PINNACLE WEST CAPITAL CORP, 10-Q filed on 5/4/2026
Quarterly Report
v3.26.1
Cover Page - shares
 3 Months Ended
Mar. 31, 2026
Apr. 28, 2026
Entity Information [Line Items]    
Document Type 10-Q  
Document Quarterly Report true  
Document Period End Date Mar. 31, 2026  
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   121,187,166
Entity Central Index Key 0000764622  
Amendment Flag false  
Current Fiscal Year End Date --12-31  
Document Fiscal Year Focus 2026  
Document Fiscal Period Focus Q1  
APS    
Entity Information [Line Items]    
Document Type 10-Q  
Document Period End Date Mar. 31, 2026  
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  
Current Fiscal Year End Date --12-31  
Document Fiscal Year Focus 2026  
Document Fiscal Period Focus Q1  
v3.26.1
CONDENSED CONSOLIDATED STATEMENTS OF INCOME - USD ($)
shares in Thousands, $ in Thousands
 3 Months Ended
Mar. 31, 2026
Mar. 31, 2025
Income Statement [Abstract]    
OPERATING REVENUES (Note 4) $ 1,149,597 $ 1,032,280
OPERATING EXPENSES    
Fuel and purchased power 436,729 380,071
Operations and maintenance 276,700 300,109
Depreciation and amortization 239,858 234,940
Taxes other than income taxes 61,972 59,354
Other expense 3,164 584
Total 1,018,423 975,058
OPERATING INCOME 131,174 57,222
OTHER INCOME (DEDUCTIONS)    
Allowance for equity funds used during construction 14,782 13,249
Pension and other postretirement non-service credits, net (Note 8) 3,982 2,958
Other income (Note 12) 4,981 17,461
Other expense (Note 12) (2,740) (2,570)
Total 21,005 31,098
INTEREST EXPENSE    
Interest charges 125,759 104,943
Allowance for borrowed funds used during construction (9,863) (10,102)
Total 115,896 94,841
Income (Loss) Before Income Taxes 36,283 (6,521)
Income taxes (benefit) 1,169 (6,183)
NET INCOME (LOSS) 35,114 (338)
Less: Net income attributable to noncontrolling interests (Note 9) 2,194 4,306
Net Income (Loss) Attributable to Common Shareholders $ 32,920 $ (4,644)
Weighted average common shares outstanding — basic (in shares) 121,360 119,594
Weighted-average common shares outstanding — diluted (in shares) 123,778 119,594
Earnings Per Weighted-Average Common Share Outstanding    
Net income (loss) attributable to common shareholders - basic (in dollars per share) $ 0.27 $ (0.04)
Net income (loss) attributable to common shareholders - diluted (in dollars per share) $ 0.27 $ (0.04)
v3.26.1
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($)
$ in Thousands
 3 Months Ended
Mar. 31, 2026
Mar. 31, 2025
Statement of Comprehensive Income [Abstract]    
NET INCOME (LOSS) $ 35,114 $ (338)
OTHER COMPREHENSIVE INCOME, NET OF TAX    
Derivative instruments net unrealized gain (loss), net of tax benefit (expense) of $14, and $— (43) 350
Pension and other postretirement benefit activity, net of tax expense of $(165) and $(164) 502 498
Total other comprehensive income 459 848
COMPREHENSIVE INCOME 35,573 510
Less: Comprehensive income attributable to noncontrolling interests 2,194 4,306
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS $ 33,379 $ (3,796)
v3.26.1
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($)
$ in Thousands
 3 Months Ended
Mar. 31, 2026
Mar. 31, 2025
Statement of Comprehensive Income [Abstract]    
Net unrealized gain (loss), net of tax benefit (expense) $ 14 $ 0
Pension and other postretirement benefit activity, net of tax benefit (expense) $ (165) $ (164)
v3.26.1
CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($)
$ in Thousands
Mar. 31, 2026
Dec. 31, 2025
CURRENT ASSETS    
Cash and cash equivalents $ 6,409 $ 6,604
Customer and other receivables 503,844 579,831
Accrued unbilled revenues (Note 4) 208,583 173,692
Allowance for doubtful accounts (Note 4) (24,626) (25,495)
Materials and supplies (at average cost) 543,198 546,329
Income tax receivable 8,416 5,979
Fossil fuel (at average cost) 19,955 18,824
Assets from risk management activities (Note 10) 388 3,250
Deferred fuel and purchased power regulatory asset (Note 7) 55,432 149,068
Other regulatory assets (Note 7) 141,297 136,941
Other current assets 151,984 108,686
Total current assets 1,614,880 1,703,709
INVESTMENTS AND OTHER ASSETS    
Nuclear decommissioning trusts (Notes 14 and 15) 1,392,817 1,414,166
Other special use funds (Notes 14 and 15) 437,745 434,827
Assets from risk management activities (Note 10) 466 5,137
Other assets 159,288 144,997
Total investments and other assets 1,990,316 1,999,127
PROPERTY, PLANT AND EQUIPMENT    
Plant in service and held for future use 27,616,435 27,370,296
Accumulated depreciation and amortization (9,146,511) (9,012,021)
Net 18,469,924 18,358,275
Construction work in progress 1,888,288 1,649,542
Palo Verde sale leaseback, net of accumulated depreciation (Note 9) 31,641 32,035
Intangible assets, net of accumulated amortization 539,939 575,978
Nuclear fuel, net of accumulated amortization 116,743 104,274
Total property, plant and equipment 21,046,535 20,720,104
DEFERRED DEBITS    
Regulatory assets (Note 7) 1,454,210 1,463,357
Operating lease right-of-use assets (Note 17) 4,060,364 3,649,669
Assets for other postretirement benefits (Note 8) 411,088 399,334
Other 113,234 96,299
Total deferred debits 6,038,896 5,608,659
TOTAL ASSETS 30,690,627 30,031,599
CURRENT LIABILITIES    
Accounts payable 601,648 680,203
Accrued taxes 240,006 186,605
Accrued interest 100,454 105,637
Common dividends payable 0 110,022
Short-term borrowings (Note 6) 594,100 757,005
Current maturities of long-term debt (Note 6) 600,000 600,000
Customer deposits 78,234 63,776
Liabilities from risk management activities (Note 10) 55,918 35,141
Liabilities for asset retirements 57,428 71,698
Operating lease liabilities (Note 17) 136,417 188,586
Regulatory liabilities (Note 7) 117,241 210,909
Other current liabilities 114,274 151,444
Total current liabilities 2,695,720 3,161,026
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 6) 9,801,675 9,205,676
DEFERRED CREDITS AND OTHER    
Liabilities from risk management activities (Note 10) 5,719 1,495
Deferred income taxes 2,479,565 2,470,932
Regulatory liabilities (Note 7) 1,751,277 1,736,121
Liabilities for pension benefits (Note 8) 170,295 167,636
Liabilities for asset retirements 1,229,369 1,198,601
Customer advances 618,106 632,169
Coal mine reclamation 161,686 159,587
Deferred investment tax credit 307,171 308,261
Unrecognized tax benefits 106,924 105,484
Operating lease liabilities (Note 17) 4,011,094 3,548,365
Other 241,058 249,171
Total deferred credits and other 11,082,264 10,577,822
COMMITMENTS AND CONTINGENCIES (Note 11)
EQUITY    
Common stock, no par value; 300,000,000 shares authorized, 121,233,629 and 120,950,839 shares issued at respective dates 3,219,691 3,231,372
Treasury stock at cost; 46,968 and 46,968 shares at respective dates (3,323) (3,323)
Total common stock 3,216,368 3,228,049
Retained earnings 3,883,738 3,850,817
Accumulated other comprehensive loss (Note 16) (31,949) (32,408)
Total shareholder equity 7,068,157 7,046,458
Noncontrolling interests (Note 9) 42,811 40,617
Total equity 7,110,968 7,087,075
TOTAL LIABILITIES AND EQUITY $ 30,690,627 $ 30,031,599
v3.26.1
CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - shares
Mar. 31, 2026
Dec. 31, 2025
EQUITY    
Common stock, authorized (in shares) 300,000,000 300,000,000
Common stock, issued (in shares) 121,233,629 120,950,839
Treasury stock at cost (in shares) 46,968 46,968
v3.26.1
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)
$ in Thousands
 3 Months Ended
Mar. 31, 2026
Mar. 31, 2025
CASH FLOWS FROM OPERATING ACTIVITIES    
Net income (loss) $ 35,114 $ (338)
Adjustments to reconcile net income to net cash provided by operating activities:    
Depreciation and amortization including nuclear fuel 259,841 250,651
Allowance for equity funds used during construction (14,782) (13,249)
Deferred income taxes 3,245 795
Deferred investment tax credit (1,090) 36
Stock compensation 8,252 7,160
Changes in current assets and liabilities:    
Customer and other receivables 79,215 93,800
Accrued unbilled revenues (34,891) 134
Materials, supplies and fossil fuel 2,000 (2,770)
Income tax receivable (2,437) 0
Deferred fuel and purchased power (26,521) (25,228)
Deferred fuel and purchased power amortization 120,157 84,789
Other current assets (23,346) (15,008)
Accounts payable (79,111) 56,010
Accrued taxes 53,401 56,520
Other current liabilities (41,432) (41,391)
Change in long-term regulatory assets 2,611 17,614
Change in long-term regulatory liabilities (58,507) 12,033
Change in other long-term assets (17,201) (45,413)
Change in operating lease assets (5,826) 3,889
Change in other long-term liabilities (27,917) (40,427)
Change in operating lease liabilities 4,521 2,288
Net cash provided by operating activities 235,296 401,895
CASH FLOWS FROM INVESTING ACTIVITIES    
Capital expenditures (628,361) (622,552)
Contributions in aid of construction 90,226 51,244
Allowance for borrowed funds used during construction (9,863) (10,102)
Proceeds from nuclear decommissioning trusts sales and other special use funds 512,234 485,814
Investment in nuclear decommissioning trusts and other special use funds (513,001) (486,385)
Other (2,783) (4,134)
Net cash used for investing activities (551,548) (586,115)
CASH FLOWS FROM FINANCING ACTIVITIES    
Issuance of long-term debt 594,840 0
Short-term borrowings and (repayments), net (162,905) 301,747
Dividends paid on common stock (108,462) (104,934)
Common stock equity issuance and (purchases), net (7,415) (6,381)
Other (1) (3)
Net cash provided by financing activities 316,057 190,429
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (195) 6,209
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 6,604 3,838
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 6,409 $ 10,047
v3.26.1
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, 2024   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)      
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        
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)      
Beginning balance (in shares) at Dec. 31, 2025 120,950,839 120,950,839        
Beginning balance at Dec. 31, 2025 $ 7,087,075 $ 3,231,372 $ (3,323) 3,850,817 (32,408) 40,617
Beginning balance (in shares) at Dec. 31, 2025 (46,968)   (46,968)      
Increase (Decrease) in Shareholders' Equity            
Net income (loss) $ 35,114     32,920   2,194
Other comprehensive income 459       459  
Issuance of common stock (in shares) [2]   282,790        
Issuance of common stock [2] (11,681) $ (11,681)        
Other $ 1     1    
Ending balance (in shares) at Mar. 31, 2026 121,233,629 121,233,629        
Ending balance at Mar. 31, 2026 $ 7,110,968 $ 3,219,691 $ (3,323) $ 3,883,738 $ (31,949) $ 42,811
Ending balance (in shares) at Mar. 31, 2026 (46,968)   (46,968)      
[1]
See Note 13 for information related to our equity forward sale agreements.
[2]
See Note 13 for information related to our equity forward sale agreements.
v3.26.1
ARIZONA PUBLIC SERVICE COMPANY - CONDENSED CONSOLIDATED STATEMENTS OF INCOME - USD ($)
$ in Thousands
 3 Months Ended
Mar. 31, 2026
Mar. 31, 2025
OPERATING REVENUES (Note 4) $ 1,149,597 $ 1,032,280
OPERATING EXPENSES    
Fuel and purchased power 436,729 380,071
Operations and maintenance 276,700 300,109
Depreciation and amortization 239,858 234,940
Taxes other than income taxes 61,972 59,354
Other expense 3,164 584
Total 1,018,423 975,058
OPERATING INCOME 131,174 57,222
OTHER INCOME (DEDUCTIONS)    
Allowance for equity funds used during construction 14,782 13,249
Pension and other postretirement non-service credits, net (Note 8) 3,982 2,958
Other income (Note 12) 4,981 17,461
Other expense (Note 12) (2,740) (2,570)
Total 21,005 31,098
INTEREST EXPENSE    
Interest charges 125,759 104,943
Allowance for borrowed funds used during construction (9,863) (10,102)
Total 115,896 94,841
Income (Loss) Before Income Taxes 36,283 (6,521)
Income taxes (benefit) 1,169 (6,183)
NET INCOME (LOSS) 35,114 (338)
Less: Net income attributable to noncontrolling interests (Note 9) 2,194 4,306
Net Income (Loss) Attributable to Common Shareholders 32,920 (4,644)
APS    
OPERATING REVENUES (Note 4) 1,149,597 1,032,280
OPERATING EXPENSES    
Fuel and purchased power 436,729 380,071
Operations and maintenance 273,315 296,651
Depreciation and amortization 239,842 234,923
Taxes other than income taxes 61,963 59,336
Other expense 3,164 584
Total 1,015,013 971,565
OPERATING INCOME 134,584 60,715
OTHER INCOME (DEDUCTIONS)    
Allowance for equity funds used during construction 14,782 13,249
Pension and other postretirement non-service credits, net (Note 8) 4,205 3,200
Other income (Note 12) 2,645 5,722
Other expense (Note 12) (2,668) (2,333)
Total 18,964 19,838
INTEREST EXPENSE    
Interest charges 101,794 88,771
Allowance for borrowed funds used during construction (9,863) (10,102)
Total 91,931 78,669
Income (Loss) Before Income Taxes 61,617 1,884
Income taxes (benefit) 7,672 (2,701)
NET INCOME (LOSS) 53,945 4,585
Less: Net income attributable to noncontrolling interests (Note 9) 2,194 4,306
Net Income (Loss) Attributable to Common Shareholders $ 51,751 $ 279
v3.26.1
ARIZONA PUBLIC SERVICE COMPANY - CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($)
$ in Thousands
 3 Months Ended
Mar. 31, 2026
Mar. 31, 2025
NET INCOME $ 35,114 $ (338)
OTHER COMPREHENSIVE INCOME, NET OF TAX    
Pension and other postretirement benefits activity, net of tax expense of $(135) and $(133) 502 498
Total other comprehensive income 459 848
COMPREHENSIVE INCOME 35,573 510
Less: Comprehensive income attributable to noncontrolling interests 2,194 4,306
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS 33,379 (3,796)
APS    
NET INCOME 53,945 4,585
OTHER COMPREHENSIVE INCOME, NET OF TAX    
Pension and other postretirement benefits activity, net of tax expense of $(135) and $(133) 410 406
Total other comprehensive income 410 406
COMPREHENSIVE INCOME 54,355 4,991
Less: Comprehensive income attributable to noncontrolling interests 2,194 4,306
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS $ 52,161 $ 685
v3.26.1
ARIZONA PUBLIC SERVICE COMPANY - CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($)
$ in Thousands
 3 Months Ended
Mar. 31, 2026
Mar. 31, 2025
Pension and other postretirement benefits activity, net of tax benefit (expense) $ (165) $ (164)
APS    
Pension and other postretirement benefits activity, net of tax benefit (expense) $ (135) $ (133)
v3.26.1
ARIZONA PUBLIC SERVICE COMPANY - CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($)
$ in Thousands
Mar. 31, 2026
Dec. 31, 2025
CURRENT ASSETS    
Cash and cash equivalents $ 6,409 $ 6,604
Customer and other receivables 503,844 579,831
Accrued unbilled revenues (Note 4) 208,583 173,692
Allowance for doubtful accounts (Note 4) (24,626) (25,495)
Materials and supplies (at average cost) 543,198 546,329
Fossil fuel (at average cost) 19,955 18,824
Assets from risk management activities (Note 10) 388 3,250
Deferred fuel and purchased power regulatory asset (Note 7) 55,432 149,068
Other regulatory assets (Note 7) 141,297 136,941
Other current assets 151,984 108,686
Total current assets 1,614,880 1,703,709
INVESTMENTS AND OTHER ASSETS    
Nuclear decommissioning trusts (Notes 14 and 15) 1,392,817 1,414,166
Other special use funds (Notes 14 and 15) 437,745 434,827
Assets from risk management activities (Note 10) 466 5,137
Other assets 159,288 144,997
Total investments and other assets 1,990,316 1,999,127
PROPERTY, PLANT AND EQUIPMENT    
Plant in service and held for future use 27,616,435 27,370,296
Accumulated depreciation and amortization (9,146,511) (9,012,021)
Net 18,469,924 18,358,275
Construction work in progress 1,888,288 1,649,542
Palo Verde sale leaseback, net of accumulated depreciation (Note 9) 31,641 32,035
Intangible assets, net of accumulated amortization 539,939 575,978
Nuclear fuel, net of accumulated amortization 116,743 104,274
Total property, plant and equipment 21,046,535 20,720,104
DEFERRED DEBITS    
Regulatory assets (Note 7) 1,454,210 1,463,357
Operating lease right-of-use assets (Note 17) 4,060,364 3,649,669
Assets for other postretirement benefits (Note 8) 411,088 399,334
Other 113,234 96,299
Total deferred debits 6,038,896 5,608,659
TOTAL ASSETS 30,690,627 30,031,599
CURRENT LIABILITIES    
Accounts payable 601,648 680,203
Accrued taxes 240,006 186,605
Accrued interest 100,454 105,637
Common dividends payable 0 110,022
Short-term borrowings (Note 6) 594,100 757,005
Current maturities of long-term debt (Note 6) 600,000 600,000
Customer deposits 78,234 63,776
Liabilities from risk management activities (Note 10) 55,918 35,141
Liabilities for asset retirements 57,428 71,698
Operating lease liabilities (Note 17) 136,417 188,586
Regulatory liabilities (Note 7) 117,241 210,909
Other current liabilities 114,274 151,444
Total current liabilities 2,695,720 3,161,026
DEFERRED CREDITS AND OTHER    
Liabilities from risk management activities (Note 10) 5,719 1,495
Deferred income taxes 2,479,565 2,470,932
Regulatory liabilities (Note 7) 1,751,277 1,736,121
Liabilities for pension benefits (Note 8) 170,295 167,636
Liabilities for asset retirements 1,229,369 1,198,601
Customer advances 618,106 632,169
Coal mine reclamation 161,686 159,587
Deferred investment tax credit 307,171 308,261
Unrecognized tax benefits 106,924 105,484
Operating lease liabilities (Note 17) 4,011,094 3,548,365
Other 241,058 249,171
Total deferred credits and other 11,082,264 10,577,822
COMMITMENTS AND CONTINGENCIES (Note 11)
CAPITALIZATION    
Retained earnings 3,883,738 3,850,817
Accumulated other comprehensive loss (Note 16) (31,949) (32,408)
Total shareholder equity 7,068,157 7,046,458
Noncontrolling interests (Note 9) 42,811 40,617
Total equity 7,110,968 7,087,075
Long-term debt less current maturities (Note 6) 9,801,675 9,205,676
TOTAL LIABILITIES AND EQUITY 30,690,627 30,031,599
APS    
CURRENT ASSETS    
Cash and cash equivalents 3,841 4,143
Customer and other receivables 502,612 592,146
Accrued unbilled revenues (Note 4) 208,583 173,692
Allowance for doubtful accounts (Note 4) (24,626) (25,495)
Materials and supplies (at average cost) 543,198 546,329
Fossil fuel (at average cost) 19,955 18,824
Assets from risk management activities (Note 10) 388 3,250
Deferred fuel and purchased power regulatory asset (Note 7) 55,432 149,068
Other regulatory assets (Note 7) 141,297 136,941
Other current assets 151,127 102,820
Total current assets 1,601,807 1,701,718
INVESTMENTS AND OTHER ASSETS    
Nuclear decommissioning trusts (Notes 14 and 15) 1,392,817 1,414,166
Other special use funds (Notes 14 and 15) 396,341 394,514
Assets from risk management activities (Note 10) 466 5,137
Other assets 56,631 50,912
Total investments and other assets 1,846,255 1,864,729
PROPERTY, PLANT AND EQUIPMENT    
Plant in service and held for future use 27,615,553 27,369,414
Accumulated depreciation and amortization (9,145,629) (9,011,139)
Net 18,469,924 18,358,275
Construction work in progress 1,888,288 1,649,542
Palo Verde sale leaseback, net of accumulated depreciation (Note 9) 31,641 32,035
Intangible assets, net of accumulated amortization 539,784 575,823
Nuclear fuel, net of accumulated amortization 116,743 104,274
Total property, plant and equipment 21,046,380 20,719,949
DEFERRED DEBITS    
Regulatory assets (Note 7) 1,454,210 1,463,357
Operating lease right-of-use assets (Note 17) 4,059,386 3,648,658
Assets for other postretirement benefits (Note 8) 404,031 392,348
Other 112,374 95,600
Total deferred debits 6,030,001 5,599,963
TOTAL ASSETS 30,524,443 29,886,359
CURRENT LIABILITIES    
Accounts payable 594,372 672,518
Accrued taxes 238,145 176,968
Accrued interest 76,898 98,434
Common dividends payable 0 110,000
Short-term borrowings (Note 6) 316,000 507,305
Current maturities of long-term debt (Note 6) 250,000 250,000
Customer deposits 78,234 63,776
Liabilities from risk management activities (Note 10) 55,918 35,141
Liabilities for asset retirements 57,428 71,698
Operating lease liabilities (Note 17) 136,264 188,437
Regulatory liabilities (Note 7) 117,241 210,909
Other current liabilities 105,747 159,039
Total current liabilities 2,026,247 2,544,225
DEFERRED CREDITS AND OTHER    
Liabilities from risk management activities (Note 10) 5,719 1,495
Deferred income taxes 2,437,541 2,427,765
Regulatory liabilities (Note 7) 1,751,277 1,736,121
Liabilities for pension benefits (Note 8) 168,133 164,892
Liabilities for asset retirements 1,229,369 1,198,601
Customer advances 618,106 632,169
Coal mine reclamation 161,686 159,587
Deferred investment tax credit 307,171 308,261
Unrecognized tax benefits 122,506 121,066
Operating lease liabilities (Note 17) 4,010,089 3,547,321
Other 225,231 232,661
Total deferred credits and other 11,036,828 10,529,939
COMMITMENTS AND CONTINGENCIES (Note 11)
CAPITALIZATION    
Common stock 178,162 178,162
Additional paid-in capital 4,491,696 4,491,696
Retained earnings 4,278,990 4,227,237
Accumulated other comprehensive loss (Note 16) (15,047) (15,457)
Total shareholder equity 8,933,801 8,881,638
Noncontrolling interests (Note 9) 42,811 40,617
Total equity 8,976,612 8,922,255
Long-term debt less current maturities (Note 6) 8,484,756 7,889,940
Total capitalization 17,461,368 16,812,195
TOTAL LIABILITIES AND EQUITY $ 30,524,443 $ 29,886,359
v3.26.1
ARIZONA PUBLIC SERVICE COMPANY - CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)
$ in Thousands
 3 Months Ended
Mar. 31, 2026
Mar. 31, 2025
CASH FLOWS FROM OPERATING ACTIVITIES    
Net income (loss) $ 35,114 $ (338)
Adjustments to reconcile net income to net cash provided by operating activities:    
Depreciation and amortization including nuclear fuel 259,841 250,651
Allowance for equity funds used during construction (14,782) (13,249)
Deferred income taxes 3,245 795
Deferred investment tax credit (1,090) 36
Changes in current assets and liabilities:    
Customer and other receivables 79,215 93,800
Accrued unbilled revenues (34,891) 134
Materials, supplies and fossil fuel 2,000 (2,770)
Deferred fuel and purchased power (26,521) (25,228)
Deferred fuel and purchased power amortization 120,157 84,789
Income tax receivable (2,437) 0
Other current assets (23,346) (15,008)
Accounts payable (79,111) 56,010
Accrued taxes 53,401 56,520
Other current liabilities (41,432) (41,391)
Change in long-term regulatory assets 2,611 17,614
Change in long-term regulatory liabilities (58,507) 12,033
Change in other long-term assets (17,201) (45,413)
Change in operating lease assets (5,826) 3,889
Change in other long-term liabilities (27,917) (40,427)
Change in operating lease liabilities 4,521 2,288
Net cash provided by operating activities 235,296 401,895
CASH FLOWS FROM INVESTING ACTIVITIES    
Capital expenditures (628,361) (622,552)
Contributions in aid of construction 90,226 51,244
Allowance for borrowed funds used during construction (9,863) (10,102)
Proceeds from nuclear decommissioning trusts sales and other special use funds 512,234 485,814
Investment in nuclear decommissioning trusts and other special use funds (513,001) (486,385)
Other (2,783) (4,134)
Net cash used for investing activities (551,548) (586,115)
CASH FLOWS FROM FINANCING ACTIVITIES    
Issuance of long-term debt 594,840 0
Short-term borrowings and (repayments), net (162,905) 301,747
Dividends paid on common stock (108,462) (104,934)
Net cash provided by financing activities 316,057 190,429
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (195) 6,209
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 6,604 3,838
CASH AND CASH EQUIVALENTS AT END OF PERIOD 6,409 10,047
APS    
CASH FLOWS FROM OPERATING ACTIVITIES    
Net income (loss) 53,945 4,585
Adjustments to reconcile net income to net cash provided by operating activities:    
Depreciation and amortization including nuclear fuel 259,825 250,634
Allowance for equity funds used during construction (14,782) (13,249)
Deferred income taxes 4,405 (123)
Deferred investment tax credit (1,090) 36
Changes in current assets and liabilities:    
Customer and other receivables 92,762 94,051
Accrued unbilled revenues (34,891) 134
Materials, supplies and fossil fuel 2,000 (2,770)
Deferred fuel and purchased power (26,521) (25,228)
Deferred fuel and purchased power amortization 120,157 84,789
Income tax receivable 0 5,421
Other current assets (28,355) (15,028)
Accounts payable (78,702) 52,351
Accrued taxes 61,177 56,040
Other current liabilities (73,911) (61,892)
Change in long-term regulatory assets 2,611 17,614
Change in long-term regulatory liabilities (58,507) 12,033
Change in other long-term assets (11,333) (30,585)
Change in operating lease assets (5,859) 3,858
Change in other long-term liabilities (13,882) (26,322)
Change in operating lease liabilities 4,560 2,325
Net cash provided by operating activities 253,609 408,674
CASH FLOWS FROM INVESTING ACTIVITIES    
Capital expenditures (628,361) (622,552)
Contributions in aid of construction 90,226 51,244
Allowance for borrowed funds used during construction (9,863) (10,102)
Proceeds from nuclear decommissioning trusts sales and other special use funds 512,234 460,538
Investment in nuclear decommissioning trusts and other special use funds (512,804) (461,109)
Other 1,122 (1,467)
Net cash used for investing activities (547,446) (583,448)
CASH FLOWS FROM FINANCING ACTIVITIES    
Issuance of long-term debt 594,840 0
Short-term borrowings and (repayments), net (191,305) 286,700
Dividends paid on common stock (110,000) (107,200)
Net cash provided by financing activities 293,535 179,500
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (302) 4,726
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 4,143 3,815
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 3,841 $ 8,541
v3.26.1
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, 2024   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         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
Beginning balance (in shares) at Dec. 31, 2025 120,950,839 120,950,839         71,264,947        
Beginning balance at Dec. 31, 2025 $ 7,087,075 $ 3,231,372 3,850,817 (32,408) 40,617 8,922,255 $ 178,162 4,491,696 4,227,237 (15,457) 40,617
Increase (Decrease) in Shareholders' Equity                      
Net income (loss) 35,114   32,920   2,194 53,945     51,751   2,194
Other comprehensive income 459     459   410       410  
Other $ 1   1     2     2    
Ending balance (in shares) at Mar. 31, 2026 121,233,629 121,233,629         71,264,947        
Ending balance at Mar. 31, 2026 $ 7,110,968 $ 3,219,691 $ 3,883,738 $ (31,949) $ 42,811 $ 8,976,612 $ 178,162 $ 4,491,696 $ 4,278,990 $ (15,047) $ 42,811
v3.26.1
Consolidation and Nature of Operations
 3 Months Ended
Mar. 31, 2026
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, and 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 VIE related to the Captive. The unaudited Condensed Consolidated Financial Statements for APS include the accounts of APS and the Palo Verde VIEs. In September 2025, APS purchased two of the three leased interests, resulting in the termination of the related lease agreements and discontinuation of VIE consolidation for those leases. As of March 31, 2026, one Palo Verde VIE lease arrangement remains active. See Note 9 for further discussion on Pinnacle West’s VIEs and APS’s remaining VIE. 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. Our accounting records are maintained in accordance with GAAP. The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Amounts reported in our 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 2025 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,
20262025
Cash paid (received) during the period for:
Income taxes, net of refunds/credits$(4)$(10,799)
Interest, net of amounts capitalized118,552 91,475 
Significant non-cash investing and financing activities:
Accrued capital expenditures281,689 315,297 
The following table summarizes supplemental APS cash flow information (dollars in thousands):
Three Months Ended March 31,
20262025
Cash paid (received) during the period for:
Income taxes, net of refunds/credits$101 $(5,392)
Interest, net of amounts capitalized112,181 84,110 
Significant non-cash investing and financing activities:
Accrued capital expenditures281,689 315,297 
v3.26.1
Business Segments
 3 Months Ended
Mar. 31, 2026
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 (loss), 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 (loss) to the Pinnacle West consolidated amounts (dollars in millions):
Three Months Ended March 31,
20262025
Regulated Electricity SegmentOther Pinnacle West ConsolidatedRegulated Electricity SegmentOther Pinnacle West Consolidated
Operating revenues$1,150 $— $1,150 $1,032 $— $1,032 
Fuel and purchased power (437)— (437)(380)— (380)
Operations and maintenance(273)(4)(277)(297)(3)(300)
Depreciation and amortization (240)— (240)(235)— (235)
Taxes other than income taxes (62)— (62)(59)— (59)
Allowance for equity funds used during construction15 — 15 13 — 13 
Pension and other postretirement non-service credits, net4 — 4 3 — 3 
Other income and (expense), net(3)2 (1)3 11 14 
Interest charges, net of allowance for borrowed funds used during construction(92)(24)(116)(79)(16)(95)
Income (taxes) benefit
(8)7 (1)3 3 6 
Less: Net income attributable to noncontrolling interests(2)— (2)(4)— (4)
Net Income (Loss) Attributable to Common Shareholders
$52 $(19)$33 $— $(5)$(5)
The following table reconciles our reportable segment’s assets to the Pinnacle West consolidated amount (dollars in millions):
March 31, 2026December 31, 2025
Regulated Electricity SegmentOtherPinnacle West ConsolidatedRegulated Electricity SegmentOtherPinnacle West Consolidated
Total Assets$30,524 $167 $30,691 $29,886 $146 $30,032 
v3.26.1
New Accounting Standards
 3 Months Ended
Mar. 31, 2026
Accounting Standards Update and Change in Accounting Principle [Abstract]  
New Accounting Standards New Accounting Standards
 
ASU 2024-03, Income Statement Reporting: 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 Consolidated 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. We are currently evaluating the transition method and date of adoption we will elect for this new standard.

ASU 2025-06, Intangibles—Goodwill and Other—Internal-Use Software: Targeted Improvements to the Accounting for Internal-Use Software

In September 2025, a new accounting standard was issued that modernizes the accounting for internal-use software costs by removing references to prescriptive and sequential development stages of a project and replacing them with new criteria used in determining when to start capitalizing software costs. Under the new guidance, capitalization begins when management authorizes and commits to funding the software project and it is probable the project will be completed and used as intended. When determining
if a project is probable of being completed, entities must evaluate whether significant development uncertainty exists, such as unresolved technological innovations or unproven features. The new guidance also clarifies that capitalized internal-use software costs are subject to the existing property, plant, and equipment disclosure requirements.

The standard will become effective for us on January 1, 2028, with early adoption permitted. Entities may adopt the standard using one of the following transition methods: a prospective approach, a retrospective approach, or a modified transition approach that considers in-process projects at the date of adoption. We are currently evaluating the impacts on our financial statements of adopting this new standard and the transition method and date of adoption we will elect. The adoption of this guidance may impact our timing and scope of software costs eligible for capitalization, and may also impact our disclosures relating to software.

ASU 2025-09, Derivatives and Hedging: Hedge Accounting Improvements

In November 2025, a new accounting standard was issued which clarifies certain aspects of the hedge accounting guidance. The new standard is intended to better align hedge accounting with the economics of an entity’s risk management activities, and provides entities the ability to apply hedge accounting to an expanded population of economic hedges of forecasted transactions. The standard will become effective for us on January 1, 2027, applied on a prospective basis. Early adoption is permitted. We expect to adopt this guidance on January 1, 2027. We are not currently applying hedge accounting, and do not expect the adoption of this guidance will have a material impact on our financial statements.

ASU 2025-10, Government Grants: Accounting for Government Grants Received by Business Entities

In December 2025, a new accounting standard was issued establishing authoritative GAAP guidance on the accounting for government grants received by business entities. Prior to the issuance of this new standard, GAAP did not include guidance relating to government grants received by business entities. The new standard is intended to eliminate diversity in practice and improve the financial reporting and consistency across business entities for government grants. The new standard defines government grants and includes recognition, measurement, presentation, and disclosure requirements. The new standard includes guidance pertaining to both government grants received relating to an asset and government grants received relating to income. The guidance includes recognition thresholds based on the probability of compliance with grant conditions and receipt of the grant, among other accounting requirements. Disclosure requirements include the nature and amounts of government grants received, the conditions attached to the grants, and accounting policies applied.
The new standard will become effective for us on January 1, 2029, with early adoption permitted. Entities may adopt the standard using various transition methods, including a modified prospective approach, a modified retrospective approach, or a retrospective approach to all government grants. We are currently evaluating the impacts on our financial statements of adopting this new standard, as well as the date we will adopt this guidance and the transition method we will elect.
v3.26.1
Revenue
 3 Months Ended
Mar. 31, 2026
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,
20262025
Retail Electric Service
Residential$493,701 $448,923 
Non-Residential601,733 524,857 
Wholesale Energy Sales14,976 24,824 
Transmission Services for Others32,027 25,547 
Other Sources7,160 8,129 
Total Operating Revenues$1,149,597 $1,032,280 

Retail Electric Service

All of Pinnacle West’s retail electric revenues are generated by APS. Retail electric revenue is generated by the sale of electricity to our customers within the regulated 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. In addition, see the section titled “2025 Rate Case” in Note 7 for details related to proposed adjustments to rate design and modifications of cost allocation methodologies to reduce cross-subsidization by ensuring customers causing increased production costs are covering those costs through rates.

Wholesale Energy Sales and Transmission Services for Others

All of Pinnacle West’s revenues from wholesale energy sales and transmission services for others are generated by APS and represent energy and transmission sales to wholesale customers. These activities consist of managing fuel and purchased power risks and transmission needs in connection with the cost of serving our retail customers’ energy requirements. We may also sell into the wholesale markets generation that is not needed for APS’s retail load. Our wholesale activities and tariff rates are regulated by FERC.
In the electricity business, some contracts to purchase energy are settled by netting against other contracts to sell electricity. This is referred to as a book-out, and usually occurs in contracts that have the same terms (product type, quantities, and delivery points) and for which power does not flow. We net these book-outs, which reduces both wholesale revenues and fuel and purchased power costs.
Revenue Activities

Our revenues primarily consist of activities that are classified as revenues from contracts with customers. We derive our revenues from contracts with customers primarily from sales of electricity to our retail customers within our regulated service area. Revenues from contracts with customers also include wholesale and transmission activities. Our revenues from contracts with customers for the three months ended March 31, 2026 and 2025 were $1,124 million and $1,019 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, 2026 and 2025 our revenues that do not qualify as revenue from contracts with customers were $26 million and $13 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 7 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):
Three Months EndedYear Ended
March 31, 2026December 31, 2025
Balance at beginning of period$25,495 $24,849 
Bad debt expense5,728 28,603 
Actual write-offs(6,597)(27,957)
Balance at end of period$24,626 $25,495 
v3.26.1
Income Taxes
 3 Months Ended
Mar. 31, 2026
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 (“Nuclear PTC”) was enacted, available from 2024 through 2032. The Nuclear PTC can be increased by five times if certain IRS prevailing wages rules are met. The Company continues to await guidance from the U.S. Treasury Department related to the definition of “gross receipts” from nuclear sales for purposes of the credit phase-out applicable to the Nuclear PTC.
The Company has claimed a $33.4 million benefit for the Nuclear PTC on its 2024 tax return using a revenue requirement methodology to determine its gross receipts from nuclear sales. In the continued absence of IRS guidance regarding the definition of gross receipts from nuclear sales, management intends to utilize this same methodology to claim a 2025 credit of $39.6 million. These benefits include the five times multiplier for complying with IRS prevailing wage rules. However, due to the continued lack of IRS guidance, management believes that there remains uncertainty as to whether the IRS will ultimately agree with the Company’s gross receipts methodology. As a result, the entire amount of the 2024 and 2025 benefits is recorded as uncertain tax positions. Additionally, the Company continues to evaluate whether it will be eligible to claim a 2026 tax credit. As of March 31, 2026, the Company continues to not recognize any income tax benefits related to the Nuclear PTC.

In March 2026, the IRS notified the Company of its intent to examine the Company's federal tax returns. We anticipate that the exam will focus primarily on 2023 general business tax credits that the Company carried back to tax year 2022, however, the IRS has not yet finalized the scope of its exam, and the final scope may cover subsequent tax years as well. As such, we are unable at this time to predict the outcome of this matter and whether it will have a material impact on our financial position, results of operations, or cash flows.
v3.26.1
Debt and Liquidity Matters
 3 Months Ended
Mar. 31, 2026
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, 2026, Pinnacle West had a $300 million revolving credit facility that matures on February 18, 2031. Pinnacle West has the option to increase the amount of the facility by $100 million to a total of $400 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. The facility is available to support Pinnacle West’s general corporate purposes, including support for Pinnacle West’s $300 million commercial paper program, bank borrowings, and issuances of letters of credit. As of March 31, 2026, Pinnacle West had no outstanding borrowings under its revolving credit facility, no letters of credit outstanding under its credit facility, and $103 million of outstanding commercial paper borrowings. The weighted-average interest rate for the outstanding borrowings on March 31, 2026 was 3.93%.

Pinnacle West has an outstanding 364-day $175 million term loan facility that matures on December 3, 2026. Borrowings under the facility bear interest at SOFR plus 0.80% per annum. On December 3, 2025, Pinnacle West drew the full amount of $175 million.
APS

As of March 31, 2026, APS had a $1.7 billion revolving credit facility that matures on February 18, 2031. APS has the option to increase the amount of the facility by $400 million to a total of $2.1 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. The facility is available to support APS’s general corporate purposes, including support for APS’s $1.5 billion commercial paper program, bank borrowings, and issuances of letters of credit. As of March 31, 2026, APS had no outstanding borrowings under its
revolving credit facility, no letters of credit outstanding under the credit facility, and $316 million of outstanding commercial paper borrowings. The weighted-average interest rate for the outstanding borrowings on March 31, 2026 was 3.96%.

On March 10, 2026, APS issued $600 million of 5.10% senior unsecured notes that mature March 15, 2036. The net proceeds from the issuances were used to repay short-term indebtedness consisting of commercial paper and for general corporate purposes.
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 11 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, 2026As of December 31, 2025
 Carrying
Amount		Fair ValueCarrying
Amount		Fair Value
Pinnacle West$1,666,919 $1,756,235 $1,665,736 $1,731,388 
APS8,734,756 7,874,786 8,139,940 7,433,142 
Total$10,401,675 $9,631,021 $9,805,676 $9,164,530 
v3.26.1
Regulatory Matters
 3 Months Ended
Mar. 31, 2026
Regulated Operations [Abstract]  
Regulatory Matters Regulatory Matters
ACC General Retail Rate Cases

2025 Rate Case

On June 13, 2025, APS filed an application with the ACC (the “2025 Rate Case”) seeking a net base rate increase of $579.5 million, which represents a 13.99% net increase. The requested net increase addresses a total base revenue deficiency of $662.4 million, offset by proposed adjustor transfers of cost recovery to base rates.

The 2025 Rate Case application includes the following proposals:

•a test year comprised of the 12-month period ended on December 31, 2024, including certain pro forma adjustments;
•12 months of post-test year plant placed into service from January 1, 2025 through December 31, 2025;
•an original cost rate base of $12.5 billion, which approximates the ACC-jurisdictional portion of the book value of utility assets, net of accumulated depreciation and other credits;
•the following proposed capital structure and costs of capital:
Capital StructureCost of Capital
Long-term debt47.65 %4.26 %
Common stock equity52.35 %10.70 %
Weighted-average cost of capital7.63 %
•a 1% return on the increment of fair value rate base above APS’s original cost rate base, as provided for by Arizona law;
•a rate of $0.043881 per kWh for the portion of APS’s base rates attributable to fuel and purchased power costs;
•adjustments to rate designs, including direct assignment of costs, to reduce cross-subsidization by certain customer classes;
•modification of cost allocation methodologies based on customer growth to ensure customers causing new production costs are covering those costs through rates, along with corresponding changes to adjustor mechanisms, such as for fuel and purchased power;
•implementation of a FRAM to assist with reducing regulatory lag and allow for rate gradualism;
•elimination of the LFCR following the first annual adjustment pursuant to the FRAM; and
•modification to the SRB due to the FRAM proposal.

On March 2 and March 18, 2026, the ACC Staff, Residential Utility Consumer Office (“RUCO”), and other intervenors filed their initial written testimony with the ACC. ACC Staff’s testimony includes the following recommendations, among others, depending on the approval of APS’s proposed FRAM, (i) a $525.2 million total base revenue increase, (ii) a 9.55% to 9.80% return on equity, (iii) a 0.20% return on the increment of fair value, and (iv) 12-months of post-test year plant. RUCO’s testimony includes the following recommendations, among others, depending on the approval of APS’s proposed FRAM, (i) a $200.2 to $278.1 million total base revenue increase, (ii) a 9.00% to 9.20% return on equity, (iii) a 0.0% return on the increment of fair value, and (iv) 0 to 12-months of post-test year plant.

On April 3, 2026 , APS filed rebuttal testimony addressing the ACC Staff and intervenors’ direct testimonies. The principal provisions of APS’s rebuttal testimony are as follows:

•a total revenue requirement increase of $694.2 million, or a net revenue requirement increase of $611.3 million after adjustor transfers;
•maintaining a return on equity request of 10.7%;
•reducing the return on the increment of fair value from 1.0% to 0.9%;
•maintaining a post-test year plant request of 12 months and updating the impacted projects, including Ironwood solar and Sundance; and
•an integrated set of FRAM modifications that are intended to be evaluated together:
◦allowing for an earnings test “deadband” range of +/- 40 basis points to APS’s authorized return before an adjustment to the FRAM would be required;
◦limiting projected plant to six months;
◦elimination of the SRB and TEAM following the first annual adjustment pursuant to the FRAM;
◦retention of the 120-day review and challenge period; and
◦elimination of the interim rate reset by accepting Commission approval prior to implementation (subject to an automatic reversion provision).
On May 1, 2026, ACC Staff, RUCO, and other intervenors filed their surrebuttal testimonies with the ACC, which are publicly available on the ACC’s eDocket website. APS is currently evaluating the surrebuttal testimony and plans to file its rejoinder testimony on May 11, 2026.

APS requested that the increase become effective in the second half of 2026. The hearing for this rate case is currently scheduled to begin in May 2026. APS cannot predict the outcome of its request nor when the 2025 Rate Case will be decided by the ACC.

2022 Rate Case

On October 28, 2022, APS filed an application with the ACC (the “2022 Rate Case”) for an increase in retail base rates, and on January 25, 2024, an Administrative Law Judge issued a ROO, as corrected on February 6, 2024 (the “2022 Rate Case ROO”).

On February 22, 2024, the ACC approved the 2022 Rate Case ROO with certain amendments 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 ASRFP, and (viii) recovery of all DSM costs through the DSM Adjustment Charge (“DSMAC”) rather than through base rates.

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 Coal Community Transition 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 ACC’s December 17, 2024 decision on the rehearing. The ACC has taken no action on these requests. In addition, each of these parties has subsequently filed an appeal to the Arizona Court of Appeals seeking review of the ACC’s decisions regarding the GAC and on rehearing. On February 25, 2026, parties provided oral arguments before the Court of Appeals. APS cannot predict the outcome of these proceedings.
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, RUCO, the Arizona Large Customer Group (“ALCG”), and an individual customer filed a lawsuit challenging the ACC’s authority to issue the formula rate policy statement outside of Arizona’s formula rulemaking process. On June 13, 2025, the lawsuit challenging the ACC’s formula rate policy was dismissed by the Superior Court of Maricopa County. Following the dismissal, the plaintiffs filed an appeal with the Arizona Court of Appeals as well as a Petition for Special Action with the Arizona Supreme Court. The Supreme Court declined to exercise jurisdiction on the Petition for Special Action. The plaintiffs also filed a Petition for Special Action with the Arizona Court of Appeals, which has accepted jurisdiction to determine whether the case should be remanded back to the Superior Court for expedited consideration of the merits. On November 21, 2025, the Arizona Court of Appeals ruled that the issue should be remanded back to the Superior Court to determine whether the ACC’s formula rate policy must go through a formal rulemaking process. In response, APS, the ACC, and several other Arizona utility companies filed petitions for review of the Court of Appeals decision with the Arizona Supreme Court, which is pending at this time. 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 Rate Case” above for modifications of adjustment mechanisms in the 2022 Rate Case and “2025 Rate Case” above for proposed modifications to adjustment mechanisms in the 2025 Rate Case.
 
Renewable Energy Standard

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, excluding any funding offsets. On July 1, 2024, APS filed its 2025 RES Implementation Plan and proposed a budget of approximately $92.7 million. On July 1, 2025, APS filed its 2026 RES Implementation Plan and proposed a budget of approximately $110.1 million, excluding any funding offsets. 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 2025. The proposed plan also notifies the ACC that continued evaluation and approval of the pending 2024 and 2025 RES Implementation Plans is no longer necessary. On February 4, 2026, the ACC approved APS’s 2026 RES Implementation Plan.

On April 22, 2025, the ACC approved APS’s request to refund uncommitted DSMAC and RES surcharge funds of approximately $9 million and $43 million, respectively, with final amounts subject to adjustment dependent upon billed usage. Refunds were issued during July and August of 2025 totaling $7.6 million for DSMAC and $44.2 million for RES.

As discussed below in “Energy Modernization Plan,” on August 14, 2025, the ACC voted to send a full repeal of the RES rules to the Secretary of State for publication. See below for more information.

APS has a Green Power Partners Program that allows customers to pay a specified price to receive a contracted amount of green power in addition to their normal rate in order to support those customers in meeting their individual sustainability goals. On June 28, 2024, APS filed an application for approval of modifications to the Green Power Partners Program and requested a renewable energy credit waiver. On February 4, 2026, the ACC approved APS’s proposed changes to the Green Power Partners Program, including modifications to pricing structures for participating customers.

Demand Side Management Adjustor Charge

The ACC Electric Energy Efficiency Standards require APS to submit a DSM Implementation Plan at least every odd year 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 November 30, 2022 and May 31 2023, APS filed its 2023 DSM Implementation Plan, which requested a budget of $88 million, and an amended 2023 DSM Implementation Plan, respectively. 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 Implementation Plan. On April 26, 2024 and June 20, 2025, APS filed amendments to the 2024 DSM Implementation Plan. The Second Amended 2024 DSM Implementation Plan, compared to the initially filed plan, supported an updated budget of $90.9 million, which reflected (i) removal of incentive funds for the Level 2 Smart Charger rebate within the EV Charging Demand Management Pilot, (ii) exclusion of the proposed tranches two and three of the Residential Battery Pilot, and inclusion of the newly approved Bring-Your-Own-Device Battery (“BYOD”) Pilot described below, and (iii) an update on the performance incentive calculation. On May 16, 2025, APS filed a request with the ACC to extend the deadline to file its 2026 DSM Implementation Plan until 120 days after the ACC acts on its Second Amended 2024 DSM Implementation
Plan. On July 9, 2025, the ACC approved APS’s extension request. On December 3, 2025, the ACC voted to reduce the budget of the DSM program to $40 million and discontinue several programs and customer rebates while promoting the expansion of Virtual Power Plant programs. On April 7, 2026, APS filed an updated DSM and Transportation Electrification Plan consistent with recent ACC orders.

On August 30, 2024, APS filed an application for a new 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.

As discussed above under “Renewable Energy Standard,” APS refunded uncommitted DSMAC funds during July and August 2025 totaling $7.6 million for DSMAC.

As discussed below in “Energy Modernization Plan,” on September 17, 2025, the ACC voted to send a full repeal of the EES rules to the Secretary of State for publication. See below for more information.

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 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,
 20262025
Balance at beginning of period$149,068 $287,597 
Deferred fuel and purchased power costs26,521 25,228 
Amounts charged to customers
(120,157)(84,789)
Balance at end of period$55,432 $228,036 

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 per kWh. 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.

On November 26, 2025, APS filed its PSA rate for the PSA year beginning February 1, 2026. The overall PSA rate of $0.016977 per kWh consists of a forward component of $0.012457 per kWh, a historical component of $0.00452 per kWh, and no transition component. This overall PSA rate is an increase of $0.003 per kWh over the prior approved rate, and it is below the annual PSA rate increase cap of $0.006 per kWh. The rate became effective the first billing cycle of February 2026.

Environmental Improvement Surcharge

Following the ACC approval to eliminate the Environmental Improvement Surcharge on March 5, 2024, the surcharge is no longer in effect, and any remaining amounts are being collected through base rates. The Environmental Improvement Surcharge 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, 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, 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 rates 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.

Effective June 1, 2025, APS’s annual wholesale transmission revenue requirement for all users of its transmission system increased by approximately $119.0 million for the 12-month period beginning June 1, 2025, in accordance with the FERC-approved formula. Of this net amount, wholesale customer rates increased by approximately $4.6 million and retail customer rates would have increased by approximately $114.4 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 $88.3 million, resulting in increases to both residential and commercial rates. An adjustment to APS’s retail rates to recover FERC-approved transmission charges went into effect automatically on June 1, 2025.

Lost Fixed Cost Recovery Mechanism

The LFCR mechanism permits APS to recover on an after-the-fact basis a portion of its fixed costs that would otherwise have been collected by APS in the kWh sales lost due to APS energy efficiency programs and to DG such as rooftop solar arrays. The 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 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). 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.

On July 31, 2025, APS filed its 2025 annual LFCR adjustment, requesting that effective
November 1, 2025, the annual LFCR recovery amount be increased to $60.1 million (a $10.5 million increase from previous levels). On November 21, 2025, the ACC approved the 2025 annual LFCR adjustment, with new rates effective in the first billing cycle of December 2025.

Tax Expense Adjustor Mechanism

The TEAM helps address potential federal income tax reform and enables 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 ACC 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, $46.9 million of which has been collected as of March 31, 2026, 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.

Solar Export Price

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 DG 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 May 1, 2024, APS filed an application for revisions to the RCP. This application would decrease the RCP price to $0.06857 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 May 1, 2025, APS filed an application for revisions to the RCP. This application would decrease the RCP price to $0.06171 per kWh, reflecting a 10% annual reduction, to become effective September 1, 2025. On August 14, 2025, the ACC approved the RCP as filed.

On May 1, 2026, APS filed an application for revisions to the RCP. This application requests a decrease to the RCP price to $0.05554 per kWh, reflecting a 10% annual reduction, to become effective September 1, 2026. APS cannot predict the outcome of this matter.

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 DG Docket. Following various conferences, the ACC Staff filed a report finding that the RCP is working as intended and recommending no changes at this time along with closure of the docket. On October 6, 2025, the ACC administratively closed the general docket, and APS expects no additional action in this matter.

Energy Modernization Plan

On May 26, 2023, the ACC opened a new docket to review the Arizona Administrative Code related to Resource Planning, the RES, and 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 an 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.

The ACC voted to send to the Secretary of State full repeals of the RES and EES rules on August 14, 2025 and September 17, 2025, respectively, for publication and to begin the public rulemaking process. On March 4, 2026, the Commission approved the ROO to repeal the RES Rules and directed Staff to create and file with the Office of the Attorney General a Notice of Final Rulemaking package. Both the Sierra Club and the State of Arizona Attorney General’s Office filed a request for rehearing of Decision No. 81677 on March 30, 2026. On April 2, 2026, a Notice of Final Rulemaking and Final Economic Impact Statement was delivered to the Attorney General’s Office. APS cannot predict the outcome of this matter.
Integrated Resource Plan

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 system resource adequacy as well as analysis of impacts from western market participation and planned resource requirements in the next IRP, which is due to be filed on August 3, 2026.

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 residential customers for nonpayment from June 1 through October 15 each year (“Annual Disconnection Moratorium”). In addition, APS pauses shutting off residential customers for nonpayment in locations where the following day’s temperature is forecasted to be 95°F. Since the Annual Disconnection Moratorium began, APS has experienced an increase in bad debt expense and the related write-offs of delinquent customer accounts. Customers with past due balances of $75 or greater as the Annual Disconnection Moratorium nears its end are automatically placed on six-month payment arrangements prior to beginning the service disconnection process.

Cholla Power Plant

On September 11, 2014, APS announced that it would close Unit 2 of Cholla and cease burning coal at the other APS-owned units (Units 1 and 3) at the plant by the mid-2020s if EPA approved a compromise proposal offered by APS to meet required environmental and emissions standards and rules. On April 14, 2015, the ACC approved APS’s plan to retire Unit 2, without expressing any view on the future recoverability of APS’s remaining investment in the unit. APS closed Unit 2 on October 1, 2015. In early 2017, EPA approved a final rule incorporating APS’s compromise proposal, which took effect on April 26, 2017. In December 2019, PacifiCorp notified APS that it planned to retire Cholla Unit 4 by the end of 2020, and the unit ceased operation in December 2020. APS was required to cease burning coal at its remaining Cholla units by April 2025.
On August 14, 2024, APS filed a request with the ACC for a deferral order associated with unrecovered book value and decommissioning and site remediation costs of Cholla Units 1 and 3 related to the cessation of coal-burning operations at Cholla in April 2025. This order would authorize APS to defer for future recovery in rates the expenses necessary to cease operating coal-fired power plant infrastructure at Cholla, including legally required site environmental remediation, CCR corrective actions, the closure of CCR management facilities, and any unrecovered plant investment and operating costs incurred through and after April 2025. On July 8, 2025, APS withdrew its deferral application, requesting that the costs that would have been covered in the deferral order request instead be addressed in the 2025 Rate Case.

APS ceased coal-burning operations at Cholla in March 2025 and formally retired Cholla Units 1 and 3 on April 30, 2025. Upon the cessation of coal-fired operations, APS had approximately $81 million of remaining net-book value associated with Units 1 and 3 plant assets. APS is currently recovering in rates a return on the net-book value of its interest in Cholla and associated depreciation costs. In the 2025 Rate Case, APS has requested recovery in rates of the ongoing environmental remediation and CCR closure costs associated with Cholla and any remaining unrecovered plant costs. The 2025 Rate Case also includes a request for an ongoing deferral order relating to anticipated increased environmental remediation costs relating to Cholla that may be incurred after the 2025 Rate Case proceeding. APS cannot predict the outcome of this matter.

For Cholla Unit 2, APS has been allowed continued recovery of the net book value of the unit and the unit’s decommissioning and other retirement-related costs, totaling $22.4 million as of March 31, 2026, in addition to a return on its investment. 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.

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, $21.4 million as of March 31, 2026, 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, $1.4 million as of March 31, 2026. 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. On June 18, 2025, the ACC denied APS’s request and recommended that wildfire related expenses be recovered in APS’s 2025 Rate Case.
On May 12, 2025, Arizona Governor Hobbs signed into law a bill that requires Arizona electric utilities to develop and seek approval for wildfire mitigation plans and defines the standard of care with respect to wildfire-related claims by reference to such plans.

On February 1, 2026, APS submitted its 2026 Comprehensive Wildfire Mitigation Plan for approval to the Department of Forestry and Fire Management (“DFFM”). On March 18, 2026, the DFFM held a public comment session for APS’s plan. The DFFM’s review of the plan is still in progress. 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,
2026		December 31,
2025
Pension(a)$712,420 $723,042 
Income taxes — AFUDC equity2055205,059 203,890 
Palo Verde sale leaseback noncontrolling interests’ acquisition (b)N/A151,506 151,506 
Ocotillo deferral203496,220 99,931 
Lease incentive (Note 17)
204588,817 90,005 
SCR deferral (c)203875,816 77,186 
Deferred fuel and purchased power — mark-to-market (Note 10)
203058,222 29,330 
Deferred fuel and purchased power (c) (d)202755,432 149,068 
Retired power plant costs203150,695 56,809 
Income taxes — investment tax credit basis adjustment (Note 5)
205642,300 42,459 
Deferred compensation203632,936 32,204 
FERC transmission true up202831,138 21,471 
Deferred property taxes202713,207 15,349 
Palo Verde VIEs (Note 9)
20468,834 8,582 
Mead-Phoenix transmission line — contributions in aid of construction20507,969 8,052 
Loss on reacquired debt20385,416 5,653 
Active union medical trust(e)4,375 3,696 
TEAM (c)20313,715 3,879 
Navajo coal reclamation20261,438 2,516 
PSA - interest2027681 5,679 
DSM (c)2026206 15,706 
OtherVarious4,537 3,353 
Total regulatory assets (f)$1,650,939 $1,749,366 
Less: current regulatory assets$196,729 $286,009 
Total non-current regulatory assets$1,454,210 $1,463,357 
(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/loss and result in lower future revenues.  The 2022 Rate Case decision allows for the full return on the pension asset in rate base. See Note 8 for further discussion.
(b)This asset relates to the purchase of previously leased interest in Palo Verde Unit 2. See Note 9.
(c)See “Cost Recovery Mechanisms” discussion above.
(d)Subject to a carrying charge.
(e)Collected in retail rates.
(f)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.”
The detail of regulatory liabilities is as follows (dollars in thousands):
Amortization ThroughMarch 31,
2026		December 31,
2025
Excess deferred income taxes - ACC — Tax Cuts and Jobs Act (a)2046$844,409 $847,572 
Excess deferred income taxes - FERC — Tax Cuts and Jobs Act (a)2058199,607 200,161 
AROs and removal costs(b)242,200 286,907 
Other postretirement benefits(c)231,269 233,952 
Four Corners coal reclamation203897,458 97,988 
Income taxes — deferred investment tax credit205681,660 81,949 
Income taxes — change in state rates205456,040 56,260 
RES (d)202753,858 54,551 
Sundance maintenance203125,195 25,668 
Spent nuclear fuel202718,917 20,492 
DSM (d)202611,802 26,228 
TCA Balancing Account (d)2027— 4,860 
TEAM (d) 20323,587 3,738 
Deferred fuel and purchased power — mark-to-market (Note 10)
2030— 3,641 
OtherVarious2,516 3,063 
Total regulatory liabilities$1,868,518 $1,947,030 
Less: current regulatory liabilities$117,241 $210,909 
Total non-current regulatory liabilities$1,751,277 $1,736,121 
(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)In accordance with regulatory accounting, APS accrues removal costs for its regulated assets, even if there is no legal obligation for removal.
(c)See Note 8.
(d)See “Cost Recovery Mechanisms” discussion above.
v3.26.1
Retirement Plans and Other Postretirement Benefits
 3 Months Ended
Mar. 31, 2026
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,
 2026202520262025
Service cost-benefits earned during the period$12,099 $10,949 $2,237 $1,982 
Non-service costs (credits):
Interest cost on benefit obligation37,612 38,976 4,979 5,102 
Expected return on plan assets(44,096)(44,547)(12,719)(12,142)
Amortization of:
Prior service cost (credit)151 — — (1,265)
Net actuarial loss (gain)
11,153 12,118 (2,700)(2,899)
Net periodic benefit costs (credits)
$16,919 $17,496 $(8,203)$(9,222)
Portion of costs (credits) charged to expense
$9,518 $10,461 $(6,509)$(6,873)
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 2026, 2027 or 2028; however, we continue to evaluate and assess our ongoing contribution strategy. Regarding contributions to our other postretirement benefit plan, we have not made a contribution year-to-date in 2026 and do not expect to make any contributions in 2026, 2027 or 2028. The Company was reimbursed $23 million in April 2026 for a prior year’s retiree medical claims from the other postretirement benefit plan trust assets.
v3.26.1
Variable Interest Entities
 3 Months Ended
Mar. 31, 2026
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 11 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 commercial and mutual 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, 2026 and 2025 of $0.4 million and $0.7 million, respectively. These amounts are fully attributable to Pinnacle West shareholders. Consolidation impacts the Pinnacle West Condensed Consolidated Statements of Income operations and maintenance expense, other income, and other expense line items.

Pinnacle West’s Condensed Consolidated Balance Sheets as of March 31, 2026 and December 31, 2025 include $42 million and $40 million, respectively, of assets relating to the Captive that is reported within the other special use funds line item. See Notes 14 and 15 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 VIE lessor trust entities in order to sell and lease back interests in Palo Verde Unit 2 and related common facilities. In September 2025, APS purchased two of the three leased interests, the two related lease agreements were terminated and VIE consolidation treatment was discontinued for those two leases. Due to the purchases, APS now owns these previously leased interests, providing APS a total ownership interest in Palo Verde Unit 2 of 23.9%. APS’s remaining leased interest in Palo Verde Unit 2 is approximately 5.2%. See Note 12 in the 2025 Form 10-K for additional details regarding the two purchased leases.
As of March 31, 2026, one VIE lease arrangement remains in effect. The VIE lease agreement that was not subject to the purchase agreements is not impacted by the purchase transactions, and APS continues to consolidate this lessor VIE.
Under the current remaining lease in effect, APS will retain the leased asset through 2033 and will be required to make payments relating to the lease in total of approximately $9 million annually for the period 2026 through 2033. At the end of the lease period, APS will have the option to purchase the leased asset at its fair market value, extend the lease for up to two years, or return the asset to the lessor. The lease terms give APS the ability to utilize the asset for a significant portion of the asset’s economic life, and therefore provide APS with the power to direct activities of the VIE that most significantly impact the VIE’s economic performance. Predominantly due to the lease terms, APS has been deemed the primary beneficiary of this VIE and therefore consolidates the VIE.
As a result of consolidation, we eliminate lease accounting and instead recognize depreciation expense, resulting in an increase in net income three months ended March 31, 2026 and 2025 of $2 million and $4 million, respectively. The increase in net income due to consolidation of the VIE is entirely attributable to the noncontrolling interests. Income attributable to Pinnacle West shareholders is not impacted by the consolidation.
Our Condensed Consolidated Balance Sheets include the following amounts relating to the VIE (dollars in thousands):
 March 31, 2026
December 31, 2025
Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation$31,641 $32,035 
Equity — Noncontrolling interests42,811 40,617 
 
Assets of the VIE 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 the VIE upon the occurrence of certain events that APS does not consider to be reasonably likely to occur.  Under certain circumstances (for example, 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 VIE’s noncontrolling equity participants and take title to the leased Unit 2 interest, which, if appropriate, may be required to be written-down in value.  If such an event were to occur during the lease period, APS may be required to pay the noncontrolling equity participant approximately $177 million in 2026 and up to $267 million over the lease term.
 
For regulatory ratemaking purposes, the lease agreement continues to be treated as an operating lease, and as a result, we have recorded a regulatory asset relating to the arrangement.
v3.26.1
Derivative Accounting
 3 Months Ended
Mar. 31, 2026
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 14 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 13 for details relating to Pinnacle West’s equity forward sale agreements and 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 7.  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, 2026December 31, 2025
PowerGigawatt-hour542 542 
GasBillion cubic feet268 211 
 
Gains and Losses from Energy Derivative Instruments
For the three months ended March 31, 2026 and 2025, 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 ContractsLocation20262025
Net Gain (Loss) Recognized in Income
Fuel and purchased power (a)$(25,897)$116,704 
(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 (dollars in thousands):

As of March 31, 2026Gross 
Recognized 
Derivatives
 (a)		Amounts 
Offset
(b)		Net
 Recognized
 Derivatives		Other
 (c)		Amounts 
Reported on 
Balance Sheets
Current assets$12,614 $(12,231)$383 $5 $388 
Investments and other assets2,396 (1,930)466 — 466 
Total assets15,010 (14,161)849 5 854 
Current liabilities(65,583)12,231 (53,352)(2,566)(55,918)
Deferred credits and other(7,649)1,930 (5,719)— (5,719)
Total liabilities(73,232)14,161 (59,071)(2,566)(61,637)
Total$(58,222)$— $(58,222)$(2,561)$(60,783)
(a)All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)No cash collateral has been provided to or received by 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 $2,566 thousand and cash margin provided to counterparties of $5 thousand.

As of December 31, 2025Gross
 Recognized
 Derivatives
 (a)		Amounts
Offset 
(b)		Net
 Recognized
 Derivatives		Other
 (c)		Amounts
 Reported on
 Balance Sheets
Current assets$12,640 $(9,395)$3,245 $5 $3,250 
Investments and other assets6,707 (1,570)5,137 — 5,137 
Total assets19,347 (10,965)8,382 5 8,387 
Current liabilities(41,970)9,395 (32,575)(2,566)(35,141)
Deferred credits and other(3,065)1,570 (1,495)— (1,495)
Total liabilities(45,035)10,965 (34,070)(2,566)(36,636)
Total$(25,688)$— $(25,688)$(2,561)$(28,249)
(a)All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)No cash collateral has been provided to or received by 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 $2,566 thousand and cash margin provided to counterparties of $5 thousand.
Credit Risk and Credit Related Contingent Features
 
We are exposed to losses in the event of nonperformance or nonpayment by energy derivative counterparties and have risk management contracts with many energy derivative counterparties. As of March 31, 2026, we have no counterparties with positive exposure greater than 10% of Pinnacle West’s $0.9 million of net risk management assets. Our risk management process assesses and monitors the financial exposure of all counterparties.  Despite the fact that the great majority of our trading counterparties’ debt is rated as investment grade by the credit rating agencies, there is still a possibility that one or more of these counterparties could default, resulting in a material impact on consolidated 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 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, 2026
Aggregate fair value of derivative instruments in a net liability position$69,364 
Additional collateral in the event credit-risk related contingent features were fully triggered (a)30,038 
(a)This amount is after counterparty netting and includes those contracts which qualify for scope exceptions, which are excluded from the derivative details above.
 
As of March 31, 2026, we also have energy related non-derivative instrument contracts, with investment grade credit-related contingent features, which could also require us to post additional collateral of approximately $710 million if our debt credit ratings were to fall below investment grade.
v3.26.1
Commitments and Contingencies
 3 Months Ended
Mar. 31, 2026
Commitments and Contingencies Disclosure [Abstract]  
Commitments and Contingencies Commitments and Contingencies
 
Palo Verde Generating Station
 
Spent Nuclear Fuel and Waste Disposal
 
On December 19, 2012, APS, acting on behalf of itself and the participant owners of Palo Verde, filed a second breach of contract lawsuit against DOE in the 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 paid 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 is currently in the process of extending the settlement to cover costs paid through December 31, 2028.

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 ACC’s decision from the 2017 rate case, this regulatory liability is being refunded to customers. On October 31, 2025, APS submitted its twelfth claim on behalf of itself and the participant owners of Palo Verde pursuant to the terms of the settlement agreement in the amount of approximately $15.4 million (APS’s share is approximately $4.5 million). In February 2026, the DOE approved approximately $15.4 million of this claim.

Nuclear Insurance
 
Public liability for incidents at nuclear power plants is governed by the Price-Anderson Nuclear Industries Indemnity Act (“Price-Anderson Act”), which limits the liability of nuclear reactor owners to the amount of insurance available from both commercial sources and an industry-wide retrospective payment plan. 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 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 $24.3 million for each retrospective premium assessment declared by NEIL’s Board of Directors due to losses.  Additionally, at the sole discretion of the NEIL Board of Directors, APS would be liable to provide approximately $66.9 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.

Nuclear Wage Class Action Lawsuit

On July 11, 2025, APS, together with all 25 other U.S. nuclear power plant operators, was named in a class action lawsuit brought in the U.S. District Court in Maryland. The lawsuit alleges the country’s nuclear operators have violated antitrust laws by agreeing to exchange compensation information and suppress compensation. The class action complaint has been brought on behalf of all persons employed in nuclear power generation in the U.S. from May 1, 2003 until the present and alleges violations of the Sherman Act. We are unable at this time to predict the outcome of this matter and whether it will have a material impact on our financial position, results of operations, or cash flows.
 
Captive Insurance Cell
Pinnacle West has established a captive insurance program to supplement commercial and mutual 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 commercial and mutual insurance coverage. 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. In addition to the policies obtained through the Captive, Pinnacle West also has commercial and mutual insurance policies purchased through third-party insurers that may provide coverage if a loss event occurs. See Note 9 for additional details.
Fuel and Purchased Power Commitments and Purchase Obligations

As of March 31, 2026, our fuel and purchased power and purchase obligation commitments have increased by $2.8 billion from the information provided in our 2025 Form 10-K, primarily due to gas tolling lease contracts. See Note 17.
Other than the items described above, there have been no material changes, as of March 31, 2026, outside the normal course of business in contractual obligations from the information provided in our 2025 Form 10-K. See Note 6 for discussion regarding changes in our short-term and long-term debt obligations.
Superfund and Other Related Matters
 
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, 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 RI/FS.  The RI/FS for OU3 was finalized and submitted to EPA at the end of 2022. EPA notified APS that the remedial investigation and feasibility study (“RI/FS”) was approved on September 11, 2024. On September 25, 2025, EPA executed a final ROD adopting the OU3 remedies proposed in the approved RI/FS OU3. APS’s expenditures related to this investigation and study are approximately $3 million. APS anticipates it may incur additional expenditures in the future, but because the final costs associated with remediation requirements set forth in the RI/FS and ROD are not yet finalized, at the present time expenditures related to this matter cannot be reasonably estimated; however, APS does not expect the outcome to have a material impact on its financial position, results of operations, or cash flows.
 
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. 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 the Ocotillo site located in Tempe, Arizona. In particular, EPA seeks information from APS regarding APS’s use, storage, and disposal of substances containing PFAS at the Ocotillo site in order to aid EPA’s investigation into actual or threatened releases of PFAS into groundwater within the South Indian Bend Wash Superfund site. The South Indian Bend Wash Superfund site includes the Ocotillo 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 South Indian Bend Wash site, including Ocotillo, 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 GHG, 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, 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, EPA has taken steps to substantially modify the federal rules governing CCR disposal. While certain changes have been prompted by utility industry petitions, others have resulted from judicial review, court-approved settlements with environmental groups, and statutory changes to RCRA. The following lists the pending regulatory changes that, if finalized, could have a material impact as to how APS manages CCR at its coal-fired power plants:

•Following the passage of the Water Infrastructure Improvements for the Nation Act in 2016, EPA possesses authority to either authorize states to develop their own permit programs for CCR management or issue federal permits governing CCR disposal both in states without their own permit programs and on tribal lands. 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 EPA, which will have to approve the entire state program before it is operational. It remains unclear when EPA would approve that permitting program pursuant to the Water Infrastructure Improvements for the Nation Act. On December 19, 2019, EPA proposed its own set of regulations governing the issuance of CCR management permits, which would impact facilities like Four Corners located on the Navajo Nation. The proposal remains pending.

•On March 1, 2018, as a result of a settlement with certain environmental groups, EPA proposed adding boron to the list of constituents that trigger corrective action requirements to remediate groundwater impacted by CCR disposal activities. Apart from a subsequent proposal issued on August 14, 2019 to add a specific health-based groundwater protection standard for boron, EPA has yet to take action on this proposal.

We cannot predict the outcome of these regulatory proceedings or when EPA will take final action on those matters that are still pending. Depending on the eventual outcome, the costs associated with
APS’s management of CCR could materially increase, which could affect our financial condition, results of operations, or cash flows.

On April 25, 2024, EPA took final action on a proposal to expand the scope of federal CCR regulations to address the impacts from historical CCR disposal activities that would have ceased prior to 2015. This new class of CCRMUs, which contain at least 1,000 tons of CCR, broadly encompasses any location at an operating coal-fired power plant where CCRs would have been placed on land. 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. Under EPA’s legacy 2024 CCRMU rule, initial CCRMU site surveys were originally due to be completed by February 2026 and final site investigation reports by February 2027.

On February 10, 2026, EPA published a final rule extending multiple compliance deadlines applicable to CCRMUs established under the prior rule. The final rule extends the deadline for completing Parts One and Two of Facility Evaluation Reports by one year to February 2027 and February 2028, respectively. EPA also extended associated compliance deadlines for groundwater monitoring and certain closure requirements. Subsequently, on April 9, 2026, EPA proposed a new regulation that contemplates a range of revisions to the 2024 legacy CCRMU rule, including full elimination of the 2024 standards among other alterations. EPA also proposes to expand the categories of activities that meet the definition of “beneficial use” of CCR, which is exempt from most federal CCR regulatory restrictions. In addition, EPA is proposing to authorize certain risk-based compliance alternatives for facilities subject to state or federal CCR permitting, which would allow adjustments to default standards for groundwater monitoring, groundwater protection standards, closure and post-closure care requirements, and additional measures concerning beneficial use.

APS is still in the process of evaluating the impacts of these CCRMU regulations on its business and cannot predict the outcome of any future rulemaking or other regulatory proceedings aimed at changing the current EPA CCRMU rules. 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 the pending legacy 2024 CCRMU rule amendments and APS’s evaluations, the costs associated with APS’s management of CCR could materially increase, which could affect our financial condition, results of operations, or cash flows.

APS currently disposes of CCR in ash ponds and dry storage areas at Four Corners. The Navajo Plant disposed of CCR only in a dry landfill storage area. Cholla disposed of CCR in ash ponds and dry storage areas prior to ceasing coal-fired operations. 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 at Cholla that had been subject to alternative closure, which initiated closure work on June 30, 2025). 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 AROs and removal costs within 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

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

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

Under current rules, carbon emission performance standards apply based on the annual capacity factors for new natural gas-fired combustion turbine power plants. The highest utilization combustion turbines must be retrofitted for CCS by 2032. Intermediate or low-load natural gas fired combustion turbines with 40% or less capacity factors do not require add-on pollution controls. Instead, natural gas-fired combustion turbines with capacity factors of up to 20% are effectively unregulated, while turbines with capacity factors over 20% and up to 40% are subject to carbon dioxide emission rate limitations.

For coal-fired power plants, instead of imposing regulations based on capacity and utilization, EPA finalized subcategories based on planned retirement dates. 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. On February 5, 2025, EPA filed an unopposed motion requesting that the D.C. Circuit Court of Appeals hold the GHG regulations case in abeyance for 60 days and withhold issuing an opinion while the new leadership at EPA evaluates the rule and determines how it wishes to proceed. On February 19, 2025, the Court granted EPA’s motion. EPA subsequently filed a second motion asking the Court to keep the GHG regulations case in abeyance for an indefinite period of time given EPA’s anticipated reconsideration of the rules, with
EPA providing status reports every 90 days. On April 25, 2025, the D.C. Circuit granted EPA’s motion for an indefinite abeyance. We cannot predict the outcome of the litigation challenging EPA’s current carbon emission standards for power plants.

If the current regulations were to remain in effect, they would 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 CCS and achieve 90% capture efficiency may not be feasible. Future resource plans and procurement efforts implicating the development of such new generation remain pending and, as such, at this time APS is not able to quantify the financial impact associated with EPA’s existing GHG regulations for power plants.

On June 11, 2025, EPA put forth a proposed rule with two scenarios for repealing the GHG regulations finalized in 2024. EPA’s primary proposal entails a full repeal of the GHG regulations based on a finding that GHG emissions from fossil fuel-fired power plants do not present a “significant contribution” to dangerous air pollution, thereby eliminating the 2024 GHG power plant regulations in their entirety.

Under EPA’s alternative proposal, only certain portions of the 2024 GHG regulations would be repealed based on a finding that they are unlawful, including the emission guidelines for existing fossil fuel-fired steam generating units (coal-fired power plants), the CCS-based standards for coal-fired steam generating units undertaking a large modification, and the CCS-based standards for new base-load stationary combustion turbines (i.e., those operating at greater than 40% annual capacity factors). This targeted approach would eliminate the CCS and natural gas co-firing technology-based pollution limits that would apply to both existing coal-fired power plants and new gas-fired combustion turbine power plants. However, efficiency-based standards for new combustion turbines would remain in place under this alternative proposal.

EPA’s proposed rule to repeal the 2024 GHG regulations was published in the Federal Register on June 17, 2025. Comments were due by August 7, 2025. 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. Further changes to these regulations may also face judicial review. APS cannot predict the outcome of any such litigation.

On February 18, 2026, EPA’s repeal of the 2009 “Endangerment Finding” was finalized and published in the Federal Register. This action is expected to provide legal and regulatory support for EPA’s pending proposals seeking to eliminate or significantly limit the scope of the current EPA carbon emission standards and guidelines for new and existing power plants. The repeal of the “Endangerment Finding” is subject to judicial review, with lawsuits being filed on February 18, 2026 in the D.C. Circuit Court of Appeals seeking to challenge the repeal. We cannot predict the outcome of the litigation.

Effluent Limitation Guidelines

EPA published ELG on October 13, 2020, and, based off those guidelines, APS completed a 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 EPA finalized in September 2015. However, on April 25, 2024, EPA finalized new ELG regulations that once again require “zero discharge” standards for flows of bottom ash transport water at power plants like Four Corners. 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.

On December 31, 2025, EPA published a final rule extending by five years the compliance deadlines for achieving the 2024 zero-discharge standards for bottom ash transport wastewater from year-end 2029 to year-end 2034, among other changes to the 2024 rulemaking. EPA is also collecting additional information on zero-discharge technologies, including cost and performance data, to inform future potential rulemakings to modify or relax the current zero-discharge 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, 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 NAAQS. Thermal power plant emission limitations are a key aspect of these regulations, which involve emission allowance trading for NOx emissions. While Arizona was not among the 23 states subject to EPA’s March 2023 final action, EPA announced on January 23, 2024, that it was proposing to add Arizona and New Mexico (along with two other additional states) to EPA’s NOx emission allowance trading program finalized last year. 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 EPA’s Good Neighbor Plan upon finalization of this proposal. 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 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, 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, EPA announced its intention to reconsider the Good Neighbor Plan and on January 30, 2026, EPA published a proposed rule in the Federal Register that would approve Arizona’s and New Mexico’s State Implementation Plans concerning the cross-state transport of ozone forming emissions. Such approval, if finalized as proposed, would remove APS’s operations in Arizona and New Mexico from the scope of future efforts to regulate such emissions. APS cannot predict the outcome of this pending regulatory action nor when EPA may take final action on this proposal. If finalized as proposed, this action would then be subject to judicial review and APS cannot predict the outcome of such litigation, if any arises. In addition, APS cannot predict the outcome of any future EPA efforts to add Arizona or New Mexico to a future federal program addressing the cross-state transport of ozone-forming emissions. Should a federal program like 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 February 20, 2026, EPA issued a final rule repealing the 2024 revisions to MATS regulations governing emissions of toxic air pollution from existing coal-fired power plants. The repeal of the 2024 amendment means that MATS regulations revert to the pre-existing framework for MATS emission limits established in 2012. As a result, the 2024 revisions that would have increased the stringency of filterable particulate matter limits used to demonstrate compliance with MATS and required the use of continuous emissions monitoring systems to ensure compliance (as opposed to periodic performance testing) will not take effect for existing coal-fired power plants, such as Four Corners.

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.

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, 2026, standby letters of credit totaled approximately $31.8 million and will expire through 2027, and surety bonds totaled approximately $24.4 million and will expire through 2028. 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 remaining Palo Verde sale leaseback transaction 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, 2026. 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 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 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, 2026, there is approximately $25.5 million remaining relating to these PTC Guarantees that are expected to terminate by 2031.

Pinnacle West issued various performance guarantees in connection with a joint venture project, the Kūpono Solar Project, by BCE, a former subsidiary of Pinnacle West. BCE was sold to Ameresco in 2024 (the “BCE Sale”). Subsequent to the BCE Sale, Pinnacle West continues to maintain these Kūpono Solar Project investment financing guarantees and is exposed to losses relating to these guarantees upon the occurrence of certain events that we consider to be remote. 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.
v3.26.1
Other Income and Other Expense
 3 Months Ended
Mar. 31, 2026
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,
 20262025
Other income:
Interest income $2,881 $5,996 
Investment gain — net (a)1,792 10,984 
Miscellaneous308 481 
Total other income$4,981 $17,461 
Other expense:
Non-operating costs$(2,462)$(2,229)
Miscellaneous(278)(341)
Total other expense$(2,740)$(2,570)
(a)Primarily relates to El Dorado investment activities. See Note 18.
The following table provides detail of APS’s other income and other expense (dollars in thousands):
Three Months Ended March 31,
 20262025
Other income:
Interest income$2,520 $5,607 
Miscellaneous125 115 
 Total other income$2,645 $5,722 
Other expense:
Non-operating costs$(2,390)$(1,992)
Miscellaneous(278)(341)
Total other expense$(2,668)$(2,333)
v3.26.1
Common Stock Equity and Earnings Per Share
 3 Months Ended
Mar. 31, 2026
Earnings Per Share [Abstract]  
Common Stock Equity and Earnings Per Share Common Stock Equity and Earnings Per Share
At-the-Market Program

On November 8, 2024, Pinnacle West opened its ATM Program, pursuant to which Pinnacle West may sell, from time to time, up to $900 million of its common stock through an at-the-market equity distribution program, which includes the ability to enter into forward sale agreements. Approximately $434 million of common stock is available to be sold under the ATM Program, which takes into account the forward sale agreements in effect as of March 31, 2026.

As of March 31, 2026, Pinnacle West had nine outstanding forward sale agreements under its ATM Program (collectively, the “ATM Forward Sale Agreements”). These agreements relate to approximately $466 million, on a gross basis, of common stock and may be settled at Pinnacle West’s discretion by issuing shares at the applicable forward sales price or, alternatively, by delivering cash in lieu of shares. On April 1, 2026, Pinnacle West entered into a tenth forward sale agreement relating to a total of $100 million, on a gross basis, of common stock, with a maturity date of September 30, 2027.
The following table presents information about the outstanding ATM Forward Sale Agreements as of March 31, 2026 based on their contractual terms at the time each agreement was entered into, including the applicable forward sale prices and related aggregate contractual values, which may differ from the gross amount of common stock referenced above (dollars in thousands, except price per share):

ATM Forward Sale AgreementsMaturity Date (a)Number of SharesForward Sales Price Per Share (b)Aggregate Value
November 2024June 30, 2026552,833 $89.73 $49,606 
March 2025September 14, 2026544,959 $90.83 $49,499 
August 2025February 16, 2027543,001 $91.21 $49,527 
September 2025February 22, 2027558,622 $88.69 $49,544 
January 2026July 2, 2027119,553 $89.88 $10,745 
March 2026September 3, 2027646,674 $99.52 $64,357 
March 2026September 10, 2027490,537 $100.94 $49,515 
March 2026September 18, 2027488,813 $101.28 $49,507 
March 2026September 30, 2027916,930 $98.12 $89,969 
4,861,922 $95.08 (c)$462,269 
(a)    Maturity date may be extended.
(b)    Subject to certain adjustments.
(c)    Total weighted-average share price.

Non-ATM February 2024 Forward Sale Agreements

In addition to the ATM Forward Sale Agreements, Pinnacle West also has Forward Sale Agreements that were entered into on February 28, 2024 (the “February 2024 Forward Sale Agreements”). These agreements may be settled at Pinnacle West’s discretion by issuing shares of Pinnacle West common stock and receiving 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 February 2024 Forward Sale Agreements were partially settled in December 2024, September 2025, and December 2025. In August 2025, APS amended the February 2024 Forward Sale Agreements with Wells Fargo Bank, National Association, to extend the maturity date of those forward confirmations to December 31, 2026.
The following table presents information about the outstanding February 2024 Forward Sale Agreements as of March 31, 2026 (dollars in thousands, except price per share):

February 2024 Forward Sale AgreementsNumber of SharesForward Sales Price Per ShareAggregate Value
Initial Price11,240,601 $64.51 (a)$725,131 
Settlements
December 23, 20245,377,115 (b)$64.17 $345,049 (c)
September 4, 2025243,186 (b)$63.12 $15,350 (c)
December 18, 20251,193,950 (b)$62.82 $75,004 (c)
(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. Interest is 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, 2026, 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, net of approximately $3 million in unamortized debt issuance costs. The estimated fair value of the Convertible Notes as of March 31, 2026 was approximately $597 million (Level 2 within the fair value hierarchy).

As of March 31, 2026, based on Pinnacle West’s average stock price and the relevant terms of the Convertible Notes, there were shares of Pinnacles West’s common stock included in diluted EPS relating to the potential conversion of the Convertible Notes, but no shares included in basic EPS.

Earnings Per Share

The following table presents the calculation of Pinnacle West’s basic and diluted EPS (dollars and shares in thousands, except earnings per share amounts):
Three Months Ended March 31,
 20262025
Net income (loss) attributable to common shareholders
$32,920 $(4,644)
Weighted average common shares outstanding — basic121,360 119,594 
Net effect of dilutive securities:
Contingently issuable performance shares and restricted stock units444 498 
Dilutive shares related to equity forward sale agreements (a)1,722 1,669 
Dilutive shares related to convertible debt instruments (b)252 — 
Total contingently issuable shares (c)2,418 2,167 
Weighted average common shares outstanding — diluted123,778 121,761 
Earnings per weighted-average common share outstanding
Net income (loss) attributable to common shareholders — basic
$0.27 $(0.04)
Net income (loss) attributable to common shareholders — diluted
$0.27 $(0.04)
(a)    For the three months ended March 31, 2026 and 2025 the diluted weighted-average common shares excludes 16,127 and 4,636 shares, respectively relating to the ATM Program. These potentially issuable shares were excluded from the calculation of diluted shares as their inclusion would have been antidilutive.
(b)     For the three months ended March 31, 2026 and 2025 the diluted weighted-average common shares excludes 0 and 192,754 shares, respectively relating to the Convertible Notes. These potentially issuable shares were excluded from the calculation of diluted shares as their inclusion would have been antidilutive.
(c)    No contingently issuable shares were excluded from the calculation of diluted weighted-average common shares outstanding for the three months ended March 31, 2026. For the three months ended March 31, 2025, 2,167,000 contingently issuable shares 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.
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 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 is reduced by the 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.
v3.26.1
Fair Value Measurements
 3 Months Ended
Mar. 31, 2026
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 2025 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 15 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, 2026 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):

Level 1Level 2Level 3OtherTotal
ASSETS
Risk management activities — derivative instruments:
Commodity contracts$— $11,142 $— $(10,288)(a)$854 
Nuclear decommissioning trusts:
Equity securities18,541 — — 3,557 (b)22,098 
U.S. commingled equity funds— — — 478,770 (c)478,770 
U.S. Treasury debt369,970 — — — 369,970 
Corporate debt— 249,372 — — 249,372 
Mortgage-backed securities— 217,924 — — 217,924 
Municipal bonds— 34,288 — — 34,288 
Other fixed income— 20,395 — — 20,395 
Subtotal nuclear decommissioning trusts388,511 521,979 — 482,327 1,392,817 
Other special use funds:
Equity securities64,850 — — 2,012 (b)66,862 
U.S. Treasury debt370,883 — — — 370,883 
Subtotal other special use funds (d)435,733 — — 2,012 437,745 
Total assets$824,244 $533,121 $— $474,051 $1,831,416 
LIABILITIES
Risk management activities — derivative instruments:
Commodity contracts$— $(35,908)$(33,456)$7,727 (a)$(61,637)
(a)Represents counterparty netting, margin, and collateral. See Note 10.
(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 $41.4 million related to Pinnacle West’s Captive investments that are classified within Level 1 equity securities. See Note 9.
 The following table presents the fair value at December 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
Risk management activities — derivative instruments:
Commodity contracts$— $19,347 $— $(10,960)(a)$8,387 
Nuclear decommissioning trusts:
Equity securities18,970 — — (3,799)(b)15,171 
U.S. commingled equity funds— — — 500,592 (c)500,592 
U.S. Treasury debt364,943 — — — 364,943 
Corporate debt— 242,176 — — 242,176 
Mortgage-backed securities— 230,695 — — 230,695 
Municipal bonds— 37,572 — — 37,572 
Other fixed income— 23,017 — — 23,017 
Subtotal nuclear decommissioning trusts383,913 533,460 — 496,793 1,414,166 
Other special use funds:
Equity securities62,573 — — 3,199 (b)65,772 
U.S. Treasury debt369,055 — — — 369,055 
Subtotal other special use funds (d)431,628 — — 3,199 434,827 
Total assets$815,541 $552,807 $— $489,032 $1,857,380 
LIABILITIES
Risk management activities — derivative instruments:
Commodity contracts$— $(21,325)$(23,710)$8,399 (a)$(36,636)
(a)Represents counterparty netting, margin, and collateral. See Note 10.
(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 $40.3 million related to Pinnacle West’s Captive investments that are classified within Level 1 equity securities. See Note 9.
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, 2026 and December 31, 2025 (dollars in thousands):

March 31, 2026
 Fair Value 		ValuationSignificantWeighted-Average
Commodity ContractsAssetsLiabilitiesTechniqueUnobservable InputRange (b)
Electricity:
Electricity Forward Contracts (a)$— $26,789 Discounted cash flowsElectricity forward price (per MWh)
$31.79
-
$138.31
$71.57
Natural Gas Forward Contracts (a)— 6,667 Discounted cash flowsNatural gas forward price (per Million British Thermal Units (“MMBtu”))
$(0.79)
-
$0.14
$0.03
Total$— $33,456 
(a)Includes swaps and physical and financial contracts.
(b)Unobservable inputs were weighted by the relative fair value of the instrument.

December 31, 2025
 Fair Value 		ValuationSignificantWeighted-Average
Commodity ContractsAssetsLiabilitiesTechniqueUnobservable InputRange(b)
Electricity Forward Contracts (a)$— $21,913 Discounted cash flowsElectricity forward price (per MWh)$41.51 -$149.37$80.20
Natural Gas Forward Contracts (a)— 1,797 Discounted cash flowsNatural gas forward price (per MMBtu)$(0.07)-$0.36$0.04
Total$— $23,710 
(a)Includes swaps and physical and financial contracts.
(b)Unobservable inputs were weighted by the relative fair value of the instrument.
The following table shows the changes in fair value for our risk management activities’ assets and liabilities that are measured at fair value on a recurring basis using Level 3 inputs (dollars in thousands):
 Three Months Ended March 31,
Commodity Contracts20262025
Balance at beginning of period$(23,710)$(15,039)
Total net losses realized/unrealized:
Deferred as a regulatory asset or liability(14,577)(5,823)
Settlements4,831 (2,287)
Transfers into Level 3 from Level 2— (59)
Transfers from Level 3 into Level 2— 368 
Balance at end of period$(33,456)$(22,840)
Net unrealized gains/losses included in earnings related to instruments still held at end of period$— $— 

             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 6 for our long-term debt fair values.
v3.26.1
Investments in Nuclear Decommissioning Trusts and Other Special Use Funds
 3 Months Ended
Mar. 31, 2026
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 14 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 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 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 April 2026, APS was reimbursed $13 million for active union employee medical claims from the active union employee medical account. The account is invested primarily in fixed income securities. In accordance with the ratemaking treatment, APS has deferred the unrealized gains and losses (including credit losses) in other regulatory assets. Activities relating to active union employee medical account investments are included within the other special use funds in the table below.

Captive Insurance Cell

Pinnacle West has investments held by 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, 2026
 Fair ValueTotal
Unrealized
Gains		Total
Unrealized
Losses
Investment Type:Nuclear Decommissioning TrustsOther Special Use FundsTotal
Equity securities$497,311 $64,850 $562,161 $407,542 (d)$(139)
Available for sale-fixed income securities891,949 370,883 1,262,832 (a)11,497 (18,344)
Other3,557 2,012 5,569 (b)— — 
Total$1,392,817 $437,745 $1,830,562 (c)$419,039 $(18,483)
(a)As of March 31, 2026, the amortized cost basis of these available-for-sale investments is $1,270 million.
(b)Represents net pending securities sales and purchases.
(c)All amounts pertain to APS, with the exception of $41.4 million of other special use fund investments in equity securities relating to investments held by the Captive.
(d)All amounts pertain to APS, with the exception of $2.8 million of unrealized gains relating to investments held by the Captive.
December 31, 2025
 Fair ValueTotal
Unrealized
Gains		Total
Unrealized
Losses
Investment Type:Nuclear Decommissioning TrustsOther Special Use FundsTotal
Equity securities$519,562 $62,573 $582,135 $433,044 (d)$(1)
Available for sale-fixed income securities898,403 369,055 1,267,458 (a)18,765 (14,993)
Other(3,799)3,199 (600)(b)— — 
Total$1,414,166 $434,827 $1,848,993 (c)$451,809 $(14,994)
(a)As of December 31, 2025, the amortized cost basis of these available-for-sale investments is $1,265 million.
(b)Represents net pending securities sales and purchases.
(c)All amounts pertain to APS, with the exception of $40.3 million of other special use fund investments in equity securities relating to investments held by the Captive.
(d)All amounts pertain to APS, with the exception of $3.2 million of unrealized gains relating to investments held by 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
2026
Realized gains$4,720 $16 $4,736 
Realized losses$(2,797)$— $(2,797)
Proceeds from the sale of securities (a)$447,883 $64,351 (b)$512,234 
2025
Realized gains$1,658 $— $1,658 
Realized losses$(2,761)$— $(2,761)
Proceeds from the sale of securities (a)$416,601 $69,213 (c)$485,814 
(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.
(c)    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, 2026 is as follows (dollars in thousands):
 
 Nuclear Decommissioning TrustsCoal Reclamation Escrow AccountActive Union Employee Medical AccountTotal
Less than one year$32,191 $108,470 $39,753 $180,414 
1 year – 5 years299,067 49,806 156,363 505,236 
5 years – 10 years168,027 — 16,491 184,518 
Greater than 10 years392,664 — — 392,664 
Total$891,949 $158,276 $212,607 $1,262,832 
v3.26.1
Changes in Accumulated Other Comprehensive Loss
 3 Months Ended
Mar. 31, 2026
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, 2025
$(32,980)$572 $(32,408)
Other comprehensive loss before reclassifications
— (43)(43)
Amounts reclassified from accumulated other comprehensive loss
502  (a)— 502 
Balance March 31, 2026
$(32,478)$529 $(31,949)
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)
(a)    These amounts primarily represent amortization of actuarial loss and are included in the computation of net periodic pension cost.  See Note 8
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, 2025
$(15,457)
Other comprehensive loss before reclassifications
— 
Amounts reclassified from accumulated other comprehensive loss
410  (a)
Balance March 31, 2026
$(15,047)
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)
(a) These amounts primarily represent amortization of actuarial loss and are included in the computation of net periodic pension cost.  See Note 8.
v3.26.1
Leases
 3 Months Ended
Mar. 31, 2026
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 power purchase or PPAs and energy storage agreements that qualify as lease arrangements. Our leases have remaining terms that expire in 2026 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. The 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 from these sale leaseback transactions are excluded from our lease disclosures as lease accounting is eliminated upon consolidation.  In September 2025, two of the three leased interests were purchased by APS. As of March 31, 2026, one VIE lease arrangement remains in effect. See Note 9.

APS is party to PPAs that allow it 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.
During the first quarter of 2026, APS modified two existing purchase power operating lease agreements. These agreements relate to natural-gas tolling purchase power agreements. Among other changes, the modifications extend the expiration date of the leases, change the periods of use, and modify the pricing. The modified lease agreements continue to qualify as operating lease agreements. These will now terminate in October 2038 and December 2046.

APS has executed various energy storage PPAs 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 July 2025.

The following table provides information related to our lease costs (dollars in thousands):

Three Months Ended March 31,
20262025
Operating Lease Cost - PPAs and Energy Storage PPA Lease Contracts$54,390 $12,547 
Operating Lease Cost - Land, Property, and Other Equipment6,301 5,337 
Total Operating Lease Cost60,691 17,884 
Variable Lease Cost (a)25,313 21,370 
Short-term Lease Cost875 592 
Total Lease Cost$86,879 $39,846 
(a)    Primarily relates to PPA lease contracts.

Lease costs are primarily included as a component of operating expenses on our Condensed Consolidated Statements of Income. Lease costs relating to PPAs and energy storage PPA 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 7. 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 PPA lease contracts. Payments under most renewable PPA 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, 2026
YearPPAs and Energy Storage PPA Lease ContractsLand, Property and Equipment LeasesTotal
2026 (remaining nine months of 2026)$308,967 $16,360 $325,327 
2027391,311 19,667 410,978 
2028431,553 16,975 448,528 
2029436,730 14,842 451,572 
2030442,013 10,620 452,633 
2031447,410 4,719 452,129 
Thereafter5,478,135 55,397 5,533,532 
Total lease commitments7,936,119 138,580 8,074,699 
Less imputed interest3,885,636 41,552 3,927,188 
Total lease liabilities$4,050,483 $97,028 $4,147,511 
    
We recognize lease assets and liabilities upon lease commencement. As of March 31, 2026, 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 $11.8 billion over the terms of the agreements. These arrangements primarily relate to energy storage PPA assets. We expect lease commencement dates ranging from April 2026 through June 2028, with lease terms expiring through June 2048.

The following tables provide other additional information related to operating lease liabilities (dollars in thousands):
Three Months Ended March 31,
20262025
Cash paid for amounts included in the measurement of lease liabilities — operating cash flows$61,114 $17,207 
Right-of-use operating lease assets obtained in exchange for operating lease liabilities$404,869 (a)$763,437 (b)

March 31, 2026December 31, 2025
Weighted average remaining lease term17 years15 years
Weighted average discount rate (c)8.72 %5.48 %
(a)Primarily relates to two PPA operating lease agreements that were modified in 2026.
(b)Primarily relates to the three new energy storage operating lease agreements that commenced in 2025.
(c)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.
v3.26.1
El Dorado Equity Investments
 3 Months Ended
Mar. 31, 2026
Equity Method Investments and Joint Ventures [Abstract]  
El Dorado Equity Investments El Dorado Equity Investments
Equity Method Investments

El Dorado holds investments in equity securities accounted for under the equity method. The equity method of accounting is applied when we have the ability to exercise significant influence over the operating and financial policies of an investee. The equity method has been applied to El Dorado’s equity investment holdings in SAI and Copper Sky.

SAI — SAI is a private corporation that manufactures electrical switchgear equipment used by data centers. El Dorado holds common stock in SAI and maintains a seat on SAI’s board of directors.

Copper Sky — Copper Sky, previously AZ-VC, is a limited liability company fund focused on analyzing, investing, managing, and otherwise dealing with investments in privately-held early stage and emerging growth technology companies and businesses primarily based in Arizona, or based in other jurisdictions and having existing or potential strategic or economic ties to companies or other interests in Arizona. El Dorado holds Class A Membership interests in the fund.

These equity method investments are included in the other assets line item on Pinnacle West’s Condensed Consolidated Balance Sheets. The following table presents El Dorado’s ownership percentages and carrying value of investments accounted for under the equity method (dollars in millions):

Investee
Pinnacle West Ownership Percentage as of March 31, 2026
March 31, 2026December 31, 2025
SAI (a)17 %$26 $21 
Copper Sky (b)23 %16 15 
Total equity method investments$42 $36 
(a)El Dorado has no further funding commitments to SAI.
(b)El Dorado has a $25.0 million funding commitment to Copper Sky, previously AZ-VC, of which approximately $16.8 million has been funded as of March 31, 2026.

Our share of the investees’ earnings or losses are recognized in other income and other expense on Pinnacle West’s Condensed Consolidated Statements of Income. For the three months ended March 31, 2026, the net equity method earnings relating to these investments was $5.9 million. For the three months ended March 31, 2025, the net equity method earnings relating to these investments was $11.8 million.

Other Investments

El Dorado holds investments in other equity securities to which the equity method of accounting does not apply due to lack of significant influence over the investees’ operating and financial policies. These equity investments do not have readily determinable fair values, and we have elected the measurement alternative for these investments. Investments accounted for under the measurement alternative are carried at cost adjusted for impairments or observable price changes. The Pinnacle West Condensed Consolidated Balance Sheets as of March 31, 2026 and December 31, 2025 include $25.2 million and $25.1 million, respectively, relating to these other El Dorado equity investments. These
investments are carried at cost, as no impairments or observable price changes have occurred as of March 31, 2026.
v3.26.1
Insider Trading Arrangements
 3 Months Ended
Mar. 31, 2026
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
v3.26.1
Consolidation and Nature of Operations (Policies)
 3 Months Ended
Mar. 31, 2026
Organization, Consolidation and Presentation of Financial Statements [Abstract]  
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 (loss), 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 2024-03, Income Statement Reporting: 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 Consolidated 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. We are currently evaluating the transition method and date of adoption we will elect for this new standard.

ASU 2025-06, Intangibles—Goodwill and Other—Internal-Use Software: Targeted Improvements to the Accounting for Internal-Use Software

In September 2025, a new accounting standard was issued that modernizes the accounting for internal-use software costs by removing references to prescriptive and sequential development stages of a project and replacing them with new criteria used in determining when to start capitalizing software costs. Under the new guidance, capitalization begins when management authorizes and commits to funding the software project and it is probable the project will be completed and used as intended. When determining
if a project is probable of being completed, entities must evaluate whether significant development uncertainty exists, such as unresolved technological innovations or unproven features. The new guidance also clarifies that capitalized internal-use software costs are subject to the existing property, plant, and equipment disclosure requirements.

The standard will become effective for us on January 1, 2028, with early adoption permitted. Entities may adopt the standard using one of the following transition methods: a prospective approach, a retrospective approach, or a modified transition approach that considers in-process projects at the date of adoption. We are currently evaluating the impacts on our financial statements of adopting this new standard and the transition method and date of adoption we will elect. The adoption of this guidance may impact our timing and scope of software costs eligible for capitalization, and may also impact our disclosures relating to software.

ASU 2025-09, Derivatives and Hedging: Hedge Accounting Improvements

In November 2025, a new accounting standard was issued which clarifies certain aspects of the hedge accounting guidance. The new standard is intended to better align hedge accounting with the economics of an entity’s risk management activities, and provides entities the ability to apply hedge accounting to an expanded population of economic hedges of forecasted transactions. The standard will become effective for us on January 1, 2027, applied on a prospective basis. Early adoption is permitted. We expect to adopt this guidance on January 1, 2027. We are not currently applying hedge accounting, and do not expect the adoption of this guidance will have a material impact on our financial statements.

ASU 2025-10, Government Grants: Accounting for Government Grants Received by Business Entities

In December 2025, a new accounting standard was issued establishing authoritative GAAP guidance on the accounting for government grants received by business entities. Prior to the issuance of this new standard, GAAP did not include guidance relating to government grants received by business entities. The new standard is intended to eliminate diversity in practice and improve the financial reporting and consistency across business entities for government grants. The new standard defines government grants and includes recognition, measurement, presentation, and disclosure requirements. The new standard includes guidance pertaining to both government grants received relating to an asset and government grants received relating to income. The guidance includes recognition thresholds based on the probability of compliance with grant conditions and receipt of the grant, among other accounting requirements. Disclosure requirements include the nature and amounts of government grants received, the conditions attached to the grants, and accounting policies applied.
The new standard will become effective for us on January 1, 2029, with early adoption permitted. Entities may adopt the standard using various transition methods, including a modified prospective approach, a modified retrospective approach, or a retrospective approach to all government grants. We are currently evaluating the impacts on our financial statements of adopting this new standard, as well as the date we will adopt this guidance and the transition method we will elect.
v3.26.1
Consolidation and Nature of Operations (Tables)
 3 Months Ended
Mar. 31, 2026
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,
20262025
Cash paid (received) during the period for:
Income taxes, net of refunds/credits$(4)$(10,799)
Interest, net of amounts capitalized118,552 91,475 
Significant non-cash investing and financing activities:
Accrued capital expenditures281,689 315,297 
The following table summarizes supplemental APS cash flow information (dollars in thousands):
Three Months Ended March 31,
20262025
Cash paid (received) during the period for:
Income taxes, net of refunds/credits$101 $(5,392)
Interest, net of amounts capitalized112,181 84,110 
Significant non-cash investing and financing activities:
Accrued capital expenditures281,689 315,297 
v3.26.1
Business Segments (Tables)
 3 Months Ended
Mar. 31, 2026
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 (loss) to the Pinnacle West consolidated amounts (dollars in millions):
Three Months Ended March 31,
20262025
Regulated Electricity SegmentOther Pinnacle West ConsolidatedRegulated Electricity SegmentOther Pinnacle West Consolidated
Operating revenues$1,150 $— $1,150 $1,032 $— $1,032 
Fuel and purchased power (437)— (437)(380)— (380)
Operations and maintenance(273)(4)(277)(297)(3)(300)
Depreciation and amortization (240)— (240)(235)— (235)
Taxes other than income taxes (62)— (62)(59)— (59)
Allowance for equity funds used during construction15 — 15 13 — 13 
Pension and other postretirement non-service credits, net4 — 4 3 — 3 
Other income and (expense), net(3)2 (1)3 11 14 
Interest charges, net of allowance for borrowed funds used during construction(92)(24)(116)(79)(16)(95)
Income (taxes) benefit
(8)7 (1)3 3 6 
Less: Net income attributable to noncontrolling interests(2)— (2)(4)— (4)
Net Income (Loss) Attributable to Common Shareholders
$52 $(19)$33 $— $(5)$(5)
The following table reconciles our reportable segment’s assets to the Pinnacle West consolidated amount (dollars in millions):
March 31, 2026December 31, 2025
Regulated Electricity SegmentOtherPinnacle West ConsolidatedRegulated Electricity SegmentOtherPinnacle West Consolidated
Total Assets$30,524 $167 $30,691 $29,886 $146 $30,032 
v3.26.1
Revenue (Tables)
 3 Months Ended
Mar. 31, 2026
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,
20262025
Retail Electric Service
Residential$493,701 $448,923 
Non-Residential601,733 524,857 
Wholesale Energy Sales14,976 24,824 
Transmission Services for Others32,027 25,547 
Other Sources7,160 8,129 
Total Operating Revenues$1,149,597 $1,032,280 
Schedule of Allowance for Doubtful Accounts
The following table provides a rollforward of Pinnacle West’s allowance for doubtful accounts (dollars in thousands):
Three Months EndedYear Ended
March 31, 2026December 31, 2025
Balance at beginning of period$25,495 $24,849 
Bad debt expense5,728 28,603 
Actual write-offs(6,597)(27,957)
Balance at end of period$24,626 $25,495 
v3.26.1
Debt and Liquidity Matters (Tables)
 3 Months Ended
Mar. 31, 2026
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, 2026As of December 31, 2025
 Carrying
Amount		Fair ValueCarrying
Amount		Fair Value
Pinnacle West$1,666,919 $1,756,235 $1,665,736 $1,731,388 
APS8,734,756 7,874,786 8,139,940 7,433,142 
Total$10,401,675 $9,631,021 $9,805,676 $9,164,530 
v3.26.1
Regulatory Matters (Tables)
 3 Months Ended
Mar. 31, 2026
Regulated Operations [Abstract]  
Schedule of Capital Structure and Cost of Capital the following proposed capital structure and costs of capital:
Capital StructureCost of Capital
Long-term debt47.65 %4.26 %
Common stock equity52.35 %10.70 %
Weighted-average cost of capital7.63 %
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,
 20262025
Balance at beginning of period$149,068 $287,597 
Deferred fuel and purchased power costs26,521 25,228 
Amounts charged to customers
(120,157)(84,789)
Balance at end of period$55,432 $228,036 
Schedule of Regulatory Assets
The detail of regulatory assets is as follows (dollars in thousands):
Amortization ThroughMarch 31,
2026		December 31,
2025
Pension(a)$712,420 $723,042 
Income taxes — AFUDC equity2055205,059 203,890 
Palo Verde sale leaseback noncontrolling interests’ acquisition (b)N/A151,506 151,506 
Ocotillo deferral203496,220 99,931 
Lease incentive (Note 17)
204588,817 90,005 
SCR deferral (c)203875,816 77,186 
Deferred fuel and purchased power — mark-to-market (Note 10)
203058,222 29,330 
Deferred fuel and purchased power (c) (d)202755,432 149,068 
Retired power plant costs203150,695 56,809 
Income taxes — investment tax credit basis adjustment (Note 5)
205642,300 42,459 
Deferred compensation203632,936 32,204 
FERC transmission true up202831,138 21,471 
Deferred property taxes202713,207 15,349 
Palo Verde VIEs (Note 9)
20468,834 8,582 
Mead-Phoenix transmission line — contributions in aid of construction20507,969 8,052 
Loss on reacquired debt20385,416 5,653 
Active union medical trust(e)4,375 3,696 
TEAM (c)20313,715 3,879 
Navajo coal reclamation20261,438 2,516 
PSA - interest2027681 5,679 
DSM (c)2026206 15,706 
OtherVarious4,537 3,353 
Total regulatory assets (f)$1,650,939 $1,749,366 
Less: current regulatory assets$196,729 $286,009 
Total non-current regulatory assets$1,454,210 $1,463,357 
(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/loss and result in lower future revenues.  The 2022 Rate Case decision allows for the full return on the pension asset in rate base. See Note 8 for further discussion.
(b)This asset relates to the purchase of previously leased interest in Palo Verde Unit 2. See Note 9.
(c)See “Cost Recovery Mechanisms” discussion above.
(d)Subject to a carrying charge.
(e)Collected in retail rates.
(f)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.”
Schedule of Regulatory Liabilities
The detail of regulatory liabilities is as follows (dollars in thousands):
Amortization ThroughMarch 31,
2026		December 31,
2025
Excess deferred income taxes - ACC — Tax Cuts and Jobs Act (a)2046$844,409 $847,572 
Excess deferred income taxes - FERC — Tax Cuts and Jobs Act (a)2058199,607 200,161 
AROs and removal costs(b)242,200 286,907 
Other postretirement benefits(c)231,269 233,952 
Four Corners coal reclamation203897,458 97,988 
Income taxes — deferred investment tax credit205681,660 81,949 
Income taxes — change in state rates205456,040 56,260 
RES (d)202753,858 54,551 
Sundance maintenance203125,195 25,668 
Spent nuclear fuel202718,917 20,492 
DSM (d)202611,802 26,228 
TCA Balancing Account (d)2027— 4,860 
TEAM (d) 20323,587 3,738 
Deferred fuel and purchased power — mark-to-market (Note 10)
2030— 3,641 
OtherVarious2,516 3,063 
Total regulatory liabilities$1,868,518 $1,947,030 
Less: current regulatory liabilities$117,241 $210,909 
Total non-current regulatory liabilities$1,751,277 $1,736,121 
(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)In accordance with regulatory accounting, APS accrues removal costs for its regulated assets, even if there is no legal obligation for removal.
(c)See Note 8.
(d)See “Cost Recovery Mechanisms” discussion above.
v3.26.1
Retirement Plans and Other Postretirement Benefits (Tables)
 3 Months Ended
Mar. 31, 2026
Retirement Benefits [Abstract]  
Schedule of Net Periodic Benefit Costs and the Portion of these Costs Charged to Expense
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,
 2026202520262025
Service cost-benefits earned during the period$12,099 $10,949 $2,237 $1,982 
Non-service costs (credits):
Interest cost on benefit obligation37,612 38,976 4,979 5,102 
Expected return on plan assets(44,096)(44,547)(12,719)(12,142)
Amortization of:
Prior service cost (credit)151 — — (1,265)
Net actuarial loss (gain)
11,153 12,118 (2,700)(2,899)
Net periodic benefit costs (credits)
$16,919 $17,496 $(8,203)$(9,222)
Portion of costs (credits) charged to expense
$9,518 $10,461 $(6,509)$(6,873)
v3.26.1
Variable Interest Entities (Tables)
 3 Months Ended
Mar. 31, 2026
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 the VIE (dollars in thousands):
 March 31, 2026
December 31, 2025
Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation$31,641 $32,035 
Equity — Noncontrolling interests42,811 40,617 
v3.26.1
Derivative Accounting (Tables)
 3 Months Ended
Mar. 31, 2026
Derivative Instruments and Hedging Activities Disclosure [Abstract]  
Schedule of Outstanding Gross Notional Amount of Derivatives, which Represents Both Purchases and Sales
The following table shows the outstanding gross notional volume of energy derivatives, which represent both purchases and sales (does not reflect net position):
Quantity
CommodityUnit of MeasureMarch 31, 2026December 31, 2025
PowerGigawatt-hour542 542 
GasBillion cubic feet268 211 
Schedule of Gains and Losses from Derivative Instruments Not Designated as Accounting Hedges Instruments The following table provides information about gains and losses from energy derivative instruments not designated as accounting hedging instruments (dollars in thousands):
Financial Statement Three Months Ended March 31,
Commodity ContractsLocation20262025
Net Gain (Loss) Recognized in Income
Fuel and purchased power (a)$(25,897)$116,704 
(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 (dollars in thousands):

As of March 31, 2026Gross 
Recognized 
Derivatives
 (a)		Amounts 
Offset
(b)		Net
 Recognized
 Derivatives		Other
 (c)		Amounts 
Reported on 
Balance Sheets
Current assets$12,614 $(12,231)$383 $5 $388 
Investments and other assets2,396 (1,930)466 — 466 
Total assets15,010 (14,161)849 5 854 
Current liabilities(65,583)12,231 (53,352)(2,566)(55,918)
Deferred credits and other(7,649)1,930 (5,719)— (5,719)
Total liabilities(73,232)14,161 (59,071)(2,566)(61,637)
Total$(58,222)$— $(58,222)$(2,561)$(60,783)
(a)All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)No cash collateral has been provided to or received by 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 $2,566 thousand and cash margin provided to counterparties of $5 thousand.

As of December 31, 2025Gross
 Recognized
 Derivatives
 (a)		Amounts
Offset 
(b)		Net
 Recognized
 Derivatives		Other
 (c)		Amounts
 Reported on
 Balance Sheets
Current assets$12,640 $(9,395)$3,245 $5 $3,250 
Investments and other assets6,707 (1,570)5,137 — 5,137 
Total assets19,347 (10,965)8,382 5 8,387 
Current liabilities(41,970)9,395 (32,575)(2,566)(35,141)
Deferred credits and other(3,065)1,570 (1,495)— (1,495)
Total liabilities(45,035)10,965 (34,070)(2,566)(36,636)
Total$(25,688)$— $(25,688)$(2,561)$(28,249)
(a)All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)No cash collateral has been provided to or received by 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 $2,566 thousand and cash margin provided to counterparties of $5 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 (dollars in thousands):

As of March 31, 2026Gross 
Recognized 
Derivatives
 (a)		Amounts 
Offset
(b)		Net
 Recognized
 Derivatives		Other
 (c)		Amounts 
Reported on 
Balance Sheets
Current assets$12,614 $(12,231)$383 $5 $388 
Investments and other assets2,396 (1,930)466 — 466 
Total assets15,010 (14,161)849 5 854 
Current liabilities(65,583)12,231 (53,352)(2,566)(55,918)
Deferred credits and other(7,649)1,930 (5,719)— (5,719)
Total liabilities(73,232)14,161 (59,071)(2,566)(61,637)
Total$(58,222)$— $(58,222)$(2,561)$(60,783)
(a)All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)No cash collateral has been provided to or received by 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 $2,566 thousand and cash margin provided to counterparties of $5 thousand.

As of December 31, 2025Gross
 Recognized
 Derivatives
 (a)		Amounts
Offset 
(b)		Net
 Recognized
 Derivatives		Other
 (c)		Amounts
 Reported on
 Balance Sheets
Current assets$12,640 $(9,395)$3,245 $5 $3,250 
Investments and other assets6,707 (1,570)5,137 — 5,137 
Total assets19,347 (10,965)8,382 5 8,387 
Current liabilities(41,970)9,395 (32,575)(2,566)(35,141)
Deferred credits and other(3,065)1,570 (1,495)— (1,495)
Total liabilities(45,035)10,965 (34,070)(2,566)(36,636)
Total$(25,688)$— $(25,688)$(2,561)$(28,249)
(a)All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)No cash collateral has been provided to or received by 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 $2,566 thousand and cash margin provided to counterparties of $5 thousand.
Schedule of Information about Derivative Instruments that have Credit-Risk-Related Contingent Features
The following table provides information about our energy derivative instruments that have credit-risk-related contingent features (dollars in thousands):
 March 31, 2026
Aggregate fair value of derivative instruments in a net liability position$69,364 
Additional collateral in the event credit-risk related contingent features were fully triggered (a)30,038 
(a)This amount is after counterparty netting and includes those contracts which qualify for scope exceptions, which are excluded from the derivative details above.
v3.26.1
Other Income and Other Expense (Tables)
 3 Months Ended
Mar. 31, 2026
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,
 20262025
Other income:
Interest income $2,881 $5,996 
Investment gain — net (a)1,792 10,984 
Miscellaneous308 481 
Total other income$4,981 $17,461 
Other expense:
Non-operating costs$(2,462)$(2,229)
Miscellaneous(278)(341)
Total other expense$(2,740)$(2,570)
(a)Primarily relates to El Dorado investment activities. See Note 18.
The following table provides detail of APS’s other income and other expense (dollars in thousands):
Three Months Ended March 31,
 20262025
Other income:
Interest income$2,520 $5,607 
Miscellaneous125 115 
 Total other income$2,645 $5,722 
Other expense:
Non-operating costs$(2,390)$(1,992)
Miscellaneous(278)(341)
Total other expense$(2,668)$(2,333)
v3.26.1
Common Stock Equity and Earnings Per Share (Tables)
 3 Months Ended
Mar. 31, 2026
Earnings Per Share [Abstract]  
Schedule of Sale of Stock by Subsidiary or Equity Method Investee Disclosure
The following table presents information about the outstanding ATM Forward Sale Agreements as of March 31, 2026 based on their contractual terms at the time each agreement was entered into, including the applicable forward sale prices and related aggregate contractual values, which may differ from the gross amount of common stock referenced above (dollars in thousands, except price per share):

ATM Forward Sale AgreementsMaturity Date (a)Number of SharesForward Sales Price Per Share (b)Aggregate Value
November 2024June 30, 2026552,833 $89.73 $49,606 
March 2025September 14, 2026544,959 $90.83 $49,499 
August 2025February 16, 2027543,001 $91.21 $49,527 
September 2025February 22, 2027558,622 $88.69 $49,544 
January 2026July 2, 2027119,553 $89.88 $10,745 
March 2026September 3, 2027646,674 $99.52 $64,357 
March 2026September 10, 2027490,537 $100.94 $49,515 
March 2026September 18, 2027488,813 $101.28 $49,507 
March 2026September 30, 2027916,930 $98.12 $89,969 
4,861,922 $95.08 (c)$462,269 
(a)    Maturity date may be extended.
(b)    Subject to certain adjustments.
(c)    Total weighted-average share price.
The following table presents information about the outstanding February 2024 Forward Sale Agreements as of March 31, 2026 (dollars in thousands, except price per share):

February 2024 Forward Sale AgreementsNumber of SharesForward Sales Price Per ShareAggregate Value
Initial Price11,240,601 $64.51 (a)$725,131 
Settlements
December 23, 20245,377,115 (b)$64.17 $345,049 (c)
September 4, 2025243,186 (b)$63.12 $15,350 (c)
December 18, 20251,193,950 (b)$62.82 $75,004 (c)
(a)    Subject to certain adjustments.
(b)    Physical delivery.
(c)    Proceeds recorded in common equity on the Condensed Consolidated Balance Sheets.
Schedule of Earnings Per Share, Basic and Diluted
The following table presents the calculation of Pinnacle West’s basic and diluted EPS (dollars and shares in thousands, except earnings per share amounts):
Three Months Ended March 31,
 20262025
Net income (loss) attributable to common shareholders
$32,920 $(4,644)
Weighted average common shares outstanding — basic121,360 119,594 
Net effect of dilutive securities:
Contingently issuable performance shares and restricted stock units444 498 
Dilutive shares related to equity forward sale agreements (a)1,722 1,669 
Dilutive shares related to convertible debt instruments (b)252 — 
Total contingently issuable shares (c)2,418 2,167 
Weighted average common shares outstanding — diluted123,778 121,761 
Earnings per weighted-average common share outstanding
Net income (loss) attributable to common shareholders — basic
$0.27 $(0.04)
Net income (loss) attributable to common shareholders — diluted
$0.27 $(0.04)
(a)    For the three months ended March 31, 2026 and 2025 the diluted weighted-average common shares excludes 16,127 and 4,636 shares, respectively relating to the ATM Program. These potentially issuable shares were excluded from the calculation of diluted shares as their inclusion would have been antidilutive.
(b)     For the three months ended March 31, 2026 and 2025 the diluted weighted-average common shares excludes 0 and 192,754 shares, respectively relating to the Convertible Notes. These potentially issuable shares were excluded from the calculation of diluted shares as their inclusion would have been antidilutive.
(c)    No contingently issuable shares were excluded from the calculation of diluted weighted-average common shares outstanding for the three months ended March 31, 2026. For the three months ended March 31, 2025, 2,167,000 contingently issuable shares 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.
v3.26.1
Fair Value Measurements (Tables)
 3 Months Ended
Mar. 31, 2026
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, 2026 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):

Level 1Level 2Level 3OtherTotal
ASSETS
Risk management activities — derivative instruments:
Commodity contracts$— $11,142 $— $(10,288)(a)$854 
Nuclear decommissioning trusts:
Equity securities18,541 — — 3,557 (b)22,098 
U.S. commingled equity funds— — — 478,770 (c)478,770 
U.S. Treasury debt369,970 — — — 369,970 
Corporate debt— 249,372 — — 249,372 
Mortgage-backed securities— 217,924 — — 217,924 
Municipal bonds— 34,288 — — 34,288 
Other fixed income— 20,395 — — 20,395 
Subtotal nuclear decommissioning trusts388,511 521,979 — 482,327 1,392,817 
Other special use funds:
Equity securities64,850 — — 2,012 (b)66,862 
U.S. Treasury debt370,883 — — — 370,883 
Subtotal other special use funds (d)435,733 — — 2,012 437,745 
Total assets$824,244 $533,121 $— $474,051 $1,831,416 
LIABILITIES
Risk management activities — derivative instruments:
Commodity contracts$— $(35,908)$(33,456)$7,727 (a)$(61,637)
(a)Represents counterparty netting, margin, and collateral. See Note 10.
(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 $41.4 million related to Pinnacle West’s Captive investments that are classified within Level 1 equity securities. See Note 9.
 The following table presents the fair value at December 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
Risk management activities — derivative instruments:
Commodity contracts$— $19,347 $— $(10,960)(a)$8,387 
Nuclear decommissioning trusts:
Equity securities18,970 — — (3,799)(b)15,171 
U.S. commingled equity funds— — — 500,592 (c)500,592 
U.S. Treasury debt364,943 — — — 364,943 
Corporate debt— 242,176 — — 242,176 
Mortgage-backed securities— 230,695 — — 230,695 
Municipal bonds— 37,572 — — 37,572 
Other fixed income— 23,017 — — 23,017 
Subtotal nuclear decommissioning trusts383,913 533,460 — 496,793 1,414,166 
Other special use funds:
Equity securities62,573 — — 3,199 (b)65,772 
U.S. Treasury debt369,055 — — — 369,055 
Subtotal other special use funds (d)431,628 — — 3,199 434,827 
Total assets$815,541 $552,807 $— $489,032 $1,857,380 
LIABILITIES
Risk management activities — derivative instruments:
Commodity contracts$— $(21,325)$(23,710)$8,399 (a)$(36,636)
(a)Represents counterparty netting, margin, and collateral. See Note 10.
(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 $40.3 million related to Pinnacle West’s Captive investments that are classified within Level 1 equity securities. See Note 9.
The following table shows the changes in fair value for our risk management activities’ assets and liabilities that are measured at fair value on a recurring basis using Level 3 inputs (dollars in thousands):
 Three Months Ended March 31,
Commodity Contracts20262025
Balance at beginning of period$(23,710)$(15,039)
Total net losses realized/unrealized:
Deferred as a regulatory asset or liability(14,577)(5,823)
Settlements4,831 (2,287)
Transfers into Level 3 from Level 2— (59)
Transfers from Level 3 into Level 2— 368 
Balance at end of period$(33,456)$(22,840)
Net unrealized gains/losses included in earnings related to instruments still held at end of period$— $— 
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, 2026 and December 31, 2025 (dollars in thousands):

March 31, 2026
 Fair Value 		ValuationSignificantWeighted-Average
Commodity ContractsAssetsLiabilitiesTechniqueUnobservable InputRange (b)
Electricity:
Electricity Forward Contracts (a)$— $26,789 Discounted cash flowsElectricity forward price (per MWh)
$31.79
-
$138.31
$71.57
Natural Gas Forward Contracts (a)— 6,667 Discounted cash flowsNatural gas forward price (per Million British Thermal Units (“MMBtu”))
$(0.79)
-
$0.14
$0.03
Total$— $33,456 
(a)Includes swaps and physical and financial contracts.
(b)Unobservable inputs were weighted by the relative fair value of the instrument.

December 31, 2025
 Fair Value 		ValuationSignificantWeighted-Average
Commodity ContractsAssetsLiabilitiesTechniqueUnobservable InputRange(b)
Electricity Forward Contracts (a)$— $21,913 Discounted cash flowsElectricity forward price (per MWh)$41.51 -$149.37$80.20
Natural Gas Forward Contracts (a)— 1,797 Discounted cash flowsNatural gas forward price (per MMBtu)$(0.07)-$0.36$0.04
Total$— $23,710 
(a)Includes swaps and physical and financial contracts.
(b)Unobservable inputs were weighted by the relative fair value of the instrument.
v3.26.1
Investments in Nuclear Decommissioning Trusts and Other Special Use Funds (Tables)
 3 Months Ended
Mar. 31, 2026
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, 2026
 Fair ValueTotal
Unrealized
Gains		Total
Unrealized
Losses
Investment Type:Nuclear Decommissioning TrustsOther Special Use FundsTotal
Equity securities$497,311 $64,850 $562,161 $407,542 (d)$(139)
Available for sale-fixed income securities891,949 370,883 1,262,832 (a)11,497 (18,344)
Other3,557 2,012 5,569 (b)— — 
Total$1,392,817 $437,745 $1,830,562 (c)$419,039 $(18,483)
(a)As of March 31, 2026, the amortized cost basis of these available-for-sale investments is $1,270 million.
(b)Represents net pending securities sales and purchases.
(c)All amounts pertain to APS, with the exception of $41.4 million of other special use fund investments in equity securities relating to investments held by the Captive.
(d)All amounts pertain to APS, with the exception of $2.8 million of unrealized gains relating to investments held by the Captive.
December 31, 2025
 Fair ValueTotal
Unrealized
Gains		Total
Unrealized
Losses
Investment Type:Nuclear Decommissioning TrustsOther Special Use FundsTotal
Equity securities$519,562 $62,573 $582,135 $433,044 (d)$(1)
Available for sale-fixed income securities898,403 369,055 1,267,458 (a)18,765 (14,993)
Other(3,799)3,199 (600)(b)— — 
Total$1,414,166 $434,827 $1,848,993 (c)$451,809 $(14,994)
(a)As of December 31, 2025, the amortized cost basis of these available-for-sale investments is $1,265 million.
(b)Represents net pending securities sales and purchases.
(c)All amounts pertain to APS, with the exception of $40.3 million of other special use fund investments in equity securities relating to investments held by the Captive.
(d)All amounts pertain to APS, with the exception of $3.2 million of unrealized gains relating to investments held by 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
2026
Realized gains$4,720 $16 $4,736 
Realized losses$(2,797)$— $(2,797)
Proceeds from the sale of securities (a)$447,883 $64,351 (b)$512,234 
2025
Realized gains$1,658 $— $1,658 
Realized losses$(2,761)$— $(2,761)
Proceeds from the sale of securities (a)$416,601 $69,213 (c)$485,814 
(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.
(c)    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, 2026 is as follows (dollars in thousands):
 
 Nuclear Decommissioning TrustsCoal Reclamation Escrow AccountActive Union Employee Medical AccountTotal
Less than one year$32,191 $108,470 $39,753 $180,414 
1 year – 5 years299,067 49,806 156,363 505,236 
5 years – 10 years168,027 — 16,491 184,518 
Greater than 10 years392,664 — — 392,664 
Total$891,949 $158,276 $212,607 $1,262,832 
v3.26.1
Changes in Accumulated Other Comprehensive Loss (Tables)
 3 Months Ended
Mar. 31, 2026
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, 2025
$(32,980)$572 $(32,408)
Other comprehensive loss before reclassifications
— (43)(43)
Amounts reclassified from accumulated other comprehensive loss
502  (a)— 502 
Balance March 31, 2026
$(32,478)$529 $(31,949)
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)
(a)    These amounts primarily represent amortization of actuarial loss and are included in the computation of net periodic pension cost.  See Note 8.
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, 2025
$(15,457)
Other comprehensive loss before reclassifications
— 
Amounts reclassified from accumulated other comprehensive loss
410  (a)
Balance March 31, 2026
$(15,047)
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)
(a) These amounts primarily represent amortization of actuarial loss and are included in the computation of net periodic pension cost.  See Note 8.
v3.26.1
Leases (Tables)
 3 Months Ended
Mar. 31, 2026
Leases [Abstract]  
Schedule of Lease Costs
The following table provides information related to our lease costs (dollars in thousands):

Three Months Ended March 31,
20262025
Operating Lease Cost - PPAs and Energy Storage PPA Lease Contracts$54,390 $12,547 
Operating Lease Cost - Land, Property, and Other Equipment6,301 5,337 
Total Operating Lease Cost60,691 17,884 
Variable Lease Cost (a)25,313 21,370 
Short-term Lease Cost875 592 
Total Lease Cost$86,879 $39,846 
(a)    Primarily relates to PPA lease contracts.
The following tables provide other additional information related to operating lease liabilities (dollars in thousands):
Three Months Ended March 31,
20262025
Cash paid for amounts included in the measurement of lease liabilities — operating cash flows$61,114 $17,207 
Right-of-use operating lease assets obtained in exchange for operating lease liabilities$404,869 (a)$763,437 (b)

March 31, 2026December 31, 2025
Weighted average remaining lease term17 years15 years
Weighted average discount rate (c)8.72 %5.48 %
(a)Primarily relates to two PPA operating lease agreements that were modified in 2026.
(b)Primarily relates to the three new energy storage operating lease agreements that commenced in 2025.
(c)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, 2026
YearPPAs and Energy Storage PPA Lease ContractsLand, Property and Equipment LeasesTotal
2026 (remaining nine months of 2026)$308,967 $16,360 $325,327 
2027391,311 19,667 410,978 
2028431,553 16,975 448,528 
2029436,730 14,842 451,572 
2030442,013 10,620 452,633 
2031447,410 4,719 452,129 
Thereafter5,478,135 55,397 5,533,532 
Total lease commitments7,936,119 138,580 8,074,699 
Less imputed interest3,885,636 41,552 3,927,188 
Total lease liabilities$4,050,483 $97,028 $4,147,511 
v3.26.1
El Dorado Equity Investments (Tables)
 3 Months Ended
Mar. 31, 2026
Equity Method Investments and Joint Ventures [Abstract]  
Schedule of El Dorado's Ownership Percentages and Carrying Value of Equity Method Investments The following table presents El Dorado’s ownership percentages and carrying value of investments accounted for under the equity method (dollars in millions):
Investee
Pinnacle West Ownership Percentage as of March 31, 2026
March 31, 2026December 31, 2025
SAI (a)17 %$26 $21 
Copper Sky (b)23 %16 15 
Total equity method investments$42 $36 
(a)El Dorado has no further funding commitments to SAI.
(b)El Dorado has a $25.0 million funding commitment to Copper Sky, previously AZ-VC, of which approximately $16.8 million has been funded as of March 31, 2026.
v3.26.1
Consolidation and Nature of Operations - Additional Information (Details) - Variable Interest Entity - APS - trust
Mar. 31, 2026
Sep. 30, 2025
Dec. 31, 1986
Utility Plant and Depreciation [Line Items]      
Number of VIE lessor trusts acquired   2  
Number of VIE lessor trusts 1   3
v3.26.1
Consolidation and Nature of Operations - Schedule of Supplemental Cash Flow Information (Details) - USD ($)
$ in Thousands
 3 Months Ended
Mar. 31, 2026
Mar. 31, 2025
Cash and Cash Equivalents [Line Items]    
Income taxes, net of refunds/credits $ (4) $ (10,799)
Interest, net of amounts capitalized 118,552 91,475
Significant non-cash investing and financing activities:    
Accrued capital expenditures 281,689 315,297
APS    
Cash and Cash Equivalents [Line Items]    
Income taxes, net of refunds/credits 101 (5,392)
Interest, net of amounts capitalized 112,181 84,110
Significant non-cash investing and financing activities:    
Accrued capital expenditures $ 281,689 $ 315,297
v3.26.1
Business Segments (Details)
$ in Thousands
 3 Months Ended
Mar. 31, 2026
USD ($)
segment
Mar. 31, 2025
USD ($)
Dec. 31, 2025
USD ($)
Revenue from External Customer [Line Items]      
Operating revenues $ 1,149,597 $ 1,032,280  
Fuel and purchased power 436,729 380,071  
Operations and maintenance 276,700 300,109  
Depreciation and amortization 239,858 234,940  
Taxes other than income taxes 61,972 59,354  
Allowance for equity funds used during construction 14,782 13,249  
Pension and other postretirement non-service credits, net 3,982 2,958  
Interest charges, net of allowance for borrowed funds used during construction (115,896) (94,841)  
Income (taxes) benefit 1,169 (6,183)  
Less: Comprehensive income attributable to noncontrolling interests 2,194 4,306  
Net Income (Loss) Attributable to Common Shareholders 32,920 (4,644)  
Total Assets $ 30,690,627   $ 30,031,599
Number of reportable segments | segment 1    
Pinnacle West Consolidated | Pinnacle West Consolidated      
Revenue from External Customer [Line Items]      
Operating revenues $ 1,150,000 1,032,000  
Fuel and purchased power (437,000) (380,000)  
Operations and maintenance (277,000) (300,000)  
Depreciation and amortization (240,000) (235,000)  
Taxes other than income taxes (62,000) (59,000)  
Allowance for equity funds used during construction 15,000 13,000  
Pension and other postretirement non-service credits, net 4,000 3,000  
Other income and (expense), net (1,000) 14,000  
Interest charges, net of allowance for borrowed funds used during construction (116,000) (95,000)  
Income (taxes) benefit (1,000) 6,000  
Less: Comprehensive income attributable to noncontrolling interests (2,000) (4,000)  
Net Income (Loss) Attributable to Common Shareholders 33,000 (5,000)  
Total Assets 30,691,000   30,032,000
Regulated Electricity Segment      
Revenue from External Customer [Line Items]      
Operating revenues 1,150,000 1,032,000  
Fuel and purchased power (437,000) (380,000)  
Operations and maintenance (273,000) (297,000)  
Depreciation and amortization (240,000) (235,000)  
Taxes other than income taxes (62,000) (59,000)  
Allowance for equity funds used during construction 15,000 13,000  
Pension and other postretirement non-service credits, net 4,000 3,000  
Other income and (expense), net (3,000) 3,000  
Interest charges, net of allowance for borrowed funds used during construction (92,000) (79,000)  
Income (taxes) benefit (8,000) 3,000  
Less: Comprehensive income attributable to noncontrolling interests (2,000) (4,000)  
Net Income (Loss) Attributable to Common Shareholders 52,000 0  
Total Assets 30,524,000   29,886,000
Other      
Revenue from External Customer [Line Items]      
Operating revenues 0 0  
Fuel and purchased power 0 0  
Operations and maintenance (4,000) (3,000)  
Depreciation and amortization 0 0  
Taxes other than income taxes 0 0  
Allowance for equity funds used during construction 0 0  
Pension and other postretirement non-service credits, net 0 0  
Other income and (expense), net 2,000 11,000  
Interest charges, net of allowance for borrowed funds used during construction (24,000) (16,000)  
Income (taxes) benefit 7,000 3,000  
Less: Comprehensive income attributable to noncontrolling interests 0 0  
Net Income (Loss) Attributable to Common Shareholders (19,000) $ (5,000)  
Total Assets $ 167,000   $ 146,000
v3.26.1
Revenue - Schedule of Disaggregation of Revenue (Details) - USD ($)
$ in Thousands
 3 Months Ended
Mar. 31, 2026
Mar. 31, 2025
Disaggregation of Revenue [Line Items]    
Total Operating Revenues $ 1,149,597 $ 1,032,280
Wholesale Energy Sales    
Disaggregation of Revenue [Line Items]    
Total Operating Revenues 14,976 24,824
Transmission Services for Others    
Disaggregation of Revenue [Line Items]    
Total Operating Revenues 32,027 25,547
Other Sources    
Disaggregation of Revenue [Line Items]    
Total Operating Revenues 7,160 8,129
Residential | Retail Electric Service    
Disaggregation of Revenue [Line Items]    
Total Operating Revenues 493,701 448,923
Non-Residential | Retail Electric Service    
Disaggregation of Revenue [Line Items]    
Total Operating Revenues $ 601,733 $ 524,857
v3.26.1
Revenue - Additional Information (Details) - USD ($)
$ in Thousands
 3 Months Ended
Mar. 31, 2026
Mar. 31, 2025
Disaggregation of Revenue [Line Items]    
Operating revenues $ 1,149,597 $ 1,032,280
Regulatory cost recovery revenue $ 26,000 13,000
Retail Electric Service    
Disaggregation of Revenue [Line Items]    
Revenue from contract with customer, payment terms 21 days  
Electric and Transmission Service    
Disaggregation of Revenue [Line Items]    
Operating revenues $ 1,124,000 $ 1,019,000
v3.26.1
Revenue - Schedule of Allowance for Doubtful Accounts (Details) - USD ($)
$ in Thousands
 3 Months Ended 12 Months Ended
Mar. 31, 2026
Dec. 31, 2025
Accounts Receivable, Allowance for Credit Loss [Roll Forward]    
Balance at beginning of period $ 25,495 $ 24,849
Bad debt expense 5,728 28,603
Actual write-offs (6,597) (27,957)
Balance at end of period $ 24,626 $ 25,495
v3.26.1
Income Taxes (Details)
$ in Millions
 3 Months Ended
Mar. 31, 2026
USD ($)
Tax Year 2024  
Income Taxes  
Income tax benefits $ 33.4
Tax Year 2025  
Income Taxes  
Income tax benefits $ 39.6
v3.26.1
Debt and Liquidity Matters - Additional Information (Details) - USD ($)
$ in Millions
 3 Months Ended
Dec. 03, 2025
Mar. 31, 2026
Mar. 10, 2026
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  
Senior Unsecured Notes Maturing March 2036 | APS | Senior Notes      
Long-Term Debt and Liquidity Matters [Line Items]      
Notes issued     $ 600.0
Interest rate     5.10%
Revolving credit facility | Revolving Credit Facility Maturing April 2029 | APS      
Long-Term Debt and Liquidity Matters [Line Items]      
Current borrowing capacity on credit facility   $ 1,700.0  
Accordion feature, increase increment   400.0  
Accordion feature, increase limit   2,100.0  
Long-term line of credit   $ 0.0  
Debt, weighted average interest rate   3.96%  
Letter of Credit | APS      
Long-Term Debt and Liquidity Matters [Line Items]      
Outstanding letters of credit   $ 31.8  
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   1,500.0  
Commercial paper | Revolving Credit Facility Maturing April 2029 | APS      
Long-Term Debt and Liquidity Matters [Line Items]      
Commercial paper   $ 316.0  
Pinnacle West Consolidated | Term Loan Facility Maturing December 3, 2026      
Long-Term Debt and Liquidity Matters [Line Items]      
Debt instrument term   364 days  
Notes issued   $ 175.0  
Debt instrument, basis spread on variable rate   0.80%  
Loan amount drawn $ 175.0    
Pinnacle West Consolidated | Revolving credit facility | Revolving Credit Facility Maturing April 2029      
Long-Term Debt and Liquidity Matters [Line Items]      
Current borrowing capacity on credit facility   $ 300.0  
Accordion feature, increase increment   100.0  
Accordion feature, increase limit   400.0  
Long-term line of credit   0.0  
Pinnacle West Consolidated | 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 Consolidated | Commercial paper | Revolving Credit Facility Maturing April 2029      
Long-Term Debt and Liquidity Matters [Line Items]      
Current borrowing capacity on credit facility   300.0  
Commercial paper   $ 103.0  
Debt, weighted average interest rate   3.93%  
v3.26.1
Debt and Liquidity Matters - Schedule of Estimated Fair Value of Long-Term Debt, Including Current Maturities (Details) - USD ($)
$ in Thousands
Mar. 31, 2026
Dec. 31, 2025
Long-Term Debt and Liquidity Matters [Line Items]    
Carrying Amount $ 10,401,675 $ 9,805,676
Fair Value 9,631,021 9,164,530
APS    
Long-Term Debt and Liquidity Matters [Line Items]    
Carrying Amount 8,734,756 8,139,940
Fair Value 7,874,786 7,433,142
Pinnacle West    
Long-Term Debt and Liquidity Matters [Line Items]    
Carrying Amount 1,666,919 1,665,736
Fair Value $ 1,756,235 $ 1,731,388
v3.26.1
Regulatory Matters - ACC General Retail Rate Cases (Details)
$ in Millions
Apr. 03, 2026
USD ($)
Mar. 18, 2026
USD ($)
Mar. 02, 2026
USD ($)
Jun. 13, 2025
USD ($)
$ / KWH_Kilowatt_hour
Feb. 22, 2024
USD ($)
Mar. 31, 2026
Public Utilities, General Disclosures [Line Items]            
Requested rate increase (decrease), amount   $ 525.2        
Increment of fair value rate, percentage     0.00%      
Requested period of post-test year plant   12 months        
Approved rate increase (decrease), amount         $ 491.7  
Minimum            
Public Utilities, General Disclosures [Line Items]            
Requested rate increase (decrease), amount     $ 200.2      
Requested return on equity, percentage   9.55% 9.00%      
Requested period of post-test year plant     0 months      
Maximum            
Public Utilities, General Disclosures [Line Items]            
Requested rate increase (decrease), amount     $ 278.1      
Requested return on equity, percentage   9.80% 9.20%      
Requested period of post-test year plant     12 months      
APS            
Public Utilities, General Disclosures [Line Items]            
Increment of fair value rate, percentage           1.00%
APS | Subsequent Event            
Public Utilities, General Disclosures [Line Items]            
Requested rate increase (decrease), amount $ 694.2          
Requested return on equity, percentage 10.70%          
Increment of fair value rate, percentage 0.90%          
Requested period of post-test year plant 12 months          
Requested net revenue requirement increase (decrease), amount $ 611.3          
Requested increase (decrease) in deadband 0.0040          
Requested projected plant duration 6 months          
Requested review and challenge period 120 days          
ACC            
Public Utilities, General Disclosures [Line Items]            
Increment of fair value rate, percentage   0.20%     0.25%  
Approved return on equity, percentage         9.55%  
ACC | APS            
Public Utilities, General Disclosures [Line Items]            
Requested rate increase (decrease), amount       $ 579.5    
Total revenue deficiency       $ 662.4    
ACC | APS | Rate Case Filing with Arizona Corporation Commission            
Public Utilities, General Disclosures [Line Items]            
Requested rate increase (decrease), percentage       13.99%    
Public utilities, test period       12 months    
Rate matter, cost base rate       $ 12,500.0    
Effective fair value percentage         4.39%  
ACC | ACC | Rate Case Filing with Arizona Corporation Commission            
Public Utilities, General Disclosures [Line Items]            
Base fuel and purchased power costs rate (in dollars per kWh) | $ / KWH_Kilowatt_hour       0.043881    
v3.26.1
Regulatory Matters - Schedule Of Capital Structure And Cost Of Capital (Details) - APS - Rate Case Filing with Arizona Corporation Commission - ACC
Jun. 13, 2025
Capital Structure  
Requested debt capital structure, percentage 47.65%
Requested equity capital structure, percentage 52.35%
Cost of Capital  
Requested Long-term debt cost of capital, percentage 4.26%
Requested equity cost of capital, percentage 10.70%
Requested weighted average cost of capital, percentage 7.63%
v3.26.1
Regulatory Matters - Cost Recovery Mechanisms (Details)
 3 Months Ended
May 01, 2026
$ / kWh
Nov. 26, 2025
$ / kWh
Aug. 14, 2025
$ / kWh
Jul. 31, 2025
USD ($)
Jun. 01, 2025
USD ($)
Nov. 27, 2024
$ / kWh
Aug. 13, 2024
$ / kWh
Jul. 31, 2024
USD ($)
Jun. 01, 2024
USD ($)
MW
Nov. 30, 2023
USD ($)
$ / kWh
Oct. 11, 2023
Jul. 31, 2023
USD ($)
Jul. 01, 2023
USD ($)
$ / KWH_Kilowatt_hour
Jun. 01, 2023
USD ($)
Feb. 01, 2023
$ / kWh
Feb. 01, 2022
$ / kWh
Mar. 31, 2026
USD ($)
$ / kWh
Dec. 03, 2025
USD ($)
Aug. 31, 2025
USD ($)
Jul. 01, 2025
USD ($)
Jun. 30, 2025
USD ($)
Apr. 22, 2025
USD ($)
Jul. 01, 2024
USD ($)
Jun. 30, 2023
USD ($)
May 31, 2023
USD ($)
Nov. 30, 2022
USD ($)
Jul. 01, 2022
USD ($)
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                                       $ 110,100,000     $ 92,700,000 $ 95,100,000     $ 86,200,000
Demand Side Management Adjustor Charge 2024 | ACC | APS                                                      
Public Utilities, General Disclosures [Line Items]                                                      
Amount of proposed budget                   $ 91,500,000                                  
Approved rate, amount of customer refunds       $ 7,600,000                                   $ 9,000,000          
Rate matter, updated budget                                   $ 40,000,000     $ 90,900,000            
Renewable Energy Adjustment Charge | ACC | APS                                                      
Public Utilities, General Disclosures [Line Items]                                                      
Approved rate, amount of customer refunds                                     $ 44,200,000     $ 43,000,000          
Demand Side Management Adjustor Charge 2023 | ACC | APS                                                      
Public Utilities, General Disclosures [Line Items]                                                      
Amount of proposed budget                                                 $ 88,000,000 $ 88,000,000  
Power Supply Adjustor (PSA) | ACC | APS                                                      
Public Utilities, General Disclosures [Line Items]                                                      
PSA rate (in dollars per kWh) | $ / kWh   0.016977       0.013977                 0.006                        
Reporting threshold of balancing account                   $ 100,000,000                                  
Overall approved PSA rate (in dollars per kWh) | $ / kWh                   0.011977                                  
Forward component of PSA rate (in dollars per kWh) | $ / kWh   0.012457       (0.000281)       (0.012624)                                  
Historical component of PSA rate (in dollars per kWh) | $ / kWh   0.00452       0.008728       0.013071                                  
Transition component of PSA rate | $ / kWh   0       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                     0.006                    
PSA rate in prior years (in dollars per kWh) | $ / kWh   0.003       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         $ 119,000,000.0       $ 27,400,000         $ 34,700,000                          
Rate matters, increase (decrease) in cost recovery, wholesale customer rates         4,600,000       16,600,000         20,700,000                          
Rate matters, increase (decrease) in cost recovery, retail customer rates         114,400,000       10,800,000         14,000,000                          
Rate matters, increase (decrease) In retail revenue requirements         $ 88,300,000       $ 8,800,000         $ (10,000,000)                          
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       60,100,000       $ 49,600,000       $ 68,700,000                              
Amount of adjustment representing annual recovery       $ 10,500,000       $ 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                                 $ 46,900,000                    
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%                    
Third-year export energy price (in dollars per kWh) | $ / kWh     0.06171       0.06857                                        
Rate lock period                     10 years                                
Net Metering | ACC | APS | Subsequent Event                                                      
Public Utilities, General Disclosures [Line Items]                                                      
Rate matters, cost of service, resource comparison proxy method, maximum annual percentage decrease 10.00%                                                    
Third-year export energy price (in dollars per kWh) | $ / kWh 0.05554                                                    
v3.26.1
Regulatory Matters - Schedule of Changes in The Deferred Fuel and Purchased Power Regulatory Asset (Details) - USD ($)
$ in Thousands
 3 Months Ended
Mar. 31, 2026
Mar. 31, 2025
Change in regulatory asset    
Deferred fuel and purchased power costs $ 26,521 $ 25,228
Amounts charged to customers (120,157) (84,789)
APS    
Change in regulatory asset    
Deferred fuel and purchased power costs 26,521 25,228
Amounts charged to customers (120,157) (84,789)
Power Supply Adjustor (PSA) | ACC | APS    
Change in regulatory asset    
Balance at beginning of period 149,068 287,597
Deferred fuel and purchased power costs 26,521 25,228
Amounts charged to customers (120,157) (84,789)
Balance at end of period $ 55,432 $ 228,036
v3.26.1
Regulatory Matters - Cholla and Navajo Plant (Details) - APS - USD ($)
$ in Millions
Mar. 31, 2026
Apr. 30, 2025
Navajo Nation, Economic Development Organization | Coal Community Transition Plan | Rate Case Filing with Arizona Corporation Commission | ACC    
Acquisition    
Disallowance of annual amortization percentage 15.00%  
Cholla Units 1 & 3    
Acquisition    
Net book value   $ 81.0
Retired power plant costs    
Acquisition    
Net book value $ 22.4  
Navajo Plant    
Acquisition    
Net book value 21.4  
Navajo Plant, Coal Reclamation Regulatory Asset    
Acquisition    
Net book value $ 1.4  
v3.26.1
Regulatory Matters - Schedule of Regulatory Assets (Details) - USD ($)
$ in Thousands
Mar. 31, 2026
Dec. 31, 2025
Detail of regulatory assets    
Total regulatory assets $ 1,650,939 $ 1,749,366
Less: current regulatory assets 196,729 286,009
Total non-current regulatory assets 1,454,210 1,463,357
Pension    
Detail of regulatory assets    
Total regulatory assets 712,420 723,042
Income taxes — AFUDC equity    
Detail of regulatory assets    
Total regulatory assets 205,059 203,890
Palo Verde sale leaseback noncontrolling interests acquisition    
Detail of regulatory assets    
Total regulatory assets 151,506 151,506
Ocotillo deferral    
Detail of regulatory assets    
Total regulatory assets 96,220 99,931
Lease incentive (Note 17)    
Detail of regulatory assets    
Total regulatory assets 88,817 90,005
SCR deferral    
Detail of regulatory assets    
Total regulatory assets 75,816 77,186
Deferred fuel and purchased power — mark-to-market (Note 10)    
Detail of regulatory assets    
Total regulatory assets 58,222 29,330
Deferred fuel and purchased power    
Detail of regulatory assets    
Total regulatory assets 55,432 149,068
Retired power plant costs    
Detail of regulatory assets    
Total regulatory assets 50,695 56,809
Income taxes — investment tax credit basis adjustment (Note 5)    
Detail of regulatory assets    
Total regulatory assets 42,300 42,459
Deferred compensation    
Detail of regulatory assets    
Total regulatory assets 32,936 32,204
FERC transmission true up    
Detail of regulatory assets    
Total regulatory assets 31,138 21,471
Deferred property taxes    
Detail of regulatory assets    
Total regulatory assets 13,207 15,349
Palo Verde VIEs (Note 9)    
Detail of regulatory assets    
Total regulatory assets 8,834 8,582
Mead-Phoenix transmission line — contributions in aid of construction    
Detail of regulatory assets    
Total regulatory assets 7,969 8,052
Loss on reacquired debt    
Detail of regulatory assets    
Total regulatory assets 5,416 5,653
Active union medical trust    
Detail of regulatory assets    
Total regulatory assets 4,375 3,696
TEAM    
Detail of regulatory assets    
Total regulatory assets 3,715 3,879
Navajo coal reclamation    
Detail of regulatory assets    
Total regulatory assets 1,438 2,516
PSA - interest    
Detail of regulatory assets    
Total regulatory assets 681 5,679
DSM    
Detail of regulatory assets    
Total regulatory assets 206 15,706
Other    
Detail of regulatory assets    
Total regulatory assets $ 4,537 $ 3,353
v3.26.1
Regulatory Matters - Schedule of Regulatory Liabilities (Details) - USD ($)
$ in Thousands
Mar. 31, 2026
Dec. 31, 2025
Detail of regulatory liabilities    
Total regulatory liabilities $ 1,868,518 $ 1,947,030
Less: current regulatory liabilities 117,241 210,909
Total non-current regulatory liabilities 1,751,277 1,736,121
AROs and removal costs    
Detail of regulatory liabilities    
Total regulatory liabilities 242,200 286,907
Other postretirement benefits    
Detail of regulatory liabilities    
Total regulatory liabilities 231,269 233,952
Four Corners coal reclamation    
Detail of regulatory liabilities    
Total regulatory liabilities 97,458 97,988
Income taxes — deferred investment tax credit    
Detail of regulatory liabilities    
Total regulatory liabilities 81,660 81,949
Income taxes — change in state rates    
Detail of regulatory liabilities    
Total regulatory liabilities 56,040 56,260
RES    
Detail of regulatory liabilities    
Total regulatory liabilities 53,858 54,551
Sundance maintenance    
Detail of regulatory liabilities    
Total regulatory liabilities 25,195 25,668
Spent nuclear fuel    
Detail of regulatory liabilities    
Total regulatory liabilities 18,917 20,492
DSM    
Detail of regulatory liabilities    
Total regulatory liabilities 11,802 26,228
TCA Balancing Account    
Detail of regulatory liabilities    
Total regulatory liabilities 0 4,860
TEAM    
Detail of regulatory liabilities    
Total regulatory liabilities 3,587 3,738
Deferred fuel and purchased power — mark-to-market (Note 10)    
Detail of regulatory liabilities    
Total regulatory liabilities 0 3,641
Other    
Detail of regulatory liabilities    
Total regulatory liabilities 2,516 3,063
ACC | Excess deferred income taxes - Tax Cuts and Jobs Act    
Detail of regulatory liabilities    
Total regulatory liabilities 844,409 847,572
FERC | Excess deferred income taxes - Tax Cuts and Jobs Act    
Detail of regulatory liabilities    
Total regulatory liabilities $ 199,607 $ 200,161
v3.26.1
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, 2026
Mar. 31, 2025
Amortization of:    
Portion of costs (credits) charged to expense $ (3,982) $ (2,958)
Pension Plans    
Defined Benefit Plan Disclosure [Line Items]    
Service cost-benefits earned during the period 12,099 10,949
Non-service costs (credits):    
Interest cost on benefit obligation 37,612 38,976
Expected return on plan assets (44,096) (44,547)
Amortization of:    
Prior service cost (credit) 151 0
Net actuarial loss (gain) 11,153 12,118
Net periodic benefit costs (credits) 16,919 17,496
Portion of costs (credits) charged to expense 9,518 10,461
Other Benefits Plans    
Defined Benefit Plan Disclosure [Line Items]    
Service cost-benefits earned during the period 2,237 1,982
Non-service costs (credits):    
Interest cost on benefit obligation 4,979 5,102
Expected return on plan assets (12,719) (12,142)
Amortization of:    
Prior service cost (credit) 0 (1,265)
Net actuarial loss (gain) (2,700) (2,899)
Net periodic benefit costs (credits) (8,203) (9,222)
Portion of costs (credits) charged to expense $ (6,509) $ (6,873)
v3.26.1
Retirement Plans and Other Postretirement Benefits - Additional Information (Details) - USD ($)
 1 Months Ended 3 Months Ended
Apr. 30, 2026
Mar. 31, 2026
Pension Plans    
Defined Benefit Plan Disclosure [Line Items]    
Minimum contributions under MAP-21   $ 0
Other Benefits Plans | Subsequent Event    
Defined Benefit Plan Disclosure [Line Items]    
Retiree medical cost reimbursement $ 23,000,000  
v3.26.1
Variable Interest Entities - Additional Information (Details)
$ in Thousands
 3 Months Ended 12 Months Ended
Mar. 31, 2026
USD ($)
trust
Mar. 31, 2025
USD ($)
Dec. 31, 2026
USD ($)
Dec. 31, 2025
USD ($)
Sep. 30, 2025
trust
Dec. 31, 1986
trust
Palo Verde Sale Leaseback Variable Interest Entities            
Net income attributable to noncontrolling interest $ 2,194 $ 4,306        
APS            
Palo Verde Sale Leaseback Variable Interest Entities            
Net income attributable to noncontrolling interest 2,194 4,306        
Special use fund       $ 40,300    
Variable Interest Entity            
Palo Verde Sale Leaseback Variable Interest Entities            
Net income attributable to noncontrolling interest 400 700        
Variable Interest Entity | APS            
Palo Verde Sale Leaseback Variable Interest Entities            
Net income attributable to noncontrolling interest $ 2,000 $ 4,000        
Number of VIE lessor trusts | trust 1         3
Number of VIE lessor trusts acquired | trust         2  
Number of VIE lessor trusts terminated | trust         2  
Annual lease payments $ 9,000          
Variable Interest Entity | APS | Forecast            
Palo Verde Sale Leaseback Variable Interest Entities            
Initial loss exposure to the VIEs noncontrolling equity participants during lease extension period     $ 177,000      
Variable Interest Entity | APS | Maximum            
Palo Verde Sale Leaseback Variable Interest Entities            
Lease period (up to) 2 years          
Maximum loss exposure to the VIE's noncontrolling equity participants during lease extension period (up to) $ 267,000          
Variable Interest Entity | APS | Palo Verde Unit 2            
Palo Verde Sale Leaseback Variable Interest Entities            
Ownership percentage 23.90%          
Leased interest percentage 5.20%          
Variable Interest Entity | Pinnacle West Captive Insurance Cell            
Palo Verde Sale Leaseback Variable Interest Entities            
Special use fund $ 42,000     $ 40,000    
v3.26.1
Variable Interest Entities - Schedule of Amounts Relating to the VIEs Included in Consolidated Balance Sheets (Details) - USD ($)
$ in Thousands
Mar. 31, 2026
Dec. 31, 2025
Palo Verde Sale Leaseback Variable Interest Entities    
Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation $ 21,046,535 $ 20,720,104
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets    
Equity — Noncontrolling interests 42,811 40,617
APS    
Palo Verde Sale Leaseback Variable Interest Entities    
Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation 21,046,380 20,719,949
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets    
Equity — Noncontrolling interests 42,811 40,617
Palo Verde VIE | APS    
Palo Verde Sale Leaseback Variable Interest Entities    
Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation 31,641 32,035
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets    
Equity — Noncontrolling interests $ 42,811 $ 40,617
v3.26.1
Derivative Accounting - Additional Information (Details)
$ in Thousands
 3 Months Ended
Mar. 31, 2026
USD ($)
counterparty
Dec. 31, 2025
USD ($)
Derivative [Line Items]    
Number of counterparties | counterparty 0  
Commodity Contracts    
Derivative [Line Items]    
Derivative asset $ 854 $ 8,387
Additional collateral to counterparties for energy related non-derivative instrument contracts $ 710,000  
Four Counterparties | Derivative Concentration | Credit Concentration    
Derivative [Line Items]    
Concentration risk, percentage 10.00%  
APS    
Derivative [Line Items]    
Percentage of unrealized gains and losses on certain derivatives deferred for future rate treatment before accounting treatment change 100.00%  
v3.26.1
Derivative Accounting - Schedule of Outstanding Gross Notional Amounts Outstanding (Details) - Commodity Contracts
MWh in Thousands
 3 Months Ended 12 Months Ended
Mar. 31, 2026
MWh
Bcf
Dec. 31, 2025
MWh
Bcf
Outstanding gross notional amount of derivatives    
Power | MWh 542 542
Gas | Bcf 268,000 211,000
v3.26.1
Derivative Accounting - Schedule of Gains and Losses from Derivative Instruments (Details) - USD ($)
$ in Thousands
 3 Months Ended
Mar. 31, 2026
Mar. 31, 2025
Commodity Contracts | Not Designated as Hedging Instruments    
Derivative Instruments Not Designated as Cash Flows Hedges    
Total $ (25,897) $ 116,704
v3.26.1
Derivative Accounting - Schedule of Derivative Instruments in the Balance Sheet (Details) - Commodity Contracts - USD ($)
$ in Thousands
Mar. 31, 2026
Dec. 31, 2025
Assets    
Gross Recognized Derivatives $ 15,010 $ 19,347
Amounts Offset (14,161) (10,965)
Net Recognized Derivatives 849 8,382
Other 5 5
Derivative asset, total 854 8,387
Liabilities    
Gross Recognized Derivatives (73,232) (45,035)
Amounts Offset 14,161 10,965
Net Recognized Derivatives (59,071) (34,070)
Other (2,566) (2,566)
Derivative liability, total (61,637) (36,636)
Assets and Liabilities    
Gross Recognized Derivatives (58,222) (25,688)
Amounts Offset 0 0
Net Recognized Derivatives (58,222) (25,688)
Other (2,561) (2,561)
Amounts  Reported on  Balance Sheets (60,783) (28,249)
Current assets    
Assets    
Gross Recognized Derivatives 12,614 12,640
Amounts Offset (12,231) (9,395)
Net Recognized Derivatives 383 3,245
Other 5 5
Derivative asset, total 388 3,250
Investments and other assets    
Assets    
Gross Recognized Derivatives 2,396 6,707
Amounts Offset (1,930) (1,570)
Net Recognized Derivatives 466 5,137
Other 0 0
Derivative asset, total 466 5,137
Current liabilities    
Liabilities    
Gross Recognized Derivatives (65,583) (41,970)
Amounts Offset 12,231 9,395
Net Recognized Derivatives (53,352) (32,575)
Other (2,566) (2,566)
Derivative liability, total (55,918) (35,141)
Deferred credits and other    
Liabilities    
Gross Recognized Derivatives (7,649) (3,065)
Amounts Offset 1,930 1,570
Net Recognized Derivatives (5,719) (1,495)
Other 0 0
Derivative liability, total $ (5,719) $ (1,495)
v3.26.1
Derivative Accounting - Schedule of Credit Risk and Related Contingent Features (Details) - Commodity Contracts
$ in Thousands
Mar. 31, 2026
USD ($)
Credit Risk and Credit-Related Contingent Features  
Aggregate fair value of derivative instruments in a net liability position $ 69,364
Additional cash collateral in the event credit-risk related contingent features were fully triggered $ 30,038
v3.26.1
Commitments and Contingencies (Details)
$ in Millions
 1 Months Ended 3 Months Ended 160 Months Ended
Oct. 31, 2025
USD ($)
Jan. 01, 2024
USD ($)
trust
Jan. 17, 2023
USD ($)
Feb. 28, 2026
USD ($)
Mar. 31, 2026
USD ($)
timePeriod
trust
Oct. 31, 2024
claim
Jul. 11, 2025
operator
Schedule of Commitments and Contingencies [Line Items]              
Production tax credit guarantees         $ 25.5    
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    
Settlement amount, sought $ 15.4            
Damages awarded       $ 15.4      
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         24.3    
Collateral assurance based on rating triggers         $ 66.9    
Period to provide collateral assurance based on rating triggers         20 days    
Number of power plant operators | operator             25
Increase (decrease) in unrecorded unconditional purchase obligation         $ 2,800.0    
APS | Surety Bonds Expiring in 2028              
Schedule of Commitments and Contingencies [Line Items]              
Surety bonds expiring, amount         24.4    
APS | Letter of Credit              
Schedule of Commitments and Contingencies [Line Items]              
Outstanding letters of credit         31.8    
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    
Settlement amount, sought $ 4.5            
NTEC | Four Corners              
Schedule of Commitments and Contingencies [Line Items]              
Asset purchase agreement, option to purchase, ownership interest, percentage         7.00%    
v3.26.1
Other Income and Other Expense (Details) - USD ($)
$ in Thousands
 3 Months Ended
Mar. 31, 2026
Mar. 31, 2025
Other income:    
Interest income $ 2,881 $ 5,996
Investment gain — net 1,792 10,984
Miscellaneous 308 481
Total other income 4,981 17,461
Other expense:    
Non-operating costs (2,462) (2,229)
Miscellaneous (278) (341)
Total other expense (2,740) (2,570)
APS    
Other income:    
Interest income 2,520 5,607
Miscellaneous 125 115
Total other income 2,645 5,722
Other expense:    
Non-operating costs (2,390) (1,992)
Miscellaneous (278) (341)
Total other expense $ (2,668) $ (2,333)
v3.26.1
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 ($)
day
Mar. 31, 2026
USD ($)
agreement
$ / shares
shares
Apr. 01, 2026
USD ($)
Dec. 31, 2025
shares
Nov. 08, 2024
USD ($)
Subsidiary or Equity Method Investee [Line Items]          
Common stock, authorized (in shares) | shares   300,000,000   300,000,000  
Convertible Notes Due Maturing June 2027 | Convertible Debt          
Subsidiary or Equity Method Investee [Line Items]          
Debt instrument, convertible, conversion ratio   0.0108338      
Pinnacle West Consolidated | Convertible Notes Due Maturing June 2027 | Convertible Debt          
Subsidiary or Equity Method Investee [Line Items]          
Notes issued $ 525        
Interest rate 4.75%        
Debt instrument, convertible, conversion price (in dollars per share) | $ / shares   $ 92.30      
Debt instrument redemption price percentage   100.00%      
Long-term debt   $ 525      
Unamortized debt issuance expense   3      
Convertible debt, fair value   597      
Pinnacle West Consolidated | 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 Consolidated | 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   $ 434     $ 900
Nine At the Market Offerings          
Subsidiary or Equity Method Investee [Line Items]          
Number of outstanding forward sale agreements | agreement   9      
Unsettled proceeds   $ 466      
Tenth ATM Forward Sale Agreement | Subsequent Event          
Subsidiary or Equity Method Investee [Line Items]          
Value of shares to be issued under ATM program     $ 100    
v3.26.1
Common Stock Equity and Earnings Per Share - Schedule of ATM Program (Details) - USD ($)
$ / shares in Units, $ in Thousands
 1 Months Ended 3 Months Ended
Dec. 18, 2025
Sep. 04, 2025
Dec. 23, 2024
Feb. 28, 2024
Mar. 31, 2026
Nov. 08, 2024
Subsidiary or Equity Method Investee [Line Items]            
Number of Shares (in shares)         4,861,922  
Forward Sales Price Per Share (in dollars per share)         $ 95.08  
Aggregate Value         $ 462,269  
ATM Program            
Subsidiary or Equity Method Investee [Line Items]            
Initial Price, Aggregate Value         $ 434,000 $ 900,000
November 2024            
Subsidiary or Equity Method Investee [Line Items]            
Number of Shares (in shares)         552,833  
Forward Sales Price Per Share (in dollars per share)         $ 89.73  
Aggregate Value         $ 49,606  
March 2025            
Subsidiary or Equity Method Investee [Line Items]            
Number of Shares (in shares)         544,959  
Forward Sales Price Per Share (in dollars per share)         $ 90.83  
Aggregate Value         $ 49,499  
August 2025            
Subsidiary or Equity Method Investee [Line Items]            
Number of Shares (in shares)         543,001  
Forward Sales Price Per Share (in dollars per share)         $ 91.21  
Aggregate Value         $ 49,527  
September 2025            
Subsidiary or Equity Method Investee [Line Items]            
Number of Shares (in shares)         558,622  
Forward Sales Price Per Share (in dollars per share)         $ 88.69  
Aggregate Value         $ 49,544  
January 2026            
Subsidiary or Equity Method Investee [Line Items]            
Number of Shares (in shares)         119,553  
Forward Sales Price Per Share (in dollars per share)         $ 89.88  
Aggregate Value         $ 10,745  
March 2026            
Subsidiary or Equity Method Investee [Line Items]            
Number of Shares (in shares)         646,674  
Forward Sales Price Per Share (in dollars per share)         $ 99.52  
Aggregate Value         $ 64,357  
March 2026            
Subsidiary or Equity Method Investee [Line Items]            
Number of Shares (in shares)         490,537  
Forward Sales Price Per Share (in dollars per share)         $ 100.94  
Aggregate Value         $ 49,515  
March 2026            
Subsidiary or Equity Method Investee [Line Items]            
Number of Shares (in shares)         488,813  
Forward Sales Price Per Share (in dollars per share)         $ 101.28  
Aggregate Value         $ 49,507  
March 2026            
Subsidiary or Equity Method Investee [Line Items]            
Number of Shares (in shares)         916,930  
Forward Sales Price Per Share (in dollars per share)         $ 98.12  
Aggregate Value         $ 89,969  
February 2024 Forward Sale Agreements            
Subsidiary or Equity Method Investee [Line Items]            
Initial Price, Number of Shares (in shares)       11,240,601    
Initial Price, Aggregate Value       $ 725,131    
Number of Shares (in shares) 1,193,950 243,186 5,377,115      
Forward Sales Price Per Share (in dollars per share) $ 62.82 $ 63.12 $ 64.17 $ 64.51    
Aggregate Value $ 75,004 $ 15,350 $ 345,049      
v3.26.1
Common Stock Equity and Earnings Per Share - Schedule of Earnings Per Share, Basic and Diluted (Details) - USD ($)
$ / shares in Units, $ in Thousands
 3 Months Ended
Mar. 31, 2026
Mar. 31, 2025
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]    
Net income (loss) attributable to common shareholders $ 32,920 $ (4,644)
Weighted average common shares outstanding — basic (in shares) 121,360,000 119,594,000
Net effect of dilutive securities:    
Contingently issuable performance shares and restricted stock units (in shares) 1,722,000 1,669,000
Dilutive shares related to equity forward sale agreements (in shares) 444,000 498,000
Dilutive shares related to convertible debt instruments (in shares) 252,000 0
Total contingently issuable shares (in shares) 2,418,000 2,167,000
Weighted average common shares outstanding — diluted (in shares) 123,778,000 119,594,000
Weighted average common shares outstanding — diluted (in shares)   121,761,000
Earnings per weighted-average common share outstanding    
Net income (loss) attributable to common shareholders - basic (in dollars per share) $ 0.27 $ (0.04)
Net income (loss) attributable to common shareholders - diluted (in dollars per share) $ 0.27 $ (0.04)
ATM Program    
Earnings per weighted-average common share outstanding    
Antidilutive securities excluded from computation of EPS (in shares) 16,127 4,636
Convertible Notes Payable    
Earnings per weighted-average common share outstanding    
Antidilutive securities excluded from computation of EPS (in shares) 0 192,754
Contingently Issuable Shares    
Earnings per weighted-average common share outstanding    
Antidilutive securities excluded from computation of EPS (in shares) 0 2,167,000
v3.26.1
Fair Value Measurements - Schedule of Assets and Liabilities Measured on a Recurring Basis (Details) - USD ($)
$ in Thousands
Mar. 31, 2026
Dec. 31, 2025
ASSETS    
Nuclear decommissioning trusts: $ 1,392,817 $ 1,414,166
Nuclear decommissioning trust, other 482,327 496,793
Other special use funds: 437,745 434,827
Other special use funds, other 2,012 3,199
Total assets 1,831,416 1,857,380
Total assets, other 474,051 489,032
Commodity contracts    
ASSETS    
Commodity contracts, other (10,288) (10,960)
Derivative asset, total 854 8,387
LIABILITIES    
Derivative instruments, other 7,727 8,399
Derivative liability, total (61,637) (36,636)
Equity securities    
ASSETS    
Nuclear decommissioning trusts: 22,098 15,171
Nuclear decommissioning trust, other 3,557 (3,799)
Other special use funds: 66,862 65,772
Other special use funds, other 2,012 3,199
U.S. commingled equity funds    
ASSETS    
Nuclear decommissioning trusts: 478,770 500,592
U.S. Treasury debt    
ASSETS    
Nuclear decommissioning trusts: 369,970 364,943
Other special use funds: 370,883 369,055
Corporate debt    
ASSETS    
Nuclear decommissioning trusts: 249,372 242,176
Mortgage-backed securities    
ASSETS    
Nuclear decommissioning trusts: 217,924 230,695
Municipal bonds    
ASSETS    
Nuclear decommissioning trusts: 34,288 37,572
Other fixed income    
ASSETS    
Nuclear decommissioning trusts: 20,395 23,017
Level 1    
ASSETS    
Nuclear decommissioning trusts: 388,511 383,913
Other special use funds: 435,733 431,628
Total assets 824,244 815,541
Level 1 | Commodity contracts    
ASSETS    
Commodity contracts 0 0
LIABILITIES    
Derivative instruments 0 0
Level 1 | Pinnacle West Captive Insurance Cell    
ASSETS    
Other special use funds: 41,400 40,300
Level 1 | Equity securities    
ASSETS    
Nuclear decommissioning trusts: 18,541 18,970
Other special use funds: 64,850 62,573
Level 1 | U.S. commingled equity funds    
ASSETS    
Nuclear decommissioning trusts: 0 0
Level 1 | U.S. Treasury debt    
ASSETS    
Nuclear decommissioning trusts: 369,970 364,943
Other special use funds: 370,883 369,055
Level 1 | Corporate debt    
ASSETS    
Nuclear decommissioning trusts: 0 0
Level 1 | Mortgage-backed securities    
ASSETS    
Nuclear decommissioning trusts: 0 0
Level 1 | Municipal bonds    
ASSETS    
Nuclear decommissioning trusts: 0 0
Level 1 | Other fixed income    
ASSETS    
Nuclear decommissioning trusts: 0 0
Level 2    
ASSETS    
Nuclear decommissioning trusts: 521,979 533,460
Other special use funds: 0 0
Total assets 533,121 552,807
Level 2 | Commodity contracts    
ASSETS    
Commodity contracts 11,142 19,347
LIABILITIES    
Derivative instruments (35,908) (21,325)
Level 2 | Equity securities    
ASSETS    
Nuclear decommissioning trusts: 0 0
Other special use funds: 0 0
Level 2 | U.S. commingled equity funds    
ASSETS    
Nuclear decommissioning trusts: 0 0
Level 2 | U.S. Treasury debt    
ASSETS    
Nuclear decommissioning trusts: 0 0
Other special use funds: 0 0
Level 2 | Corporate debt    
ASSETS    
Nuclear decommissioning trusts: 249,372 242,176
Level 2 | Mortgage-backed securities    
ASSETS    
Nuclear decommissioning trusts: 217,924 230,695
Level 2 | Municipal bonds    
ASSETS    
Nuclear decommissioning trusts: 34,288 37,572
Level 2 | Other fixed income    
ASSETS    
Nuclear decommissioning trusts: 20,395 23,017
Level 3    
ASSETS    
Nuclear decommissioning trusts: 0 0
Other special use funds: 0 0
Total assets 0 0
Level 3 | Commodity contracts    
ASSETS    
Commodity contracts 0 0
LIABILITIES    
Derivative instruments (33,456) (23,710)
Level 3 | Equity securities    
ASSETS    
Nuclear decommissioning trusts: 0 0
Other special use funds: 0 0
Level 3 | U.S. commingled equity funds    
ASSETS    
Nuclear decommissioning trusts: 0 0
Level 3 | U.S. Treasury debt    
ASSETS    
Nuclear decommissioning trusts: 0 0
Other special use funds: 0 0
Level 3 | Corporate debt    
ASSETS    
Nuclear decommissioning trusts: 0 0
Level 3 | Mortgage-backed securities    
ASSETS    
Nuclear decommissioning trusts: 0 0
Level 3 | Municipal bonds    
ASSETS    
Nuclear decommissioning trusts: 0 0
Level 3 | Other fixed income    
ASSETS    
Nuclear decommissioning trusts: 0 0
Fair Value Measured at Net Asset Value Per Share | U.S. commingled equity funds    
ASSETS    
Nuclear decommissioning trusts:   $ 500,592
Nuclear decommissioning trust, other $ 478,770  
v3.26.1
Fair Value Measurements - Schedule of Significant Unobservable Inputs Used to Value Level 3 Instruments (Details)
$ in Thousands
Mar. 31, 2026
USD ($)
$ / MWh
$ / MMBTU
Dec. 31, 2025
USD ($)
$ / MWh
$ / MMBTU
Commodity Contracts    
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments    
Derivative asset $ 854 $ 8,387
Derivative liability 61,637 36,636
Commodity Contracts | Level 3    
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments    
Derivative asset 0 0
Derivative liability 33,456 23,710
Electricity Forward Contract | Level 3    
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments    
Derivative asset 0 0
Derivative liability $ 26,789 $ 21,913
Electricity Forward Contract | Minimum | Level 3    
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments    
Derivative liability, measurement input | $ / MWh 31.79 41.51
Derivative asset, measurement input | $ / MWh 31.79 41.51
Electricity Forward Contract | Maximum | Level 3    
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments    
Derivative liability, measurement input | $ / MWh 138.31 149.37
Derivative asset, measurement input | $ / MWh 138.31 149.37
Electricity Forward Contract | Weighted Average | Level 3    
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments    
Derivative liability, measurement input | $ / MWh 71.57 80.20
Derivative asset, measurement input | $ / MWh 71.57 80.20
Natural Gas Forward Contract | Level 3    
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments    
Derivative asset $ 0 $ 0
Derivative liability $ 6,667 $ 1,797
Natural Gas Forward Contract | Minimum | Level 3    
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments    
Derivative liability, measurement input | $ / MMBTU (0.79) (0.07)
Derivative asset, measurement input | $ / MMBTU (0.79) (0.07)
Natural Gas Forward Contract | Maximum | Level 3    
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments    
Derivative liability, measurement input | $ / MMBTU 0.14 0.36
Derivative asset, measurement input | $ / MMBTU 0.14 0.36
Natural Gas Forward Contract | Weighted Average | Level 3    
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments    
Derivative liability, measurement input | $ / MMBTU 0.03 0.04
Derivative asset, measurement input | $ / MMBTU 0.03 0.04
v3.26.1
Fair Value Measurements - Schedule of Fair value for our risk management activities (Details) - Commodity Contracts - Level 3 - USD ($)
$ in Thousands
 3 Months Ended
Mar. 31, 2026
Mar. 31, 2025
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]    
Balance at beginning of period $ (23,710) $ (15,039)
Deferred as a regulatory asset or liability (14,577) (5,823)
Settlements 4,831 (2,287)
Transfers into Level 3 from Level 2 0 (59)
Transfers from Level 3 into Level 2 0 368
Balance at end of period (33,456) (22,840)
Net unrealized gains/losses included in earnings related to instruments still held at end of period $ 0 $ 0
v3.26.1
Investments in Nuclear Decommissioning Trusts and Other Special Use Funds - Additional Information (Details)
$ in Millions
 1 Months Ended
Apr. 30, 2026
USD ($)
APS | Subsequent Event  
Schedule of Equity Method Investments [Line Items]  
Employee medical claims amount $ 13
v3.26.1
Investments in Nuclear Decommissioning Trusts and Other Special Use Funds - Schedule of Investments in Nuclear Decommissioning Trusts and Other Special Use Funds (Details) - USD ($)
$ in Thousands
 3 Months Ended 12 Months Ended
Mar. 31, 2026
Mar. 31, 2025
Dec. 31, 2025
Variable Interest Entity | Pinnacle West Captive Insurance Cell      
Nuclear decommissioning trust fund assets      
Special use fund $ 42,000   $ 40,000
APS      
Nuclear decommissioning trust fund assets      
Total 1,830,562   1,848,993
Total Unrealized Gains 419,039   451,809
Total Unrealized Losses (18,483)   (14,994)
Amortized cost 1,270,000   1,265,000
Special use fund     40,300
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds      
Realized gains 4,736 $ 1,658  
Realized losses (2,797) (2,761)  
Proceeds from the sale of securities 512,234 485,814  
APS | Nuclear Decommissioning Trusts      
Nuclear decommissioning trust fund assets      
Total 1,392,817   1,414,166
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds      
Realized gains 4,720 1,658  
Realized losses (2,797) (2,761)  
Proceeds from the sale of securities 447,883 416,601  
APS | Other Special Use Funds      
Nuclear decommissioning trust fund assets      
Total 437,745   434,827
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds      
Realized gains 16 0  
Realized losses 0 0  
Proceeds from the sale of securities 64,351 69,213  
APS | Captive Insurance Cell      
Nuclear decommissioning trust fund assets      
Total Unrealized Gains 2,800   3,200
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 562,161   582,135
Total Unrealized Gains 407,542   433,044
Total Unrealized Losses (139)   (1)
APS | Equity securities | Nuclear Decommissioning Trusts      
Nuclear decommissioning trust fund assets      
Equity securities 497,311   519,562
APS | Equity securities | Other Special Use Funds      
Nuclear decommissioning trust fund assets      
Equity securities 64,850   62,573
APS | Available for sale-fixed income securities      
Nuclear decommissioning trust fund assets      
Available for sale-fixed income securities 1,262,832   1,267,458
Total Unrealized Gains 11,497   18,765
Total Unrealized Losses (18,344)   (14,993)
Fair value of fixed income securities, summarized by contractual maturities      
Less than one year 180,414    
1 year – 5 years 505,236    
5 years – 10 years 184,518    
Greater than 10 years 392,664    
Total 1,262,832    
APS | Available for sale-fixed income securities | Nuclear Decommissioning Trusts      
Nuclear decommissioning trust fund assets      
Available for sale-fixed income securities 891,949   898,403
Fair value of fixed income securities, summarized by contractual maturities      
Less than one year 32,191    
1 year – 5 years 299,067    
5 years – 10 years 168,027    
Greater than 10 years 392,664    
Total 891,949    
APS | Available for sale-fixed income securities | Other Special Use Funds      
Nuclear decommissioning trust fund assets      
Available for sale-fixed income securities 370,883   369,055
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 108,470    
1 year – 5 years 49,806    
5 years – 10 years 0    
Greater than 10 years 0    
Total 158,276    
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 39,753    
1 year – 5 years 156,363    
5 years – 10 years 16,491    
Greater than 10 years 0    
Total 212,607    
APS | Other      
Nuclear decommissioning trust fund assets      
Other 5,569   (600)
Total Unrealized Gains 0   0
Total Unrealized Losses 0   0
APS | Other | Nuclear Decommissioning Trusts      
Nuclear decommissioning trust fund assets      
Other 3,557   (3,799)
APS | Other | Other Special Use Funds      
Nuclear decommissioning trust fund assets      
Other 2,012   $ 3,199
Pinnacle West | Variable Interest Entity | Pinnacle West Captive Insurance Cell      
Nuclear decommissioning trust fund assets      
Special use fund $ 41,400    
v3.26.1
Changes in Accumulated Other Comprehensive Loss (Details) - USD ($)
$ in Thousands
 3 Months Ended
Mar. 31, 2026
Mar. 31, 2025
Changes in accumulated other comprehensive income (loss) by component    
Beginning balance $ 7,087,075 $ 6,857,478
Ending balance 7,110,968 6,845,982
Accumulated Other Comprehensive Loss    
Changes in accumulated other comprehensive income (loss) by component    
Beginning balance (32,408) (30,942)
Other comprehensive income (loss) before reclassifications (43) 350
Amounts reclassified from accumulated other comprehensive loss 502 498
Ending balance (31,949) (30,094)
Pension and Other Postretirement Benefits    
Changes in accumulated other comprehensive income (loss) by component    
Beginning balance (32,980) (31,661)
Other comprehensive income (loss) before reclassifications 0 0
Amounts reclassified from accumulated other comprehensive loss 502 498
Ending balance (32,478) (31,163)
Derivative Instruments    
Changes in accumulated other comprehensive income (loss) by component    
Beginning balance 572 719
Other comprehensive income (loss) before reclassifications (43) 350
Amounts reclassified from accumulated other comprehensive loss 0 0
Ending balance 529 1,069
APS    
Changes in accumulated other comprehensive income (loss) by component    
Beginning balance 8,922,255 8,376,332
Ending balance 8,976,612 8,381,322
APS | Accumulated Other Comprehensive Loss    
Changes in accumulated other comprehensive income (loss) by component    
Beginning balance (15,457) (14,116)
Ending balance (15,047) (13,710)
APS | Pension and Other Postretirement Benefits    
Changes in accumulated other comprehensive income (loss) by component    
Beginning balance (15,457) (14,116)
Other comprehensive income (loss) before reclassifications 0 0
Amounts reclassified from accumulated other comprehensive loss 410 406
Ending balance $ (15,047) $ (13,710)
v3.26.1
Leases - Additional Information (Details)
$ in Billions
Mar. 31, 2026
USD ($)
trust
agreement
Sep. 30, 2025
trust
Dec. 31, 1986
lease
trust
Lessee, Lease, Description [Line Items]      
Number of lease agreements, sell and lease back | lease     3
Number of lease agreements modified | agreement 2    
Term of contract 20 years    
Lease not yet commenced | $ $ 11.8    
Variable Interest Entity | APS      
Lessee, Lease, Description [Line Items]      
Number of VIE lessor trusts acquired   2  
Number of VIE lessor trusts 1   3
v3.26.1
Leases - Schedule of Lease costs (Details) - USD ($)
$ in Thousands
 3 Months Ended
Mar. 31, 2026
Mar. 31, 2025
Lessee, Lease, Description [Line Items]    
Total Operating Lease Cost $ 60,691 $ 17,884
Variable Lease Cost 25,313 21,370
Short-term Lease Cost 875 592
Operating Lease Cost - PPAs and Energy Storage PPA Lease Contracts    
Lessee, Lease, Description [Line Items]    
Total Operating Lease Cost 54,390 12,547
Operating Lease Cost - Land, Property, and Other Equipment    
Lessee, Lease, Description [Line Items]    
Total Operating Lease Cost 6,301 5,337
Total Lease Cost $ 86,879 $ 39,846
v3.26.1
Leases - Schedule of Maturity of our operating lease liabilities (Details)
$ in Thousands
Mar. 31, 2026
USD ($)
Lessee, Lease, Description [Line Items]  
2026 (remaining nine months of 2026) $ 325,327
2027 410,978
2028 448,528
2029 451,572
2030 452,633
2031 452,129
Thereafter 5,533,532
Total lease commitments 8,074,699
Less imputed interest 3,927,188
Total lease liabilities 4,147,511
PPAs and Energy Storage PPA Lease Contracts  
Lessee, Lease, Description [Line Items]  
2026 (remaining nine months of 2026) 308,967
2027 391,311
2028 431,553
2029 436,730
2030 442,013
2031 447,410
Thereafter 5,478,135
Total lease commitments 7,936,119
Less imputed interest 3,885,636
Total lease liabilities 4,050,483
Land, Property and Equipment Leases  
Lessee, Lease, Description [Line Items]  
2026 (remaining nine months of 2026) 16,360
2027 19,667
2028 16,975
2029 14,842
2030 10,620
2031 4,719
Thereafter 55,397
Total lease commitments 138,580
Less imputed interest 41,552
Total lease liabilities $ 97,028
v3.26.1
Leases - Schedule of Other Additional Information Related to Operating Lease Liabilities (Details)
$ in Thousands
 3 Months Ended
Mar. 31, 2026
USD ($)
lease
Mar. 31, 2025
USD ($)
Dec. 31, 2025
lease
Leases [Abstract]      
Cash paid for amounts included in the measurement of lease liabilities — operating cash flows $ 61,114 $ 17,207  
Right-of-use operating lease assets obtained in exchange for operating lease liabilities $ 404,869 $ 763,437  
Weighted average remaining lease term 17 years   15 years
Weighted average discount rate 8.72%   5.48%
Number of new energy storage operating lease agreement | lease 2   3
v3.26.1
El Dorado Equity Investments - Schedule of El Dorado’s Ownership Percentages and Carrying Value of Investments Accounted for Under the Equity Method Investments (Details) - USD ($)
$ in Thousands
Mar. 31, 2026
Dec. 31, 2025
Schedule of Equity Method Investments [Line Items]    
Total equity method investments $ 42,000 $ 36,000
SAI    
Schedule of Equity Method Investments [Line Items]    
Pinnacle West Ownership Percentage as of March 31, 2026 17.00%  
Total equity method investments $ 26,000 21,000
Copper Sky    
Schedule of Equity Method Investments [Line Items]    
Pinnacle West Ownership Percentage as of March 31, 2026 23.00%  
Total equity method investments $ 16,000 $ 15,000
Funding commitment 25,000  
Funding commitment, amount funded $ 16,800  
v3.26.1
El Dorado Equity Investments - Additional Information (Details) - SAI & Copper Sky - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2026
Mar. 31, 2025
Dec. 31, 2025
Schedule of Equity Method Investments [Line Items]      
Income (loss) from equity method investments $ 5.9 $ 11.8  
Equity investments $ 25.2   $ 25.1