Consolidated Statements of Income, APS Condensed Consolidated Balance Sheets, and APS Condensed Consolidated Statements of Cash Flows. The following table reconciles our reportable segment’s revenues, significant expenses, and net income to the Pinnacle West Consolidated amounts (dollars in millions):

Three Months Ended March 31,
20252024
Regulated Electricity SegmentOther Pinnacle West ConsolidatedRegulated Electricity SegmentOther Pinnacle West Consolidated
Operating Revenues$1,032 $— $1,032 $952 $— $952 
Fuel and purchased power (380)— (380)(358)— (358)
Operations and maintenance(297)(3)(300)(254)(4)(258)
Depreciation and amortization (235)— (235)(210)— (210)
Taxes other than income taxes (59)— (59)(59)— (59)
Pension and other postretirement non-service credits, net3 — 3 12 — 12 
Allowance for equity funds used during construction13 — 13 10 — 10 
Other income and expenses, net3 11 14 4 19 23 
Interest expense and costs(79)(16)(95)(74)(13)(87)
Income Taxes3 3 6 (4)— (4)
Less: Net income attributable to noncontrolling interests(4)— (4)(4)— (4)
Net Income (Loss) $— $(5)$(5)$15 $2 $17 

The following table reconciles our reportable segment's assets to the Pinnacle West Consolidated amount (dollars in millions):
March 31, 2025December 31, 2024
Regulated Electricity SegmentOtherPinnacle West ConsolidatedRegulated Electricity SegmentOtherPinnacle West Consolidated
Total Assets$27,097 $139 $27,236 $25,988 $115 $26,103 
v3.25.1
New Accounting Standards
 3 Months Ended
Mar. 31, 2025
Accounting Standards Update and Change in Accounting Principle [Abstract]  
New Accounting Standards New Accounting Standards
 
ASU 2023-09, Income Taxes: Improvements to Income Tax Disclosures

In December 2023, a new accounting standard was issued that expands disclosures relating to income taxes. The expanded disclosures include a tabular income tax rate reconciliation, disclosure of specific reconciliation categories and reconciling items, the amount of income taxes paid by jurisdiction, and other disclosures. We will adopt this standard on December 31, 2025, using a prospective approach. The adoption of the new standard will result in changes to our income tax disclosures, but will not impact our accounting for income taxes or our financial statement results.

ASU 2024-03, Income Statement: Expense Disaggregation Disclosures

In November 2024, a new accounting standard was issued that requires specific disclosures related to certain costs and expenses. Companies will be required to disclose the amounts of certain cost and expense categories, such as: purchases of inventory, employee compensation, depreciation, and
amortization, among other disclosures. The new disclosures may be provided in the notes to the financial statements, and will not require changes to the face of the Statements of Income. The standard becomes effective on December 31, 2027, using either a prospective or retrospective approach, with early adoption permitted. The adoption of the new standard will result in disclosure changes, but will not impact our accounting for such costs and expenses or our financial statement results.
v3.25.1
Revenue
 3 Months Ended
Mar. 31, 2025
Revenue from Contract with Customer [Abstract]  
Revenue Revenue
Sources of Revenue

The following table provides detail of Pinnacle West’s consolidated revenues disaggregated by revenue sources (dollars in thousands):
Three Months Ended March 31,
20252024
Retail Electric Service
Residential$448,923 $432,692 
Non-Residential524,857 461,483 
Wholesale Energy Sales24,824 26,864 
Transmission Services for Others25,547 27,712 
Other Sources8,129 2,961 
Total Operating Revenues$1,032,280 $951,712 

Retail Electric Revenues

All of Pinnacle West’s retail electric revenues are 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, 2025 and 2024 were $1,019 million and $943 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, 2025 and 2024 our revenues that do not qualify as revenue from contracts with customers were $13 million and $9 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 6 for a discussion of our regulatory cost recovery mechanisms.
Allowance for Doubtful Accounts
The allowance for doubtful accounts represents our best estimate of customer and other receivables 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, 2025December 31, 2024
Balance at beginning of period$24,849 $22,433 
Bad debt expense4,789 35,799 
Actual write-offs(6,599)(33,383)
Balance at end of period$23,039 $24,849 
v3.25.1
Debt and Liquidity Matters
 3 Months Ended
Mar. 31, 2025
Debt Disclosure [Abstract]  
Debt and Liquidity Matters 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

As of March 31, 2025, Pinnacle West had a $200 million revolving credit facility that matures on April 10, 2029. 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 provides for an interest rate reduction or increase, by meeting or missing, respectively, targets related to specific environmental and employee health and safety sustainability objectives. Under certain circumstances, the sustainability-linked pricing metric can be terminated for the final year of the credit facility. 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. As of March 31, 2025, Pinnacle West had no outstanding borrowings under its revolving credit facility, no letters of credit outstanding under its credit facility, and $44 million of outstanding commercial paper borrowings. The weighted-average interest rate for the outstanding borrowings on March 31, 2025 was 4.65%.

Pinnacle West also has an outstanding 364-day $200 million term loan facility that matures on December 4, 2025. Borrowings under the facility bear interest at SOFR plus 0.95% per annum.
On February 28, 2024, Pinnacle West entered into equity forward sale agreements (the “February 2024 Forward Sale Agreements”), which may be settled with Pinnacle West common stock or cash. Pinnacle West also has an at-the-market equity distribution program (the “ATM Program”) under which it may offer and sell common stock and enter into forward sale agreements from time to time, subject to market conditions and other factors. See Note 12 for more information on the February 2024 Forward Sale Agreements and the ATM Program.
APS

As of March 31, 2025, APS had a $1.25 billion revolving credit facility, that matures on April 10, 2029. 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 provides for an interest rate reduction or increase, by meeting or missing, respectively, targets related to specific environmental and employee health and safety sustainability objectives. Under certain circumstances, the sustainability-linked pricing metric can be terminated for the final year of the credit facility. The facility is available to support APS’s general corporate purposes, including support for APS’s $1 billion commercial paper program, for bank borrowings or for issuances of letters of credit. As of March 31, 2025, APS had no outstanding borrowings under its revolving credit facility, no letters of credit outstanding under the credit facility, and $627 million of outstanding commercial paper borrowings. The weighted-average interest rate for the outstanding borrowings on March 31, 2025 was 4.64%.

On December 5, 2024, APS entered into a $400 million 364-Day Term Loan Agreement that matures on December 4, 2025. Borrowings under the facility bear interest at SOFR plus 0.90% per annum. On April 29, 2025, APS drew the full amount of $400 million.
The ACC has authorized a limit on yearly equity infusions into APS equal to 2.5% of APS’s total assets each calendar year on a three-year rolling average basis, subject to APS’s equity ratio remaining below the most recently approved rate case capital structure plus 50 basis points.
See “Financial Assurances” in Note 10 for a discussion of other outstanding letters of credit.

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, 2025As of December 31, 2024
 Carrying
Amount		Fair ValueCarrying
Amount		Fair Value
Pinnacle West$1,368,746 $1,437,105 $1,367,770 $1,393,744 
APS7,491,990 6,596,763 7,490,878 6,525,248 
Total$8,860,736 $8,033,868 $8,858,648 $7,918,992 
v3.25.1
Regulatory Matters
 3 Months Ended
Mar. 31, 2025
Regulated Operations [Abstract]  
Regulatory Matters Regulatory Matters
ACC General Retail Rate Cases

APS expects to file an application with the ACC for its next general rate case mid-year 2025 and is continuing to evaluate the timing of such filing.

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 January 25, 2024, an Administrative Law Judge issued a Recommended Opinion and Order (“ROO”) 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 Power Plant (“Four Corners”) Effluent Limitations Guideline (“ELG”) project, (vi) the approval of APS’s System Reliability Benefit (“SRB”) proposal with certain procedural and other modifications, (vii) no additional Coal Community Transition (“CCT”) funding, (viii) a 5.0% return on the prepaid pension asset and a return of 5.35% on the Other Post-Employment Benefits 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 Demand Side Management (“DSM”) performance incentives and the requested DSM transfer to base rates, (ii) the retention of $1.9 million of Renewable Energy Adjustment Charge (“REAC”) in the adjustor rather than base rates, (iii) a partial transfer of $27.1 million of Lost Fixed Cost
Recovery Mechanism (“LFCR”) funds to base rates, and (iv) the adoption of an increase in the annual Power Supply Adjustor (“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 (“ASRFP”), and (viii) recovery of all DSM costs through the DSM Adjustment Charge (“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 (“AriSEIA”), Solar Energy Industries Association (“SEIA”), and Vote Solar specifically to review 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. A limited rehearing was held October 28 through November 1, 2024. Following the limited rehearing, an Administrative Law Judge issued a ROO (the “Limited Rehearing ROO”) on December 3, 2024. The Limited Rehearing ROO recommended affirming the GAC as just and reasonable and that the GAC is not discriminatory to solar customers and the absence of a GAC is not discriminatory to non-solar customers. On December 17, 2024, the ACC approved the Limited Rehearing ROO with an amendment that requires APS in its next rate case to propose a revenue allocation based on a site-load cost of service study in order to bring further parity in revenue collection between solar and non-solar customers. SEIA, AriSEIA, Vote Solar, the Arizona Attorney General, and two individual customers have filed requests for rehearing of the Commission’s December 17, 2024 decision on the rehearing. The Commission has taken no action on these requests. In addition, each of these parties have subsequently filed notices of appeal to the Arizona Court of Appeals seeking review of the ACC’s decisions regarding the GAC and on rehearing. APS cannot predict the outcome of these proceedings.
Coal Community Transition

On October 31, 2019, APS filed an application with the ACC (the “2019 Rate Case”) for an annual increase in retail base rates. As a part of the 2019 Rate Case decision, the ACC approved the Coal Community Transition (“CCT”) Plan consisting of payments to certain impacted communities. APS has completed the following payments that are being recovered through rates related to CCT Plan: (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) $2 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 also authorized $1.25 million to be spent for electrification of homes and businesses on each of the Navajo Nation and Hopi reservations. 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 funds 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.

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 and held two workshops exploring ways to reduce regulatory lag, including alternative ratemaking structures such as future test years, hybrid test years, and formula rates. On December 3, 2024, the ACC approved a policy statement regarding formula rate plans. The policy statement provides regulated utilities with the opportunity to propose formula rate plans in future rate cases. On March 28, 2025, the Residential Utility Consumer Office filed a lawsuit challenging the ACC’s authority to issue the formula rate policy statement outside of Arizona’s formula rulemaking process. 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 (“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, for example, 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.

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 2023. 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. APS cannot predict the outcome of this proceeding.

On July 1, 2024, APS filed its 2025 RES Implementation Plan and proposed a budget of approximately $92.7 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 2024. The ACC has not yet ruled on the 2025 RES Implementation Plan. APS cannot predict the outcome of this proceeding.

On June 14, 2021, APS filed an application for approval of its Green Power Partners Program (“GPP”). On September 1, 2021, the ACC approved the application. On June 28, 2024, APS filed an application for approval of modifications to the GPP and requested a renewable generation renewable energy credits waiver. The ACC has not yet ruled on the GPP application. APS cannot predict the outcome of this proceeding.

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 Implementation Plan requested a budget of $78.4 million. 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 Transportation Electrification (“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 of $90.9 million to reflect removal of incentive funds for the Level 2 Smart Charger rebate within 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. In a letter filed May 31, 2024, APS said it would not file a 2025 DSM Implementation Plan pending ACC review of the amended 2024 DSM Implementation Plan. APS cannot predict the outcome of this proceeding.

On August 30, 2024, APS filed an application for a new Bring-Your-Own-Device (“BYOD”) Battery Pilot Plan of Administration with the ACC as required by Decision No. 79293. This plan would allow APS to work with residential customers to enable APS to dispatch participating batteries and use them to provide demand response capacity to the grid. On March 20, 2025, the ACC approved the BYOD Plan of Administration. The BYOD program will be incorporated into future DSM plan filings.

On March 6, 2025, APS filed an application to refund uncommitted surcharge funds that were collected through the DSMAC and REAC adjustors. On April 22, 2025, the ACC voted to approve the refund of the DSMAC and REAC uncommitted surcharge funds. This refund will be provided directly to customers during the months of July and August 2025. The proposed rates are designed to refund customers $9 million for DSMAC and $43 million for REAC, although the actual refund amount is dependent upon monthly usage billed.

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 portion of APS’s retail base rates attributable to fuel and purchased power costs (“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 (dollars in thousands):
 Three Months Ended March 31,
 20252024
Balance at beginning of period$287,597 $463,195 
Deferred fuel and purchased power costs25,228 33,094 
Amounts charged to customers
(84,789)(108,552)
Balance at end of period$228,036 $387,737 

On November 30, 2021, APS filed its PSA rate for the PSA year beginning February 1, 2022. That rate was $0.007544 per kWh, which consisted of a forward component of $(0.004842) per kWh and a historical component of $0.012386 per kWh. The 2022 PSA rate was a $0.004 per kWh increase compared to the 2021 PSA year, which is the maximum permitted under the Plan of Administration for the PSA. These rates went into effect as filed on February 1, 2022.

On November 30, 2022, APS filed its PSA rate for the PSA year beginning February 1, 2023. In this filing, APS also requested that one of three different options be adopted to address the growing undercollected PSA balance. 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. On November 30, 2023, APS notified the ACC that it will be maintaining a 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 overall PSA rate was reduced to offset an increase in base fuel prices. The rate became effective on March 8, 2024.

On November 27, 2024, APS filed its PSA rate for the PSA year beginning February 1, 2025. The overall PSA rate of $0.013977 per kWh consists of a forward component of $(0.000281) per kWh, a historical component of $0.008728 per kWh, and a transition component of $0.005530. This overall PSA rate is an increase of $0.002 per kWh over the prior overall rate approved in the 2022 Rate Case decision, and it is below the annual PSA rate increase cap of $0.006 per kWh. On February 5, 2025, the ACC voted to approve this request, with a rate effective date of the first billing cycle in March 2025.

Environmental Improvement Surcharge (“EIS”)

On March 5, 2024, because the ACC approved the elimination of the EIS, the surcharge is no longer in effect and any remaining amounts are being collected through base rates. 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.
 
Transmission Rates, Transmission Cost Adjustor (“TCA”) and Other Transmission Matters

APS’s retail transmission charges’ 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.

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.

Effective June 1, 2024, APS’s annual wholesale transmission revenue requirement for all users of its transmission system increased by approximately $27.4 million for the 12-month period beginning June 1, 2024 in accordance with the FERC-approved formula. Of this net amount, wholesale customer rates increased by approximately $16.6 million and retail customer rates would have increased by approximately $10.8 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 increased by $8.8 million, resulting in an increase to residential and commercial rates over 3 MW and a decrease to commercial rates less than or equal to 3 MW. An adjustment to APS’s retail rates to recover FERC-approved transmission charges went into effect automatically on June 1, 2024.
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.
 
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 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.

On June 5, 2024, APS filed a revised LFCR Plan of Administration in accordance with Decision No. 79293. The ACC approved the revised Plan of Administration on October 8, 2024.

On July 31, 2024, APS filed its 2024 annual LFCR adjustment, requesting that effective November 1, 2024, the annual LFCR recovery amount be increased to $49.6 million (an $8 million increase from previous levels). On December 3, 2024, the ACC approved the 2024 annual LFCR adjustment, with new rates effective in the first billing cycle of January 2025.

Tax Expense Adjustor Mechanism (“TEAM”)

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. Currently, the TEAM is set to a zero rate as per Decision No. 79293.
Court Resolution Surcharge

Following an appeal of the 2019 Rate Case decision, the ACC approved a Court Resolution Surcharge (“CRS”) mechanism that permits APS to recover certain costs associated with investments and expenses for APS’s purchase and installation of selective catalytic reduction (“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 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 2021 and June 20, 2023, $29.5 million of which has been collected as of March 31, 2025, 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.

Net Metering

Payments by APS for energy exported to the grid from residential DG solar facilities are determined using a Resource Comparison Proxy (“RCP”) methodology as determined in the ACC’s generic Value and Cost of Distributed Generation docket. The 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 is updated annually (between general retail rate cases) but cannot be decreased by more than 10% per year.

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 May 1, 2024, APS filed an application for revisions to the RCP. This application would decrease the RCP price to 6.857 cents per kWh, reflecting a 10% annual reduction, to become effective September 1, 2024. On August 13, 2024, 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 took place on May 20, 2024 and ACC Staff issued a request for additional information to investigate the issues related to the matter on May 31, 2024.
Stakeholders provided responses to the ACC Staff’s request for additional information on July 1, 2024, and on October 15, 2024, the ACC Staff filed a report finding that the RCP is working as intended and recommending no changes to the RCP at this time. The ACC Staff also recommended that the ACC close the docket without a hearing or further action. On March 19, 2025, the ACC Hearing Division filed a ROO that agreed with Staff’s recommendation to close the docket. The ACC has not yet acted on the ACC Staff’s recommendation. 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 RES, and energy efficiency standards (“EES”). On January 9, 2024, the ACC approved the opening of new dockets to begin rulemaking process for EES and RES. It was also ordered that an existing rulemaking docket would be utilized to review proposed updates to the ASRFP and Resource Planning Rules. During the ACC Open Meeting on February 6, 2024, the ACC approved motions to direct ACC Staff to include recommendations to repeal the current EES and RES rules during the rulemaking process. On August 21, 2024, the ACC Staff filed separate reports for each set of rules, including its recommendations to repeal the EES and RES rules along with required preliminary economic, small business, and consumer impact statements. APS and other interested parties have filed comments about the ACC Staff reports. APS cannot predict the outcome of this matter.

Integrated Resource Planning (“IRP”)

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 filed its response to stakeholder comments on May 31, 2024. On July 31, 2024, the ACC held an IRP workshop where utilities and stakeholders presented on the 2023 IRPs. On October 8, 2024, the ACC acknowledged APS’s 2023 IRP and approved certain amendments to the IRP process, including requirements for APS to demonstrate resource adequacy prior to exiting Four Corners as well as analysis of impacts from western market participation and planned resource requirements in the next IRP.

Residential Electric Utility Customer Service Disconnections

In accordance with the ACC’s service disconnection rules, APS uses a calendar-based method to suspend the disconnection of customers for nonpayment from June 1 through October 15 each year (“Annual Disconnection Moratorium”). Since the Annual Disconnection Moratorium began, APS has experienced an increase in bad debt expense and the related write-offs of delinquent customer accounts. Pursuant to an ACC order, customers with past due balances of $75 or greater as of approximately one month prior to the end of the Annual Disconnection Moratorium are automatically placed on six-month payment arrangements.
Cholla ACC Deferral Request

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, the 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 was 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 is allowed continued recovery of the net book value of the unit and the unit’s decommissioning and other retirement-related costs, $27 million as of March 31, 2025, 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 regulatory assets. In accordance with the 2019 Rate Case decision, the regulatory asset is being amortized through 2033.

On August 14, 2024, APS filed a request with the ACC for a deferral order associated with unrecovered book value and closure costs of Cholla Units 1 and 3. This order would authorize APS to defer, for future recovery in rates, both the expenses necessary to close and decommission coal-fired power plant infrastructure at Cholla, including legally required site environmental remediation, coal combustion residuals (“CCR”) corrective actions, the closure of CCR management facilities, and any unrecovered plant investment and operating costs incurred through and after April 2025. APS cannot predict the outcome of this matter.

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 regulatory assets.

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, $31 million as of March 31, 2025, 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, $5.7 million as of March 31, 2025. The disallowed recovery of 15% of the annual amortization does not have a material impact on APS financial statements.
Fire Mitigation

On August 14, 2024, APS filed a request with the ACC for a deferral order that would authorize APS to defer, for future recovery in rates, operations and maintenance expenses associated with wildfire management, including increased insurance costs. APS cannot predict the outcome of this matter.

Regulatory Assets and Liabilities

The detail of regulatory assets is as follows (dollars in thousands):
Amortization ThroughMarch 31,
2025		December 31,
2024
Pension(a)$739,549 $750,976 
Deferred fuel and purchased power (b) (c)2026228,036 287,597 
Income taxes — allowance for funds used during construction equity2054192,894 192,936 
Ocotillo deferral2034111,064 114,775 
Lease incentives(g)84,483 70,541 
SCR deferral (e)203881,639 83,123 
Retired power plant costs203364,591 68,380 
FERC Transmission true up202744,253 35,159 
Income taxes — investment tax credit basis adjustment205634,839 34,834 
Deferred compensation203634,423 33,108 
Deferred property taxes202721,776 23,918 
Palo Verde VIEs (Note 8)
204620,571 20,611 
Mead-Phoenix transmission line contributions in aid of construction (“CIAC”)20508,301 8,384 
Active Union Medical Trust(f)6,664 9,673 
Loss on reacquired debt20386,425 6,682 
Navajo coal reclamation20265,747 7,905 
Tax expense adjustor mechanism (b)20314,370 4,534 
PSA - interest20261,712 11,525 
Deferred fuel and purchased power — mark-to-market (Note 9)
— 42,275 
OtherVarious3,493 3,522 
Total regulatory assets (d)$1,694,830 $1,810,458 
Less: current regulatory assets$322,070 $420,969 
Total non-current regulatory assets$1,372,760 $1,389,489 

(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 other comprehensive income 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. Subsequently, the 2022 Rate Case decision allowed for the full return on the pension asset in rate base. See Note 7 for further discussion.
(b)See “Cost Recovery Mechanisms” discussion above.
(c)Subject to a carrying charge.
(d)There are no regulatory assets for which the ACC has allowed recovery of costs, but not allowed a return by exclusion from rate base. FERC rates are set using a formula rate as described in “Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters.”
(e)See “Court Resolution Surcharge” 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,
2025		December 31,
2024
Excess deferred income taxes - ACC — Tax Cuts and Jobs Act (a)2046$889,034 $888,896 
Excess deferred income taxes - FERC — Tax Cuts and Jobs Act (a)2058207,424 207,400 
Asset retirement obligations and removal costs(d)330,787 358,403 
Other postretirement benefits(c)233,978 238,113 
Four Corners coal reclamation203897,532 77,532 
Deferred fuel and purchased power — mark-to-market (Note 9)
202885,540 — 
Renewable energy standard (b)202670,217 68,523 
Income taxes — deferred investment tax credit205666,336 66,327 
Income taxes — change in rates205359,142 59,133 
Demand side management (b)202527,157 23,927 
Spent nuclear fuel202725,355 26,818 
Sundance maintenance203123,860 23,086 
TCA Balancing Account (b)202611,189 14,834 
Property tax deferral20274,238 4,785 
Tax expense adjustor mechanism (b)20324,192 4,343 
OtherVarious115 113 
Total regulatory liabilities$2,136,096 $2,062,233 
Less: current regulatory liabilities$225,332 $206,955 
Total non-current regulatory liabilities$1,910,764 $1,855,278 
(a)For purposes of presentation on the Statements 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 7.
(d)In accordance with regulatory accounting, APS accrues removal costs for its regulated assets, even if there is no legal obligation for removal.
v3.25.1
Retirement Plans and Other Postretirement Benefits
 3 Months Ended
Mar. 31, 2025
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 detail of the plans’ net periodic benefit costs and the portion of these costs charged to expense (including administrative costs and excluding amounts capitalized as overhead construction or billed to electric plant participants) (dollars in thousands):
Pension PlansOther Benefits Plans
Three Months Ended March 31,Three Months Ended March 31,
 2025202420252024
Service cost-benefits earned during the period$10,949 $10,631 $1,982 $2,459 
Non-service costs (credits):
Interest cost on benefit obligation38,976 37,236 5,102 5,613 
Expected return on plan assets(44,547)(46,983)(12,142)(11,709)
Amortization of:
Prior service credit (a)— — (1,265)(9,447)
Net actuarial loss (gain)
12,118 10,944 (2,899)(2,080)
Net periodic benefit costs (credits)
$17,496 $11,828 $(9,222)$(15,164)
Portion of costs (credits) charged to expense
$10,461 $6,337 $(6,873)$(11,306)
(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 and they became fully amortized as of January 31, 2025.
Contributions
 
Future year contribution amounts are dependent on plan asset performance and plan actuarial assumptions. The expected minimum required cash contributions for the pension plan are zero for the next three years and we do not expect to make any voluntary contributions in 2025, 2026 or 2027. With regard to contributions to our other postretirement benefit plan, we have not made a contribution year-to-date in 2025 and do not expect to make any contributions in 2025, 2026 or 2027.
v3.25.1
Variable Interest Entities
 3 Months Ended
Mar. 31, 2025
Variable Interest Entities [Abstract]  
Variable Interest Entities Variable Interest Entities
 
Pinnacle West

Captive Insurance Cell VIE

To support our overall insurance program, Pinnacle West established a captive insurance cell to insure certain risks of Pinnacle West and our subsidiaries. The Captive is a protected separate cell captive insurance company sponsored by Energy Insurance Services, Inc (“EISI”). EISI is owned by Energy Insurance Mutual Limited Company and allows participating member sponsoring organizations, such as Pinnacle West, to insure risks using captive entities. Pinnacle West, through its contractual rights, has a controlling financial interest in the separate protected Captive cell’s assets. Pinnacle West obtains all the benefits from the Captive and makes all the primary controlling decisions that economically impact the Captive. As a separate protected cell, Pinnacle West is the Captive’s only participant. The Captive is a VIE for which Pinnacle West is the primary beneficiary. Accordingly, Pinnacle West consolidates the Captive.
Under a mutual business program participation agreement between the Captive and EISI, EISI will issue policies, make claim disbursements, claim expenses and other underwriting fees on behalf of the Captive, as necessary.

The Captive insures Pinnacle West and its subsidiaries for terrorism coverage, excess liability including certain wildfire coverage, excess property insurance, and excess employment practice liability. The Captive policies exclude nuclear liability at Palo Verde. See Note 10 for details regarding nuclear liability insurance. Claim payments to the insureds can only be made up to the amount of the Captive’s available assets. In the event that claims exceed the Captive’s available assets, Pinnacle West may be required to provide additional funding to the Captive. In addition to policies obtained through the Captive, Pinnacle West also has insurance policies purchased through third-party insurers that may provide coverage if a loss event occurs.

As a result of consolidation, we eliminate intercompany transactions between Pinnacle West and the Captive and record the Captive’s assets, liabilities and third-party operating activities. In consolidation, the Captive’s insurance premium revenues derived from Pinnacle West policies are eliminated against the insurance premium expense recorded by Pinnacle West and our subsidiaries relating to insurance policy coverage provided by the Captive. Consolidation primarily resulted in Pinnacle West reflecting the Captive’s investment holdings on its Condensed Consolidated Balance Sheets, and the Captive’s investment gains and losses reflected through earnings on Pinnacle West’s Condensed Consolidated Statements of Income.

Consolidation of the Captive resulted in an increase in Pinnacle West’s net income for the three months ended March 31, 2025 and March 31, 2024 of $0.7 million and zero, respectively. Amounts are fully attributable to Pinnacle West shareholders. Consolidation impacts the Pinnacle West Condensed Consolidated Income Statement’s operations and maintenance expense and other income line items.

Pinnacle West’s Condensed Consolidated Balance Sheets as of March 31, 2025 and December 31, 2024 include $35 million and $34 million, respectively, of assets relating to the Captive that is reported within the other special use funds line item. See Notes 13 and 14 for additional details on these investment holdings.

APS’s financial statements are not impacted by Pinnacle West’s consolidation of the Captive VIE.
APS

Palo Verde Sale Leaseback VIEs

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 2025 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, 2025 and 2024. 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 these VIEs (dollars in thousands):
 March 31, 2025December 31, 2024
Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation$81,589 $82,556 
Equity — Noncontrolling interests107,474 103,167 
 
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 $345 million beginning in 2025, and up to $501 million over the lease extension terms.
 
For regulatory ratemaking purposes, the agreements continue to be treated as operating leases and, as a result, we have recorded a regulatory asset relating to the arrangements.
v3.25.1
Derivative Accounting
 3 Months Ended
Mar. 31, 2025
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 Condensed Consolidated Balance Sheets as an asset or liability and are measured at fair value.  See Note 13 for a discussion of fair value measurements.  Derivative instruments may qualify for the normal purchases and normal sales scope exception if they require physical delivery, and the quantities represent those transacted in the normal course of business.  Derivative instruments qualifying for the normal purchases and sales scope exception are accounted for under the accrual method of accounting and excluded from our derivative instrument discussion and disclosures below.

See Note 12 for details relating to Pinnacle West’s equity forward sale agreements and Note 5 for Pinnacle West’s Convertible Notes. These equity-linked transactions are indexed to Pinnacle West common stock and qualify for a derivative scope exception, and as such, 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 6.  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, 2025December 31, 2024
PowerGWh1,734 1,051 
GasBillion cubic feet269 235 
 
Gains and Losses from Energy Derivative Instruments
For the three months ended March 31, 2025 and 2024, 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 Three Months Ended March 31,
Commodity ContractsLocation20252024
Net Gain (Loss) Recognized in Income
Fuel and purchased power (a)$116,704 $(55,942)
(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, 2025:
 (dollars in thousands) 		Gross 
Recognized 
Derivatives
 (a)		Amounts 
Offset
(b)		Net
 Recognized
 Derivatives		Other
 (c)		Amounts 
Reported on 
Balance Sheets
Current assets$78,883 $(1,338)$77,545 $5 $77,550 
Investments and other assets32,353 (978)31,375 — 31,375 
Total assets111,236 (2,316)108,920 5 108,925 
Current liabilities(15,350)1,338 (14,012)(4,196)(18,208)
Deferred credits and other(10,346)978 (9,368)— (9,368)
Total liabilities(25,696)2,316 (23,380)(4,196)(27,576)
Total$85,540 $— $85,540 $(4,191)$81,349 
(a)All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)No cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting.
(c)Represents cash collateral and cash margin that is not subject to offsetting. Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument.  Includes cash collateral received from counterparties of $4,196 thousand and cash margin provided to counterparties of $5 thousand.
As of December 31, 2024:
 (dollars in thousands) 		Gross
 Recognized
 Derivatives
 (a)		Amounts
Offset 
(b)		Net
 Recognized
 Derivatives		Other
 (c)		Amounts
 Reported on
 Balance Sheets
Current assets$13,718 $(3,158)$10,560 $18 $10,578 
Investments and other assets6,610 (630)5,980 — 5,980 
Total assets20,328 (3,788)16,540 18 16,558 
Current liabilities(52,527)3,158 (49,369)(2,971)(52,340)
Deferred credits and other(10,076)630 (9,446)— (9,446)
Total liabilities(62,603)3,788 (58,815)(2,971)(61,786)
Total$(42,275)$— $(42,275)$(2,953)$(45,228)
(a)All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)No cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting.
(c)Represents cash collateral and cash margin that is not subject to offsetting.  Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument.  Includes cash collateral received from counterparties of $2,971 thousand and cash margin provided to counterparties of $18 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, 2025, we have three counterparties for which our exposure represents approximately 59% of Pinnacle West’s $108.9 million of risk management assets. This exposure relates to ISDA master agreements with the respective counterparties. The counterparties are rated as investment grade by Standard & Poor’s. 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 results of operations 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, 2025
Aggregate fair value of derivative instruments in a net liability position$25,696 
Additional collateral in the event credit-risk related contingent features were fully triggered (a)20 
(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, including energy storage lease contracts, with investment grade credit-related contingent features, which could also require us to post additional collateral of approximately $416 million if our debt credit ratings were to fall below investment grade.
v3.25.1
Commitments and Contingencies
 3 Months Ended
Mar. 31, 2025
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 recovered costs for eleven claims pursuant to the terms of the August 15, 2014 settlement agreement, for eleven separate time periods during July 1, 2011, through October 31, 2024. The DOE has approved and paid approximately $174.3 million for these claims (APS’s share is approximately $50.7 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.

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 $24.2 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 $66.4 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.
 
Captive Insurance Cell

Pinnacle West has established a captive insurance program to supplement third-party insurance coverage for certain risks. The Captive insures Pinnacle West and its subsidiaries for terrorism coverage, excess liability including certain wildfire coverage, excess property insurance, and excess employment practice liability. These coverages may be supplemented with third-party insurance policies. The Captive policies exclude nuclear liability at Palo Verde. The Captive may hold investment assets in cash, cash equivalents, and equity and fixed income instruments, which in the event of an insured loss would be available to pay covered claims. In the event of an insured loss event, Pinnacle West may be required to provide additional funding to the Captive. The Captive is a VIE, and Pinnacle West is the primary beneficiary of the VIE and consolidates the assets and liabilities of the Captive. See Note 8 for additional details.
As of March 31, 2025, there have been no material changes outside of the normal course of business in contractual obligations from the information provided in our 2024 Form 10-K. See Note 5 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. EPA notified APS that the RI/FS was approved on September 11, 2024. APS’s estimated costs related to this investigation and study are approximately $3 million. APS anticipates incurring additional expenditures in the future, but because the final costs associated with remediation requirements set forth in the RI/FS are not yet finalized, 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 in the U.S. District Court for Arizona, which concerns $8.3 million in remediation legal expenses. 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 its 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 APS 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 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, the EPA issued its final regulations governing the handling and disposal of CCRs, 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, the 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 (“WIIN”) Act in 2016, the 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. Arizona Department of Environmental Quality (“ADEQ”) has taken steps to develop a CCR permitting program and proposed state regulations governing CCR permitting in the summer of 2024. On April 1, 2025, the Arizona Governor’s Regulatory Review Council approved ADEQ’s proposed rulemaking governing CCR permitting. ADEQ will submit an approval package to the EPA, which will have to approve the entire state program before it is operational. It remains unclear when the EPA would approve that permitting program pursuant to the WIIN Act. On December 19, 2019, the 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, the 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 the EPA on November 30, 2020. While the EPA has deemed APS’s application administratively “complete,” the Agency’s approval remains pending. If granted, this application would allow the continued disposal of CCRs 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 in 2025. APS’s Cholla plant ceased operations on March 17, 2025.

We cannot predict the outcome of these regulatory proceedings or when the EPA will take final action on those matters that are still pending. Depending on the eventual outcome, the costs associated with APS’s management of CCR could materially increase, which could affect 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 CCRs 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 by February 2026 and final site investigation reports to be finalized by February 2027. Based on the information available to APS at this time, APS cannot reasonably estimate the cost of the entire CCRMU asset retirement obligation. Depending on the outcome of those evaluations and site investigations, the costs associated with APS’s management of CCR could materially increase, which could affect our financial condition, results of operations, or cash flows. In addition, the EPA under the current presidential administration has recently stated that it intends on prioritizing a number of timely actions on coal ash, including state permit program reviews and updates to the coal ash regulations. We cannot predict the outcome of a future rulemaking or other regulatory proceedings aimed at changing the current EPA CCRMU rules.

APS currently disposes of CCR in ash ponds and dry storage areas at Four Corners. The Navajo Plant disposed of CCR only in a dry landfill storage area. The Cholla Plant disposed of CCR in ash ponds and dry storage areas prior to retirement. 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 as of April 11, 2021 (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 has also solicited input from the public and hosted 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, Removal Costs and Regulatory Liabilities. 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, we cannot predict any ultimate impacts to APS; however, at this time APS does not believe that any potential changes to the cost estimate from the CCR rule’s corrective action assessment process 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

The 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, the 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 the 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 the EPA’s authority under the Clean Air Act.

In the final regulations governing power plant carbon dioxide emissions, released April 25, 2024, the EPA issued emission standards and guidelines for various subcategories of new and existing power plants. Unlike the 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, the EPA is proposing that carbon emission performance standards apply based on the annual capacity factors. For the highest utilization combustion turbines, the 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, the 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, the 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.

As of May 10, 2024, several states, electric utility companies, affiliated trade associations, and other entities filed petitions for review of these regulations in the D.C. Circuit Court of Appeals. APS is participating in that litigation as part of an ad hoc coalition of electric utility companies, independent power producers, and trade groups, called Electric Generators for a Sensible Transition. We cannot predict the outcome of the litigation challenging EPA’s latest carbon emission standards for power plants. In addition, the EPA under the current presidential administration recently stated that it intends to reverse or substantially revise these standards. We cannot predict the outcome of future rulemaking or other regulatory proceedings aimed at changing or eliminating the current EPA emission standards for power plants.

If this regulation remains in effect, it will likely lead to a material increase in APS’s costs to build, operate, and maintain new, frequently operated gas-fired power plants. The regulatory deadlines in 2032 by which new, frequently operated gas-fired power plants must install carbon capture and sequestration and
achieve 90% capture efficiency may not be feasible. Future resource plans and procurement efforts implicating the development of such new generation remains pending and, as such, at this time APS is not able to quantify the financial impact associated with the EPA’s GHG regulations for power plants.

Effluent Limitation Guidelines

The 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 2020 relaxed the “zero discharge” standard for bottom ash transport waters the EPA finalized in September 2015. However, on April 25, 2024, the 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. In addition, the EPA under the current presidential administration has announced that it intends to reconsider the ELG standards. We cannot predict the outcome of any future rulemaking or other regulatory proceedings aimed at modifying the current ELG standards.

EPA Good Neighbor Proposal for Arizona

On March 15, 2023, the 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 the 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 the EPA’s NOx emission allowance trading program finalized last year. That proposal involves adding these states to the Good Neighbor Plan and disapproving the corresponding provisions of each state’s State Implementation Plan. Because 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 the EPA’s Good Neighbor Plan upon finalization of this proposal. The EPA’s final Good Neighbor Plan is subject to ongoing judicial review in the D.C. Circuit Court of Appeals. On June 27, 2024, the U.S. Supreme Court granted a motion to stay the effectiveness of the EPA’s final Good Neighbor Plan pending the resolution of the litigation. As such, APS will not be impacted by the Good Neighbor Plan until the outcome of this litigation is finalized. In addition, on December 19, 2024, the EPA announced that it was withdrawing its proposal to add Arizona (along with other western states) to the federal Good Neighbor Plan. On March 12, 2025, the EPA under the current administration announced its intention to reconsider the Good Neighbor Plan. As such, while the EPA may elect to resume work on and finalize this proposal in the future, it is unlikely to do so over a near-term horizon. APS cannot predict the outcome of any future the EPA efforts to add Arizona to the federal Good Neighbor Plan (which depends on action disapproving the Arizona State Implementation Plan) or whether the Good Neighbor Plan itself will remain in effect pending the outcome of judicial review in the D.C. Circuit Court of Appeals. Should the Good Neighbor Plan ultimately be imposed on APS and its operations in Arizona and New Mexico, it would have material impact on both the costs to operate current APS power plants and APS’s ability to develop new thermal generation to serve load. At this time, APS cannot predict the impact on the Company’s financial condition, results of operations, or cash flows.
Revised Mercury and Air Toxics Standard (“MATS”) Proposal

On April 25, 2024, the 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. Based on APS’s assessment of the revised MATS regulations, this final rule is unlikely to have a material impact on plant operations or require significant capital expenditures to ensure compliance. Additionally, the EPA under the current presidential administration has stated it intends to reconsider the MATS rules.

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. 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 and administratively closes the litigation filed in January 2021.

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, 2025, standby letters of credit totaled approximately $18.7 million and surety bonds totaled approximately $22.8 million; both will expire through 2026. 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 as of March 31, 2025. In connection with the sale of Pinnacle West’s wholly-owned subsidiary, 4C Acquisition, LLC’s 7% interest in Units 4 and 5 of Four Corners to Navajo Transitional Energy Corporation (“NTEC”), Pinnacle West guaranteed certain obligations that NTEC has 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 (“PTC”) 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, 2025, there is approximately $28 million of remaining guarantees relating to these PTC Guarantees that are expected to terminate by 2031.

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 consider to be remote. These guarantees were issued in connection with Pinnacle West’s BCE subsidiary, which was sold to Ameresco in 2024 (the “BCE Sale”). See Note 18. Subsequent to the BCE Sale, Pinnacle West continues to maintain these Kūpono Solar Project investment financing guarantees. Under the Kūpono Solar Project sale-leaseback financing, Pinnacle West has committed to certain performance guarantees that may apply upon the occurrence of specified events, such as uninsured loss events. Ameresco, the owner of the Kūpono Solar Project, has agreed to make efforts to refinance the project and eliminate these guarantees prior to 2030. Pinnacle West has not needed to perform under these guarantees. Maximum obligations are not explicitly stated in the guarantees and cannot be reasonably estimated. Ameresco is obligated to reimburse Pinnacle West for any payments made by Pinnacle West under such guarantees. We consider the fair value of these guarantees, including expected credit losses, to be immaterial.
v3.25.1
Other Income and Other Expense
 3 Months Ended
Mar. 31, 2025
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,
 20252024
Other income:
Interest income (a)$5,996 $7,560 
Investment gain — net (b)10,984 — 
Gain on sale of BCE (Note 18)
— 22,988 
Miscellaneous481 59 
Total other income$17,461 $30,607 
Other expense:
Non-operating costs$(2,229)$(6,150)
Investment losses — net— (777)
Miscellaneous(341)(640)
Total other expense$(2,570)$(7,567)

(a)Interest income is primarily related to PSA interest. See Note 6.
(b)Investment gain is primarily related to El Dorado’s equity investment in SAI Advanced Power Solutions.
The following table provides detail of APS’s other income and other expense (dollars in thousands):
Three Months Ended March 31,
 20252024
Other income:
Interest income (a)$5,607 $6,796 
Miscellaneous115 59 
 Total other income$5,722 $6,855 
Other expense:
Non-operating costs$(1,992)$(2,255)
Miscellaneous(341)(639)
Total other expense$(2,333)$(2,894)
(a)Interest income is primarily related to PSA interest. See Note 6.
v3.25.1
Common Stock Equity and Earnings Per Share
 3 Months Ended
Mar. 31, 2025
Earnings Per Share [Abstract]  
Common Stock Equity and Earnings Per Share Common Stock Equity and Earnings Per Share
ATM Program

On November 8, 2024, Pinnacle West entered into an equity distribution sales agreement, pursuant to which Pinnacle West may sell, from time to time, up to $900 million of its common stock through an at-
the-market (“ATM”) equity distribution program, which includes the ability to enter into forward sale agreements. As of March 31, 2025, approximately $800 million of common stock is available to be issued under the ATM Program, which takes into account the forward sale agreements in effect as of March 31, 2025.

As of March 31, 2025, Pinnacle West had two outstanding forward sale agreements under the ATM Program relating to approximately $100 million of common stock. These agreements are the November 2024 ATM Forward Sale Agreement and the March 2025 ATM Forward Sale Agreement (collectively, the “ATM Forward Sale Agreements”), which may be settled at Pinnacle West’s discretion no later than June 30, 2026 and September 14, 2026, respectively. On a given settlement date, Pinnacle West will issue shares of common stock at the then-applicable forward sales price. Additionally, the terms of the forward sale agreements allow Pinnacle West, at its option, to settle the agreements with the counterparties by delivering cash, in lieu of shares.

The following table presents the calculation of Pinnacle West’s ATM Program as of March 31, 2025 (in thousands, except share amounts and price per share):

As of March 31, 2025
November 2024 ATM Forward Sale AgreementMarch 2025 ATM Forward Sale Agreement
Initial Price
Number of Shares552,833 544,959 
Forward Sales Price Per Share (a)$89.73 $90.83 
Aggregate Value (in thousands)$49,606 $49,499 

(a)    Subject to certain adjustments.

Non-ATM February 2024 Forward Sale Agreements

On February 28, 2024, Pinnacle West executed equity forward sale agreements (“February 2024 Forward Sale Agreements”). The February 2024 Forward Sale Agreements may be settled at Pinnacle West’s discretion no later than September 4, 2025, and were not issued under the ATM Program discussed above. On a settlement date, Pinnacle West will issue shares of Pinnacle West common stock and receive cash, if any, at the then-applicable forward sales price. The terms of the February 2024 Forward Sale Agreements also allow Pinnacle West, at its option, to settle the agreements with the counterparties by delivering cash, in lieu of shares.
The following table presents the calculation of Pinnacle West’s February 2024 Forward Sale Agreements as of March 31, 2025 (in thousands, except share amounts and price per share):

As of March 31, 2025
February 2024 Forward Sale Agreements
Initial Price
Number of Shares11,240,601 
Forward Sales Price Per Share (a)$64.51 
Aggregate Value (in thousands)$725,131 
Settlements
Date12/23/2024
Number of Shares Settled (b)5,377,115 
Forward Sales Price Upon Settlement$64.17 
Net Proceeds (in thousands) (c)$345,049 

(a)    Subject to certain adjustments.
(b)    Physical delivery.
(c)    Proceeds recorded in common equity on the Condensed Consolidated Balance Sheets.

Convertible Notes

In June 2024, Pinnacle West issued $525 million of 4.75% Convertible Senior Notes due 2027, which are senior unsecured obligations of Pinnacle West, and will mature on June 15, 2027. The Convertible Notes bear interest at a fixed rate of 4.75% per year, payable semiannually in arrears on June 15 and December 15 of each year, beginning on December 15, 2024.

Prior to March 15, 2027, the holders of the Convertible Notes may elect at their option to convert all or any portion of their Convertible Notes under the following limited circumstances:

•during any calendar quarter (and only during such calendar quarter), if the sale price of Pinnacle West common stock for at least 20 trading days (whether or not consecutive) during a period of 30 consecutive trading days ending on, and including, the last trading day of the immediately preceding calendar quarter, is greater than or equal to 130% of the conversion price on each applicable trading day;

•during the five business day period after any 10 consecutive trading day period (“Measurement Period”) in which the trading price per $1,000 principal amount of Convertible Notes for each trading day of the Measurement Period was less than 98% of the product of the last reported sale price of Pinnacle West common stock and the conversion rate on such trading day; or

•upon the occurrence of certain corporate events, as defined in the Convertible Notes’ indenture.

On or after March 15, 2027, until the maturity date, the holders of the Convertible Notes may elect at their option to convert all or any portion of their notes. Upon conversion, Pinnacle West will pay cash up to the aggregate principal amount of the Convertible Notes converted and at Pinnacle West’s sole discretion, pay or deliver cash, shares of Pinnacle West common stock or a combination of both, in respect
to the remainder, if any, of Pinnacle West’s conversion obligation in excess of the aggregate principal amount of the Convertible Notes being converted. The initial conversion rate, which is subject to certain adjustments as set forth in the indenture, is 10.8338 shares of common stock per $1,000 principal amount of Convertible Notes, which is equivalent to an initial conversion price of approximately $92.30 per share. The conversion rate is not subject to adjustment for any accrued and unpaid interest.

If Pinnacle West undergoes a fundamental change, as defined in the Convertible Notes’ indenture, then, subject to certain conditions, holders of the Convertible Notes may require Pinnacle West to repurchase for cash all or any portion of its Convertible Notes at a repurchase price equal to 100% of the principal amount of the Convertible Notes to be repurchased, plus accrued and unpaid interest to, but excluding, the fundamental change repurchase date.

As of March 31, 2025, the conditions allowing holders to convert their Convertible Notes were not met, and as a result, the Convertible Notes were classified as long term debt on Pinnacle West’s Condensed Consolidated Balance Sheets with a carrying amount of $525 million, including unamortized debt issuance costs of $6 million. The estimated fair value of the Convertible Notes as of March 31, 2025 was $591 million (Level 2 within the fair value hierarchy).

As of March 31, 2025, based on Pinnacle West’s average stock price, the net loss position, and the relevant terms of the Convertible Notes, there were no shares of Pinnacles West’s common stock included in basic or diluted EPS relating to the potential conversion of the Convertible Notes.
Earnings Per Share

The following table presents the calculation of Pinnacle West’s basic and diluted EPS (in thousands, except earnings per share amounts):
Three Months Ended March 31,
 20252024
Net income (loss) attributable to common shareholders$(4,644)$16,862 
Weighted average common shares outstanding — basic119,594 113,621 
Net effect of dilutive securities:
Contingently issuable performance shares and restricted stock units498 327 
Dilutive shares related to equity forward sale agreements (a)1,669 279 
Total contingently issuable shares (b)2,167 606 
Weighted average common shares outstanding — diluted121,761 114,227 
Earnings per weighted-average common share outstanding
Net income (loss) attributable to common shareholders — basic$(0.04)$0.15 
Net income (loss) attributable to common shareholders — diluted (b)$(0.04)$0.15 

(a)    For the three months ended March 31, 2025 and 2024, diluted weighted average common shares excludes 197,390 and 0 shares, respectively, relating to the Convertible Notes and the November 2024 ATM Forward Sale Agreements. These potentially issuable shares were excluded from the calculation of diluted shares as their inclusion would have been antidilutive.
(b)    Contingently issuable shares of 2,167,000 were excluded from the calculation of diluted weighted average common shares outstanding, as their inclusion would have been antidilutive due to the Net Loss results for the three months ended March 31, 2025. For the three months ended March 31, 2024, 0 contingently issuable shares were excluded from the calculation of diluted weighted average common shares outstanding.
Pinnacle West’s forward sale agreements are classified as equity transactions, and are not recorded on the Pinnacle West Condensed Consolidated Balance Sheets until shares are settled. Delivery of shares to settle equity forward agreements will 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, 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 the 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.
v3.25.1
Fair Value Measurements
 3 Months Ended
Mar. 31, 2025
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 2024 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, the active union employee medical account, and the Captive. See Note 14 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 daily 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 as of March 31, 2025 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):

Level 1Level 2Level 3OtherTotal
ASSETS
Cash equivalents$23 $— $— $— $23 
Risk management activities — derivative instruments:
Commodity contracts— 110,047 1,189 (2,311)(a)108,925 
Nuclear decommissioning trusts:
Equity securities11,490 — — 2,690 (b)14,180 
U.S. commingled equity funds— — — 405,263 (c)405,263 
U.S. Treasury debt359,911 — — — 359,911 
Corporate debt— 220,641 — — 220,641 
Mortgage-backed securities— 224,983 — — 224,983 
Municipal bonds— 33,817 — — 33,817 
Other fixed income— 27,306 — — 27,306 
Subtotal nuclear decommissioning trusts371,401 506,747 — 407,953 1,286,101 
Other special use funds:
Equity securities37,234 — — 2,030 (b)39,264 
U.S. Treasury debt376,137 — — — 376,137 
Subtotal other special use funds (d)413,371 — — 2,030 415,401 
Total assets$784,795 $616,794 $1,189 $407,672 $1,810,450 
LIABILITIES
Risk management activities — derivative instruments:
Commodity contracts$— $(1,667)$(24,029)$(1,880)(a)$(27,576)
(a)Represents counterparty netting, margin, and collateral. See Note 9.
(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.
(d)All amounts relate to APS, with the exception of $35.1 million related to Pinnacle West’s Captive investments that are classified within Level 1, $10.0 million related to equity securities and $25.1 million related to U.S. treasury debt. See Note 8.
 The following table presents the fair value at December 31, 2024 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):
 
Level 1Level 2Level 3OtherTotal
ASSETS
Cash equivalents$23 $— $— $— $23 
Risk management activities — derivative instruments:
Commodity contracts— 13,152 7,176 (3,770)(a)16,558 
Nuclear decommissioning trusts:
Equity securities11,859 542 — 3,335 (b)15,736 
U.S. commingled equity funds— — — 423,069 (c)423,069 
U.S. Treasury debt367,396 — — — 367,396 
Corporate debt— 203,180 — — 203,180 
Mortgage-backed securities— 208,533 — — 208,533 
Municipal bonds— 37,429 — — 37,429 
Other fixed income— 27,502 — — 27,502 
Subtotal nuclear decommissioning trusts379,255 477,186 — 426,404 1,282,845 
Other special use funds:
Cash equivalents25,000 — — — (d)25,000 
Equity securities24,962 — — 2,851 (b) (d)27,813 
U.S. Treasury debt355,544 — — — 355,544 
Subtotal other special use funds (d)405,506 — — 2,851 408,357 
Total assets$784,784 $490,338 $7,176 $425,485 $1,707,783 
LIABILITIES
Risk management activities — derivative instruments:
Commodity contracts$— $(40,388)$(22,215)$817 (a)$(61,786)
(a)Represents counterparty netting, margin, and collateral. See Note 9.
(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.
(d)All amounts relate to APS, with the exception of $34.2 million related to Pinnacle West’s Captive investments that are classified within Level 1, $25.0 million in cash equivalents and $9.2 million related to equity securities. See Note 8.
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.
 
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 as of March 31, 2025 and December 31, 2024:

March 31, 2025
 Fair Value (thousands) 		ValuationSignificantWeighted-Average
Commodity ContractsAssetsLiabilitiesTechniqueUnobservable InputRange (b)
Electricity Forward Contracts (a)$703 $23,218 Discounted cash flowsElectricity forward price (per MWh)
$26.23
-
$151.56
$90.74
Natural Gas Forward Contracts (a)486 811 Discounted cash flowsNatural gas forward price (per MMBtu)
$(1.92)
-
$0.09
$0.02
Total$1,189 $24,029 
(a)Includes swaps and physical and financial contracts.
(b)Unobservable inputs were weighted by the relative fair value of the instrument.

December 31, 2024
 Fair Value (thousands) 		ValuationSignificantWeighted-Average
Commodity ContractsAssetsLiabilitiesTechniqueUnobservable InputRange(b)
Electricity Forward Contracts (a)$708 $21,890 Discounted cash flowsElectricity forward price (per MWh)$25.25 -$151.11$106.06
Natural Gas Forward Contracts (a)6,468 325 Discounted cash flowsNatural gas forward price (per MMBtu)$(0.89)-$1.47$0.71
Total$7,176 $22,215 
(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 Contracts20252024
Balance at beginning of period$(15,039)$4,921 
Total net losses realized/unrealized:
Deferred as a regulatory asset or liability(5,823)(23,600)
Settlements(2,287)2,708 
Transfers into Level 3 from Level 2(59)— 
Transfers from Level 3 into Level 2368 — 
Balance at end of period$(22,840)$(15,971)
Net unrealized gains/losses included in earnings related to instruments still held at end of period$— $— 

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

Financial Instruments Not Carried at Fair Value
 
The carrying values of our short-term borrowings approximate fair value and are classified within Level 2 of the fair value hierarchy.  See Note 5 for our long-term debt fair values.
v3.25.1
Investments in Nuclear Decommissioning Trusts and Other Special Use Funds
 3 Months Ended
Mar. 31, 2025
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 and other special use funds. 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 13 for a discussion of how fair value is determined and the classification of the investments within the fair value hierarchy. The investments in each trust or account are restricted for use and are intended to fund specified costs and activities as further described for each fund below.

Nuclear Decommissioning Trusts

APS established external decommissioning trusts in accordance with NRC regulations to fund the future costs APS expects to incur to decommission Palo Verde.  Third-party investment managers are authorized to buy and sell securities per stated investment guidelines.  The trust funds are invested in fixed income securities and equity securities. Earnings and proceeds from sales and maturities of securities are reinvested in the trusts. Because of the ability of APS to recover decommissioning costs in rates, and in accordance with the regulatory treatment, APS has deferred realized and unrealized gains and losses (including credit losses) in other regulatory liabilities.

Coal Reclamation Escrow Account

APS has investments restricted for the future coal mine reclamation funding related to Four Corners. This escrow account is primarily invested in fixed income securities. Earnings and proceeds
from sales of securities are reinvested in the escrow account. Because of the ability of APS to recover coal reclamation costs in rates, and in accordance with the regulatory treatment, APS has deferred realized and unrealized gains and losses (including credit losses) in other regulatory liabilities. Activities relating to APS coal mine reclamation escrow account investments are included within the other special use funds in the table below.

Active Union Employee Medical Account

APS has investments restricted for paying active union employee medical costs. These investments may be used to pay active union employee medical costs incurred in the current and future periods. In 2024, 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 and liabilities. Activities relating to active union employee medical account investments are included within the other special use funds in the table below.

Captive Insurance Cell

Pinnacle West has investments in the Captive that may be used to pay insurance losses in the event of certain insured loss events. The Captive may hold investment assets in cash, cash equivalents, and equity and fixed income instruments. These investments are restricted for insured loss events.

Pinnacle West Consolidated investment holdings reflected in the tables below primarily relate to APS, with the exception of the Captive’s investments included within other special use funds.

The following tables present the unrealized gains and losses based on the original cost of the investment and summarize the fair value of the nuclear decommissioning trusts and other special use fund assets (dollars in thousands): 
March 31, 2025
 Fair ValueTotal
Unrealized
Gains		Total
Unrealized
Losses
Investment Type:Nuclear Decommissioning TrustsOther Special Use FundsTotal
Equity securities$416,753 $37,234 $453,987 $341,566 $(325)
Available for sale-fixed income securities866,658 376,137 1,242,795 (a)13,416 (22,318)
Other2,690 2,030 4,720 (b)— — 
Total$1,286,101 $415,401 $1,701,502 (c)$354,982 $(22,643)
(a)As of March 31, 2025, the amortized cost basis of these available-for-sale investments is $1,252 million.
(b)Represents net pending securities sales and purchases.
(c)All amounts pertain to APS, with the exception of $35.1 million of other special use fund investments in equity securities relating to the Captive.
December 31, 2024
 Fair ValueTotal
Unrealized
Gains		Total
Unrealized
Losses
Investment Type:Nuclear Decommissioning TrustsOther Special Use FundsTotal
Equity securities$435,470 $24,962 $460,432 $359,127 $(176)
Available for sale-fixed income securities844,040 355,544 1,199,584 (a)7,717 (31,960)
Other3,335 27,851 31,186 (b)— — 
Total$1,282,845 $408,357 $1,691,202 (c)$366,844 $(32,136)
(a)As of December 31, 2024, the amortized cost basis of these available-for-sale investments is $1,224 million.
(b)Represents net pending securities sales and purchases.
(c)All amounts pertain to APS, with the exception of $34.2 million of other special use fund investments in equity securities relating to the Captive.
The following table sets forth 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
2025
Realized gains$1,658 $— $1,658 
Realized losses$(2,761)$— $(2,761)
Proceeds from the sale of securities (a)$416,601 $69,213 (b)$485,814 
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 

(a)    Proceeds are reinvested in the nuclear decommissioning trusts and other special use funds, excluding investment fees and amounts reimbursed to the Company for active union employee medical claims from the active union employee medical account.
(b) All amounts pertain to APS, with the exception of $25.3 million of other special use fund proceeds from the sale of securities relating to the Captive.
Fixed Income Securities Contractual Maturities

The fair value fixed income securities summarized by contractual maturities as of March 31, 2025 is as follows (dollars in thousands):
 
 Nuclear Decommissioning TrustsCoal Reclamation Escrow AccountActive Union Employee Medical Account
Captive Insurance Cell (a)
Total
Less than one year$32,422 $90,167 $39,464 25,149 $187,202 
1 year – 5 years292,409 48,289 157,055 — 497,753 
5 years – 10 years137,989 — 16,013 — 154,002 
Greater than 10 years403,838 — — — 403,838 
Total$866,658 $138,456 $212,532 25,149 $1,242,795 
(a)All amounts pertain to APS, with the exception of $25.1 million of other special use fund investments in fixed income securities relating to the Captive.
v3.25.1
Changes in Accumulated Other Comprehensive Loss
 3 Months Ended
Mar. 31, 2025
Comprehensive Income (Loss), Net of Tax, Attributable to Parent [Abstract]  
Changes in Accumulated Other Comprehensive Loss Changes in Accumulated Other Comprehensive Loss
 
The following table shows the changes in Pinnacle West’s consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component (dollars in thousands): 
 Pension and Other Postretirement BenefitsDerivative Instruments Total
Three Months Ended March 31
Balance December 31, 2024
$(31,661)$719 $(30,942)
Other comprehensive income before reclassifications
— 350 350 
Amounts reclassified from accumulated other comprehensive loss
498  (a)— 498 
Balance March 31, 2025
$(31,163)$1,069 $(30,094)
Balance December 31, 2023
$(34,754)$1,610 $(33,144)
Other comprehensive (loss) before reclassifications
— — — 
Amounts reclassified from accumulated other comprehensive loss
562  (a)— 562 
Balance March 31, 2024
$(34,192)$1,610 $(32,582)

(a)    These amounts primarily represent amortization of actuarial loss and are included in the computation of net periodic pension cost.  See Note 7
The following table shows the changes in APS’s 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, 2024
$(14,116)
Other comprehensive (loss) before reclassifications
— 
Amounts reclassified from accumulated other comprehensive loss
406  (a)
Balance March 31, 2025
$(13,710)
Balance December 31, 2023
$(17,219)
Other comprehensive (loss) before reclassifications
— 
Amounts reclassified from accumulated other comprehensive loss
490  (a)
Balance March 31, 2024
$(16,729)

(a) These amounts primarily represent amortization of actuarial loss and are included in the computation of net periodic pension cost.  See Note 7.
v3.25.1
Leases
 3 Months Ended
Mar. 31, 2025
Leases [Abstract]  
Leases Leases
 
We lease certain land, buildings, vehicles, equipment, and other property through operating rental agreements with varying terms, provisions, and expiration dates. APS also has certain purchased power and energy storage agreements that qualify as lease arrangements. Our leases have remaining terms that expire in 2025 through 2073. Substantially all of our leasing activities relate to APS.

In 1986, APS entered into agreements with three separate lessor trust entities in order to sell and lease back interests in Palo Verde Unit 2 and related common facilities.  These lessor trust entities have been deemed VIEs for which APS is the primary beneficiary.  As the primary beneficiary, APS consolidated these lessor trust entities.  The impacts of these sale leaseback transactions are excluded from our lease disclosures as lease accounting is eliminated upon consolidation.  See Note 8 for a discussion of VIEs.

APS has purchased power lease agreements that allow APS the right to the generation capacity from certain natural-gas fueled generators during certain months of each year throughout the term of the arrangements. As APS only has rights to use the assets during certain periods of each year, the leases have non-consecutive periods of use. APS does not operate or maintain the leased assets. APS controls the dispatch of the leased assets during the months of use and is required to pay a fixed monthly capacity payment during these periods of use. For these types of leased assets, APS has elected to combine both the lease and non-lease payment components and accounts for the entire fixed payment as a lease obligation. In addition to the fixed monthly capacity payments, APS must also pay variable charges based on the actual production volume of the assets. The variable consideration is not included in the measurement of our lease obligation.
APS has executed various energy storage purchased power lease agreements that allow APS the right to charge and discharge energy storage facilities. APS pays a fixed monthly capacity price for rights to use the lease assets. The agreements generally have 20-year lease terms and provide APS with the exclusive use of the energy storage assets through the lease term. APS does not operate or maintain the energy storage facilities and has no purchase options or residual value guarantees relating to these lease assets. For this class of energy storage lease assets, APS has elected to separate the lease and non-lease components. These leases are accounted for as operating leases, with lease terms that commenced between September 2023 and March 2025.

The following table provides information related to our lease costs (dollars in thousands):
Three Months Ended March 31,
20252024
Operating Lease Cost - Purchased Power and Energy Storage Lease Contracts$12,547 $937 
Operating Lease Cost - Land, Property, and Other Equipment5,337 4,773 
Total Operating Lease Cost17,884 5,710 
Variable Lease Cost (a)21,370 21,564 
Short-term Lease Cost592 2,800 
Total Lease Cost$39,846 $30,074 
(a)     Primarily relates to purchased power lease contracts.

Lease costs are primarily included as a component of operating expenses on our Condensed Consolidated Statements of Income. Lease costs relating to purchased power and energy storage lease contracts are recorded in fuel and purchased power on the Condensed Consolidated Statements of Income and are subject to recovery under the PSA or RES. See Note 6. The tables above reflect the lease cost amounts before the effect of regulatory deferral under the PSA and RES. Variable lease costs are recognized in the period the costs are incurred, and primarily relate to renewable purchased power lease contracts. Payments under most renewable purchased power lease contracts are dependent upon environmental factors, and due to the inherent uncertainty associated with the reliability of the fuel source, the payments are considered variable and are excluded from the measurement of lease liabilities and right-of-use lease assets. Certain of our lease agreements have lease terms with non-consecutive periods of use. For these agreements, we recognize lease costs during the periods of use. Leases with initial terms of 12 months or less are considered short-term leases and are not recorded on the balance sheets.
The following table provides information related to the maturity of our operating lease liabilities (dollars in thousands):
March 31, 2025
YearPurchased Power and Energy Storage Lease ContractsLand, Property and Equipment LeasesTotal
2025 (remaining nine months of 2025)$197,622 $12,933 $210,555 
2026236,859 14,891 251,750 
2027262,780 12,310 275,090 
2028266,577 9,641 276,218 
2029270,514 7,516 278,030 
2030274,492 4,392 278,884 
Thereafter1,850,659 57,475 1,908,134 
Total lease commitments3,359,503 119,158 3,478,661 
Less imputed interest1,036,548 40,691 1,077,239 
Total lease liabilities$2,322,955 $78,467 $2,401,422 
    
We recognize lease assets and liabilities upon lease commencement. As of March 31, 2025, we have various lease arrangements that have been executed, but have not yet commenced. We expect the total fixed consideration paid for these arrangements, which includes both lease and non-lease payments, will approximate $14.8 billion over the terms of the agreements. These arrangements primarily relate to energy storage assets. We expect lease commencement dates ranging from April 2025 through June 2028, with lease terms expiring through June 2048. The lease commencement dates for certain arrangements have experienced delays. As a result of these delays and other events, APS has received cash proceeds from certain lessors prior to lease commencement. Proceeds received from lessors relating to energy storage Power Purchase Agreement (“PPA”) leases are accounted for as lease incentives on our Condensed Consolidated Balance Sheets, and upon lease commencement are amortized over the associated lease term. For regulatory purposes, the proceeds received by APS relating to these PPA leases are treated as a reduction to fuel and purchased power costs through the PSA in the period proceeds are received. See Note 6.
The following tables provide other additional information related to operating lease liabilities (dollars in thousands):
Three Months Ended March 31,
20252024
Cash paid for amounts included in the measurement of lease liabilities — operating cash flows:$17,207 $3,544 
Right-of-use operating lease assets obtained in exchange for operating lease liabilities:$763,437 (a)$6,747 

March 31, 2025December 31, 2024
Weighted average remaining lease term14 years11 years
Weighted average discount rate (b)5.17 %4.90 %

(a)Primarily relates to the three new energy storage operating lease agreements that commenced in 2025.
(b)Most of our lease agreements do not contain an implicit rate that is readily determinable. For these agreements we use our incremental borrowing rate to measure the present value of lease liabilities. We determine our incremental borrowing rate at lease commencement based on the rate of interest that we would have to pay to borrow, on a collateralized basis over a similar term, an amount equal to the lease payments in a similar economic environment. We use the implicit rate when it is readily determinable.
v3.25.1
Income Taxes
 3 Months Ended
Mar. 31, 2025
Income Tax Disclosure [Abstract]  
Income Taxes Income Taxes
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 (“Nuclear PTC”), 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, 2025.
v3.25.1
Sale of Bright Canyon Energy
 3 Months Ended
Mar. 31, 2025
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. The BCE Sale was 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 was $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 included $41 million of liabilities that have been assumed by Ameresco. The consideration
received by Pinnacle West included 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. 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. Our Condensed Consolidated Statements of Income for the year ended 2024, included 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 of December 31, 2024 the interest-bearing promissory note had been paid in full.

 On January 30, 2024, Pinnacle West entered into a tax credit transfer agreement to purchase from Ameresco $23 million of investment tax credits from the BCE Los Alamitos project for $21 million.
Additionally, Pinnacle West continues to maintain certain guarantees relating to the Kūpono Solar Project sale-leaseback financing, which were not transferred in the BCE Sale transaction. See Note 10.
v3.25.1
Insider Trading Arrangements
 3 Months Ended
Mar. 31, 2025
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
v3.25.1
Consolidation and Nature of Operations (Policies)
 3 Months Ended
Mar. 31, 2025
Organization, Consolidation and Presentation of Financial Statements [Abstract]  
Business Segments Business Segments
 
Pinnacle West’s reportable business segment is our regulated electricity segment, which consists of retail and wholesale sales supplied under traditional cost-based regulation and related activities and includes electricity generation, transmission, and distribution. Our reportable segment activities are conducted through our wholly-owned subsidiary, APS. All other operating segment activities are insignificant to Pinnacle West.

For segment reporting purposes, Pinnacle West’s Chief Executive Officer performs the function of chief operating decision maker (“CODM”). Our CODM uses net income to measure an operating segment’s profitability. When assessing the performance of an operating segment, and making decisions about allocating resources, our CODM evaluates net income actual results compared to budget. Net income is also used when implementing strategic initiatives and selecting projects to meet business objectives. Our reportable segment’s revenue streams are dependent upon regulated rate recovery, which is a primary factor in how we identify operating segments.
For information on our reportable business segment’s revenues, significant expenses, net income, assets, and other reportable segment items, see the APS Condensed Consolidated Statements of Income, APS Condensed Consolidated Balance Sheets, and APS Condensed Consolidated Statements of Cash Flows.
New Accounting Standards New Accounting Standards
 
ASU 2023-09, Income Taxes: Improvements to Income Tax Disclosures

In December 2023, a new accounting standard was issued that expands disclosures relating to income taxes. The expanded disclosures include a tabular income tax rate reconciliation, disclosure of specific reconciliation categories and reconciling items, the amount of income taxes paid by jurisdiction, and other disclosures. We will adopt this standard on December 31, 2025, using a prospective approach. The adoption of the new standard will result in changes to our income tax disclosures, but will not impact our accounting for income taxes or our financial statement results.

ASU 2024-03, Income Statement: Expense Disaggregation Disclosures

In November 2024, a new accounting standard was issued that requires specific disclosures related to certain costs and expenses. Companies will be required to disclose the amounts of certain cost and expense categories, such as: purchases of inventory, employee compensation, depreciation, and
amortization, among other disclosures. The new disclosures may be provided in the notes to the financial statements, and will not require changes to the face of the Statements of Income. The standard becomes effective on December 31, 2027, using either a prospective or retrospective approach, with early adoption permitted. The adoption of the new standard will result in disclosure changes, but will not impact our accounting for such costs and expenses or our financial statement results.
v3.25.1
Consolidation and Nature of Operations (Tables)
 3 Months Ended
Mar. 31, 2025
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,
20252024
Cash paid (received) during the period for:
Income taxes, net of refunds$(10,799)$20,970 
Interest, net of amounts capitalized91,475 83,974 
Significant non-cash investing and financing activities:
Accrued capital expenditures$315,297 $217,684 
BCE Sale non-cash consideration (Note 18)
— 45,608 

The following table summarizes supplemental APS cash flow information (dollars in thousands):
Three Months Ended March 31,
20252024
Cash paid (received) during the period for:
Income taxes, net of refunds$(5,392)$— 
Interest, net of amounts capitalized84,110 73,035 
Significant non-cash investing and financing activities:
Accrued capital expenditures$315,297 $217,684 
v3.25.1
Business Segments (Tables)
 3 Months Ended
Mar. 31, 2025
Segment Reporting [Abstract]  
Schedule of Reportable Segment’s Revenues, Significant Expenses, Net Income, and Assets The following table reconciles our reportable segment’s revenues, significant expenses, and net income to the Pinnacle West Consolidated amounts (dollars in millions):
Three Months Ended March 31,
20252024
Regulated Electricity SegmentOther Pinnacle West ConsolidatedRegulated Electricity SegmentOther Pinnacle West Consolidated
Operating Revenues$1,032 $— $1,032 $952 $— $952 
Fuel and purchased power (380)— (380)(358)— (358)
Operations and maintenance(297)(3)(300)(254)(4)(258)
Depreciation and amortization (235)— (235)(210)— (210)
Taxes other than income taxes (59)— (59)(59)— (59)
Pension and other postretirement non-service credits, net3 — 3 12 — 12 
Allowance for equity funds used during construction13 — 13 10 — 10 
Other income and expenses, net3 11 14 4 19 23 
Interest expense and costs(79)(16)(95)(74)(13)(87)
Income Taxes3 3 6 (4)— (4)
Less: Net income attributable to noncontrolling interests(4)— (4)(4)— (4)
Net Income (Loss) $— $(5)$(5)$15 $2 $17 

The following table reconciles our reportable segment's assets to the Pinnacle West Consolidated amount (dollars in millions):
March 31, 2025December 31, 2024
Regulated Electricity SegmentOtherPinnacle West ConsolidatedRegulated Electricity SegmentOtherPinnacle West Consolidated
Total Assets$27,097 $139 $27,236 $25,988 $115 $26,103 
v3.25.1
Revenue (Tables)
 3 Months Ended
Mar. 31, 2025
Revenue from Contract with Customer [Abstract]  
Schedule of Disaggregation of Revenue
The following table provides detail of Pinnacle West’s consolidated revenues disaggregated by revenue sources (dollars in thousands):
Three Months Ended March 31,
20252024
Retail Electric Service
Residential$448,923 $432,692 
Non-Residential524,857 461,483 
Wholesale Energy Sales24,824 26,864 
Transmission Services for Others25,547 27,712 
Other Sources8,129 2,961 
Total Operating Revenues$1,032,280 $951,712 
Schedule of Allowance for Doubtful Accounts
The following table provides a rollforward of Pinnacle West’s allowance for doubtful accounts (dollars in thousands):

March 31, 2025December 31, 2024
Balance at beginning of period$24,849 $22,433 
Bad debt expense4,789 35,799 
Actual write-offs(6,599)(33,383)
Balance at end of period$23,039 $24,849 
v3.25.1
Debt and Liquidity Matters (Tables)
 3 Months Ended
Mar. 31, 2025
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, 2025As of December 31, 2024
 Carrying
Amount		Fair ValueCarrying
Amount		Fair Value
Pinnacle West$1,368,746 $1,437,105 $1,367,770 $1,393,744 
APS7,491,990 6,596,763 7,490,878 6,525,248 
Total$8,860,736 $8,033,868 $8,858,648 $7,918,992 
v3.25.1
Regulatory Matters (Tables)
 3 Months Ended
Mar. 31, 2025
Regulated Operations [Abstract]  
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 (dollars in thousands):
 Three Months Ended March 31,
 20252024
Balance at beginning of period$287,597 $463,195 
Deferred fuel and purchased power costs25,228 33,094 
Amounts charged to customers
(84,789)(108,552)
Balance at end of period$228,036 $387,737 
Schedule of Regulatory Assets
The detail of regulatory assets is as follows (dollars in thousands):
Amortization ThroughMarch 31,
2025		December 31,
2024
Pension(a)$739,549 $750,976 
Deferred fuel and purchased power (b) (c)2026228,036 287,597 
Income taxes — allowance for funds used during construction equity2054192,894 192,936 
Ocotillo deferral2034111,064 114,775 
Lease incentives(g)84,483 70,541 
SCR deferral (e)203881,639 83,123 
Retired power plant costs203364,591 68,380 
FERC Transmission true up202744,253 35,159 
Income taxes — investment tax credit basis adjustment205634,839 34,834 
Deferred compensation203634,423 33,108 
Deferred property taxes202721,776 23,918 
Palo Verde VIEs (Note 8)
204620,571 20,611 
Mead-Phoenix transmission line contributions in aid of construction (“CIAC”)20508,301 8,384 
Active Union Medical Trust(f)6,664 9,673 
Loss on reacquired debt20386,425 6,682 
Navajo coal reclamation20265,747 7,905 
Tax expense adjustor mechanism (b)20314,370 4,534 
PSA - interest20261,712 11,525 
Deferred fuel and purchased power — mark-to-market (Note 9)
— 42,275 
OtherVarious3,493 3,522 
Total regulatory assets (d)$1,694,830 $1,810,458 
Less: current regulatory assets$322,070 $420,969 
Total non-current regulatory assets$1,372,760 $1,389,489 

(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 other comprehensive income 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. Subsequently, the 2022 Rate Case decision allowed for the full return on the pension asset in rate base. See Note 7 for further discussion.
(b)See “Cost Recovery Mechanisms” discussion above.
(c)Subject to a carrying charge.
(d)There are no regulatory assets for which the ACC has allowed recovery of costs, but not allowed a return by exclusion from rate base. FERC rates are set using a formula rate as described in “Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters.”
(e)See “Court Resolution Surcharge” 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,
2025		December 31,
2024
Excess deferred income taxes - ACC — Tax Cuts and Jobs Act (a)2046$889,034 $888,896 
Excess deferred income taxes - FERC — Tax Cuts and Jobs Act (a)2058207,424 207,400 
Asset retirement obligations and removal costs(d)330,787 358,403 
Other postretirement benefits(c)233,978 238,113 
Four Corners coal reclamation203897,532 77,532 
Deferred fuel and purchased power — mark-to-market (Note 9)
202885,540 — 
Renewable energy standard (b)202670,217 68,523 
Income taxes — deferred investment tax credit205666,336 66,327 
Income taxes — change in rates205359,142 59,133 
Demand side management (b)202527,157 23,927 
Spent nuclear fuel202725,355 26,818 
Sundance maintenance203123,860 23,086 
TCA Balancing Account (b)202611,189 14,834 
Property tax deferral20274,238 4,785 
Tax expense adjustor mechanism (b)20324,192 4,343 
OtherVarious115 113 
Total regulatory liabilities$2,136,096 $2,062,233 
Less: current regulatory liabilities$225,332 $206,955 
Total non-current regulatory liabilities$1,910,764 $1,855,278 
(a)For purposes of presentation on the Statements 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 7.
(d)In accordance with regulatory accounting, APS accrues removal costs for its regulated assets, even if there is no legal obligation for removal.
v3.25.1
Retirement Plans and Other Postretirement Benefits (Tables)
 3 Months Ended
Mar. 31, 2025
Retirement Benefits [Abstract]  
Schedule of Net Periodic Benefit Costs and the Portion of these Costs Charged to Expense (Including Administrative Costs and Excluding Amounts Capitalized as Overhead Construction, Billed to Electric Plant Participants or Charged or Amortized to the Regulatory Asset)
The following table provides detail of the plans’ net periodic benefit costs and the portion of these costs charged to expense (including administrative costs and excluding amounts capitalized as overhead construction or billed to electric plant participants) (dollars in thousands):
Pension PlansOther Benefits Plans
Three Months Ended March 31,Three Months Ended March 31,
 2025202420252024
Service cost-benefits earned during the period$10,949 $10,631 $1,982 $2,459 
Non-service costs (credits):
Interest cost on benefit obligation38,976 37,236 5,102 5,613 
Expected return on plan assets(44,547)(46,983)(12,142)(11,709)
Amortization of:
Prior service credit (a)— — (1,265)(9,447)
Net actuarial loss (gain)
12,118 10,944 (2,899)(2,080)
Net periodic benefit costs (credits)
$17,496 $11,828 $(9,222)$(15,164)
Portion of costs (credits) charged to expense
$10,461 $6,337 $(6,873)$(11,306)
(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 and they became fully amortized as of January 31, 2025.
v3.25.1
Variable Interest Entities (Tables)
 3 Months Ended
Mar. 31, 2025
Variable Interest Entities [Abstract]  
Schedule of Amounts Relating to the VIEs Included in Consolidated Balance Sheets
Our Condensed Consolidated Balance Sheets include the following amounts relating to these VIEs (dollars in thousands):
 March 31, 2025December 31, 2024
Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation$81,589 $82,556 
Equity — Noncontrolling interests107,474 103,167 
v3.25.1
Derivative Accounting (Tables)
 3 Months Ended
Mar. 31, 2025
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, 2025December 31, 2024
PowerGWh1,734 1,051 
GasBillion cubic feet269 235 
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 Three Months Ended March 31,
Commodity ContractsLocation20252024
Net Gain (Loss) Recognized in Income
Fuel and purchased power (a)$116,704 $(55,942)
(a)Amounts are before the effect of PSA deferrals.
Schedule of the Entity's Fair Value of Risk Management Activities Reported on a Gross Basis and the Impacts on Offsetting Liabilities
The following tables provide information about the fair value of APS’s risk management activities reported on a gross basis and the impacts of offsetting.  These amounts relate to commodity contracts and are located in the assets and liabilities from risk management activities lines of APS’s Condensed Consolidated Balance Sheets.
As of March 31, 2025:
 (dollars in thousands) 		Gross 
Recognized 
Derivatives
 (a)		Amounts 
Offset
(b)		Net
 Recognized
 Derivatives		Other
 (c)		Amounts 
Reported on 
Balance Sheets
Current assets$78,883 $(1,338)$77,545 $5 $77,550 
Investments and other assets32,353 (978)31,375 — 31,375 
Total assets111,236 (2,316)108,920 5 108,925 
Current liabilities(15,350)1,338 (14,012)(4,196)(18,208)
Deferred credits and other(10,346)978 (9,368)— (9,368)
Total liabilities(25,696)2,316 (23,380)(4,196)(27,576)
Total$85,540 $— $85,540 $(4,191)$81,349 
(a)All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)No cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting.
(c)Represents cash collateral and cash margin that is not subject to offsetting. Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument.  Includes cash collateral received from counterparties of $4,196 thousand and cash margin provided to counterparties of $5 thousand.
As of December 31, 2024:
 (dollars in thousands) 		Gross
 Recognized
 Derivatives
 (a)		Amounts
Offset 
(b)		Net
 Recognized
 Derivatives		Other
 (c)		Amounts
 Reported on
 Balance Sheets
Current assets$13,718 $(3,158)$10,560 $18 $10,578 
Investments and other assets6,610 (630)5,980 — 5,980 
Total assets20,328 (3,788)16,540 18 16,558 
Current liabilities(52,527)3,158 (49,369)(2,971)(52,340)
Deferred credits and other(10,076)630 (9,446)— (9,446)
Total liabilities(62,603)3,788 (58,815)(2,971)(61,786)
Total$(42,275)$— $(42,275)$(2,953)$(45,228)
(a)All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)No cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting.
(c)Represents cash collateral and cash margin that is not subject to offsetting.  Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument.  Includes cash collateral received from counterparties of $2,971 thousand and cash margin provided to counterparties of $18 thousand.
Schedule of the Entity's Fair Value of Risk Management Activities Reported on a Gross Basis and the Impacts on Offsetting Assets
The following tables provide information about the fair value of APS’s risk management activities reported on a gross basis and the impacts of offsetting.  These amounts relate to commodity contracts and are located in the assets and liabilities from risk management activities lines of APS’s Condensed Consolidated Balance Sheets.
As of March 31, 2025:
 (dollars in thousands) 		Gross 
Recognized 
Derivatives
 (a)		Amounts 
Offset
(b)		Net
 Recognized
 Derivatives		Other
 (c)		Amounts 
Reported on 
Balance Sheets
Current assets$78,883 $(1,338)$77,545 $5 $77,550 
Investments and other assets32,353 (978)31,375 — 31,375 
Total assets111,236 (2,316)108,920 5 108,925 
Current liabilities(15,350)1,338 (14,012)(4,196)(18,208)
Deferred credits and other(10,346)978 (9,368)— (9,368)
Total liabilities(25,696)2,316 (23,380)(4,196)(27,576)
Total$85,540 $— $85,540 $(4,191)$81,349 
(a)All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)No cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting.
(c)Represents cash collateral and cash margin that is not subject to offsetting. Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument.  Includes cash collateral received from counterparties of $4,196 thousand and cash margin provided to counterparties of $5 thousand.
As of December 31, 2024:
 (dollars in thousands) 		Gross
 Recognized
 Derivatives
 (a)		Amounts
Offset 
(b)		Net
 Recognized
 Derivatives		Other
 (c)		Amounts
 Reported on
 Balance Sheets
Current assets$13,718 $(3,158)$10,560 $18 $10,578 
Investments and other assets6,610 (630)5,980 — 5,980 
Total assets20,328 (3,788)16,540 18 16,558 
Current liabilities(52,527)3,158 (49,369)(2,971)(52,340)
Deferred credits and other(10,076)630 (9,446)— (9,446)
Total liabilities(62,603)3,788 (58,815)(2,971)(61,786)
Total$(42,275)$— $(42,275)$(2,953)$(45,228)
(a)All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)No cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting.
(c)Represents cash collateral and cash margin that is not subject to offsetting.  Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument.  Includes cash collateral received from counterparties of $2,971 thousand and cash margin provided to counterparties of $18 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, 2025
Aggregate fair value of derivative instruments in a net liability position$25,696 
Additional collateral in the event credit-risk related contingent features were fully triggered (a)20 
(a)This amount is after counterparty netting and includes those contracts which qualify for scope exceptions, which are excluded from the derivative details above.
v3.25.1
Other Income and Other Expense (Tables)
 3 Months Ended
Mar. 31, 2025
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,
 20252024
Other income:
Interest income (a)$5,996 $7,560 
Investment gain — net (b)10,984 — 
Gain on sale of BCE (Note 18)
— 22,988 
Miscellaneous481 59 
Total other income$17,461 $30,607 
Other expense:
Non-operating costs$(2,229)$(6,150)
Investment losses — net— (777)
Miscellaneous(341)(640)
Total other expense$(2,570)$(7,567)

(a)Interest income is primarily related to PSA interest. See Note 6.
(b)Investment gain is primarily related to El Dorado’s equity investment in SAI Advanced Power Solutions.
The following table provides detail of APS’s other income and other expense (dollars in thousands):
Three Months Ended March 31,
 20252024
Other income:
Interest income (a)$5,607 $6,796 
Miscellaneous115 59 
 Total other income$5,722 $6,855 
Other expense:
Non-operating costs$(1,992)$(2,255)
Miscellaneous(341)(639)
Total other expense$(2,333)$(2,894)
(a)Interest income is primarily related to PSA interest. See Note 6.
v3.25.1
Common Stock Equity and Earnings Per Share (Tables)
 3 Months Ended
Mar. 31, 2025
Earnings Per Share [Abstract]  
Schedule of Sale of Stock by Subsidiary or Equity Method Investee Disclosure
The following table presents the calculation of Pinnacle West’s ATM Program as of March 31, 2025 (in thousands, except share amounts and price per share):

As of March 31, 2025
November 2024 ATM Forward Sale AgreementMarch 2025 ATM Forward Sale Agreement
Initial Price
Number of Shares552,833 544,959 
Forward Sales Price Per Share (a)$89.73 $90.83 
Aggregate Value (in thousands)$49,606 $49,499 

(a)    Subject to certain adjustments.
The following table presents the calculation of Pinnacle West’s February 2024 Forward Sale Agreements as of March 31, 2025 (in thousands, except share amounts and price per share):

As of March 31, 2025
February 2024 Forward Sale Agreements
Initial Price
Number of Shares11,240,601 
Forward Sales Price Per Share (a)$64.51 
Aggregate Value (in thousands)$725,131 
Settlements
Date12/23/2024
Number of Shares Settled (b)5,377,115 
Forward Sales Price Upon Settlement$64.17 
Net Proceeds (in thousands) (c)$345,049 

(a)    Subject to certain adjustments.
(b)    Physical delivery.
(c)    Proceeds recorded in common equity on the Condensed Consolidated Balance Sheets.
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 earnings per share amounts):
Three Months Ended March 31,
 20252024
Net income (loss) attributable to common shareholders$(4,644)$16,862 
Weighted average common shares outstanding — basic119,594 113,621 
Net effect of dilutive securities:
Contingently issuable performance shares and restricted stock units498 327 
Dilutive shares related to equity forward sale agreements (a)1,669 279 
Total contingently issuable shares (b)2,167 606 
Weighted average common shares outstanding — diluted121,761 114,227 
Earnings per weighted-average common share outstanding
Net income (loss) attributable to common shareholders — basic$(0.04)$0.15 
Net income (loss) attributable to common shareholders — diluted (b)$(0.04)$0.15 

(a)    For the three months ended March 31, 2025 and 2024, diluted weighted average common shares excludes 197,390 and 0 shares, respectively, relating to the Convertible Notes and the November 2024 ATM Forward Sale Agreements. These potentially issuable shares were excluded from the calculation of diluted shares as their inclusion would have been antidilutive.
(b)    Contingently issuable shares of 2,167,000 were excluded from the calculation of diluted weighted average common shares outstanding, as their inclusion would have been antidilutive due to the Net Loss results for the three months ended March 31, 2025. For the three months ended March 31, 2024, 0 contingently issuable shares were excluded from the calculation of diluted weighted average common shares outstanding.
v3.25.1
Fair Value Measurements (Tables)
 3 Months Ended
Mar. 31, 2025
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 as of March 31, 2025 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):

Level 1Level 2Level 3OtherTotal
ASSETS
Cash equivalents$23 $— $— $— $23 
Risk management activities — derivative instruments:
Commodity contracts— 110,047 1,189 (2,311)(a)108,925 
Nuclear decommissioning trusts:
Equity securities11,490 — — 2,690 (b)14,180 
U.S. commingled equity funds— — — 405,263 (c)405,263 
U.S. Treasury debt359,911 — — — 359,911 
Corporate debt— 220,641 — — 220,641 
Mortgage-backed securities— 224,983 — — 224,983 
Municipal bonds— 33,817 — — 33,817 
Other fixed income— 27,306 — — 27,306 
Subtotal nuclear decommissioning trusts371,401 506,747 — 407,953 1,286,101 
Other special use funds:
Equity securities37,234 — — 2,030 (b)39,264 
U.S. Treasury debt376,137 — — — 376,137 
Subtotal other special use funds (d)413,371 — — 2,030 415,401 
Total assets$784,795 $616,794 $1,189 $407,672 $1,810,450 
LIABILITIES
Risk management activities — derivative instruments:
Commodity contracts$— $(1,667)$(24,029)$(1,880)(a)$(27,576)
(a)Represents counterparty netting, margin, and collateral. See Note 9.
(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.
(d)All amounts relate to APS, with the exception of $35.1 million related to Pinnacle West’s Captive investments that are classified within Level 1, $10.0 million related to equity securities and $25.1 million related to U.S. treasury debt. See Note 8.
 The following table presents the fair value at December 31, 2024 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):
 
Level 1Level 2Level 3OtherTotal
ASSETS
Cash equivalents$23 $— $— $— $23 
Risk management activities — derivative instruments:
Commodity contracts— 13,152 7,176 (3,770)(a)16,558 
Nuclear decommissioning trusts:
Equity securities11,859 542 — 3,335 (b)15,736 
U.S. commingled equity funds— — — 423,069 (c)423,069 
U.S. Treasury debt367,396 — — — 367,396 
Corporate debt— 203,180 — — 203,180 
Mortgage-backed securities— 208,533 — — 208,533 
Municipal bonds— 37,429 — — 37,429 
Other fixed income— 27,502 — — 27,502 
Subtotal nuclear decommissioning trusts379,255 477,186 — 426,404 1,282,845 
Other special use funds:
Cash equivalents25,000 — — — (d)25,000 
Equity securities24,962 — — 2,851 (b) (d)27,813 
U.S. Treasury debt355,544 — — — 355,544 
Subtotal other special use funds (d)405,506 — — 2,851 408,357 
Total assets$784,784 $490,338 $7,176 $425,485 $1,707,783 
LIABILITIES
Risk management activities — derivative instruments:
Commodity contracts$— $(40,388)$(22,215)$817 (a)$(61,786)
(a)Represents counterparty netting, margin, and collateral. See Note 9.
(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.
(d)All amounts relate to APS, with the exception of $34.2 million related to Pinnacle West’s Captive investments that are classified within Level 1, $25.0 million in cash equivalents and $9.2 million related to equity securities. See Note 8.
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 Contracts20252024
Balance at beginning of period$(15,039)$4,921 
Total net losses realized/unrealized:
Deferred as a regulatory asset or liability(5,823)(23,600)
Settlements(2,287)2,708 
Transfers into Level 3 from Level 2(59)— 
Transfers from Level 3 into Level 2368 — 
Balance at end of period$(22,840)$(15,971)
Net unrealized gains/losses included in earnings related to instruments still held at end of period$— $— 
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 as of March 31, 2025 and December 31, 2024:

March 31, 2025
 Fair Value (thousands) 		ValuationSignificantWeighted-Average
Commodity ContractsAssetsLiabilitiesTechniqueUnobservable InputRange (b)
Electricity Forward Contracts (a)$703 $23,218 Discounted cash flowsElectricity forward price (per MWh)
$26.23
-
$151.56
$90.74
Natural Gas Forward Contracts (a)486 811 Discounted cash flowsNatural gas forward price (per MMBtu)
$(1.92)
-
$0.09
$0.02
Total$1,189 $24,029 
(a)Includes swaps and physical and financial contracts.
(b)Unobservable inputs were weighted by the relative fair value of the instrument.

December 31, 2024
 Fair Value (thousands) 		ValuationSignificantWeighted-Average
Commodity ContractsAssetsLiabilitiesTechniqueUnobservable InputRange(b)
Electricity Forward Contracts (a)$708 $21,890 Discounted cash flowsElectricity forward price (per MWh)$25.25 -$151.11$106.06
Natural Gas Forward Contracts (a)6,468 325 Discounted cash flowsNatural gas forward price (per MMBtu)$(0.89)-$1.47$0.71
Total$7,176 $22,215 
(a)Includes swaps and physical and financial contracts.
(b)Unobservable inputs were weighted by the relative fair value of the instrument.
v3.25.1
Investments in Nuclear Decommissioning Trusts and Other Special Use Funds (Tables)
 3 Months Ended
Mar. 31, 2025
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 summarize the fair value of the nuclear decommissioning trusts and other special use fund assets (dollars in thousands): 
March 31, 2025
 Fair ValueTotal
Unrealized
Gains		Total
Unrealized
Losses
Investment Type:Nuclear Decommissioning TrustsOther Special Use FundsTotal
Equity securities$416,753 $37,234 $453,987 $341,566 $(325)
Available for sale-fixed income securities866,658 376,137 1,242,795 (a)13,416 (22,318)
Other2,690 2,030 4,720 (b)— — 
Total$1,286,101 $415,401 $1,701,502 (c)$354,982 $(22,643)
(a)As of March 31, 2025, the amortized cost basis of these available-for-sale investments is $1,252 million.
(b)Represents net pending securities sales and purchases.
(c)All amounts pertain to APS, with the exception of $35.1 million of other special use fund investments in equity securities relating to the Captive.
December 31, 2024
 Fair ValueTotal
Unrealized
Gains		Total
Unrealized
Losses
Investment Type:Nuclear Decommissioning TrustsOther Special Use FundsTotal
Equity securities$435,470 $24,962 $460,432 $359,127 $(176)
Available for sale-fixed income securities844,040 355,544 1,199,584 (a)7,717 (31,960)
Other3,335 27,851 31,186 (b)— — 
Total$1,282,845 $408,357 $1,691,202 (c)$366,844 $(32,136)
(a)As of December 31, 2024, the amortized cost basis of these available-for-sale investments is $1,224 million.
(b)Represents net pending securities sales and purchases.
(c)All amounts pertain to APS, with the exception of $34.2 million of other special use fund investments in equity securities relating to the Captive.
Schedule of Realized Gains and Losses and Proceeds from the Sale of Securities by the Nuclear Decommissioning Trust Funds
The following table sets forth 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
2025
Realized gains$1,658 $— $1,658 
Realized losses$(2,761)$— $(2,761)
Proceeds from the sale of securities (a)$416,601 $69,213 (b)$485,814 
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 

(a)    Proceeds are reinvested in the nuclear decommissioning trusts and other special use funds, excluding investment fees and amounts reimbursed to the Company for active union employee medical claims from the active union employee medical account.
(b) All amounts pertain to APS, with the exception of $25.3 million of other special use fund proceeds from the sale of securities relating to the Captive.
Schedule of Fair Value of Fixed Income Securities, Summarized by Contractual Maturities
The fair value fixed income securities summarized by contractual maturities as of March 31, 2025 is as follows (dollars in thousands):
 
 Nuclear Decommissioning TrustsCoal Reclamation Escrow AccountActive Union Employee Medical Account
Captive Insurance Cell (a)
Total
Less than one year$32,422 $90,167 $39,464 25,149 $187,202 
1 year – 5 years292,409 48,289 157,055 — 497,753 
5 years – 10 years137,989 — 16,013 — 154,002 
Greater than 10 years403,838 — — — 403,838 
Total$866,658 $138,456 $212,532 25,149 $1,242,795 
(a)All amounts pertain to APS, with the exception of $25.1 million of other special use fund investments in fixed income securities relating to the Captive.
v3.25.1
Changes in Accumulated Other Comprehensive Loss (Tables)
 3 Months Ended
Mar. 31, 2025
Comprehensive Income (Loss), Net of Tax, Attributable to Parent [Abstract]  
Schedule of Changes in Accumulated Other Comprehensive Loss Including Reclassification Adjustments, by Component
The following table shows the changes in Pinnacle West’s consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component (dollars in thousands): 
 Pension and Other Postretirement BenefitsDerivative Instruments Total
Three Months Ended March 31
Balance December 31, 2024
$(31,661)$719 $(30,942)
Other comprehensive income before reclassifications
— 350 350 
Amounts reclassified from accumulated other comprehensive loss
498  (a)— 498 
Balance March 31, 2025
$(31,163)$1,069 $(30,094)
Balance December 31, 2023
$(34,754)$1,610 $(33,144)
Other comprehensive (loss) before reclassifications
— — — 
Amounts reclassified from accumulated other comprehensive loss
562  (a)— 562 
Balance March 31, 2024
$(34,192)$1,610 $(32,582)

(a)    These amounts primarily represent amortization of actuarial loss and are included in the computation of net periodic pension cost.  See Note 7
The following table shows the changes in APS’s 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, 2024
$(14,116)
Other comprehensive (loss) before reclassifications
— 
Amounts reclassified from accumulated other comprehensive loss
406  (a)
Balance March 31, 2025
$(13,710)
Balance December 31, 2023
$(17,219)
Other comprehensive (loss) before reclassifications
— 
Amounts reclassified from accumulated other comprehensive loss
490  (a)
Balance March 31, 2024
$(16,729)

(a) These amounts primarily represent amortization of actuarial loss and are included in the computation of net periodic pension cost.  See Note 7.
v3.25.1
Leases (Tables)
 3 Months Ended
Mar. 31, 2025
Leases [Abstract]  
Schedule of Lease Costs
The following table provides information related to our lease costs (dollars in thousands):
Three Months Ended March 31,
20252024
Operating Lease Cost - Purchased Power and Energy Storage Lease Contracts$12,547 $937 
Operating Lease Cost - Land, Property, and Other Equipment5,337 4,773 
Total Operating Lease Cost17,884 5,710 
Variable Lease Cost (a)21,370 21,564 
Short-term Lease Cost592 2,800 
Total Lease Cost$39,846 $30,074 
The following tables provide other additional information related to operating lease liabilities (dollars in thousands):
Three Months Ended March 31,
20252024
Cash paid for amounts included in the measurement of lease liabilities — operating cash flows:$17,207 $3,544 
Right-of-use operating lease assets obtained in exchange for operating lease liabilities:$763,437 (a)$6,747 

March 31, 2025December 31, 2024
Weighted average remaining lease term14 years11 years
Weighted average discount rate (b)5.17 %4.90 %

(a)Primarily relates to the three new energy storage operating lease agreements that commenced in 2025.
(b)Most of our lease agreements do not contain an implicit rate that is readily determinable. For these agreements we use our incremental borrowing rate to measure the present value of lease liabilities. We determine our incremental borrowing rate at lease commencement based on the rate of interest that we would have to pay to borrow, on a collateralized basis over a similar term, an amount equal to the lease payments in a similar economic environment. We use the implicit rate when it is readily determinable.
Schedule of Maturities of Operating Lease Labilities
The following table provides information related to the maturity of our operating lease liabilities (dollars in thousands):
March 31, 2025
YearPurchased Power and Energy Storage Lease ContractsLand, Property and Equipment LeasesTotal
2025 (remaining nine months of 2025)$197,622 $12,933 $210,555 
2026236,859 14,891 251,750 
2027262,780 12,310 275,090 
2028266,577 9,641 276,218 
2029270,514 7,516 278,030 
2030274,492 4,392 278,884 
Thereafter1,850,659 57,475 1,908,134 
Total lease commitments3,359,503 119,158 3,478,661 
Less imputed interest1,036,548 40,691 1,077,239 
Total lease liabilities$2,322,955 $78,467 $2,401,422 
v3.25.1
Consolidation and Nature of Operations (Details) - USD ($)
$ in Thousands
 3 Months Ended
Mar. 31, 2025
Mar. 31, 2024
Cash and Cash Equivalents [Line Items]    
Income taxes, net of refunds $ (10,799) $ 20,970
Interest, net of amounts capitalized 91,475 83,974
Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]    
Accrued capital expenditures 315,297 217,684
BCE Sale non-cash consideration (Note 18) 0 45,608
APS    
Cash and Cash Equivalents [Line Items]    
Income taxes, net of refunds (5,392) 0
Interest, net of amounts capitalized 84,110 73,035
Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]    
Accrued capital expenditures $ 315,297 $ 217,684
v3.25.1
Business Segments (Details) - USD ($)
$ in Thousands
 3 Months Ended
Mar. 31, 2025
Mar. 31, 2024
Dec. 31, 2024
Revenue from External Customer [Line Items]      
Operating Revenues $ 1,032,280 $ 951,712  
Fuel and purchased power 380,071 357,864  
Operations and maintenance 300,109 257,578  
Depreciation and amortization 234,940 210,294  
Taxes other than income taxes 59,354 59,164  
Pension and other postretirement non-service credits, net 2,958 11,568  
Allowance for equity funds used during construction 13,249 10,292  
Interest expense and costs 94,841 86,633  
Income taxes (benefit) (6,183) 3,891  
Less: Net income attributable to noncontrolling interests (Note 8) 4,306 4,306  
Net Income (Loss) Attributable to Common Shareholders (4,644) 16,862  
TOTAL ASSETS 27,236,478   $ 26,102,760
Reportable Segment | Pinnacle West      
Revenue from External Customer [Line Items]      
Operating Revenues 1,032,000 952,000  
Fuel and purchased power (380,000) (358,000)  
Operations and maintenance (300,000) (258,000)  
Depreciation and amortization (235,000) (210,000)  
Taxes other than income taxes (59,000) (59,000)  
Pension and other postretirement non-service credits, net 3,000 12,000  
Allowance for equity funds used during construction 13,000 10,000  
Other income and expenses, net 14,000 23,000  
Interest expense and costs (95,000) (87,000)  
Income taxes (benefit) 6,000 (4,000)  
Less: Net income attributable to noncontrolling interests (Note 8) (4,000) (4,000)  
Net Income (Loss) Attributable to Common Shareholders (5,000) 17,000  
TOTAL ASSETS 27,236,000   26,103,000
Regulated Electricity Segment      
Revenue from External Customer [Line Items]      
Operating Revenues 1,032,000 952,000  
Fuel and purchased power (380,000) (358,000)  
Operations and maintenance (297,000) (254,000)  
Depreciation and amortization (235,000) (210,000)  
Taxes other than income taxes (59,000) (59,000)  
Pension and other postretirement non-service credits, net 3,000 12,000  
Allowance for equity funds used during construction 13,000 10,000  
Other income and expenses, net 3,000 4,000  
Interest expense and costs (79,000) (74,000)  
Income taxes (benefit) 3,000 (4,000)  
Less: Net income attributable to noncontrolling interests (Note 8) (4,000) (4,000)  
Net Income (Loss) Attributable to Common Shareholders 0 15,000  
TOTAL ASSETS 27,097,000   25,988,000
Other      
Revenue from External Customer [Line Items]      
Operating Revenues 0 0  
Fuel and purchased power 0 0  
Operations and maintenance (3,000) (4,000)  
Depreciation and amortization 0 0  
Taxes other than income taxes 0 0  
Pension and other postretirement non-service credits, net 0 0  
Allowance for equity funds used during construction 0 0  
Other income and expenses, net 11,000 19,000  
Interest expense and costs (16,000) (13,000)  
Income taxes (benefit) 3,000 0  
Less: Net income attributable to noncontrolling interests (Note 8) 0 0  
Net Income (Loss) Attributable to Common Shareholders (5,000) $ 2,000  
TOTAL ASSETS $ 139,000   $ 115,000
v3.25.1
Revenue - Schedule of Disaggregation of Revenue (Details) - USD ($)
$ in Thousands
 3 Months Ended
Mar. 31, 2025
Mar. 31, 2024
Disaggregation of Revenue [Line Items]    
Total Operating Revenues $ 1,032,280 $ 951,712
Retail Electric Service | Residential    
Disaggregation of Revenue [Line Items]    
Total Operating Revenues 448,923 432,692
Retail Electric Service | Non-Residential    
Disaggregation of Revenue [Line Items]    
Total Operating Revenues 524,857 461,483
Wholesale Energy Sales    
Disaggregation of Revenue [Line Items]    
Total Operating Revenues 24,824 26,864
Transmission Services for Others    
Disaggregation of Revenue [Line Items]    
Total Operating Revenues 25,547 27,712
Other Sources    
Disaggregation of Revenue [Line Items]    
Total Operating Revenues $ 8,129 $ 2,961
v3.25.1
Revenue - Additional Information (Details) - USD ($)
$ in Thousands
 3 Months Ended
Mar. 31, 2025
Mar. 31, 2024
Disaggregation of Revenue [Line Items]    
Operating revenues $ 1,032,280 $ 951,712
Regulatory cost recovery revenue 13,000 9,000
Electric and Transmission Service    
Disaggregation of Revenue [Line Items]    
Operating revenues $ 1,019,000 $ 943,000
v3.25.1
Revenue - Schedule of Allowance for Doubtful Accounts (Details) - USD ($)
$ in Thousands
 3 Months Ended
Mar. 31, 2025
Mar. 31, 2024
Accounts Receivable, Allowance for Credit Loss [Roll Forward]    
Balance at beginning of period $ 24,849 $ 22,433
Bad debt expense 4,789 35,799
Actual write-offs (6,599) $ (33,383)
Balance at end of period $ 23,039  
v3.25.1
Debt and Liquidity Matters - Additional Information (Details) - USD ($)
$ in Millions
 3 Months Ended
Apr. 29, 2025
Dec. 17, 2024
Dec. 05, 2024
Mar. 31, 2025
Aug. 02, 2024
APS          
Long-Term Debt and Liquidity Matters [Line Items]          
Public utilities, request to permanently modify permitted yearly equity infusions   2.50%      
Public utilities, number of basis point of approved rate       0.0050  
Term Loan | APS          
Long-Term Debt and Liquidity Matters [Line Items]          
Debt instrument term     364 days    
Notes issued     $ 400.0    
Debt instrument, basis spread on variable rate     0.90%    
Term Loan | APS | Subsequent Event          
Long-Term Debt and Liquidity Matters [Line Items]          
Proceeds from issuance of unsecured debt $ 400.0        
Revolving credit facility | Revolving Credit Facility Maturing April 2029 | APS          
Long-Term Debt and Liquidity Matters [Line Items]          
Current borrowing capacity on credit facility       $ 1,250.0  
Accordion feature, increase limit       400.0  
Long-term line of credit       $ 0.0  
Debt, weighted average interest rate       4.64%  
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders       $ 1,650.0  
Letter of Credit | APS          
Long-Term Debt and Liquidity Matters [Line Items]          
Outstanding letters of credit       18.7  
Letter of Credit | Revolving Credit Facility Maturing April 2029 | APS          
Long-Term Debt and Liquidity Matters [Line Items]          
Outstanding letters of credit       0.0  
Commercial paper | APS          
Long-Term Debt and Liquidity Matters [Line Items]          
Maximum commercial paper support available under credit facility       1,000.0  
Commercial paper | Revolving Credit Facility Maturing April 2029 | APS          
Long-Term Debt and Liquidity Matters [Line Items]          
Commercial paper       $ 627.0  
Pinnacle West | Term Loan          
Long-Term Debt and Liquidity Matters [Line Items]          
Debt instrument term       364 days  
Notes issued       $ 200.0  
Debt instrument, basis spread on variable rate       0.95%  
Pinnacle West | Revolving credit facility | Revolving Credit Facility Maturing April 2029          
Long-Term Debt and Liquidity Matters [Line Items]          
Current borrowing capacity on credit facility       $ 200.0  
Accordion feature, increase limit       300.0  
Long-term line of credit       0.0  
Pinnacle West | Letter of Credit | Revolving Credit Facility Maturing April 2029          
Long-Term Debt and Liquidity Matters [Line Items]          
Outstanding letters of credit       $ 0.0  
Pinnacle West | Commercial paper | Revolving Credit Facility Maturing April 2029          
Long-Term Debt and Liquidity Matters [Line Items]          
Commercial paper         $ 44.0
Debt, weighted average interest rate       4.65%  
v3.25.1
Debt and Liquidity Matters - Schedule of Estimated Fair Value of Long-Term Debt, Including Current Maturities (Details) - USD ($)
$ in Thousands
Mar. 31, 2025
Dec. 31, 2024
Estimated fair value of long-term debt, including current maturities    
Carrying Amount $ 8,860,736 $ 8,858,648
Fair Value 8,033,868 7,918,992
APS    
Estimated fair value of long-term debt, including current maturities    
Carrying Amount 7,491,990 7,490,878
Fair Value 6,596,763 6,525,248
Pinnacle West    
Estimated fair value of long-term debt, including current maturities    
Carrying Amount 1,368,746 1,367,770
Fair Value $ 1,437,105 $ 1,393,744
v3.25.1
Regulatory Matters - ACC General Retail Rate Cases (Details)
$ in Thousands
Feb. 22, 2024
USD ($)
Jan. 25, 2024
USD ($)
$ / MWh
Nov. 02, 2021
USD ($)
Public Utilities, General Disclosures [Line Items]      
Revenue increase (decrease) $ 491,700 $ 523,100  
ACC      
Public Utilities, General Disclosures [Line Items]      
Recommended return on equity, percentage 9.55% 9.55%  
Increment of fair value rate, percentage 0.25% 0.25%  
ACC | Navajo Nation | Coal Community Transition Plan      
Public Utilities, General Disclosures [Line Items]      
Regulatory matters, amounts recoverable by rates     $ 10,000
ACC | Navajo County Communities | Coal Community Transition Plan      
Public Utilities, General Disclosures [Line Items]      
Regulatory matters, amounts recoverable by rates     500
ACC | Navajo Nation, Hopi Tribe | Coal Community Transition Plan      
Public Utilities, General Disclosures [Line Items]      
Regulatory matters, amounts recoverable by rates     1,000
ACC | Navajo Nation, Electrification Projects | Coal Community Transition Plan      
Public Utilities, General Disclosures [Line Items]      
Amount funded by shareholders     2,000
ACC | Navajo County Communities, CCT and Economic Development | Coal Community Transition Plan      
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      
Public Utilities, General Disclosures [Line Items]      
Amount funded by shareholders     1,250
ACC | Navajo Nation, Hopi Reservation | Coal Community Transition Plan      
Public Utilities, General Disclosures [Line Items]      
Regulatory matters, amounts recoverable by rates     $ 1,250
APS | Retail Rate Case Filing with Arizona Corporation Commission | ACC      
Public Utilities, General Disclosures [Line Items]      
Effective fair value percentage 4.39% 4.36%  
Prepaid pension asset rate (in percent)   5.00%  
Pension and other post-retirement and post employment benefit plans (in percent)   5.35%  
Retention of REAC   $ 1,900  
Transfer to LFCR   $ 27,100  
Base fuel rate (in dollars per kWh) | $ / MWh   0.006  
Increases in annual revenue $ 253,400    
Increase to the typical residential customer’s bill (in percent) 8.00%    
v3.25.1
Regulatory Matters - Cost Recovery Mechanisms (Details)
 3 Months Ended
Nov. 27, 2024
$ / kWh
Jul. 31, 2024
USD ($)
Jun. 01, 2024
USD ($)
MW
May 01, 2024
$ / kWh
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
Feb. 23, 2023
$ / kWh
Feb. 01, 2023
$ / kWh
Jul. 12, 2022
$ / kWh
Jun. 01, 2022
USD ($)
Feb. 15, 2022
USD ($)
Feb. 01, 2022
$ / kWh
Oct. 01, 2021
$ / kWh
Feb. 15, 2021
USD ($)
Feb. 01, 2020
$ / kWh
Sep. 01, 2017
Mar. 31, 2025
USD ($)
Mar. 06, 2025
USD ($)
Jul. 01, 2024
USD ($)
Apr. 26, 2024
USD ($)
Jun. 30, 2023
USD ($)
May 31, 2023
USD ($)
Nov. 30, 2022
USD ($)
Jul. 01, 2022
USD ($)
Apr. 18, 2022
USD ($)
Dec. 17, 2021
USD ($)
APS | Damage from Fire, Explosion or Other Hazard                                                              
Public Utilities, General Disclosures [Line Items]                                                              
Past due balance threshold qualifying for payment extension                                                           $ 75  
Arizona Renewable Energy Standard and Tariff | ACC | APS                                                              
Public Utilities, General Disclosures [Line Items]                                                              
Plan term                                           5 years                  
Arizona Renewable Energy Standard and Tariff 2018 | ACC | APS                                                              
Public Utilities, General Disclosures [Line Items]                                                              
Amount of proposed budget                                               $ 92,700,000   $ 95,100,000     $ 86,200,000    
Demand Side Management Adjustor Charge 2022 | ACC | APS                                                              
Public Utilities, General Disclosures [Line Items]                                                              
Amount of proposed budget                                                             $ 78,400,000
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                                                    
Rate matter, updated budget                                                 $ 90,900,000            
Proposed rate on refund customers                                             $ 9,000,000                
Renewable Energy Adjustment Charge | ACC | APS                                                              
Public Utilities, General Disclosures [Line Items]                                                              
Proposed rate on refund customers                                             $ 43,000,000                
Power Supply Adjustor (PSA) | ACC | APS                                                              
Public Utilities, General Disclosures [Line Items]                                                              
PSA rate (in dollars per kWh) | $ / kWh 0.013977       0.019074             0.019074 0.006       0.007544                            
Forward component of PSA rate1 (in dollars per kWh) | $ / kWh (0.000281)       (0.012624)             (0.005527)         0.004842                            
Historical component of PSA rate1 (in dollars per kWh) | $ / kWh 0.008728       0.013071             0.013071         0.012386                            
Reporting threshold of balancing account         $ 100,000,000                                                    
Overall approved PSA rate1 (in dollars per kWh) | $ / kWh         0.011977                                                    
Transition component of PSA rate | $ / kWh 0.005530       0.011530                                                    
Power Supply Adjustor (PSA) | ACC | APS | Cost Recovery Mechanisms                                                              
Public Utilities, General Disclosures [Line Items]                                                              
Maximum increase decrease in PSA rate (in dollars per kWh) | $ / kWh 0.006                                     0.006                      
PSA rate In prior years1 (in dollars per kWh) | $ / kWh 0.002                               0.004                            
Transmission rates, transmission cost adjustor and other transmission matters | FERC | APS                                                              
Public Utilities, General Disclosures [Line Items]                                                              
Rate matters, increase (decrease) In cost recovery     $ 27,400,000             $ 34,700,000         $ (33,000,000)                                
Rate matters, increase (decrease) in cost recovery, wholesale customer rates     16,600,000             20,700,000         (6,400,000)                                
Rate matters, increase (decrease) in cost recovery, retail customer rates     10,800,000             14,000,000         (26,600,000)                                
Rate matters, increase (decrease) In retail revenue requirements     $ 8,800,000             $ (10,000,000)         $ (2,400,000)                                
Rate matters, increase in residential and commercial rates (in MW) | MW     3                                                        
Rate matters, decrease in commercial rates (in MW) | MW     3                                                        
Lost Fixed Cost Recovery Mechanism | APS                                                              
Public Utilities, General Disclosures [Line Items]                                                              
Rate matter cap percentage of retail revenue                                           1.00%                  
Amount of adjustment approved representing prorated sales losses pending approval   $ 49,600,000           $ 68,700,000               $ 59,100,000                              
Increase in amount of adjustment representing prorated sales losses                               $ 32,500,000     $ 11,800,000                        
Amount of adjustment representing annual recovery   $ 8,000,000           $ 9,600,000                                              
Lost Fixed Cost Recovery Mechanism | 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                                            
Lost revenue recovery collected                                           $ 29,500,000                  
Net Metering | ACC | APS                                                              
Public Utilities, General Disclosures [Line Items]                                                              
Rate matters, cost of service, resource comparison proxy method, maximum annual percentage decrease       10.00%     10.00%       10.00%     10.00%             10.00%                    
Rate matter, request second-year energy price for exported energy1 (in dollars per kwh) | $ / kWh                           0.0846       0.094                          
Third-year export energy price (in dollars per kWh) | $ / kWh       0.06857             0.07619                                        
Rate lock period             10 years                                                
v3.25.1
Regulatory Matters - Schedule of Changes in The Deferred Fuel and Purchased Power Regulatory Asset (Details) - USD ($)
$ in Thousands
 3 Months Ended
Mar. 31, 2025
Mar. 31, 2024
Change in regulatory asset    
Deferred fuel and purchased power costs $ 25,228 $ 33,094
Amounts charged to customers (84,789) (108,552)
APS    
Change in regulatory asset    
Deferred fuel and purchased power costs 25,228 33,094
Amounts charged to customers (84,789) (108,552)
Power Supply Adjustor (PSA) | ACC | APS    
Change in regulatory asset    
Balance at beginning of period 287,597 463,195
Deferred fuel and purchased power costs 25,228 33,094
Amounts charged to customers (84,789) (108,552)
Balance at end of period $ 228,036 $ 387,737
v3.25.1
Regulatory Matters - Four Corners, Cholla and Navajo Plant (Details) - APS - USD ($)
$ in Millions
Mar. 31, 2025
Aug. 02, 2021
Navajo Nation, Economic Development Organization | Coal Community Transition Plan | Retail Rate Case Filing with Arizona Corporation Commission | ACC    
Acquisition    
Disallowance of annual amortization percentage   15.00%
Retired power plant costs    
Acquisition    
Net book value $ 27.0  
Navajo Plant    
Acquisition    
Net book value 31.0  
Navajo Plant, Coal Reclamation Regulatory Asset    
Acquisition    
Net book value $ 5.7  
v3.25.1
Regulatory Matters - Schedule of Regulatory Assets (Details) - USD ($)
$ in Thousands
Mar. 31, 2025
Dec. 31, 2024
Detail of regulatory assets    
Total regulatory assets $ 1,694,830 $ 1,810,458
Less: current regulatory assets 322,070 420,969
Total non-current regulatory assets 1,372,760 1,389,489
Pension    
Detail of regulatory assets    
Total regulatory assets 739,549 750,976
Deferred fuel and purchased power    
Detail of regulatory assets    
Total regulatory assets 228,036 287,597
Income taxes — allowance for funds used during construction equity    
Detail of regulatory assets    
Total regulatory assets 192,894 192,936
Ocotillo deferral    
Detail of regulatory assets    
Total regulatory assets 111,064 114,775
Lease incentives    
Detail of regulatory assets    
Total regulatory assets 84,483 70,541
SCR deferral    
Detail of regulatory assets    
Total regulatory assets 81,639 83,123
Retired power plant costs    
Detail of regulatory assets    
Total regulatory assets 64,591 68,380
FERC Transmission true up    
Detail of regulatory assets    
Total regulatory assets 44,253 35,159
Income taxes — investment tax credit basis adjustment    
Detail of regulatory assets    
Total regulatory assets 34,839 34,834
Deferred compensation    
Detail of regulatory assets    
Total regulatory assets 34,423 33,108
Deferred property taxes    
Detail of regulatory assets    
Total regulatory assets 21,776 23,918
Palo Verde VIEs (Note 8)    
Detail of regulatory assets    
Total regulatory assets 20,571 20,611
Mead-Phoenix transmission line contributions in aid of construction (“CIAC”)    
Detail of regulatory assets    
Total regulatory assets 8,301 8,384
Active Union Medical Trust    
Detail of regulatory assets    
Total regulatory assets 6,664 9,673
Loss on reacquired debt    
Detail of regulatory assets    
Total regulatory assets 6,425 6,682
Navajo coal reclamation    
Detail of regulatory assets    
Total regulatory assets 5,747 7,905
Tax expense adjustor mechanism    
Detail of regulatory assets    
Total regulatory assets 4,370 4,534
PSA - interest    
Detail of regulatory assets    
Total regulatory assets 1,712 11,525
Deferred fuel and purchased power — mark-to-market (Note 9)    
Detail of regulatory assets    
Total regulatory assets 0 42,275
Other    
Detail of regulatory assets    
Total regulatory assets $ 3,493 $ 3,522
v3.25.1
Regulatory Matters - Schedule of Regulatory Liabilities (Details) - USD ($)
$ in Thousands
Mar. 31, 2025
Dec. 31, 2024
Detail of regulatory liabilities    
Total regulatory liabilities $ 2,136,096 $ 2,062,233
Less: current regulatory liabilities 225,332 206,955
Total non-current regulatory liabilities 1,910,764 1,855,278
Asset retirement obligations and removal costs    
Detail of regulatory liabilities    
Total regulatory liabilities 330,787 358,403
Other postretirement benefits    
Detail of regulatory liabilities    
Total regulatory liabilities 233,978 238,113
Four Corners coal reclamation    
Detail of regulatory liabilities    
Total regulatory liabilities 97,532 77,532
Deferred fuel and purchased power — mark-to-market (Note 9)    
Detail of regulatory liabilities    
Total regulatory liabilities 85,540 0
Renewable energy standard    
Detail of regulatory liabilities    
Total regulatory liabilities 70,217 68,523
Income taxes — deferred investment tax credit    
Detail of regulatory liabilities    
Total regulatory liabilities 66,336 66,327
Income taxes — change in rates    
Detail of regulatory liabilities    
Total regulatory liabilities 59,142 59,133
Demand side management    
Detail of regulatory liabilities    
Total regulatory liabilities 27,157 23,927
Spent nuclear fuel    
Detail of regulatory liabilities    
Total regulatory liabilities 25,355 26,818
Sundance maintenance    
Detail of regulatory liabilities    
Total regulatory liabilities 23,860 23,086
TCA Balancing Account    
Detail of regulatory liabilities    
Total regulatory liabilities 11,189 14,834
Property tax deferral    
Detail of regulatory liabilities    
Total regulatory liabilities 4,238 4,785
Tax expense adjustor mechanism    
Detail of regulatory liabilities    
Total regulatory liabilities 4,192 4,343
Other    
Detail of regulatory liabilities    
Total regulatory liabilities 115 113
ACC | Excess deferred income taxes - Tax Cuts and Jobs Act    
Detail of regulatory liabilities    
Total regulatory liabilities 889,034 888,896
FERC | Excess deferred income taxes - Tax Cuts and Jobs Act    
Detail of regulatory liabilities    
Total regulatory liabilities $ 207,424 $ 207,400
v3.25.1
Retirement Plans and Other Postretirement Benefits - Schedule of Net Periodic Benefit Costs and Portion including Portion Charged to Expense (Details) - USD ($)
$ in Thousands
 3 Months Ended
Mar. 31, 2025
Mar. 31, 2024
Net periodic benefit costs and the portion of these costs charged to expense    
Portion of costs (credits) charged to expense $ (2,958) $ (11,568)
Pension Plans    
Net periodic benefit costs and the portion of these costs charged to expense    
Service cost-benefits earned during the period 10,949 10,631
Interest cost on benefit obligation 38,976 37,236
Expected return on plan assets (44,547) (46,983)
Prior service credit 0 0
Net actuarial loss (gain) 12,118 10,944
Net periodic benefit costs (credits) 17,496 11,828
Portion of costs (credits) charged to expense 10,461 6,337
Other Benefits Plans    
Net periodic benefit costs and the portion of these costs charged to expense    
Service cost-benefits earned during the period 1,982 2,459
Interest cost on benefit obligation 5,102 5,613
Expected return on plan assets (12,142) (11,709)
Prior service credit (1,265) (9,447)
Net actuarial loss (gain) (2,899) (2,080)
Net periodic benefit costs (credits) (9,222) (15,164)
Portion of costs (credits) charged to expense $ (6,873) $ (11,306)
v3.25.1
Retirement Plans and Other Postretirement Benefits - Additional Information (Details)
 3 Months Ended
Mar. 31, 2025
USD ($)
Pension Plans  
Defined Benefit Plan Disclosure [Line Items]  
Minimum contributions under MAP-21 $ 0
v3.25.1
Variable Interest Entities - Additional Information (Details)
$ in Thousands
 3 Months Ended
Mar. 31, 2025
USD ($)
lease
Mar. 31, 2024
USD ($)
Dec. 31, 2024
USD ($)
Dec. 31, 1986
trust
Palo Verde Sale Leaseback Variable Interest Entities        
Net income attributable to noncontrolling interest $ 4,306 $ 4,306    
APS        
Palo Verde Sale Leaseback Variable Interest Entities        
Net income attributable to noncontrolling interest 4,306 4,306    
Special use fund     $ 34,200  
Variable Interest Entity        
Palo Verde Sale Leaseback Variable Interest Entities        
Net income attributable to noncontrolling interest 700 0    
Variable Interest Entity | Pinnacle West Captive Insurance Cell        
Palo Verde Sale Leaseback Variable Interest Entities        
Special use fund 35,000   $ 34,000  
Variable Interest Entity | APS        
Palo Verde Sale Leaseback Variable Interest Entities        
Net income attributable to noncontrolling interest 4,000 $ 4,000    
Number of Vie lessor trusts | trust       3
Initial loss exposure to the VIEs noncontrolling equity participants during lease extension period 345,000      
Variable Interest Entity | 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      
Variable Interest Entity | APS | Sale Leaseback Transaction 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      
Variable Interest Entity | APS | Period 2022 through 2023 | Maximum        
Palo Verde Sale Leaseback Variable Interest Entities        
Lease period (up to) 2 years      
v3.25.1
Variable Interest Entities - Schedule of Amounts Relating to the VIEs Included in Consolidated Balance Sheets (Details) - USD ($)
$ in Thousands
Mar. 31, 2025
Dec. 31, 2024
Palo Verde Sale Leaseback Variable Interest Entities    
Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation $ 19,606,637 $ 19,197,899
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets    
Equity — Noncontrolling interests 107,474 103,167
APS    
Palo Verde Sale Leaseback Variable Interest Entities    
Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation 19,606,481 19,197,743
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets    
Equity — Noncontrolling interests 107,474 103,167
Palo Verde VIE | APS    
Palo Verde Sale Leaseback Variable Interest Entities    
Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation 81,589 82,556
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets    
Equity — Noncontrolling interests $ 107,474 $ 103,167
v3.25.1
Derivative Accounting - Additional Information (Details) - USD ($)
$ in Thousands
 3 Months Ended
Mar. 31, 2025
Dec. 31, 2024
Commodity Contracts    
Derivative [Line Items]    
Derivative asset $ 108,925 $ 16,558
Additional collateral to counterparties for energy related non-derivative instrument contracts $ 416,000  
Three Counterparties | Derivative Concentration | Credit Concentration    
Derivative [Line Items]    
Concentration risk, percentage 59.00%  
APS    
Derivative [Line Items]    
Percentage of unrealized gains and losses on certain derivatives deferred for future rate treatment before accounting treatment change 100.00%  
v3.25.1
Derivative Accounting - Schedule of Outstanding Gross Notional Amounts Outstanding (Details) - Commodity Contracts
MWh in Thousands
 3 Months Ended 12 Months Ended
Mar. 31, 2025
MWh
Bcf
Dec. 31, 2024
MWh
Bcf
Outstanding gross notional amount of derivatives    
Power | MWh 1,734 1,051
Gas | Bcf 269,000 235,000
v3.25.1
Derivative Accounting - Schedule of Gains and Losses from Derivative Instruments (Details) - USD ($)
$ in Thousands
 3 Months Ended
Mar. 31, 2025
Mar. 31, 2024
Commodity Contracts | Fuel and purchased power | Not Designated as Hedging Instruments    
Derivative Instruments Not Designated as Cash Flows Hedges    
Net Gain (Loss) Recognized in Income $ 116,704 $ (55,942)
v3.25.1
Derivative Accounting - Schedule of Derivative Instruments in the Balance Sheet (Details) - Commodity Contracts - USD ($)
$ in Thousands
Mar. 31, 2025
Dec. 31, 2024
Assets    
Gross Recognized Derivatives $ 111,236 $ 20,328
Amounts Offset (2,316) (3,788)
Net Recognized Derivatives 108,920 16,540
Other 5 18
Amounts  Reported on  Balance Sheets 108,925 16,558
Liabilities    
Gross Recognized Derivatives (25,696) (62,603)
Amounts Offset 2,316 3,788
Net Recognized Derivatives (23,380) (58,815)
Other (4,196) (2,971)
Amounts Reported on Balance Sheets (27,576) (61,786)
Assets and Liabilities    
Gross Recognized Derivatives 85,540 (42,275)
Amounts Offset 0 0
Net Recognized Derivatives 85,540 (42,275)
Other (4,191) (2,953)
Amounts  Reported on  Balance Sheets 81,349 (45,228)
Current assets    
Assets    
Gross Recognized Derivatives 78,883 13,718
Amounts Offset (1,338) (3,158)
Net Recognized Derivatives 77,545 10,560
Other 5 18
Amounts  Reported on  Balance Sheets 77,550 10,578
Investments and other assets    
Assets    
Gross Recognized Derivatives 32,353 6,610
Amounts Offset (978) (630)
Net Recognized Derivatives 31,375 5,980
Other 0 0
Amounts  Reported on  Balance Sheets 31,375 5,980
Current liabilities    
Liabilities    
Gross Recognized Derivatives (15,350) (52,527)
Amounts Offset 1,338 3,158
Net Recognized Derivatives (14,012) (49,369)
Other (4,196) (2,971)
Amounts Reported on Balance Sheets (18,208) (52,340)
Deferred credits and other    
Liabilities    
Gross Recognized Derivatives (10,346) (10,076)
Amounts Offset 978 630
Net Recognized Derivatives (9,368) (9,446)
Other 0 0
Amounts Reported on Balance Sheets $ (9,368) $ (9,446)
v3.25.1
Derivative Accounting - Schedule of Credit Risk and Related Contingent Features (Details) - Commodity Contracts
$ in Thousands
Mar. 31, 2025
USD ($)
Credit Risk and Credit-Related Contingent Features  
Aggregate fair value of derivative instruments in a net liability position $ 25,696
Additional cash collateral in the event credit-risk related contingent features were fully triggered $ 20
v3.25.1
Commitments and Contingencies (Details)
$ in Millions
 3 Months Ended 148 Months Ended
Jan. 01, 2024
USD ($)
trust
Jan. 17, 2023
USD ($)
Sep. 30, 2022
USD ($)
Jul. 03, 2018
Mar. 31, 2025
USD ($)
trust
timePeriod
Oct. 31, 2023
claim
Schedule of Commitments and Contingencies [Line Items]            
Production tax credit guarantees         $ 28.0  
Arizona Public Service Company and Palo Verde Owners vs. United States Department of Energy - Spent Nuclear Fuel and Waste Disposal            
Schedule of Commitments and Contingencies [Line Items]            
Settlement amount, awarded to company         $ 174.3  
APS            
Schedule of Commitments and Contingencies [Line Items]            
Maximum insurance against public liability per occurrence for a nuclear incident $ 16,300.0          
Maximum available nuclear liability insurance 500.0          
Remaining nuclear liability insurance through mandatory industry wide retrospective assessment program 15,800.0          
Maximum assessment per reactor for each nuclear incident 165.9          
Annual limit per incident with respect to maximum assessment $ 24.7          
Number of VIE lessor trusts | trust 3       3  
Maximum potential retrospective assessment per incident of APS $ 144.9          
Annual payment limitation with respect to maximum potential retrospective assessment $ 21.6          
Amount of "all risk" (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde         $ 2,800.0  
Request second-year energy price for exported energy         24.2  
Collateral assurance based on rating triggers         $ 66.4  
Period to provide collateral assurance based on rating triggers         20 days  
APS | Surety Bonds Expiring in 2025            
Schedule of Commitments and Contingencies [Line Items]            
Surety bonds expiring, amount         $ 22.8  
APS | Letter of Credit            
Schedule of Commitments and Contingencies [Line Items]            
Outstanding letters of credit         18.7  
APS | Contaminated Groundwater Wells            
Schedule of Commitments and Contingencies [Line Items]            
Costs related to investigation and study under Superfund site         $ 3.0  
Remedial investigation work   $ 1.7        
APS | Contaminated Groundwater Wells | Pending Litigation            
Schedule of Commitments and Contingencies [Line Items]            
Settlement amount     $ 8.3      
APS | Arizona Public Service Company and Palo Verde Owners vs. United States Department of Energy - Spent Nuclear Fuel and Waste Disposal            
Schedule of Commitments and Contingencies [Line Items]            
Number of claims submitted | claim           11
Gain contingency, number of settlement agreement time periods | timePeriod         11  
Settlement amount, awarded to company         $ 50.7  
NTEC | Four Corners            
Schedule of Commitments and Contingencies [Line Items]            
Asset purchase agreement, option to purchase, ownership interest, percentage       7.00%    
v3.25.1
Other Income and Other Expense (Details) - USD ($)
$ in Thousands
 3 Months Ended
Mar. 31, 2025
Mar. 31, 2024
Other income:    
Interest income $ 5,996 $ 7,560
Investment gain 10,984 0
Gain on sale of BCE (Note 18) 0 22,988
Miscellaneous 481 59
Total other income 17,461 30,607
Other expense:    
Non-operating costs (2,229) (6,150)
Investment losses — net 0 (777)
Miscellaneous (341) (640)
Total other expense (2,570) (7,567)
APS    
Other income:    
Interest income 5,607 6,796
Miscellaneous 115 59
Total other income 5,722 6,855
Other expense:    
Non-operating costs (1,992) (2,255)
Miscellaneous (341) (639)
Total other expense $ (2,333) $ (2,894)
v3.25.1
Common Stock Equity and Earnings Per Share - Additional Information (Details)
$ / shares in Units, $ in Millions
 1 Months Ended 3 Months Ended
Jun. 30, 2024
USD ($)
day
Mar. 31, 2025
USD ($)
agreement
$ / shares
Nov. 08, 2024
USD ($)
Subsidiary or Equity Method Investee [Line Items]      
Unsettled proceeds   $ 100  
Convertible Notes Due Maturing June 2027 | Convertible Debt      
Subsidiary or Equity Method Investee [Line Items]      
Debt instrument, convertible, conversion ratio   0.0108338  
Pinnacle West | Convertible Notes Due Maturing June 2027 | Convertible Debt      
Subsidiary or Equity Method Investee [Line Items]      
Notes issued $ 525    
Interest rate (as a percent) 4.75%    
Debt instrument, convertible, conversion price (in usd per share) | $ / shares   $ 92.30  
Debt instrument redemption price percentage   100.00%  
Long-term debt   $ 525  
Unamortized debt issuance expense   6  
Convertible debt, fair value   591  
Pinnacle West | Convertible Notes Due Maturing June 2027 | Convertible Debt | Debt Conversion Terms One      
Subsidiary or Equity Method Investee [Line Items]      
Debt instrument, convertible, threshold trading days | day 20    
Debt instrument, convertible, threshold consecutive trading days | day 30    
Debt instrument, convertible, threshold percentage of stock price trigger 130.00%    
Pinnacle West | Convertible Notes Due Maturing June 2027 | Convertible Debt | Debt Conversion Terms Two      
Subsidiary or Equity Method Investee [Line Items]      
Debt instrument, convertible, threshold trading days | day 5    
Debt instrument, convertible, threshold consecutive trading days | day 10    
Debt instrument, convertible, threshold percentage of stock price trigger 98.00%    
ATM Program      
Subsidiary or Equity Method Investee [Line Items]      
Value of shares to be issued under ATM program   $ 800 $ 900
At the Market Offering      
Subsidiary or Equity Method Investee [Line Items]      
Number of outstanding forward sale agreements | agreement   2  
v3.25.1
Common Stock Equity and Earnings Per Share - Schedule of ATM Program (Details) - USD ($)
$ / shares in Units, $ in Thousands
 3 Months Ended
Dec. 23, 2024
Mar. 31, 2025
Mar. 31, 2024
Nov. 08, 2024
Subsidiary or Equity Method Investee [Line Items]        
Aggregate Value [1]     $ 4,830  
ATM Program        
Subsidiary or Equity Method Investee [Line Items]        
Aggregate Value   $ 800,000   $ 900,000
November 2024 Forward Sale Agreement        
Subsidiary or Equity Method Investee [Line Items]        
Number of Shares (in shares)   552,833    
Forward Sales Price Per Share (in usd per share)   $ 89.73    
Aggregate Value   $ 49,606    
March 2025 ATM Forward Sale Agreement        
Subsidiary or Equity Method Investee [Line Items]        
Number of Shares (in shares)   544,959    
Forward Sales Price Per Share (in usd per share)   $ 90.83    
Aggregate Value   $ 49,499    
February 2024 Forward Sale Agreements        
Subsidiary or Equity Method Investee [Line Items]        
Number of Shares (in shares) 5,377,115      
Forward Sales Price Per Share (in usd per share) $ 64.17 $ 64.51    
Number of Shares (in shares)   11,240,601    
Aggregate Value   $ 725,131    
Net Proceeds $ 345,049      
[1] See Note 12 for information related to our equity forward sale agreements.
v3.25.1
Common Stock Equity and Earnings Per Share - Schedule of Earnings Per Weighted Average Common Share Outstanding (Details) - USD ($)
$ / shares in Units, $ in Thousands
 3 Months Ended
Mar. 31, 2025
Mar. 31, 2024
Earnings Per Share [Abstract]    
Net income (loss) attributable to common shareholders $ (4,644) $ 16,862
Weighted average common shares outstanding — basic (in shares) 119,594,000 113,621,000
Net effect of dilutive securities:    
Contingently issuable performance shares and restricted stock units (in shares) 498,000 327,000
Dilutive shares related to equity forward sale agreements (in shares) 1,669,000 279,000
Total contingently issuable shares 2,167,000 606,000
Weighted Average Number of Shares Outstanding, Diluted And Contingently Issuable Shares 121,761,000  
Weighted average common shares outstanding — diluted (in shares) 119,594,000 114,227,000
Earnings per weighted-average common share outstanding    
Net income attributable to common shareholders - basic (in dollars per share) $ (0.04) $ 0.15
Net income attributable to common shareholders — diluted (in dollars per share) $ (0.04) $ 0.15
Convertible Notes and November 2024 ATM Forward Sale Agreements    
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]    
Antidilutive securities excluded from computation of EPS (in shares) 197,390 0
Contingently Issuable Shares    
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]    
Antidilutive securities excluded from computation of EPS (in shares) 2,167,000 0
v3.25.1
Fair Value Measurements - Assets and Liabilities Measured on a Recurring Basis (Details) - USD ($)
$ in Thousands
Mar. 31, 2025
Dec. 31, 2024
ASSETS    
Cash equivalents $ 23 $ 23
Nuclear decommissioning trust 1,286,101 1,282,845
Nuclear decommissioning trust, other 407,953 426,404
Other special use fund 415,401 408,357
Other special use funds, other 2,030 2,851
Total assets 1,810,450 1,707,783
Total assets, other 407,672 425,485
Commodity contracts    
ASSETS    
Commodity contracts, assets 108,925 16,558
Commodity contracts assets, other (2,311) (3,770)
LIABILITIES    
Derivative instruments, other (1,880) 817
Derivative instruments, total (27,576) (61,786)
Equity securities    
ASSETS    
Nuclear decommissioning trust 14,180 15,736
Nuclear decommissioning trust, other 2,690 3,335
Other special use fund 39,264 27,813
Other special use funds, other 2,030 2,851
U.S. commingled equity funds    
ASSETS    
Nuclear decommissioning trust 405,263 423,069
U.S. Treasury debt    
ASSETS    
Nuclear decommissioning trust 359,911 367,396
Other special use fund 376,137 355,544
Corporate debt    
ASSETS    
Nuclear decommissioning trust 220,641 203,180
Mortgage-backed securities    
ASSETS    
Nuclear decommissioning trust 224,983 208,533
Municipal bonds    
ASSETS    
Nuclear decommissioning trust 33,817 37,429
Other fixed income    
ASSETS    
Nuclear decommissioning trust 27,306 27,502
Cash equivalents    
ASSETS    
Other special use fund   25,000
Other special use funds, other   0
Level 1    
ASSETS    
Cash equivalents 23 23
Nuclear decommissioning trust 371,401 379,255
Other special use fund 413,371 405,506
Total assets 784,795 784,784
Level 1 | Pinnacle West Captive Insurance Cell    
ASSETS    
Other special use fund 35,100 34,200
Level 1 | Commodity contracts    
ASSETS    
Commodity contracts, assets 0 0
LIABILITIES    
Derivative instruments 0 0
Level 1 | Equity securities    
ASSETS    
Nuclear decommissioning trust 11,490 11,859
Other special use fund 37,234 24,962
Level 1 | Equity securities | Pinnacle West Captive Insurance Cell    
ASSETS    
Other special use fund 10,000 9,200
Level 1 | U.S. commingled equity funds    
ASSETS    
Nuclear decommissioning trust 0 0
Level 1 | U.S. Treasury debt    
ASSETS    
Nuclear decommissioning trust 359,911 367,396
Other special use fund 376,137 355,544
Level 1 | U.S. Treasury debt | Pinnacle West Captive Insurance Cell    
ASSETS    
Other special use fund 25,100  
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 1 | Cash equivalents    
ASSETS    
Other special use fund   25,000
Level 1 | Cash equivalents | Pinnacle West Captive Insurance Cell    
ASSETS    
Other special use fund   25,000
Level 2    
ASSETS    
Cash equivalents 0 0
Nuclear decommissioning trust 506,747 477,186
Other special use fund 0 0
Total assets 616,794 490,338
Level 2 | Commodity contracts    
ASSETS    
Commodity contracts, assets 110,047 13,152
LIABILITIES    
Derivative instruments (1,667) (40,388)
Level 2 | Equity securities    
ASSETS    
Nuclear decommissioning trust 0 542
Other special use fund 0 0
Level 2 | U.S. commingled equity funds    
ASSETS    
Nuclear decommissioning trust 0 0
Level 2 | U.S. Treasury debt    
ASSETS    
Nuclear decommissioning trust 0 0
Other special use fund 0 0
Level 2 | Corporate debt    
ASSETS    
Nuclear decommissioning trust 220,641 203,180
Level 2 | Mortgage-backed securities    
ASSETS    
Nuclear decommissioning trust 224,983 208,533
Level 2 | Municipal bonds    
ASSETS    
Nuclear decommissioning trust 33,817 37,429
Level 2 | Other fixed income    
ASSETS    
Nuclear decommissioning trust 27,306 27,502
Level 2 | Cash equivalents    
ASSETS    
Other special use fund   0
Level 3    
ASSETS    
Cash equivalents 0 0
Nuclear decommissioning trust 0 0
Other special use fund 0 0
Total assets 1,189 7,176
Level 3 | Commodity contracts    
ASSETS    
Commodity contracts, assets 1,189 7,176
LIABILITIES    
Derivative instruments (24,029) (22,215)
Level 3 | Equity securities    
ASSETS    
Nuclear decommissioning trust 0 0
Other special use fund 0 0
Level 3 | U.S. commingled equity funds    
ASSETS    
Nuclear decommissioning trust 0 0
Level 3 | U.S. Treasury debt    
ASSETS    
Nuclear decommissioning trust 0 0
Other special use fund 0 0
Level 3 | Corporate debt    
ASSETS    
Nuclear decommissioning trust 0 0
Level 3 | Mortgage-backed securities    
ASSETS    
Nuclear decommissioning trust 0 0
Level 3 | Municipal bonds    
ASSETS    
Nuclear decommissioning trust 0 0
Level 3 | Other fixed income    
ASSETS    
Nuclear decommissioning trust 0 0
Level 3 | Cash equivalents    
ASSETS    
Other special use fund   0
Fair Value Measured at Net Asset Value Per Share | U.S. commingled equity funds    
ASSETS    
Nuclear decommissioning trust $ 405,263 $ 423,069
v3.25.1
Fair Value Measurements - Significant Unobservable Inputs Used to Value Level 3 Instruments (Details 2)
$ in Thousands
 3 Months Ended 12 Months Ended
Mar. 31, 2025
USD ($)
$ / MWh
$ / MMBTU
Dec. 31, 2024
USD ($)
$ / MMBTU
$ / MWh
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments    
Assets $ 1,810,450 $ 1,707,783
Level 3    
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments    
Assets 1,189 7,176
Level 3 | Forward Contracts | Commodity Contracts    
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments    
Assets 1,189 7,176
Liabilities $ 24,029 $ 22,215
Level 3 | Forward Contracts | Valuation Technique, Discounted Cash Flow | Commodity Contracts | Minimum    
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments    
Electricity forward price (per MWh) | $ / MWh 26.23 25.25
Natural gas forward price (per MMBtu) | $ / MMBTU 1.92 (0.89)
Level 3 | Forward Contracts | Valuation Technique, Discounted Cash Flow | Commodity Contracts | Maximum    
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments    
Electricity forward price (per MWh) | $ / MWh 151.56 151.11
Natural gas forward price (per MMBtu) | $ / MMBTU 0.09 1.47
Level 3 | Forward Contracts | Valuation Technique, Discounted Cash Flow | Commodity Contracts | Weighted Average    
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments    
Electricity forward price (per MWh) | $ / MWh 90.74 106.06
Natural gas forward price (per MMBtu) | $ / MMBTU 0.02 0.71
Level 3 | Forward Contracts | Valuation Technique, Discounted Cash Flow | Electricity: | Commodity Contracts    
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments    
Assets $ 703 $ 708
Liabilities 23,218 21,890
Level 3 | Forward Contracts | Valuation Technique, Discounted Cash Flow | Natural Gas: | Commodity Contracts    
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments    
Assets 486 6,468
Liabilities $ 811 $ 325
v3.25.1
Fair Value Measurements - Fair value for our risk management activities (Details) - Commodity Contracts - Level 3 - USD ($)
$ in Thousands
 3 Months Ended
Mar. 31, 2025
Mar. 31, 2024
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]    
Net derivative balance at beginning of period $ (15,039) $ 4,921
Deferred as a regulatory asset or liability (5,823) (23,600)
Settlements (2,287) 2,708
Transfers into Level 3 from Level 2 (59) 0
Transfers from Level 3 into Level 2 368 0
Net derivative balance at end of period (22,840) (15,971)
Net unrealized gains/losses included in earnings related to instruments still held at end of period $ 0 $ 0
v3.25.1
Investments in Nuclear Decommissioning Trusts and Other Special Use Funds - Additional Information (Details)
$ in Millions
 12 Months Ended
Dec. 31, 2024
USD ($)
APS  
Schedule of Equity Method Investments [Line Items]  
Employee medical claims amount $ 14
v3.25.1
Investments in Nuclear Decommissioning Trusts and Other Special Use Funds (Details) - USD ($)
$ in Thousands
 3 Months Ended
Mar. 31, 2025
Mar. 31, 2024
Dec. 31, 2024
Variable Interest Entity | Pinnacle West Captive Insurance Cell      
Fair value of fixed income securities, summarized by contractual maturities      
Special use fund $ 35,000   $ 34,000
APS      
Nuclear decommissioning trust fund assets      
Fair Value 1,701,502   1,691,202
Total Unrealized Gains 354,982 $ 366,844  
Total Unrealized Losses (22,643) (32,136)  
Amortized cost 1,252,000   1,224,000
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds      
Realized gains 1,658 54,572  
Realized losses (2,761) (2,815)  
Proceeds from the sale of securities 485,814 443,870  
Fair value of fixed income securities, summarized by contractual maturities      
Special use fund     34,200
APS | Nuclear Decommissioning Trusts      
Nuclear decommissioning trust fund assets      
Fair Value 1,286,101   1,282,845
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds      
Realized gains 1,658 54,492  
Realized losses (2,761) (2,815)  
Proceeds from the sale of securities 416,601 377,822  
APS | Other Special Use Funds      
Nuclear decommissioning trust fund assets      
Fair Value 415,401   408,357
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds      
Realized gains 0 80  
Realized losses 0 0  
Proceeds from the sale of securities 69,213 66,048  
APS | Captive Insurance Cell      
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds      
Proceeds from the sale of securities 25,300    
APS | Equity securities      
Nuclear decommissioning trust fund assets      
Equity securities 453,987   460,432
Total Unrealized Gains 341,566 359,127  
Total Unrealized Losses (325) (176)  
APS | Equity securities | Nuclear Decommissioning Trusts      
Nuclear decommissioning trust fund assets      
Equity securities 416,753   435,470
APS | Equity securities | Other Special Use Funds      
Nuclear decommissioning trust fund assets      
Equity securities 37,234   24,962
APS | Available for sale-fixed income securities      
Nuclear decommissioning trust fund assets      
Fair Value 1,242,795   1,199,584
Total Unrealized Gains 13,416 7,717  
Total Unrealized Losses (22,318) (31,960)  
Fair value of fixed income securities, summarized by contractual maturities      
Less than one year 187,202    
1 year – 5 years 497,753    
5 years – 10 years 154,002    
Greater than 10 years 403,838    
Total 1,242,795    
APS | Available for sale-fixed income securities | Nuclear Decommissioning Trusts      
Nuclear decommissioning trust fund assets      
Fair Value 866,658   844,040
Fair value of fixed income securities, summarized by contractual maturities      
Less than one year 32,422    
1 year – 5 years 292,409    
5 years – 10 years 137,989    
Greater than 10 years 403,838    
Total 866,658    
APS | Available for sale-fixed income securities | Other Special Use Funds      
Nuclear decommissioning trust fund assets      
Fair Value 376,137   355,544
APS | Available for sale-fixed income securities | Coal Reclamation Escrow Account      
Fair value of fixed income securities, summarized by contractual maturities      
Less than one year 90,167    
1 year – 5 years 48,289    
5 years – 10 years 0    
Greater than 10 years 0    
Total 138,456    
APS | 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 39,464    
1 year – 5 years 157,055    
5 years – 10 years 16,013    
Greater than 10 years 0    
Total 212,532    
APS | Available for sale-fixed income securities | Captive Insurance Cell      
Fair value of fixed income securities, summarized by contractual maturities      
Less than one year 25,149    
1 year – 5 years 0    
5 years – 10 years 0    
Greater than 10 years 0    
Total 25,149    
APS | Other      
Nuclear decommissioning trust fund assets      
Fair Value 4,720   31,186
Total Unrealized Gains 0 0  
Total Unrealized Losses 0 $ 0  
APS | Other | Nuclear Decommissioning Trusts      
Nuclear decommissioning trust fund assets      
Fair Value 2,690   3,335
APS | Other | Other Special Use Funds      
Nuclear decommissioning trust fund assets      
Fair Value 2,030   $ 27,851
Pinnacle West | Variable Interest Entity | Pinnacle West Captive Insurance Cell      
Fair value of fixed income securities, summarized by contractual maturities      
Special use fund $ 35,100    
v3.25.1
Changes in Accumulated Other Comprehensive Loss (Details) - USD ($)
$ in Thousands
 3 Months Ended
Mar. 31, 2025
Mar. 31, 2024
Changes in accumulated other comprehensive income (loss) by component    
Beginning balance $ 6,857,478 $ 6,284,862
Other comprehensive income (loss) before reclassifications 350 0
Amounts reclassified from accumulated other comprehensive loss 498 562
Ending balance 6,845,982 6,310,533
Accumulated Other Comprehensive Loss    
Changes in accumulated other comprehensive income (loss) by component    
Beginning balance (30,942) (33,144)
Ending balance (30,094) (32,582)
Pension and Other Postretirement Benefits    
Changes in accumulated other comprehensive income (loss) by component    
Beginning balance (31,661) (34,754)
Other comprehensive income (loss) before reclassifications 0 0
Amounts reclassified from accumulated other comprehensive loss 498 562
Ending balance (31,163) (34,192)
Derivative Instruments    
Changes in accumulated other comprehensive income (loss) by component    
Beginning balance 719 1,610
Other comprehensive income (loss) before reclassifications 350 0
Amounts reclassified from accumulated other comprehensive loss 0 0
Ending balance 1,069 1,610
APS    
Changes in accumulated other comprehensive income (loss) by component    
Beginning balance 8,376,332 7,349,136
Ending balance 8,381,322 7,369,047
APS | Accumulated Other Comprehensive Loss    
Changes in accumulated other comprehensive income (loss) by component    
Beginning balance (14,116) (17,219)
Ending balance (13,710) (16,729)
APS | Pension and Other Postretirement Benefits    
Changes in accumulated other comprehensive income (loss) by component    
Beginning balance (14,116) (17,219)
Other comprehensive income (loss) before reclassifications 0 0
Amounts reclassified from accumulated other comprehensive loss 406 490
Ending balance $ (13,710) $ (16,729)
v3.25.1
Leases - Additional information (Details)
$ in Billions
Mar. 31, 2025
USD ($)
lease
Leases [Abstract]  
Number of lease agreements, sell and lease back | lease 3
Term of contract 20 years
Lease not yet commenced | $ $ 14.8
v3.25.1
Leases - Schedule of Lease costs (Details) - USD ($)
$ in Thousands
 3 Months Ended
Mar. 31, 2025
Mar. 31, 2024
Operating Leased Assets [Line Items]    
Total Operating Lease Cost $ 17,884 $ 5,710
Variable Lease Cost 21,370 21,564
Short-term Lease Cost 592 2,800
Operating Lease Cost - Purchased Power and Energy Storage Lease Contracts    
Operating Leased Assets [Line Items]    
Total Operating Lease Cost 12,547 937
Operating Lease Cost - Land, Property, and Other Equipment    
Operating Leased Assets [Line Items]    
Total Operating Lease Cost 5,337 4,773
Total Lease Cost $ 39,846 $ 30,074
v3.25.1
Leases - Schedule of Maturity of our operating lease liabilities (Details)
$ in Thousands
Mar. 31, 2025
USD ($)
Lessee, Lease, Description [Line Items]  
2025 (remaining nine months of 2025) $ 210,555
2026 251,750
2027 275,090
2028 276,218
2029 278,030
2030 278,884
Thereafter 1,908,134
Total lease commitments 3,478,661
Less imputed interest 1,077,239
Total lease liabilities 2,401,422
Operating Lease Cost - Purchased Power and Energy Storage Lease Contracts  
Lessee, Lease, Description [Line Items]  
2025 (remaining nine months of 2025) 197,622
2026 236,859
2027 262,780
2028 266,577
2029 270,514
2030 274,492
Thereafter 1,850,659
Total lease commitments 3,359,503
Less imputed interest 1,036,548
Total lease liabilities 2,322,955
Operating Lease Cost - Land, Property, and Other Equipment  
Lessee, Lease, Description [Line Items]  
2025 (remaining nine months of 2025) 12,933
2026 14,891
2027 12,310
2028 9,641
2029 7,516
2030 4,392
Thereafter 57,475
Total lease commitments 119,158
Less imputed interest 40,691
Total lease liabilities $ 78,467
v3.25.1
Leases - Other additional information related to operating lease liabilities (Details)
$ in Thousands
 3 Months Ended
Mar. 31, 2025
USD ($)
agreement
Mar. 31, 2024
USD ($)
Dec. 31, 2024
Leases [Abstract]      
Cash paid for amounts included in the measurement of lease liabilities — operating cash flows $ 17,207 $ 3,544  
Right-of-use operating lease assets obtained in exchange for operating lease liabilities $ 763,437 $ 6,747  
Weighted average remaining lease term 14 years   11 years
Weighted average discount rate (in percent) 5.17%   4.90%
Number of new energy storage operating lease agreement | agreement 3    
v3.25.1
Sale of Bright Canyon Energy (Details) - USD ($)
$ in Thousands
 3 Months Ended 5 Months Ended 12 Months Ended
Jan. 30, 2024
Mar. 31, 2025
Mar. 31, 2024
Jan. 12, 2024
Dec. 31, 2024
Dec. 31, 2023
Aug. 04, 2023
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]              
Gain on sale relating to BCE   $ 0 $ 22,988        
Bridge Loan | Equity Bridge Loan Facility | Bright Canyon Energy Corporation              
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]              
Debt instrument, face amount             $ 31,000
Term Loan | Non-Recourse Construction Term Loan Facility | Bright Canyon Energy Corporation              
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]              
Debt instrument, face amount             36,000
Discontinued Operations, Disposed of by Sale | Bright Canyon Energy Corporation              
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]              
Assets held-for-sale       $ 35,000      
Consideration received       108,000     $ 44,000
Gain on sale relating to BCE       29,000 $ 23,000 $ 6,000  
Investment tax credits $ 23,000            
Payments to acquire investment tax credits $ 21,000            
Discontinued Operations, Disposed of by Sale | Bright Canyon Energy Corporation | Ameresco, Inc.              
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