PINNACLE WEST CAPITAL CORP, 10-K filed on 2/25/2026
Annual Report
v3.25.4
Cover Page - USD ($)
 12 Months Ended
Dec. 31, 2025
Feb. 19, 2026
Jun. 30, 2025
Entity Information [Line Items]      
Document Type 10-K    
Document Annual Report true    
Document Period End Date Dec. 31, 2025    
Current Fiscal Year End Date --12-31    
Document Transition Report false    
Entity File Number 1-8962    
Entity Registrant Name PINNACLE WEST CAPITAL CORPORATION    
Entity Tax Identification Number 86-0512431    
Entity Incorporation, State or Country Code AZ    
Entity Address, Address Line One 400 North Fifth Street, P.O. Box 53999    
Entity Address, City or Town Phoenix    
Entity Address, State or Province AZ    
Entity Address, Postal Zip Code 85072-3999    
City Area Code (602)    
Local Phone Number 250-1000    
Title of 12(b) Security Common Stock,No Par Value    
Trading Symbol PNW    
Security Exchange Name NYSE    
Entity Well-known Seasoned Issuer Yes    
Entity Voluntary Filers No    
Entity Current Reporting Status Yes    
Entity Interactive Data Current Yes    
Entity Filer Category Large Accelerated Filer    
Entity Small Business false    
Entity Emerging Growth Company false    
ICFR Auditor Attestation Flag true    
Document Financial Statement Error Correction [Flag] false    
Entity Shell Company false    
Entity Public Float     $ 10,673,413,436
Entity Common Stock, Shares Outstanding   120,905,390  
Documents Incorporated by Reference
Portions of Pinnacle West Capital Corporation’s definitive Proxy Statement relating to its Annual Meeting of Shareholders to be held on May 14, 2026 are incorporated by reference into Part III hereof.
    
Entity Central Index Key 0000764622    
Amendment Flag false    
Document Fiscal Year Focus 2025    
Document Fiscal Period Focus FY    
APS      
Entity Information [Line Items]      
Document Type 10-K    
Document Period End Date Dec. 31, 2025    
Current Fiscal Year End Date --12-31    
Entity File Number 1-4473    
Entity Registrant Name ARIZONA PUBLIC SERVICE COMPANY    
Entity Tax Identification Number 86-0011170    
Entity Incorporation, State or Country Code AZ    
Entity Address, Address Line One 400 North Fifth Street, P.O. Box 53999    
Entity Address, City or Town Phoenix    
Entity Address, State or Province AZ    
Entity Address, Postal Zip Code 85072-3999    
City Area Code (602)    
Local Phone Number 250-1000    
Title of 12(g) Security Common Stock    
Entity Well-known Seasoned Issuer Yes    
Entity Voluntary Filers No    
Entity Current Reporting Status Yes    
Entity Interactive Data Current Yes    
Entity Filer Category Non-accelerated Filer    
Entity Small Business false    
Entity Emerging Growth Company false    
Entity Shell Company false    
Entity Public Float     $ 0
Entity Common Stock, Shares Outstanding   71,264,947  
Documents Incorporated by Reference
Arizona Public Service Company meets the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and is therefore filing this form with the reduced disclosure format allowed under General Instruction I(2).
    
Entity Central Index Key 0000007286    
Amendment Flag false    
Document Fiscal Year Focus 2025    
Document Fiscal Period Focus FY    
v3.25.4
Audit Information
 12 Months Ended
Dec. 31, 2025
Auditor [Line Items]  
Auditor Name Deloitte & Touche LLP
Auditor Location Tempe, Arizona
Auditor Firm ID 34
APS  
Auditor [Line Items]  
Auditor Name Deloitte & Touche LLP
Auditor Location Tempe, Arizona
Auditor Firm ID 34
v3.25.4
CONSOLIDATED STATEMENTS OF INCOME - USD ($)
shares in Thousands, $ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Income Statement [Abstract]      
OPERATING REVENUES (Note 4) $ 5,339,939 $ 5,124,915 $ 4,695,991
OPERATING EXPENSES      
Fuel and purchased power 1,933,420 1,822,566 1,792,657
Operations and maintenance 1,185,065 1,165,156 1,058,725
Depreciation and amortization 915,343 895,346 794,043
Taxes other than income taxes 234,797 227,395 224,013
Other expense 3,684 2,389 1,913
Total 4,272,309 4,112,852 3,871,351
OPERATING INCOME 1,067,630 1,012,063 824,640
OTHER INCOME (DEDUCTIONS)      
Allowance for equity funds used during construction (Note 1) 61,146 38,620 53,118
Pension and other postretirement non-service credits, net (Note 9) 12,420 48,870 40,648
Other income (Note 15) 49,406 48,614 33,666
Other expense (Note 15) (30,265) (34,136) (25,056)
Total 92,707 101,968 102,376
INTEREST EXPENSE      
Interest charges 469,701 425,742 374,887
Allowance for borrowed funds used during construction (Note 1) (47,733) (48,270) (43,564)
Total 421,968 377,472 331,323
Income Before Income Taxes 738,369 736,559 595,693
Income Taxes (Note 5) 106,726 110,529 76,912
NET INCOME 631,643 626,030 518,781
Less: Net income attributable to noncontrolling interests (Note 12) 15,112 17,224 17,224
Net Income (Loss) Attributable to Common Shareholders $ 616,531 $ 608,806 $ 501,557
Weighted average common shares outstanding — basic (in shares) 119,687 113,846 113,442
Weighted-average common shares outstanding — diluted (in shares) 121,971 116,232 113,804
Earnings Per Weighted-Average Common Share Outstanding      
Net income attributable to common shareholders — basic (in dollars per share) $ 5.15 $ 5.35 $ 4.42
Net income attributable to common shareholders — diluted (in dollars per share) $ 5.05 $ 5.24 $ 4.41
v3.25.4
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Statement of Comprehensive Income [Abstract]      
NET INCOME $ 631,643 $ 626,030 $ 518,781
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX      
Derivative instruments net unrealized gain (loss), net of tax benefit (expense) of $49, $(292), and $234 (147) (891) 713
Pension and other postretirement benefits activity, net of tax benefit (expense) of $484, $(1,073), and $801 (Note 9) (1,319) 3,093 (2,422)
Total other comprehensive income (loss) (1,466) 2,202 (1,709)
COMPREHENSIVE INCOME 630,177 628,232 517,072
Less: Comprehensive income attributable to noncontrolling interests 15,112 17,224 17,224
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS $ 615,065 $ 611,008 $ 499,848
v3.25.4
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Statement of Comprehensive Income [Abstract]      
Net unrealized gain (loss), tax benefit (expense) $ 49 $ (292) $ 234
Pension and other postretirement benefits activity, tax benefit (expense) $ 484 $ (1,073) $ 801
v3.25.4
CONSOLIDATED BALANCE SHEETS - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
CURRENT ASSETS    
Cash and cash equivalents $ 6,604 $ 3,838
Customer and other receivables 579,831 525,608
Accrued unbilled revenues (Note 4) 173,692 176,903
Allowance for doubtful accounts (Note 4) (25,495) (24,849)
Materials and supplies (at average cost) 546,329 469,022
Income tax receivable (Note 5) 5,979 0
Fossil fuel (at average cost) 18,824 32,420
Assets from risk management activities (Note 13) 3,250 10,578
Deferred fuel and purchased power regulatory asset (Note 8) 149,068 287,597
Other regulatory assets (Note 8) 136,941 133,372
Other current assets 108,686 74,915
Total current assets 1,703,709 1,689,404
INVESTMENTS AND OTHER ASSETS    
Nuclear decommissioning trusts (Notes 17 and 18) 1,414,166 1,282,845
Other special use funds (Notes 17 and 18) 434,827 408,357
Assets from risk management activities (Note 13) 5,137 5,980
Other assets 144,997 115,095
Total investments and other assets 1,999,127 1,812,277
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 7 and 11)    
Plant in service and held for future use 27,370,296 25,860,950
Accumulated depreciation and amortization (9,012,021) (9,027,426)
Net 18,358,275 16,833,524
Construction work in progress 1,649,542 1,592,659
Palo Verde sale leaseback, net of accumulated depreciation of $110,886 and $268,894 (Note 12) 32,035 82,556
Intangible assets, net of accumulated amortization of $1,057,812 and $925,880 575,978 591,310
Nuclear fuel, net of accumulated amortization of $111,096 and $115,894 104,274 97,850
Total property, plant and equipment 20,720,104 19,197,899
DEFERRED DEBITS    
Regulatory assets (Notes 1, 5, 8 and 9) 1,463,357 1,389,489
Operating lease right-of-use assets (Note 20) 3,649,669 1,605,463
Assets for other postretirement benefits (Note 9) 399,334 342,102
Other 96,299 66,126
Total deferred debits 5,608,659 3,403,180
TOTAL ASSETS 30,031,599 26,102,760
CURRENT LIABILITIES    
Accounts payable 680,203 485,426
Accrued taxes 186,605 175,863
Accrued interest 105,637 81,799
Common dividends payable 110,022 106,592
Short-term borrowings (Note 6) 757,005 568,450
Current maturities of long-term debt (Note 6) 600,000 800,000
Customer deposits 63,776 44,345
Liabilities from risk management activities (Note 13) 35,141 52,340
Liabilities for asset retirements (Note 21) 71,698 50,009
Operating lease liabilities (Note 20) 188,586 100,367
Regulatory liabilities (Note 8) 210,909 206,955
Other current liabilities 151,444 171,651
Total current liabilities 3,161,026 2,843,797
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 7) 9,205,676 8,058,648
DEFERRED CREDITS AND OTHER    
Liabilities from risk management activities (Note 13) 1,495 9,446
Deferred income taxes (Note 5) 2,470,932 2,444,473
Regulatory liabilities (Notes 1, 5, 8 and 9) 1,736,121 1,855,278
Liabilities for pension benefits (Note 9) 167,636 139,317
Liabilities for asset retirements (Note 21) 1,198,601 1,096,577
Customer advances 632,169 569,343
Coal mine reclamation 159,587 171,483
Deferred investment tax credit 308,261 249,490
Unrecognized tax benefits 105,484 44,233
Operating lease liabilities (Note 20) 3,548,365 1,520,877
Other 249,171 242,320
Total deferred credits and other 10,577,822 8,342,837
COMMITMENTS AND CONTINGENCIES (Note 14)
EQUITY    
Common stock, no par value; authorized 300,000,000 and 150,000,000 shares authorized at respective dates, 120,950,839 and 119,143,782 shares issued at respective dates 3,231,372 3,121,617
Treasury stock at cost; 46,968 and 46,968 shares at respective dates (3,323) (3,323)
Total common stock 3,228,049 3,118,294
Retained earnings 3,850,817 3,666,959
Accumulated other comprehensive loss (Note 19) (32,408) (30,942)
Total shareholder equity 7,046,458 6,754,311
Noncontrolling interests (Note 12) 40,617 103,167
Total equity 7,087,075 6,857,478
TOTAL LIABILITIES AND EQUITY $ 30,031,599 $ 26,102,760
v3.25.4
CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($)
$ in Thousands
Dec. 31, 2025
May 22, 2025
May 21, 2025
Dec. 31, 2024
PROPERTY, PLANT AND EQUIPMENT        
Accumulated depreciation of Palo Verde sale leaseback $ 110,886     $ 268,894
Accumulated amortization on intangible assets 1,057,812     925,880
Accumulated amortization on nuclear fuel $ 111,096     $ 115,894
EQUITY        
Common stock, authorized (in shares) 300,000,000 300,000,000 150,000,000 150,000,000
Common stock, issued (in shares) 120,950,839     119,143,782
Treasury stock at cost (in shares) 46,968     46,968
v3.25.4
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
CASH FLOWS FROM OPERATING ACTIVITIES      
Net income $ 631,643 $ 626,030 $ 518,781
Adjustments to reconcile net income to net cash provided by operating activities:      
Gain on sale relating to BCE 0 (22,988) (6,423)
Depreciation and amortization including nuclear fuel 969,615 956,184 854,136
Allowance for equity funds used during construction (61,146) (38,620) (53,118)
Deferred income taxes (50,850) (20,923) (24,310)
Deferred investment tax credit 58,772 (8,253) 77,065
Change in derivative instruments fair value 0 0 (777)
Stock compensation 27,457 23,532 17,341
Changes in current assets and liabilities:      
Customer and other receivables (51,275) (12,696) (61,983)
Accrued unbilled revenues 3,211 (9,350) (2,789)
Materials, supplies and fossil fuel (63,711) (7,895) (42,911)
Income tax receivable (5,979) 332 13,754
Deferred fuel and purchased power (324,482) (250,288) (549,877)
Deferred fuel and purchased power amortization 463,011 425,886 547,243
Other current assets (42,991) (50,225) (19,550)
Accounts payable 171,138 (7,214) (75,623)
Accrued taxes 10,742 9,030 2,393
Other current liabilities 18,714 47,329 40,510
Change in unrecognized tax benefits 81,090 75 1,177
Change in long-term regulatory assets 91,373 43,305 53,112
Change in long-term regulatory liabilities 37,205 9,416 28,495
Change in other long-term assets (283,507) (132,563) (195,598)
Change in operating lease assets 151,522 98,214 90,525
Change in other long-term liabilities 138,934 24,719 61,903
Change in operating lease liabilities (165,391) (93,214) (65,779)
Net cash provided by operating activities 1,805,095 1,609,823 1,207,697
CASH FLOWS FROM INVESTING ACTIVITIES      
Capital expenditures (2,624,618) (2,249,195) (1,846,370)
Contributions in aid of construction 306,380 311,358 180,866
Proceeds from sale relating to BCE 0 84,322 23,400
Allowance for borrowed funds used during construction (47,733) (48,270) (43,564)
Proceeds from nuclear decommissioning trusts sales and other special use funds 1,855,200 1,686,094 1,679,722
Investment in nuclear decommissioning trusts and other special use funds (1,858,991) (1,709,526) (1,681,845)
Other (8,912) (8,413) (6,458)
Net cash used for investing activities (2,378,674) (1,933,630) (1,694,249)
CASH FLOWS FROM FINANCING ACTIVITIES      
Issuance of long-term debt 1,742,754 1,313,229 689,349
Repayment of long-term debt (800,000) (875,000) (32,740)
Short-term borrowings and (repayments) — net 213,555 (241,050) 241,900
Short-term debt borrowings under term loan facility 575,000 550,000 0
Short-term debt repayments under term loan facility (600,000) (350,000) 0
Dividends paid on common stock (422,792) (394,663) (386,486)
Common stock equity issuance and purchases — net 84,613 341,429 (4,093)
Palo Verde sale leaseback noncontrolling interest acquisition (198,744) 0 0
Capital activities by noncontrolling interests (18,041) (21,255) (21,255)
Net cash provided by financing activities 576,345 322,690 486,675
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 2,766 (1,117) 123
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 3,838 4,955 4,832
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 6,604 $ 3,838 $ 4,955
v3.25.4
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY - USD ($)
$ in Thousands
Total
Common Stock
Treasury Stock
Retained Earnings
Accumulated Other Comprehensive Income (Loss)
Noncontrolling Interests
Beginning balance (in shares) at Dec. 31, 2022   113,247,189        
Beginning balance at Dec. 31, 2022 $ 6,159,876 $ 2,724,740 $ (5,005) $ 3,360,347 $ (31,435) $ 111,229
Beginning balance (in shares) at Dec. 31, 2022     (73,613)      
Increase (Decrease) in Shareholders' Equity            
Net income 518,781     501,557   17,224
Other comprehensive (loss) income (1,709)       (1,709)  
Dividends on common stock (395,585)     (395,585)    
Issuance of common stock (in shares)   290,500        
Issuance of common stock 27,936 $ 27,936        
Purchase of treasury stock (in shares) [1]     (72,180)      
Purchase of treasury stock [1] (5,466)   $ (5,466)      
Reissuance of treasury stock for stock-based compensation and other (in shares)     32,521      
Reissuance of treasury stock for stock-based compensation and other 2,287   $ 2,287      
Capital activities by noncontrolling interests (21,255)         (21,255)
Other (3)   (1) (2)    
Ending balance (in shares) at Dec. 31, 2023   113,537,689        
Ending balance at Dec. 31, 2023 6,284,862 $ 2,752,676 $ (8,185) 3,466,317 (33,144) 107,198
Ending balance (in shares) at Dec. 31, 2023     (113,272)      
Increase (Decrease) in Shareholders' Equity            
Net income 626,030     608,806   17,224
Other comprehensive (loss) income 2,202       2,202  
Dividends on common stock (408,162)     (408,162)    
Issuance of common stock (in shares) [2]   5,606,093        
Issuance of common stock [2] 368,941 $ 368,941        
Purchase of treasury stock (in shares) [1]     (71,008)      
Purchase of treasury stock [1] (4,907)   $ (4,907)      
Reissuance of treasury stock for stock-based compensation and other (in shares)     137,312      
Reissuance of treasury stock for stock-based compensation and other 9,768   $ 9,768      
Capital activities by noncontrolling interests (21,255)         (21,255)
Other $ (1)   1 (2)    
Ending balance (in shares) at Dec. 31, 2024 119,143,782 119,143,782        
Ending balance at Dec. 31, 2024 $ 6,857,478 $ 3,121,617 $ (3,323) 3,666,959 (30,942) 103,167
Ending balance (in shares) at Dec. 31, 2024 (46,968)   (46,968)      
Increase (Decrease) in Shareholders' Equity            
Net income $ 631,643     616,531   15,112
Other comprehensive (loss) income (1,466)       (1,466)  
Dividends on common stock (432,671)     (432,671)    
Issuance of common stock (in shares) [2]   1,807,057        
Issuance of common stock [2] 109,755 $ 109,755        
Capital activities by noncontrolling interests (18,041)         (18,041)
Deconsolidation of noncontrolling interests [3] (59,621)         (59,621)
Other $ (2)     (2)    
Ending balance (in shares) at Dec. 31, 2025 120,950,839 120,950,839        
Ending balance at Dec. 31, 2025 $ 7,087,075 $ 3,231,372 $ (3,323) $ 3,850,817 $ (32,408) $ 40,617
Ending balance (in shares) at Dec. 31, 2025 (46,968)   (46,968)      
[1] Primarily represents shares of common stock withheld from certain stock awards for tax purposes.
[2] See Note 16 for information related to our equity forward sale agreements.
[3] See Note 12 for information related to the Palo Verde sale leaseback purchases.
v3.25.4
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Parenthetical) - $ / shares
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Statement of Stockholders' Equity [Abstract]      
Dividends on common stock (in dollars per share) $ 3.61 $ 3.55 $ 3.49
v3.25.4
ARIZONA PUBLIC SERVICE COMPANY - CONSOLIDATED STATEMENTS OF INCOME - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
OPERATING REVENUES (Note 4) $ 5,339,939 $ 5,124,915 $ 4,695,991
OPERATING EXPENSES      
Fuel and purchased power 1,933,420 1,822,566 1,792,657
Operations and maintenance 1,185,065 1,165,156 1,058,725
Depreciation and amortization 915,343 895,346 794,043
Taxes other than income taxes 234,797 227,395 224,013
Other expense 3,684 2,389 1,913
Total 4,272,309 4,112,852 3,871,351
OPERATING INCOME 1,067,630 1,012,063 824,640
OTHER INCOME (DEDUCTIONS)      
Allowance for equity funds used during construction (Note 1) 61,146 38,620 53,118
Pension and other postretirement non-service credits, net (Note 9) 12,420 48,870 40,648
Other income (Note 15) 49,406 48,614 33,666
Other expense (Note 15) (30,265) (34,136) (25,056)
Total 92,707 101,968 102,376
INTEREST EXPENSE      
Interest charges 469,701 425,742 374,887
Allowance for borrowed funds used during construction (Note 1) (47,733) (48,270) (43,564)
Total 421,968 377,472 331,323
Income Before Income Taxes 738,369 736,559 595,693
Income Taxes (Note 5) 106,726 110,529 76,912
NET INCOME 631,643 626,030 518,781
Less: Net income attributable to noncontrolling interests (Note 12) 15,112 17,224 17,224
Net Income (Loss) Attributable to Common Shareholders 616,531 608,806 501,557
APS      
OPERATING REVENUES (Note 4) 5,339,939 5,124,915 4,695,991
OPERATING EXPENSES      
Fuel and purchased power 1,933,420 1,822,566 1,792,657
Operations and maintenance 1,177,089 1,158,634 1,043,570
Depreciation and amortization 915,275 895,171 793,958
Taxes other than income taxes 234,733 227,307 223,962
Other expense 3,684 2,389 1,913
Total 4,264,201 4,106,067 3,856,060
OPERATING INCOME 1,075,738 1,018,848 839,931
OTHER INCOME (DEDUCTIONS)      
Allowance for equity funds used during construction (Note 1) 61,146 38,620 53,118
Pension and other postretirement non-service credits, net (Note 9) 13,365 49,489 41,577
Other income (Note 15) 16,214 21,094 27,072
Other expense (Note 15) (26,382) (29,698) (18,264)
Total 64,343 79,505 103,503
INTEREST EXPENSE      
Interest charges 379,468 360,481 323,719
Allowance for borrowed funds used during construction (Note 1) (47,733) (48,270) (39,030)
Total 331,735 312,211 284,689
Income Before Income Taxes 808,346 786,142 658,745
Income Taxes (Note 5) 125,919 126,993 94,184
NET INCOME 682,427 659,149 564,561
Less: Net income attributable to noncontrolling interests (Note 12) 15,112 17,224 17,224
Net Income (Loss) Attributable to Common Shareholders $ 667,315 $ 641,925 $ 547,337
v3.25.4
ARIZONA PUBLIC SERVICE COMPANY - CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
NET INCOME $ 631,643 $ 626,030 $ 518,781
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX      
Pension and other postretirement benefits activity, net of tax benefit (expense) of $440, $(1,022), and $536 (Note 9) (1,319) 3,093 (2,422)
Total other comprehensive income (loss) (1,466) 2,202 (1,709)
COMPREHENSIVE INCOME 630,177 628,232 517,072
Less: Comprehensive income attributable to noncontrolling interests 15,112 17,224 17,224
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS 615,065 611,008 499,848
APS      
NET INCOME 682,427 659,149 564,561
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX      
Pension and other postretirement benefits activity, net of tax benefit (expense) of $440, $(1,022), and $536 (Note 9) (1,341) 3,103 (1,623)
Total other comprehensive income (loss) (1,341) 3,103 (1,623)
COMPREHENSIVE INCOME 681,086 662,252 562,938
Less: Comprehensive income attributable to noncontrolling interests 15,112 17,224 17,224
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS $ 665,974 $ 645,028 $ 545,714
v3.25.4
ARIZONA PUBLIC SERVICE COMPANY - CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Pension and other postretirement benefits activity, net of tax benefit (expense) $ 484 $ (1,073) $ 801
APS      
Pension and other postretirement benefits activity, net of tax benefit (expense) $ 440 $ (1,022) $ 536
v3.25.4
ARIZONA PUBLIC SERVICE COMPANY - CONSOLIDATED BALANCE SHEETS - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
CURRENT ASSETS    
Cash and cash equivalents $ 6,604 $ 3,838
Customer and other receivables 579,831 525,608
Accrued unbilled revenues (Note 4) 173,692 176,903
Allowance for doubtful accounts (Note 4) (25,495) (24,849)
Materials and supplies (at average cost) 546,329 469,022
Income tax receivable (Note 5) 5,979 0
Fossil fuel (at average cost) 18,824 32,420
Assets from risk management activities (Note 13) 3,250 10,578
Deferred fuel and purchased power regulatory asset (Note 8) 149,068 287,597
Other regulatory assets (Note 8) 136,941 133,372
Other current assets 108,686 74,915
Total current assets 1,703,709 1,689,404
INVESTMENTS AND OTHER ASSETS    
Nuclear decommissioning trusts (Notes 17 and 18) 1,414,166 1,282,845
Other special use funds (Notes 17 and 18) 434,827 408,357
Assets from risk management activities (Note 13) 5,137 5,980
Other assets 144,997 115,095
Total investments and other assets 1,999,127 1,812,277
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 7 and 11)    
Plant in service and held for future use 27,370,296 25,860,950
Accumulated depreciation and amortization (9,012,021) (9,027,426)
Net 18,358,275 16,833,524
Construction work in progress 1,649,542 1,592,659
Palo Verde sale leaseback, net of accumulated depreciation of $110,886 and $268,894 (Note 12) 32,035 82,556
Intangible assets, net of accumulated amortization of $1,057,812 and $925,880 575,978 591,310
Nuclear fuel, net of accumulated amortization of $111,096 and $115,894 104,274 97,850
Total property, plant and equipment 20,720,104 19,197,899
DEFERRED DEBITS    
Regulatory assets (Notes 1, 5, 8 and 9) 1,463,357 1,389,489
Operating lease right-of-use assets (Note 20) 3,649,669 1,605,463
Assets for other postretirement benefits (Note 9) 399,334 342,102
Other 96,299 66,126
Total deferred debits 5,608,659 3,403,180
TOTAL ASSETS 30,031,599 26,102,760
CURRENT LIABILITIES    
Accounts payable 680,203 485,426
Accrued taxes 186,605 175,863
Accrued interest 105,637 81,799
Common dividends payable 110,022 106,592
Short-term borrowings (Note 6) 757,005 568,450
Current maturities of long-term debt (Note 6) 600,000 800,000
Customer deposits 63,776 44,345
Liabilities from risk management activities (Note 13) 35,141 52,340
Liabilities for asset retirements (Note 21) 71,698 50,009
Operating lease liabilities (Note 20) 188,586 100,367
Regulatory liabilities (Note 8) 210,909 206,955
Other current liabilities 151,444 171,651
Total current liabilities 3,161,026 2,843,797
DEFERRED CREDITS AND OTHER    
Liabilities from risk management activities (Note 13) 1,495 9,446
Deferred income taxes (Note 5) 2,470,932 2,444,473
Regulatory liabilities (Notes 1, 5, 8 and 9) 1,736,121 1,855,278
Liabilities for pension benefits (Note 9) 167,636 139,317
Liabilities for asset retirements (Note 21) 1,198,601 1,096,577
Customer advances 632,169 569,343
Coal mine reclamation 159,587 171,483
Deferred investment tax credit 308,261 249,490
Unrecognized tax benefits 105,484 44,233
Operating lease liabilities (Note 20) 3,548,365 1,520,877
Other 249,171 242,320
Total deferred credits and other 10,577,822 8,342,837
COMMITMENTS AND CONTINGENCIES (Note 14)
CAPITALIZATION    
Retained earnings 3,850,817 3,666,959
Accumulated other comprehensive loss (Note 19) (32,408) (30,942)
Total shareholder equity 7,046,458 6,754,311
Noncontrolling interests (Note 12) 40,617 103,167
Total equity 7,087,075 6,857,478
Long-term debt less current maturities (Note 7) 9,205,676 8,058,648
TOTAL LIABILITIES AND EQUITY 30,031,599 26,102,760
APS    
CURRENT ASSETS    
Cash and cash equivalents 4,143 3,815
Customer and other receivables 592,146 522,886
Accrued unbilled revenues (Note 4) 173,692 176,903
Allowance for doubtful accounts (Note 4) (25,495) (24,849)
Materials and supplies (at average cost) 546,329 469,022
Income tax receivable (Note 5) 0 5,463
Fossil fuel (at average cost) 18,824 32,420
Assets from risk management activities (Note 13) 3,250 10,578
Deferred fuel and purchased power regulatory asset (Note 8) 149,068 287,597
Other regulatory assets (Note 8) 136,941 133,372
Other current assets 102,820 65,754
Total current assets 1,701,718 1,682,961
INVESTMENTS AND OTHER ASSETS    
Nuclear decommissioning trusts (Notes 17 and 18) 1,414,166 1,282,845
Other special use funds (Notes 17 and 18) 394,514 374,156
Assets from risk management activities (Note 13) 5,137 5,980
Other assets 50,912 49,673
Total investments and other assets 1,864,729 1,712,654
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 7 and 11)    
Plant in service and held for future use 27,369,414 25,860,068
Accumulated depreciation and amortization (9,011,139) (9,026,544)
Net 18,358,275 16,833,524
Construction work in progress 1,649,542 1,592,659
Palo Verde sale leaseback, net of accumulated depreciation of $110,886 and $268,894 (Note 12) 32,035 82,556
Intangible assets, net of accumulated amortization of $1,057,812 and $925,880 575,823 591,154
Nuclear fuel, net of accumulated amortization of $111,096 and $115,894 104,274 97,850
Total property, plant and equipment 20,719,949 19,197,743
DEFERRED DEBITS    
Regulatory assets (Notes 1, 5, 8 and 9) 1,463,357 1,389,489
Operating lease right-of-use assets (Note 20) 3,648,658 1,604,324
Assets for other postretirement benefits (Note 9) 392,348 335,458
Other 95,600 65,606
Total deferred debits 5,599,963 3,394,877
TOTAL ASSETS 29,886,359 25,988,235
CURRENT LIABILITIES    
Accounts payable 672,518 481,955
Accrued taxes 176,968 181,698
Accrued interest 98,434 79,308
Common dividends payable 110,000 107,200
Short-term borrowings (Note 6) 507,305 339,900
Current maturities of long-term debt (Note 6) 250,000 300,000
Customer deposits 63,776 44,345
Liabilities from risk management activities (Note 13) 35,141 52,340
Liabilities for asset retirements (Note 21) 71,698 50,009
Operating lease liabilities (Note 20) 188,437 100,229
Regulatory liabilities (Note 8) 210,909 206,955
Other current liabilities 159,039 177,019
Total current liabilities 2,544,225 2,120,958
DEFERRED CREDITS AND OTHER    
Liabilities from risk management activities (Note 13) 1,495 9,446
Deferred income taxes (Note 5) 2,427,765 2,419,937
Regulatory liabilities (Notes 1, 5, 8 and 9) 1,736,121 1,855,278
Liabilities for pension benefits (Note 9) 164,892 134,855
Liabilities for asset retirements (Note 21) 1,198,601 1,096,577
Customer advances 632,169 569,343
Coal mine reclamation 159,587 171,483
Deferred investment tax credit 308,261 249,490
Unrecognized tax benefits 121,066 48,725
Operating lease liabilities (Note 20) 3,547,321 1,519,683
Other 232,661 225,250
Total deferred credits and other 10,529,939 8,300,067
COMMITMENTS AND CONTINGENCIES (Note 14)
CAPITALIZATION    
Common stock 178,162 178,162
Additional paid-in capital 4,491,696 4,116,696
Retained earnings 4,227,237 3,992,423
Accumulated other comprehensive loss (Note 19) (15,457) (14,116)
Total shareholder equity 8,881,638 8,273,165
Noncontrolling interests (Note 12) 40,617 103,167
Total equity 8,922,255 8,376,332
Long-term debt less current maturities (Note 7) 7,889,940 7,190,878
Total capitalization 16,812,195 15,567,210
TOTAL LIABILITIES AND EQUITY $ 29,886,359 $ 25,988,235
v3.25.4
ARIZONA PUBLIC SERVICE COMPANY - CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
PROPERTY, PLANT AND EQUIPMENT    
Palo Verde sale leaseback, net of accumulated depreciation $ 110,886 $ 268,894
Intangible assets, net of accumulated amortization 1,057,812 925,880
Nuclear fuel, net of accumulated amortization 111,096 115,894
APS    
PROPERTY, PLANT AND EQUIPMENT    
Palo Verde sale leaseback, net of accumulated depreciation 110,886 268,894
Intangible assets, net of accumulated amortization 1,057,812 925,880
Nuclear fuel, net of accumulated amortization $ 111,096 $ 115,894
v3.25.4
ARIZONA PUBLIC SERVICE COMPANY - CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
CASH FLOWS FROM OPERATING ACTIVITIES      
Net income $ 631,643 $ 626,030 $ 518,781
Adjustments to reconcile net income to net cash provided by operating activities:      
Depreciation and amortization including nuclear fuel 969,615 956,184 854,136
Allowance for equity funds used during construction (61,146) (38,620) (53,118)
Deferred income taxes (50,850) (20,923) (24,310)
Deferred investment tax credit 58,772 (8,253) 77,065
Changes in current assets and liabilities:      
Customer and other receivables (51,275) (12,696) (61,983)
Accrued unbilled revenues 3,211 (9,350) (2,789)
Materials, supplies and fossil fuel (63,711) (7,895) (42,911)
Income tax receivable (5,979) 332 13,754
Deferred fuel and purchased power (324,482) (250,288) (549,877)
Deferred fuel and purchased power amortization 463,011 425,886 547,243
Other current assets (42,991) (50,225) (19,550)
Accounts payable 171,138 (7,214) (75,623)
Accrued taxes 10,742 9,030 2,393
Other current liabilities 18,714 47,329 40,510
Change in unrecognized tax benefits 81,090 75 1,177
Change in long-term regulatory assets 91,373 43,305 53,112
Change in long-term regulatory liabilities 37,205 9,416 28,495
Change in other long-term assets (283,507) (132,563) (195,598)
Change in operating lease assets 151,522 98,214 90,525
Change in other long-term liabilities 138,934 24,719 61,903
Change in operating lease liabilities (165,391) (93,214) (65,779)
Net cash provided by operating activities 1,805,095 1,609,823 1,207,697
CASH FLOWS FROM INVESTING ACTIVITIES      
Capital expenditures (2,624,618) (2,249,195) (1,846,370)
Contributions in aid of construction 306,380 311,358 180,866
Allowance for borrowed funds used during construction (47,733) (48,270) (43,564)
Proceeds from nuclear decommissioning trusts sales and other special use funds 1,855,200 1,686,094 1,679,722
Investment in nuclear decommissioning trusts and other special use funds (1,858,991) (1,709,526) (1,681,845)
Other (8,912) (8,413) (6,458)
Net cash used for investing activities (2,378,674) (1,933,630) (1,694,249)
CASH FLOWS FROM FINANCING ACTIVITIES      
Issuance of long-term debt 1,742,754 1,313,229 689,349
Repayment of long-term debt (800,000) (875,000) (32,740)
Short-term borrowings and (repayments) — net 213,555 (241,050) 241,900
Short-term debt borrowings under term loan facility 575,000 550,000 0
Short-term debt repayments under term loan facility (600,000) (350,000) 0
Dividends paid on common stock (422,792) (394,663) (386,486)
Palo Verde sale leaseback noncontrolling interest acquisition (198,744) 0 0
Capital activities by noncontrolling interests (18,041) (21,255) (21,255)
Net cash provided by financing activities 576,345 322,690 486,675
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 2,766 (1,117) 123
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 3,838 4,955 4,832
CASH AND CASH EQUIVALENTS AT END OF PERIOD 6,604 3,838 4,955
APS      
CASH FLOWS FROM OPERATING ACTIVITIES      
Net income 682,427 659,149 564,561
Adjustments to reconcile net income to net cash provided by operating activities:      
Depreciation and amortization including nuclear fuel 969,547 956,009 854,051
Allowance for equity funds used during construction (61,146) (38,620) (53,118)
Deferred income taxes (58,483) (56,461) (10,314)
Deferred investment tax credit 58,772 (8,253) 77,065
Changes in current assets and liabilities:      
Customer and other receivables (66,312) (13,570) (62,716)
Accrued unbilled revenues 3,211 (9,350) (2,789)
Materials, supplies and fossil fuel (63,711) (7,895) (42,911)
Income tax receivable 5,463 (5,463) 1,102
Deferred fuel and purchased power (324,482) (250,288) (549,877)
Deferred fuel and purchased power amortization 463,011 425,886 547,243
Other current assets (46,286) (14,704) (20,243)
Accounts payable 166,924 (2,500) (70,622)
Accrued taxes (4,730) 19,410 5,542
Other current liabilities 16,162 31,982 62,212
Change in unrecognized tax benefits 81,090 75 1,177
Change in long-term regulatory assets 91,373 43,305 53,112
Change in long-term regulatory liabilities 37,205 9,416 28,495
Change in other long-term assets (256,960) (159,940) (188,483)
Change in operating lease assets 151,394 97,989 90,234
Change in other long-term liabilities 147,447 27,127 57,397
Change in operating lease liabilities (165,241) (93,076) (65,482)
Net cash provided by operating activities 1,826,675 1,610,228 1,275,636
CASH FLOWS FROM INVESTING ACTIVITIES      
Capital expenditures (2,624,618) (2,249,195) (1,825,585)
Contributions in aid of construction 306,380 311,358 180,866
Allowance for borrowed funds used during construction (47,733) (48,270) (39,030)
Proceeds from nuclear decommissioning trusts sales and other special use funds 1,803,767 1,686,094 1,679,722
Investment in nuclear decommissioning trusts and other special use funds (1,807,558) (1,684,526) (1,681,845)
Other 145 (1,660) (1,397)
Net cash used for investing activities (2,369,617) (1,986,199) (1,687,269)
CASH FLOWS FROM FINANCING ACTIVITIES      
Issuance of long-term debt 947,350 445,842 496,025
Repayment of long-term debt (300,000) (250,000) 0
Short-term borrowings and (repayments) — net 167,405 (192,950) 180,970
Short-term debt borrowings under term loan facility 400,000 350,000 0
Short-term debt repayments under term loan facility (400,000) (350,000) 0
Dividends paid on common stock (429,700) (401,400) (393,600)
Equity infusion from Pinnacle West 375,000 795,000 150,000
Palo Verde sale leaseback noncontrolling interest acquisition (198,744) 0 0
Capital activities by noncontrolling interests (18,041) (21,255) (21,255)
Net cash provided by financing activities 543,270 375,237 412,140
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 328 (734) 507
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 3,815 4,549 4,042
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 4,143 $ 3,815 $ 4,549
v3.25.4
ARIZONA PUBLIC SERVICE COMPANY - CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY - USD ($)
$ in Thousands
Total
Common Stock
Retained Earnings
Accumulated Other Comprehensive Income (Loss)
Noncontrolling Interests
APS
APS
Common Stock
APS
Additional Paid-In Capital
APS
Retained Earnings
APS
Accumulated Other Comprehensive Income (Loss)
APS
Noncontrolling Interests
Beginning balance (in shares) at Dec. 31, 2022   113,247,189         71,264,947        
Beginning balance at Dec. 31, 2022 $ 6,159,876 $ 2,724,740 $ 3,360,347 $ (31,435) $ 111,229 $ 7,052,955 $ 178,162 $ 3,171,696 $ 3,607,464 $ (15,596) $ 111,229
Increase (Decrease) in Shareholders' Equity                      
Equity infusion from Pinnacle West           150,000   150,000      
Net income 518,781   501,557   17,224 564,561     547,337   17,224
Other comprehensive (loss) income (1,709)     (1,709)   (1,623)       (1,623)  
Dividends on common stock (395,585)   (395,585)     (395,500)     (395,500)    
Capital activities by noncontrolling interests (21,255)       (21,255) (21,255)         (21,255)
Other (3)   (2)     (2)     (2)   0
Ending balance (in shares) at Dec. 31, 2023   113,537,689         71,264,947        
Ending balance at Dec. 31, 2023 6,284,862 $ 2,752,676 3,466,317 (33,144) 107,198 7,349,136 $ 178,162 3,321,696 3,759,299 (17,219) 107,198
Increase (Decrease) in Shareholders' Equity                      
Equity infusion from Pinnacle West           795,000   795,000      
Net income 626,030   608,806   17,224 659,149     641,925   17,224
Other comprehensive (loss) income 2,202     2,202   3,103       3,103  
Dividends on common stock (408,162)   (408,162)     (408,800)     (408,800)    
Capital activities by noncontrolling interests (21,255)       (21,255) (21,255)         (21,255)
Other $ (1)   (2)     (1)     (1)    
Ending balance (in shares) at Dec. 31, 2024 119,143,782 119,143,782         71,264,947        
Ending 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                      
Equity infusion from Pinnacle West           375,000   375,000      
Net income 631,643   616,531   15,112 682,427     667,315   15,112
Other comprehensive (loss) income (1,466)     (1,466)   (1,341)       (1,341)  
Dividends on common stock (432,671)   (432,671)     (432,500)     (432,500)    
Capital activities by noncontrolling interests (18,041)       (18,041) (18,041)         (18,041)
Deconsolidation of noncontrolling interests (59,621) [1]       (59,621) [1] (59,621) [2]         (59,621) [2]
Other $ (2)   (2)     (1)     (1)    
Ending balance (in shares) at Dec. 31, 2025 120,950,839 120,950,839         71,264,947        
Ending 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
[1] See Note 12 for information related to the Palo Verde sale leaseback purchases.
[2] See Note 12 for information related to the Palo Verde sale leaseback purchases.
v3.25.4
Summary of Significant Accounting Policies
 12 Months Ended
Dec. 31, 2025
Accounting Policies [Abstract]  
Summary of Significant Accounting Policies Summary of Significant Accounting Policies
Description of Business and Basis of Presentation
 
Pinnacle West is an investor-owned electric utility holding company that conducts business through its subsidiaries, APS, El Dorado and PNW Power. APS, our wholly-owned subsidiary, is a vertically-integrated electric utility that provides either retail or wholesale electric service to substantially all of the state of Arizona, with the major exceptions of about one-half of the Phoenix metropolitan area, the Tucson metropolitan area and Mohave County in northwestern Arizona.  APS accounts for essentially all of our revenues and earnings and is expected to continue to do so.  El Dorado is a wholly-owned subsidiary that invests in energy-related and Arizona community-based ventures. PNW Power, formed in September 2023, is a wholly-owned subsidiary that holds certain wind and transmission joint-venture investments previously held by BCE. BCE was sold on January 12, 2024 and is no longer included in the Company’s consolidated financial statements. See Note 22 for additional information.
 
Pinnacle West’s Consolidated Financial Statements include the accounts of Pinnacle West and our subsidiaries, including APS, El Dorado, and PNW Power, as well as BCE through the date of its sale. Pinnacle West’s Consolidated Financial Statements also include the accounts of a VIE relating to the Captive. APS’s Consolidated Financial Statements include the accounts of APS and certain VIEs relating to the Palo Verde sale leaseback.  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. See Note 12 for additional information. Intercompany accounts and transactions between the consolidated companies have been eliminated.
 
We consolidate VIEs for which we are the primary beneficiary.  We determine whether we are the primary beneficiary of a VIE through a qualitative analysis that identifies which variable interest holder has the controlling financial interest in the VIE.  In performing our primary beneficiary analysis, we consider all relevant facts and circumstances, including the design and activities of the VIE, the terms of the contracts the VIE has entered into, and which parties participated significantly in the design or redesign of the entity.  We continually evaluate our primary beneficiary conclusions to determine if changes have occurred which would impact our primary beneficiary assessments.  We have determined that APS is the primary beneficiary of a VIE lessor trust relating to the Palo Verde sale leaseback, and therefore APS consolidates this entity. We have also determined that Pinnacle West is the primary beneficiary of a protected captive insurance cell VIE, and therefore Pinnacle West consolidates this insurance cell. See Note 12 for additional information.
 
Accounting Records and Use of Estimates
 
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.
Regulatory Accounting
 
APS is regulated by the ACC and FERC.  The accompanying financial statements reflect the rate-making policies of these commissions.  As a result, we capitalize certain costs that would be included as expense in the current period by unregulated companies.  Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in customer rates. Regulatory liabilities generally represent amounts collected in rates to recover costs expected to be incurred in the future or amounts collected in excess of costs incurred and are refundable to customers.
 
Management judgments include continually assessing the likelihood of future recovery of regulatory assets and/or a disallowance of part of the cost of recently completed plant, by considering factors such as applicable regulatory environment changes and recent rate orders to other regulated entities in the same jurisdiction.  This determination reflects the current political and regulatory climate in Arizona and is subject to change in the future.  If future recovery of costs ceases to be probable, the assets would be written off as a charge in current period earnings. Management judgments also include assessing the impact of potential commission-ordered refunds to customers on regulatory liabilities. See Note 8 for additional information.
 
Electric Revenues
 
Revenues primarily consist of activities that are classified as revenues from contracts with customers. Our electric revenues generally represent a single performance obligation delivered over time. We have elected to apply the practical expedient that allows us to recognize revenue based on the amount to which we have a right to invoice for services performed.

We derive electric revenues primarily from sales of electricity to our regulated retail customers. Revenues related to the sale of electricity are generally recognized when service is rendered or electricity is delivered to customers. Unbilled revenues are estimated by applying an average revenue/kWh by customer class to the number of estimated kWhs delivered but not billed. Differences historically between the actual and estimated unbilled revenues are immaterial. We exclude sales taxes and franchise fees on electric revenues from both revenue and taxes other than income taxes.
 
Revenues from our regulated retail customers and non-derivative instruments are reported on a gross basis on Pinnacle West’s Consolidated Statements of Income. In the electricity business, some contracts to purchase electricity are netted against other contracts to sell electricity. This is called a “book-out” and usually occurs for contracts that have the same terms (quantities, delivery points and delivery periods) and for which power does not flow. We net these book-outs, which reduces both wholesale revenues and fuel and purchased power costs.

Certain cost recovery mechanisms may qualify as alternative revenue programs. For alternative revenue programs that meet specified accounting criteria, we recognize revenues when the specific events permitting billing of the additional revenues have been completed. See Notes 4 and 8 for additional information.
Allowance for Doubtful Accounts
 
The allowance for doubtful accounts represents our best estimate of accounts receivable and accrued unbilled revenues that will ultimately be uncollectible due to credit loss risk. The allowance includes a write-off component that is calculated by applying an estimated write-off factor to retail electric revenues. The write-off factor used to estimate uncollectible accounts is based upon consideration of historical collections experience, the current and forecasted economic environment, changes to our collection policies, and management’s best estimate of future collections success. See Note 4 for additional information.
 
Property, Plant and Equipment
 
Utility plant is the term we use to describe the business property and equipment that supports electric service, consisting primarily of generation, transmission, and distribution facilities.  We report utility plant at its original cost, which includes:

•material and labor;
•contractor costs;
•capitalized leases;
•construction overhead costs (where applicable); and
•AFUDC.

Pinnacle West’s property, plant and equipment included in the December 31, 2025, and 2024 Consolidated Balance Sheets is composed of the following (dollars in thousands):

Property, Plant and Equipment:20252024
Generation$9,687,466 $9,675,576 
Transmission4,451,936 4,135,970 
Distribution9,626,629 9,016,843 
Energy storage515,935 276,954 
Solar plant1,501,301 1,159,385 
General plant1,587,029 1,596,222 
Plant in service and held for future use27,370,296 25,860,950 
Accumulated depreciation and amortization(9,012,021)(9,027,426)
Net18,358,275 16,833,524 
Construction work in progress1,649,542 1,592,659 
Palo Verde sale leaseback, net of accumulated depreciation32,035 82,556 
Intangible assets, net of accumulated amortization575,978 591,310 
Nuclear fuel, net of accumulated amortization104,274 97,850 
Total property, plant and equipment$20,720,104 $19,197,899 

Property, plant and equipment balances and classes for APS are not materially different than Pinnacle West.

We expense the costs of plant outages, major maintenance and routine maintenance as incurred.  We charge retired utility plant to accumulated depreciation.  Liabilities associated with the retirement of
tangible long-lived assets are recognized at fair value as incurred and capitalized as part of the related tangible long-lived assets.  Accretion of the liability due to the passage of time is an operating expense, and the capitalized cost is depreciated over the useful life of the long-lived asset.  See Note 21 for additional information.

APS records a regulatory liability for the excess that has been recovered in regulated rates over the amount calculated in accordance with guidance on accounting for AROs.  APS believes it is probable it will recover in regulated rates, the costs calculated in accordance with this accounting guidance.
 
We record depreciation and amortization on utility plant on a straight-line basis over the remaining useful life of the related assets.  The approximate remaining average useful lives of our utility property at December 31, 2025, were as follows:

•Steam generation — 21 years;
•Nuclear plant — 30 years;
•Other generation — 16 years;
•Transmission — 34 years;
•Distribution — 33 years;
•Energy storage — 19 years;
•Solar plant — 28 years; and
•General plant — 10 years.
 
Depreciation of utility property, plant and equipment is computed on a straight-line, remaining-life basis. Depreciation expense was $732 million in 2025, $723 million in 2024, and $669 million in 2023. For the years 2023 through 2025, the depreciation rates ranged from a low of 1.37% to a high of 12.37%.  The weighted-average depreciation rate was 3.06% in 2025, 3.13% in 2024, and 2.98% in 2023.

Asset Retirement Obligations

APS has AROs for its Palo Verde nuclear facilities and certain other generation assets.  The Palo Verde ARO primarily relates to final plant decommissioning.  This obligation is based on the NRC’s requirements for disposal of irradiated property or plant and agreements APS reached with the ACC for final decommissioning of the plant.  The non-nuclear generation AROs primarily relate to requirements for removing portions of those plants at the end of the plant life or lease term and coal ash pond closures. Some of APS’s transmission and distribution assets have AROs because they are subject to right of way and easement agreements that require final removal.  These agreements have a history of uninterrupted renewal that APS expects to continue.  As a result, APS cannot reasonably estimate the fair value of the ARO related to such transmission and distribution assets. Additionally, APS has aquifer protection permits for some of its generation sites that require the closure of certain facilities at those sites. See Note 21 for additional information.

Allowance for Funds Used During Construction
 
AFUDC represents the approximate net composite interest cost of borrowed funds and an allowed return on the equity funds used for construction of regulated utility plant.  Both the debt and equity components of AFUDC are non-cash amounts within the Consolidated Statements of Income.  Plant
construction costs, including AFUDC, are recovered in authorized rates through depreciation when completed projects are placed into commercial operation.
 
AFUDC was calculated by using a composite rate of 6.67% for 2025, 6.23% for 2024, and 6.29% for 2023.  APS compounds AFUDC semi-annually and ceases to accrue AFUDC when construction work is completed and the property is placed in service.

Materials and Supplies
 
APS values materials, supplies and fossil fuel inventory using a weighted-average cost method.  APS materials, supplies and fossil fuel inventories are carried at the lower of weighted-average cost or net realizable value, unless evidence indicates that the weighted-average cost (even if in excess of market) will be recovered.
 
Fair Value Measurements
 
We apply recurring fair value measurements to cash equivalents, derivative instruments, investments held in the nuclear decommissioning trust and other special use funds. On an annual basis, we apply fair value measurements to plan assets held in our retirement and other benefits plans. Due to the nature of short-term borrowings, the carrying values of these instruments approximate fair value.  Fair value measurements may also be applied on a nonrecurring basis to other assets and liabilities in certain circumstances such as impairments.  We also disclose fair value information for our long-term debt, which is carried at amortized cost. See Note 7 for additional information.
 
Fair value is the price that would be received for an asset or paid to transfer a liability (exit price) in the principal or most advantageous market which we can access for the asset or liability in an orderly transaction between willing market participants on the measurement date.  Inputs to fair value may include observable and unobservable data.  We maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.
 
We determine fair market value using observable inputs such as actively-quoted prices for identical instruments when available.  When actively-quoted prices are not available for the identical instruments, we use other observable inputs, such as prices for similar instruments, other corroborative market information, or prices provided by other external sources.  For options, long-term contracts, and other contracts for which observable price data are not available, we use models and other valuation methods, which may incorporate unobservable inputs to determine fair market value.

The use of models and other valuation methods to determine fair market value often requires subjective and complex judgment.  Actual results could differ from the results estimated through application of these methods. See Note 17 for additional information.
Derivative Accounting
 
We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas, coal and in interest rates.  We manage risks associated with market volatility by utilizing various physical and financial instruments including futures, forwards, options, and swaps.  As part of our overall risk management program, we may use derivative instruments to hedge purchases and sales of electricity and natural gas as well as interest rate risk.  The changes in market value
of such contracts have a high correlation to price changes in the hedged transactions.  We also enter into derivative instruments for economic hedging purposes.  Contracts that have the same terms (quantities, delivery points and delivery periods) and for which power does not flow are netted, which reduces both revenues and fuel and purchased power expenses in our Consolidated Statements of Income, but does not impact our financial condition, net income, or cash flows.
 
We account for our derivative contracts in accordance with derivatives and hedging guidance, which requires all derivatives not qualifying for a scope exception to be measured at fair value on the balance sheet as either assets or liabilities.  Transactions with counterparties that have master netting arrangements are reported net on the balance sheet.  See Note 13 for additional information.
 
Loss Contingencies and Environmental Liabilities
 
Pinnacle West and APS are involved in certain legal and environmental matters that arise in the normal course of business.  Contingent losses and environmental liabilities are recorded when it is determined that it is probable that a loss has occurred, and the amount of the loss can be reasonably estimated.  When a range of the probable loss exists and no amount within the range is a better estimate than any other amount, Pinnacle West and APS record a loss contingency at the minimum amount in the range.  Unless otherwise required by GAAP, legal fees are expensed as incurred.
 
The Captive’s contingent losses may include an amount for losses incurred but not reported (“IBNR”). A reserve for IBNR is based upon a loss analysis prepared using actuarial assumptions and techniques. Such liabilities are necessarily based on estimates and the ultimate obligation may be in excess of or less than the estimated liability. The methods for making such estimates and for establishing the resulting liability are continually reviewed, and any adjustments for the review process as well as differences between estimates and ultimate payments are reflected in earnings currently. As of December 31, 2025, no IBNR reserve relating to our Captive has been recorded. See Note 12 for additional information.

Retirement Plans and Other Postretirement Benefits
 
Pinnacle West sponsors a qualified defined benefit and account balance pension plan for the employees of Pinnacle West and its subsidiaries, in addition to a non-qualified pension plan.  We also sponsor another postretirement benefit plan for the employees of Pinnacle West and its subsidiaries that provides medical and life insurance benefits to retired employees.  Pension and other postretirement benefit expense are determined by actuarial valuations, based on assumptions that are evaluated annually.  See Note 9 for additional information.
 
Nuclear Fuel
 
APS amortizes nuclear fuel by using the unit-of-production method.  The unit-of-production method is based on actual physical usage.  APS divides the cost of the fuel by the estimated number of thermal units it expects to produce with that fuel.  APS then multiplies that rate by the number of thermal units produced within the current period.  This calculation determines the current period nuclear fuel expense.
 
APS also charges nuclear fuel expense for the interim storage and permanent disposal of spent nuclear fuel.  The DOE is responsible for the permanent disposal of spent nuclear fuel and charged APS
$0.001 per kWh of nuclear generation through May 2014, at which point the DOE reduced the fee to zero.  In accordance with a settlement agreement with the DOE in August 2014 for interim storage, we accrued a receivable and an offsetting regulatory liability through the settlement period ended December of 2025. See Note 14 for additional information.
 
Income Taxes
 
Income taxes are provided using the asset and liability approach prescribed by guidance relating to accounting for income taxes and are based on currently enacted tax rates.  We file our federal income tax return on a consolidated basis, and we file our state income tax returns on a consolidated or unitary basis.  In accordance with our intercompany tax sharing agreement, federal and state income taxes are allocated to each first-tier subsidiary as though each first-tier subsidiary filed a separate income tax return.  Any difference between that method and the consolidated (and unitary) income tax liability is attributed to the parent company.  The income tax accounts reflect the tax and interest associated with management’s estimate of the largest amount of tax benefit that is greater than 50% likely of being realized upon settlement for all known and measurable tax exposures. See Note 5 for additional information.
Cash and Cash Equivalents

     We consider cash equivalents to be highly liquid investments with a remaining maturity of three months or less at acquisition.

The following table summarizes supplemental Pinnacle West cash flow information for each of the last three years (dollars in thousands):
Year Ended December 31,
202520242023
Cash paid during the period for:
Income taxes, net of refunds/credits$22,754 $133,968 $8,788 
Interest, net of amounts capitalized388,540 360,349 310,996 
Significant non-cash investing and financing activities:
Accrued capital expenditures$281,133 $257,494 $206,269 
Dividends accrued but not yet paid110,022 106,592 99,813 
BCE Sale non-cash consideration (Note 22)
— — 28,262 

The following table summarizes supplemental APS cash flow information for each of the last three years (dollars in thousands):
Year Ended December 31,
202520242023
Cash paid during the period for:
Income taxes, net of refunds/credits$53,638 $179,013 $21,734 
Interest, net of amounts capitalized307,520 299,799 267,261 
Significant non-cash investing and financing activities:
Accrued capital expenditures$281,133 $257,494 $206,269 
Dividends accrued but not yet paid110,000 107,200 99,800 
Intangible Assets
 
We have separately disclosed intangible assets on Pinnacle West’s Consolidated Balance Sheets. The intangible assets relate primarily to APS’s internal-use software. We have no goodwill recorded. The intangible assets are amortized over their finite useful lives.  Amortization expense was $157 million in 2025, $136 million in 2024, and $90 million in 2023.  Estimated amortization expense on existing intangible assets over the next five years is $109 million in 2026, $75 million in 2027, $45 million in 2028, $26 million in 2029, and $14 million in 2030.  At December 31, 2025, the weighted-average remaining amortization period for intangible assets was 6 years.
 
Investments
 
El Dorado holds investments in both debt and equity securities.  Investments in debt securities are generally accounted for as held-to-maturity and investments in equity securities are accounted for using either the equity method (if significant influence) or the measurement alternative for investments without readily determinable fair values (if less than 3-5% ownership and no significant influence). See Note 23 for additional information.

PNW Power holds investments in equity securities. Investments in equity securities are accounted for using either the equity method (if significant influence) or the measurement alternative for investments without readily determinable fair values (if less than 3-5% ownership and no significant influence).
 
Our investments in the nuclear decommissioning trusts, and other special use funds, are accounted for in accordance with guidance on accounting for investments in debt and equity securities. See Notes 17 and 18 for additional information.

Leases

We determine if an agreement is a lease at contract inception. A lease is defined as a contract, or part of a contract, that conveys the right to control the use of an identified asset for a period of time in exchange for consideration. To control the use of an identified asset an entity must have both a right to obtain substantially all of the benefits from the use of the asset and the right to direct the use of the asset. If we determine an agreement is a lease, and we are the lessee, we recognize a right-of-use lease asset and a lease liability at the lease commencement date. Lease liabilities are recognized based on the present value of the fixed lease payments over the lease term. To present value lease liabilities we use the implicit rate in the lease if the information is readily available, otherwise we use our incremental borrowing rate determined at lease commencement. Our incremental borrowing rate is based on the rate of interest we would have to borrow on a collateralized basis over a similar term an amount equal to the lease payments in a similar economic environment. When measuring right-of-use assets and lease liabilities we exclude variable lease payments, other than those that depend on an index or rate or are in-substance fixed payments. For short-term leases with terms of 12 months or less, we do not recognize a right-of-use lease asset or lease liability. We recognize operating lease expense using a straight-line pattern over the periods of use.

APS enters into purchased power contracts that may contain leases. This occurs when a PPA designates a specific power plant or facility, APS obtains substantially all of the economic benefits from the use of the facility and has the right to direct the use of the facility. Purchased power lease contracts may also include energy storage facilities. Lease costs relating to purchased power lease contracts are
reported in fuel and purchased power on the Consolidated Statements of Income and are subject to recovery under the PSA or RES. See Note 8 for additional information. We also may enter into lease agreements related to vehicles, office space, land, and other equipment. See Note 20 for additional information.

Preferred Stock

At December 31, 2025, Pinnacle West had 10 million shares of serial preferred stock authorized with no par value, none of which was outstanding, and APS had 15,535,000 shares of various types of preferred stock authorized with $25, $50, and $100 par values, none of which was outstanding.
v3.25.4
Business Segments
 12 Months Ended
Dec. 31, 2025
Segment Reporting [Abstract]  
Business Segments Business Segments
 
Pinnacle West’s reportable business segment is our regulated electricity segment, which consists of retail and wholesale sales supplied under traditional cost-based regulation and related activities and includes electricity generation, transmission, and distribution. Our reportable segment activities are conducted through our wholly-owned subsidiary, APS. All other operating segment activities are insignificant to Pinnacle West.

For segment reporting purposes, Pinnacle West’s Chief Executive Officer performs the function of chief operating decision maker (“CODM”). Our CODM uses net income to measure an operating segment’s profitability. When assessing the performance of an operating segment, and making decisions about allocating resources, our CODM evaluates net income actual results compared to budget. Net income is also used when implementing strategic initiatives and selecting projects to meet business objectives. Our reportable segment’s revenue streams are dependent upon regulated rate recovery, which is a primary factor in how we identify operating segments.

For information on our reportable business segment’s revenues, significant expenses, net income (loss), assets, and other reportable segment items, see the APS Consolidated Statements of Income, APS Consolidated Balance Sheets, and APS 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):
Year Ended December 31,
202520242023
Regulated Electricity SegmentOtherPinnacle West ConsolidatedRegulated Electricity SegmentOtherPinnacle West ConsolidatedRegulated Electricity SegmentOther Pinnacle West Consolidated
Operating revenues$5,340 $— $5,340 $5,125 $— $5,125 $4,696 $— $4,696 
Fuel and purchased power (1,933)— (1,933)(1,823)— (1,823)(1,793)— (1,793)
Operations and maintenance(1,177)(8)(1,185)(1,159)(6)(1,165)(1,044)(15)(1,059)
Depreciation and amortization (915)— (915)(895)— (895)(794)— (794)
Taxes other than income taxes (235)— (235)(227)— (227)(224)— (224)
Allowance for equity funds used during construction61 — 61 39 — 39 53 — 53 
Pension and other postretirement non-service credits, net13 (1)12 49 — 49 42 (1)41 
Other income and (expense), net(14)30 16 (11)22 11 7 — 7 
Interest charges, net of allowance for borrowed funds used during construction(332)(90)(422)(312)(65)(377)(285)(46)(331)
Income taxes(126)19 (107)(127)16 (111)(94)17 (77)
Less: Net income attributable to noncontrolling interests(15)— (15)(17)— (17)(17)— (17)
Net Income (Loss) $667 $(50)$617 $642 $(33)$609 $547 $(45)$502 
The following table reconciles our reportable segment’s assets to the Pinnacle West consolidated amount (dollars in millions):
December 31, 2025December 31, 2024
Regulated Electricity SegmentOtherPinnacle West ConsolidatedRegulated Electricity SegmentOtherPinnacle West Consolidated
Total Assets$29,886 $146 $30,032 $25,988 $115 $26,103 
v3.25.4
New Accounting Standards
 12 Months Ended
Dec. 31, 2025
Accounting Standards Update and Change in Accounting Principle [Abstract]  
New Accounting Standards New Accounting Standards
 
ASU 2023-09, Income Taxes: Improvements to Income Tax Disclosures

In December 2023, a new accounting standard was issued that expands disclosures relating to income taxes. The expanded disclosures include a tabular income tax rate reconciliation, disclosure of specific reconciliation categories and reconciling items, the amount of income taxes paid by jurisdiction, and other disclosures. We adopted this standard on December 31, 2025, using a retrospective approach. The adoption of the new standard results in changes to our income tax disclosures, but did not impact our accounting for income taxes or our financial statement results. See Note 5.

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 2025-03, Business Combinations and Consolidation: Determining the Accounting Acquirer in the Acquisition of a Variable Interest Entity

In May 2025, a new accounting standard was issued that revises the guidance on identifying the accounting acquirer in a business combination in which the acquiree is a VIE that meets the definition of a business. Prior to the issuance of the amended guidance, for certain transactions, the primary beneficiary of the VIE was always required to be deemed the acquirer in the transaction. Under the amended guidance, an entity will now need to complete an assessment of the transaction to determine the acquiring entity and is no longer required to assume that the primary beneficiary is the acquirer in the transaction.

The standard will become effective for us on January 1, 2027, with early adoption permitted. We expect to adopt this guidance on January 1, 2027, and will apply the guidance prospectively to acquisition transactions occurring on and after the adoption date. Upon adoption, we do not expect the guidance will have a material impact on our financial statements. The adoption of this guidance will not impact the APS purchase transactions relating to the Palo Verde sale leaseback VIEs. See Note 12.

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 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.
v3.25.4
Revenue
 12 Months Ended
Dec. 31, 2025
Revenue from Contract with Customer [Abstract]  
Revenue Revenue
Sources of Revenue

The following table provides detail of Pinnacle West’s consolidated revenues disaggregated by revenue sources (dollars in thousands):

Year Ended December 31,
202520242023
Retail Electric Service
Residential$2,541,320 $2,562,822 $2,289,196 
Non-Residential2,542,936 2,334,925 2,048,416 
Wholesale Energy Sales108,661 96,857 208,985 
Transmission Services for Others129,667 119,038 138,631 
Other Sources17,355 11,273 10,763 
Total Operating Revenues$5,339,939 $5,124,915 $4,695,991 
Retail Electric Revenues

All of Pinnacle West’s retail electric revenues are generated by APS. Retail electric revenue is generated by the sale of electricity to our regulated customers within the authorized service territory at tariff rates approved by the ACC and based on customer usage. Revenues related to the sale of electricity are generally recognized when service is rendered, or electricity is delivered to customers. The billing of electricity sales to individual customers is based on the reading of their meters. We obtain customers’ meter data on a systematic basis throughout the month, and generally bill customers within a month from when service was provided. Customers are generally required to pay for services within 21 days of when the services are billed. See “Allowance for Doubtful Accounts” discussion below for additional details regarding payment terms. In addition, see the section titled “2025 Rate Case” in Note 8 for details related to proposed adjustments to rate design and modifications of cost allocation methodologies to reduce cross-subsidization by ensuring customers causing production costs are covering those costs through rates.

Wholesale Energy Sales and Transmission Services for Others

All of Pinnacle West’s wholesale energy sales and transmission services for others revenues is generated by APS. Revenues from wholesale energy sales and transmission services for others 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.
Revenue Activities

Our revenues primarily consist of activities that are classified as revenues from contracts with customers. We derive our revenues from contracts with customers primarily from sales of electricity to our regulated retail customers. Revenues from contracts with customers also include wholesale and transmission activities. Our revenues from contracts with customers for the year ended December 31, 2025, 2024 and 2023 were $5,319 million, $5,073 million, and $4,651 million, respectively.

We have certain revenues that do not meet the specific accounting criteria to be classified as revenues from contracts with customers. For the year ended December 31, 2025, 2024, and 2023 our revenues that do not qualify as revenue from contracts with customers were $21 million, $52 million, and $45 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 8 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):

Year Ended December 31,
202520242023
Balance at beginning of period$24,849 $22,433 $23,778 
Bad debt expense28,603 35,799 23,399 
Actual write-offs(27,957)(33,383)(24,744)
Balance at end of period$25,495 $24,849 $22,433 
v3.25.4
Income Taxes
 12 Months Ended
Dec. 31, 2025
Income Tax Disclosure [Abstract]  
Income Taxes Income Taxes
Certain assets and liabilities are reported differently for income tax purposes than they are for financial statement purposes.  The tax effect of these differences is recorded as deferred taxes.  We calculate deferred taxes using currently enacted income tax rates.    

APS has recorded regulatory assets and regulatory liabilities related to income taxes on its Consolidated Balance Sheets in accordance with accounting guidance for regulated operations.  The regulatory assets are for certain temporary differences, primarily the allowance for equity funds used during construction, ITC basis adjustment and tax expense of Medicare subsidy.  The regulatory liabilities primarily relate to the change in income tax rates and deferred taxes resulting from ITCs.    

In accordance with regulatory requirements, APS ITCs are deferred and are amortized over the life of the related property with such amortization applied as a credit to reduce current income tax expense in the Statements of Income.

On January 30, 2024, Pinnacle West entered into a tax credit transfer agreement to purchase from Ameresco $23 million of investment tax credits from the BCE Los Alamitos project for $21 million. While the $23 million reduced tax payments, the $21 million paid to Ameresco is not included in the income taxes paid table below. See Note 22 for more information about the BCE Sale.

The Company 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 and the Company continues to not recognize any income tax benefits related to the Nuclear PTC.
Net income associated with the Captive and Palo Verde sale leaseback VIEs is not subject to tax.  As a result, there is no income tax expense associated with the VIEs recorded on the Pinnacle West Consolidated and APS Consolidated Statements of Income. See Note 12 for additional details related to Palo Verde sale leaseback VIEs.

The components of income tax expense are as follows (dollars in thousands):
Pinnacle West ConsolidatedAPS Consolidated
 Year Ended December 31,Year Ended December 31,
 202520242023202520242023
Current:   
Federal$87,913 $137,342 $21,272 $94,207 $165,653 $26,405 
State10,892 2,392 2,854 31,424 26,054 1,027 
Total current98,805 139,734 24,126 125,631 191,707 27,432 
Deferred:
Federal(11,073)(53,228)37,273 (2,902)(69,075)44,922 
State18,994 24,023 15,513 3,190 4,361 21,830 
Total deferred7,921 (29,205)52,786 288 (64,714)66,752 
Income tax expense
106,726 110,529 76,912 125,919 126,993 94,184 
The following table compares Pinnacle West Consolidated pretax income at the 21% statutory federal income tax rate to income tax expense (dollars in thousands) and effective tax rates:
Pinnacle West Consolidated
 Year Ended December 31,
202520242023
 AmountPercentAmountPercentAmountPercent
Income before income taxes (a)$738,369 $736,559 $595,693 
Federal income tax expense at statutory rate155,057 21.00 %154,677 21.00 %125,095 21.00 %
State income tax net of federal income tax benefit (b)23,610 3.20 %23,735 3.22 %17,832 2.99 %
Changes in Valuation Allowance— — %— — %— — %
Nontaxable or Nondeductible Items
Share based compensation(4,062)(0.55)%(421)(0.06)%1,346 0.23 %
Palo Verde VIE noncontrolling interest (Note 12)
(3,173)(0.43)%(3,617)(0.49)%(3,617)(0.61)%
Other Nontaxable or Nondeductible Items5,896 0.80 %3,667 0.50 %2,405 0.40 %
Effect of changes in tax laws or rates enacted in the current period— — %— — %— — %
Tax Credits
Solar or Wind Production Tax Credit(14,698)(1.99)%(15,206)(2.07)%(8,441)(1.42)%
Other Federal Income Tax Credits(19)— %(242)(0.03)%(650)(0.11)%
Investment credit amortization – deferral method(12,625)(1.71)%(9,425)(1.28)%(9,495)(1.59)%
Changes in Unrecognized Tax Benefits1,523 0.21 %(28)— %(1,961)(0.33)%
Effects of Utility Ratemaking
Excess deferred income taxes — Tax Cuts and Jobs Act(36,558)(4.95)%(36,559)(4.96)%(36,558)(6.14)%
Allowance for equity funds used during construction (Note 1)
(7,005)(0.95)%(2,545)(0.35)%(5,964)(1.00)%
Other regulatory amortization(2,758)(0.38)%(1,796)(0.24)%(1,828)(0.31)%
Other Adjustments1,538 0.20 %(1,711)(0.23)%(1,252)(0.20)%
Income tax expense
$106,726 14.45 %$110,529 15.01 %$76,912 12.91 %
(a)     Income before income taxes is from continuing operations and is entirely domestic.
(b)     The State of Arizona makes up the majority (greater than 50 percent) of the effect of the state and local income tax category.
The following table compares APS Consolidated pretax income at the 21% statutory federal income tax rate to income tax expense (dollars in thousands) and effective tax rates:
APS Consolidated
 Year Ended December 31,
202520242023
 AmountPercentAmountPercentAmountPercent
Income before income taxes (a)$808,346 $786,142 $658,745 
Federal income tax expense at statutory rate169,753 21.00 %165,090 21.00 %138,337 21.00 %
State income tax net of federal income tax benefit (b)27,345 3.38 %26,824 3.41 %21,453 3.26 %
Changes in Valuation Allowance— — %— — %— — %
Nontaxable or Nondeductible Items
Share based compensation(2,482)(0.31)%23 — %997 0.15 %
Palo Verde VIE noncontrolling interest (Note 12)
(3,173)(0.39)%(3,617)(0.46)%(3,617)(0.55)%
Other Nontaxable or Nondeductible Items1,727 0.21 %694 0.09 %263 0.04 %
Effect of changes in tax laws or rates enacted in the current period— — %— — %— — %
Tax Credits
Solar or Wind Production Tax Credit(11,254)(1.39)%(12,110)(1.54)%(5,460)(0.83)%
Other Federal Income Tax Credits(19)— %(242)(0.03)%(650)(0.10)%
Investment credit amortization – deferral method(12,625)(1.56)%(9,425)(1.20)%(9,495)(1.44)%
Changes in Unrecognized Tax Benefits1,483 0.18 %(107)(0.01)%(1,946)(0.30)%
Effects of Utility Ratemaking
Excess deferred income taxes — Tax Cuts and Jobs Act(36,558)(4.52)%(36,559)(4.65)%(36,558)(5.55)%
Allowance for equity funds used during construction (Note 1)
(7,005)(0.87)%(2,545)(0.32)%(5,964)(0.91)%
Other regulatory amortization(2,758)(0.34)%(1,796)(0.23)%(1,828)(0.28)%
Other Adjustments1,485 0.19 %763 0.09 %(1,348)(0.19)%
Income tax expense
$125,919 15.58 %$126,993 16.15 %$94,184 14.30 %
(a)     Income before income taxes is from continuing operations and is entirely domestic.
(b)     The State of Arizona makes up the majority (greater than 50 percent) of the effect of the state and local income tax category.
The following table presents the income taxes paid for Pinnacle West and APS on a retrospective basis (dollars in thousands):
Pinnacle West ConsolidatedAPS Consolidated
 Year Ended December 31,Year Ended December 31,
 202520242023202520242023
Federal$20,894 $112,870 $8,609 $30,207 $156,112 $21,438 
State1,860 128 179 23,431 22,901 296 
Total$22,754 $112,998 $8,788 $53,638 $179,013 $21,734 
    
State income taxes paid (net of refunds) exceed 5 percent of total income taxes paid (net of refunds) in the following jurisdictions (dollars in thousands):
Pinnacle West ConsolidatedAPS Consolidated
 Year Ended December 31,Year Ended December 31,
 202520242023202520242023
Arizona$2,000 $— (a)$— (a)$23,423 $22,788 $— (a)

(a)    Jurisdiction below the threshold for the period presented.

The following is a tabular reconciliation of the total amounts of unrecognized tax benefits, excluding interest and penalties, at the beginning and end of the year that are included in accrued taxes and unrecognized tax benefits (dollars in thousands):

Pinnacle West ConsolidatedAPS Consolidated
 202520242023202520242023
Total unrecognized tax benefits, January 1$44,349 $44,274 $43,097 $44,349 $44,274 $43,097 
Additions for tax positions of the current year81,286 1,271 1,473 81,286 1,271 1,473 
Additions for tax positions of prior years2,818 2,031 419 2,818 2,031 419 
Reductions for tax positions of prior years for:000000
Changes in judgment(2,044)(2,043)661 (2,044)(2,043)661 
Settlements with taxing authorities— — — — — — 
Lapses of applicable statute of limitations(970)(1,184)(1,376)(970)(1,184)(1,376)
Total unrecognized tax benefits, December 31$125,439 $44,349 $44,274 $125,439 $44,349 $44,274 

Included in the balances of unrecognized tax benefits are the following tax positions that, if recognized, would decrease our effective tax rate (dollars in thousands):

Pinnacle West ConsolidatedAPS Consolidated
 202520242023202520242023
Tax positions, that if recognized, would decrease our effective tax rate$103,785 $27,899 $28,762 $103,785 $27,899 $28,762 

As of December 31, 2025, the tax year ended December 31, 2022 and all subsequent tax years remain subject to examination by the IRS.  With a few exceptions, we are no longer subject to state income tax examinations by tax authorities for years before 2021.
We reflect interest and penalties, if any, on unrecognized tax benefits in the Pinnacle West Consolidated and APS Consolidated Statements of Income as income tax expense.  The amount of interest expense or benefit recognized related to unrecognized tax benefits are as follows (dollars in thousands):

Pinnacle West ConsolidatedAPS Consolidated
 202520242023202520242023
Unrecognized tax benefit interest expense recognized
$3,610 $2,743 $452 $3,610 $2,743 $452 

Following are the total amounts of accrued liabilities for interest recognized related to unrecognized benefits that could reverse and decrease our effective tax rate to the extent matters are settled favorably (dollars in thousands):

Pinnacle West ConsolidatedAPS Consolidated
 202520242023202520242023
Unrecognized tax benefit interest accrued $7,986 $4,376 $1,633 $7,986 $4,376 $1,633 

As of December 31, 2025, we have recognized approximately $2.8 million of interest expense to be paid on the underpayment of income taxes for certain adjustments that we have filed, or will file, with the IRS.
The components of the net deferred income tax liability were as follows (dollars in thousands):

Pinnacle West ConsolidatedAPS Consolidated
 December 31,December 31,
 2025202420252024
DEFERRED TAX ASSETS 
Risk management activities$8,422 $14,539 $8,422 $14,539 
Regulatory liabilities:
Excess deferred income taxes — Tax Cuts and Jobs Act259,000 271,004 259,000 271,004 
Asset retirement obligation and removal costs66,031 81,308 66,031 81,308 
Unamortized investment tax credits81,949 66,327 81,949 66,327 
Other postretirement benefits57,833 58,862 57,833 58,862 
Other50,611 47,671 50,611 47,671 
Operating lease liabilities923,774 400,771 923,479 400,442 
Pension liabilities46,613 39,070 43,422 36,100 
Coal reclamation liabilities39,450 42,391 39,450 42,391 
Renewable energy incentives11,908 14,571 11,908 14,571 
Credit and loss carryforwards— 7,682 — — 
Employee benefit liabilities56,447 57,853 55,243 56,561 
Other49,098 44,412 49,098 44,412 
Total deferred tax assets1,651,136 1,146,461 1,646,446 1,134,188 
DEFERRED TAX LIABILITIES   
Plant-related(2,595,668)(2,562,990)(2,595,668)(2,562,990)
Risk management activities(2,072)(4,089)(2,072)(4,089)
Pension and other postretirement assets(97,557)(83,401)(96,988)(82,925)
Other special use funds(58,175)(55,146)(58,175)(55,146)
Operating lease right-of-use assets(923,774)(400,771)(923,479)(400,443)
Regulatory assets:
Allowance for equity funds used during construction(50,402)(47,694)(50,402)(47,694)
Deferred fuel and purchased power(45,504)(84,393)(45,504)(84,393)
Pension benefits(178,736)(185,641)(178,736)(185,641)
Ocotillo deferral(24,703)(28,372)(24,703)(28,372)
SCR deferral(19,080)(20,548)(19,080)(20,548)
Retired power plant costs (13,157)(16,904)(13,157)(16,904)
Other(58,822)(57,602)(58,822)(57,602)
Other(54,418)(43,383)(7,425)(7,378)
Total deferred tax liabilities(4,122,068)(3,590,934)(4,074,211)(3,554,125)
Deferred income taxes — net$(2,470,932)$(2,444,473)$(2,427,765)$(2,419,937)

As of December 31, 2025, Pinnacle West consolidated deferred tax assets for credit and loss carryforwards relate to federal credit carryforwards of $27.9 million. Pinnacle West consolidated credit and loss carryforwards amount above has been reduced by $27.9 million of unrecognized tax benefits.

As of December 31, 2025, APS consolidated deferred tax assets for credit and loss carryforwards relate to federal credit carryforwards of $12.4 million. APS consolidated credit and loss carryforwards amount above has been reduced by $12.4 million of unrecognized tax benefits.
v3.25.4
Lines of Credit and Short-Term Borrowings
 12 Months Ended
Dec. 31, 2025
Debt Disclosure [Abstract]  
Lines of Credit and Short-Term Borrowings Lines of Credit and Short-Term Borrowings
Pinnacle West and APS maintain committed revolving credit facilities in order to enhance liquidity and provide credit support for their commercial paper programs, to refinance indebtedness, and for other general corporate purposes.
The table below presents the consolidated credit and term loan facilities and the amounts available and outstanding (dollars in thousands): 
December 31, 2025December 31, 2024
Pinnacle West ConsolidatedAPS ConsolidatedTotalPinnacle West ConsolidatedAPS ConsolidatedTotal
Commitments under Revolving Credit and Term Loan Facilities$375,000 $1,250,000 $1,625,000 $400,000 $1,650,000 $2,050,000 
Outstanding short-term borrowings(249,700)(507,305)(757,005)(228,550)(339,900)(568,450)
Amount available under Revolving Credit and Term Loan Facilities$125,300 $742,695 $867,995 $171,450 $1,310,100 $1,481,550 
Weighted-Average Commitment Fees0.225%0.175%0.225%0.175%
Pinnacle West

As of December 31, 2025, Pinnacle West had a $200 million revolving credit facility that matures on April 10, 2029. Pinnacle West has the option to increase the amount of the facility up to a total of $300 million upon the satisfaction of certain conditions and with the consent of the lenders. Interest rates are based on Pinnacle West’s senior unsecured debt credit ratings and the agreement includes a sustainability-linked pricing metric which provides for an interest rate reduction or increase, by meeting or missing, respectively, targets related to specific environmental and employee health and safety sustainability objectives. Under certain circumstances, the sustainability-linked pricing metric can be terminated for the final year of the credit facility. The facility is available to support Pinnacle West’s general corporate purposes, including support for Pinnacle West’s $200 million commercial paper program, for bank borrowings or for issuances of letters of credit. As of December 31, 2025, Pinnacle West had no outstanding borrowings under its revolving credit facility, no letters of credit outstanding under its credit facility, and $75 million of outstanding commercial paper borrowings. The weighted-average interest rate for the outstanding borrowings on December 31, 2025 was 3.81%.

On February 18, 2026, Pinnacle West’s revolving credit facility was amended and extended with the following modifications, among others: (1) increasing the amount of the facility to $300 million and maintaining the option to expand it up to a total of $400 million, (2) extending the maturity date to February 18, 2031, with two 1-year extension options, (3) eliminating the sustainability-linked pricing metric, and (4) certain modifications to the definition and calculation of indebtedness to exclude (a) PPAs and energy storage leases that are recoverable through the PSA and (b) certain qualified securitization bonds. Pinnacle West’s commercial paper program was also increased to $300 million.

Pinnacle West had an outstanding 364-day $200 million term loan facility that matured on December 4, 2025. Borrowings under the facility bore interest at SOFR plus 0.95% per annum. On December 20, 2024, Pinnacle West drew the full amount of $200 million and repaid it on December 4,
2025 using proceeds from a new unsecured 364-day $175 million term loan facility discussed below and commercial paper borrowings.

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 December 31, 2025, APS had a $1.25 billion revolving credit facility, that matures on April 10, 2029. APS has the option to increase the amount of the facility to a total of $1.65 billion, upon the satisfaction of certain conditions and with the consent of the lenders. Interest rates are based on APS’s senior unsecured debt credit ratings, and the agreement includes a sustainability-linked pricing metric which provides for an interest rate reduction or increase, by meeting or missing, respectively, targets related to specific environmental and employee health and safety sustainability objectives. Under certain circumstances, the sustainability-linked pricing metric can be terminated for the final year of the credit facility. The facility is available to support APS’s general corporate purposes, including support for APS’s $1 billion commercial paper program, for bank borrowings or for issuances of letters of credit. As of December 31, 2025, APS had no outstanding borrowings under its revolving credit facility, no letters of credit outstanding under the credit facility, and $507 million of outstanding commercial paper borrowings. The weighted-average interest rate for the outstanding borrowings on December 31, 2025 was 3.83%.

On February 18, 2026, APS’s revolving credit facility was amended and extended with the following modifications, among others: (1) increasing the amount of the facility to $1.7 billion and maintaining the option to expand it up to a total of $2.1 billion, (2) extending the maturity date to February 18, 2031, with two 1-year extension options, (3) eliminating the sustainability-linked pricing metric, and (4) certain modifications to the definition and calculation of indebtedness to exclude (a) PPAs and energy storage leases that are recoverable through the PSA and (b) certain qualified securitization bonds. APS’s commercial paper program was also increased to $1.5 billion.

On December 5, 2024, APS entered into a $400 million 364-Day Term Loan Agreement that matured on December 4, 2025. Borrowings under the facility bore interest at SOFR plus 0.90% per annum. APS drew the full amount of $400 million on April 29, 2025 and repaid it on August 15, 2025 using proceeds from unsecured senior notes issuances. See Note 7.
See “Financial Assurances” in Note 14 for a discussion of other outstanding letters of credit.

Debt Provisions
 
On December 17, 2024, the ACC issued a financing order that reaffirmed APS’s short-term debt authorization equal to the sum of (i) 7% of APS’s capitalization, and (ii) $500 million (which is required to be used for costs relating to purchases of natural gas and power) and increased the long-term debt limit to $9.5 billion and made certain changes to permitted annual equity infusions into APS. See Note 7 for additional long-term debt provisions.
v3.25.4
Long-Term Debt and Liquidity Matters
 12 Months Ended
Dec. 31, 2025
Debt Disclosure [Abstract]  
Long-Term Debt and Liquidity Matters Long-Term Debt and Liquidity Matters
All of Pinnacle West’s and APS’s debt is unsecured.  The following table presents the components of long-term debt on the Consolidated Balance Sheets outstanding (dollars in thousands):
 MaturityInterestDecember 31,
 Dates (a)Rates20252024
APS    
Pollution control bonds:    
Variable2029(b)$163,975 $163,975 
Total pollution control bonds  163,975 163,975 
Senior unsecured notes2026-2055
2.20%-6.88%
8,030,000 7,380,000 
Unamortized discount  (16,796)(14,252)
Unamortized premium  17,144 9,955 
Unamortized debt issuance cost(54,383)(48,800)
Total APS long-term debt  8,139,940 7,490,878 
Less current maturities 250,000 300,000 
Total APS long-term debt less current maturities  7,889,940 7,190,878 
Pinnacle West    
Senior unsecured notes2027-2030
4.75%-5.15%
1,325,000 1,025,000 
Floating rate note2026(c)350,000 350,000 
Unamortized discount(681)(5)
Unamortized debt issuance cost(8,583)(7,225)
Total Pinnacle West long-term debt1,665,736 1,367,770 
Less current maturities350,000 500,000 
Total Pinnacle West long-term debt less current maturities1,315,736 867,770 
TOTAL LONG-TERM DEBT LESS CURRENT MATURITIES
$9,205,676 $8,058,648 
(a)    This schedule does not reflect the timing of redemptions that may occur prior to scheduled maturity.
(b)    The weighted-average interest rate for the variable rate pollution control bonds was 3.52% at December 31, 2025, and 4.01% at December 31, 2024.
(c)    The weighted-average interest rate was 5.10% at December 31, 2025, and was 5.88% at December 31, 2024. See additional details below.
The following table shows principal payments due on Pinnacle West’s and APS’s total long-term debt (dollars in thousands):
YearPinnacle West ConsolidatedAPS Consolidated
2026$600,000 $250,000 
2027825,000 300,000 
2028400,000 — 
2029568,975 568,975 
2030400,000 — 
Thereafter7,075,000 7,075,000 
Total$9,868,975 $8,193,975 
 
Debt Fair Value
 
Our long-term debt fair value estimates are classified within Level 2 of the fair value hierarchy. The following table represents the estimated fair value of our long-term debt, including current maturities (dollars in thousands):
 As of December 31, 2025As of December 31, 2024
 Carrying
Amount		Fair ValueCarrying
Amount		Fair Value
Pinnacle West$1,665,736 $1,731,388 $1,367,770 $1,393,744 
APS8,139,940 7,433,142 7,490,878 6,525,248 
Total$9,805,676 $9,164,530 $8,858,648 $7,918,992 
 
Debt and Equity Issuances

Pinnacle West

On February 28, 2024, Pinnacle West entered into equity forward sale agreements (the “February 2024 Forward Sale Agreements”), which may be settled with Pinnacle West common stock or cash. Pinnacle West also has an ATM Program under which it may offer and sell common stock and enter into forward sale agreements from time to time, subject to market conditions and other factors.

In August 2025, Pinnacle West amended the February 2024 Forward Sale Agreements with Wells Fargo Bank, National Association to extend the maturity date to December 31, 2026. In September 2025, Pinnacle West partially settled the February 2024 Forward Sale Agreements by issuing 243,186 shares of common stock and receiving net proceeds of $15 million. In December 2025, Pinnacle West partially settled the February 2024 Forward Sale Agreements by issuing 1,193,950 shares of common stock and receiving net proceeds of $75 million. The proceeds from both partial settlements were recorded in equity and were used for general corporate purposes. See Note 16 for more information on the February 2024 Forward Sale Agreements and the ATM Program.

On May 15, 2025, Pinnacle West issued $400 million of 4.90% senior unsecured notes that mature May 15, 2028 and $400 million of 5.15% senior unsecured notes that mature May 15, 2030. The net proceeds from the issuances were used to repay $500 million of 1.3% senior unsecured notes that were maturing June 15, 2025 and for general corporate purposes.
Pinnacle West also has $525 million of 4.75% Convertible Senior Notes due 2027 (“Convertible Notes”) outstanding, which are senior unsecured obligations of Pinnacle West and will mature on June 15, 2027. See Note 16 for more information.

APS

On May 15, 2025, Pinnacle West contributed $300 million into APS in the form of an equity infusion. APS used this contribution to repay the $300 million of 3.15% senior notes that matured on the same date.

On December 18, 2025, Pinnacle West contributed $75 million into APS in the form of an equity infusion. APS used this contribution for general corporate purposes.

On August 15, 2025, APS issued $700 million of 5.90% senior unsecured notes that mature August 15, 2055 and reopened its 5.70% senior unsecured notes that mature August 15, 2034, issuing an additional $250 million of such notes. The net proceeds from the issuances were used to repay the $400 million 364-day Term Loan and for general corporate purposes. See Note 6.
See “Lines of Credit and Short-Term Borrowings” in Note 6 for discussion of Pinnacle West’s and APS’s revolving credit facilities. See Notes 6 and 14 for discussion of APS’s separate outstanding letters of credit.
 
Debt Provisions
 
Pinnacle West’s and APS’s debt covenants related to their respective bank financing arrangements include maximum debt to capitalization ratios. Pinnacle West and APS comply with these covenants.  For both Pinnacle West and APS, this covenant requires that the ratio of consolidated debt to total consolidated capitalization not exceed 65%.  At December 31, 2025, the ratio was approximately 60% for Pinnacle West and 50% for APS.  Failure to comply with such covenant levels would result in an event of default, which, generally speaking, would require the immediate repayment of the debt subject to the covenants and could cross-default other debt.  See further discussion of “cross-default” provisions below.
 
Neither Pinnacle West’s nor APS’s financing agreements contain “rating triggers” that would result in an acceleration of the required interest and principal payments in the event of a rating downgrade.  However, our bank credit agreements contain a pricing grid in which the interest rates we pay for borrowings thereunder are determined by our current credit ratings.
 
All of Pinnacle West’s and APS’s credit agreements contain “cross-default” provisions that would result in defaults and the potential acceleration of payment if Pinnacle West or APS were to default under certain other material agreements. Pinnacle West and APS do not have a material adverse change covenant for credit facility borrowings.

Although provisions in APS’s articles of incorporation and ACC financing orders establish maximum amounts of preferred stock and debt that APS may issue, APS does not expect any of these provisions to limit its ability to meet its capital requirements.
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 Note 6 for additional short-term debt provisions.
v3.25.4
Regulatory Matters
 12 Months Ended
Dec. 31, 2025
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.

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 Recommended Opinion and Order (“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 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 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, AriSEIA, 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 have subsequently filed an appeal to the Arizona Court of Appeals seeking review of the ACC’s decisions regarding the GAC and on rehearing. APS cannot predict the outcome of these proceedings.

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, 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. 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. APS cannot predict the outcome of this matter, or the impact it may have on the RES surcharge.

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.

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. APS will file a compliance plan with the ACC within 120 days of the decision.

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 “RES,” 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. APS cannot predict the outcome of this matter, or the impact it may have on the DSMAC.

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):
 Year Ended December 31,
 20252024
Balance at beginning of period$287,597 $463,195 
Deferred fuel and purchased power costs324,482 250,288 
Amounts charged to customers
(463,011)(425,886)
Balance at end of period$149,068 $287,597 

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 a transition component of $0.0 per kWh. 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, $43.2 million of which has been collected as of December 31, 2025, will cease upon full collection of the lost revenue. Additionally, the CRS tariff was updated to remove the return on equity component and account for SCR-related depreciation and deferral adjustments approved in Decision No. 79293 in the 2022 Rate Case.

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, 2023, APS filed an application for revisions to the RCP. This application would decrease the RCP price to $0.07619 per kWh, reflecting a 10% annual reduction, to become effective September 1, 2023. On August 25, 2023, the ACC approved the RCP as filed.

On May 1, 2024, APS filed an application for revisions to the RCP. This application would decrease the RCP price to $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 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. APS cannot predict the outcome of these matters, or the impacts they may have on the RES or DSM surcharges discussed above.

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

Cholla 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 cannot predict the outcome of this matter.

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.

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 $23.6 million as of December 31, 2025, 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, $23.8 million as of December 31, 2025, in addition to a return on the net book value, with the exception of 15% of the annual amortization expense in rates. In addition, APS will be allowed recovery of other costs related to retirement and closure, including the Navajo coal reclamation regulatory asset, $2.5 million as of December 31, 2025. The disallowed recovery of 15% of the annual amortization does not have a material impact on APS financial statements.

Fire Mitigation

On August 14, 2024, APS filed a request with the ACC for a deferral order that would authorize APS to defer, for future recovery in rates, operations and maintenance expenses associated with wildfire management, including increased insurance costs. 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.
Regulatory Assets and Liabilities

The detail of regulatory assets is as follows (dollars in thousands):
Amortization ThroughDecember 31,
2025		December 31,
2024
Pension(a)$723,042 $750,976 
Income taxes — AFUDC equity2054203,890 192,936 
Palo Verde sale leaseback noncontrolling interests’ acquisition (b)N/A151,506 — 
Deferred fuel and purchased power (c) (d)2026149,068 287,597 
Ocotillo deferral203499,931 114,775 
Lease incentive (Note 20)
204590,005 70,541 
SCR deferral (c)203877,186 83,123 
Retired power plant costs203156,809 68,380 
Income taxes — investment tax credit basis adjustment (Note 5)
205642,459 34,834 
Deferred compensation203632,204 33,108 
Deferred fuel and purchased power — mark-to-market (Note 13)
202629,330 42,275 
FERC transmission true up202721,471 35,159 
DSM (c)202515,706 — 
Deferred property taxes202715,349 23,918 
Palo Verde VIEs (Note 12)
20468,582 20,611 
Mead-Phoenix transmission line — contributions in aid of construction20508,052 8,384 
PSA - interest20265,679 11,525 
Loss on reacquired debt20385,653 6,682 
TEAM (c)20313,879 4,534 
Active union medical trust(e)3,696 9,673 
Navajo coal reclamation20262,516 7,905 
OtherVarious3,353 3,522 
Total regulatory assets (f)$1,749,366 $1,810,458 
Less: current regulatory assets$286,009 $420,969 
Total non-current regulatory assets$1,463,357 $1,389,489 
(a)This asset represents the future recovery of pension benefit obligations and expense through retail rates.  If these costs are disallowed by the ACC, this regulatory asset would be charged to other comprehensive income/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 9 for further discussion.
(b)This asset relates to the acquisition of previously leased interest in Palo Verde Unit 2. See Note 12.
(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, TCA, and Other Transmission Matters.”
The detail of regulatory liabilities is as follows (dollars in thousands):
Amortization ThroughDecember 31,
2025		December 31,
2024
Excess deferred income taxes - ACC — Tax Cuts and Jobs Act (a)2046$847,572 $888,896 
Excess deferred income taxes - FERC — Tax Cuts and Jobs Act (a)2058200,161 207,400 
AROs and removal costs(b)286,907 358,403 
Other postretirement benefits(c)233,952 238,113 
Four Corners coal reclamation203897,988 77,532 
Income taxes — deferred investment tax credit205681,949 66,327 
Income taxes — change in rates205456,260 59,133 
RES (d)202654,551 68,523 
DSM (d)202526,228 23,927 
Sundance maintenance203125,668 23,086 
Spent nuclear fuel202720,492 26,818 
TCA Balancing Account (d)20274,860 14,834 
TEAM (d) 20323,738 4,343 
Deferred fuel and purchased power — mark-to-market (Note 13)
20283,641 — 
OtherVarious3,063 4,898 
Total regulatory liabilities$1,947,030 $2,062,233 
Less: current regulatory liabilities$210,909 $206,955 
Total non-current regulatory liabilities$1,736,121 $1,855,278 
(a)For purposes of presentation on the Statements of Cash Flows, amortization of the regulatory liabilities for excess deferred income taxes are reflected as “Deferred income taxes” under Cash Flows From Operating Activities.
(b)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 9.
(d)See “Cost Recovery Mechanisms” discussion above.
v3.25.4
Retirement Plans and Other Postretirement Benefits
 12 Months Ended
Dec. 31, 2025
Retirement Benefits [Abstract]  
Retirement Plans and Other Postretirement Benefits Retirement Plans and Other Postretirement Benefits
Pinnacle West sponsors a qualified defined benefit and account balance pension plan (The Pinnacle West Capital Corporation Retirement Plan) and a non-qualified supplemental excess benefit retirement plan for the employees of Pinnacle West and its subsidiaries.  All new employees participate in the account balance plan.  Defined benefit plans specify the amount of benefits a plan participant is to receive using information about the participant.  The pension plan covers nearly all employees.  The supplemental excess benefit retirement plan covers officers of the Company and highly compensated employees designated for participation by the Board of Directors.  Our employees do not contribute directly to the plans.  We calculate the benefits based on age, years of service and pay.

Pinnacle West also sponsors other postretirement benefit plans (Pinnacle West Capital Corporation Group Life and Medical Plan and Pinnacle West Capital Corporation Post-65 Retiree Health Reimbursement Arrangement “HRA”) for the employees of Pinnacle West and its subsidiaries.  These plans provide medical and life insurance benefits to retired employees.  Employees must retire to become eligible for these retirement benefits, which are based on years of service and age.  For the medical
insurance plan, retirees make contributions to cover a portion of the plan costs.  For the life insurance plan, retirees do not make contributions.  We retain the right to change or eliminate these benefits.

Pinnacle West uses a December 31 measurement date each year for its pension and other postretirement benefit plans.  The market-related value of our plan assets is their fair value at the measurement date.  See Note 17 for further discussion of how fair values are determined.  Due to subjective and complex judgments, which may be required in determining fair values, actual results could differ from the results estimated through the application of these methods.

A significant portion of the changes in the actuarial gains and losses of our pension and postretirement plans is attributable to APS and are recoverable in rates.  Accordingly, these changes are recorded as a regulatory asset or regulatory liability. Our retail rates provide for the inclusion of annual benefit expense, which allows for recovery or return of this regulatory asset/liability. See Note 8.
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
 202520242023202520242023
Service cost-benefits earned during the period$44,153 $43,641 $39,461 $8,081 $9,955 $8,567 
Non-service costs (credits):
Interest cost on benefit obligation155,121 148,643 153,561 20,345 22,169 22,509 
Expected return on plan assets(178,793)(188,651)(182,938)(48,569)(46,834)(43,486)
Amortization of:
Prior service credit (a)— — — (1,265)(37,789)(37,789)
Net actuarial loss (gain)
46,731 41,915 38,420 (11,727)(8,676)(9,614)
Net periodic benefit costs (credits)
$67,212 $45,548 $48,504 $(33,135)$(61,175)$(59,813)
Portion of costs (credits) charged to expense
$38,977 $23,652 $27,029 $(25,736)$(45,557)$(43,408)
(a)    Prior-service costs or credits reflect the impact of modifications to the pension or postretirement plan benefits. The impact of these modifications is amortized over a period which reflects the demographics of the impacted population. In 2014, Pinnacle West made changes to the postretirement benefits offered to Medicare eligible retirees which resulted in prior-service credits. We have been amortizing these prior-serviced credits since 2015, and they became fully amortized as of January 31, 2025.
The following table shows the plans’ changes in the benefit obligations and funded status (dollars in thousands):
 Pension PlansOther Benefits Plans
 2025202420252024
Change in Benefit Obligation    
Benefit obligation at January 1$2,792,309 $2,908,063 $360,090 $430,434 
Service cost44,153 43,641 8,081 9,955 
Interest cost155,121 148,643 20,345 22,169 
Benefit payments(226,888)(216,238)(28,293)(30,516)
Actuarial (gain) loss79,363 (91,800)7,759 (71,952)
Other plan changes6,752 — — — 
Benefit obligation at December 312,850,810 2,792,309 367,982 360,090 
Change in Plan Assets    
Fair value of plan assets at January 12,639,862 2,835,549 702,192 696,494 
Actual return on plan assets244,343 4,518 65,124 32,816 
Benefit payments(213,684)(200,205)— (27,118)
Fair value of plan assets at December 312,670,521 2,639,862 767,316 702,192 
Funded (Underfunded) Status at December 31$(180,289)$(152,447)$399,334 $342,102 

The following table shows information for pension plans with an accumulated obligation in excess of plan assets (dollars in thousands):
As of December 31,
 20252024
Accumulated benefit obligation$113,245 $113,541 
Fair value of plan assets— — 
 
The Pinnacle West Capital Corporation Retirement Plan is more than 100% funded on an accumulated benefit obligation basis at December 31, 2025, and December 31, 2024, therefore, the only pension plan with an accumulated benefit obligation in excess of plan assets in 2025 and 2024 is the non-qualified supplemental excess benefit retirement plan.

The following table shows information for pension plans with a projected benefit obligation in excess of plan assets (dollars in thousands):
As of December 31,
 20252024
Projected benefit obligation$2,850,810 $2,792,309 
Fair value of plan assets2,670,521 2,639,862 

The Pinnacle West Capital Corporation Retirement Plan, on a projected benefit obligation basis, was 98% funded at December 31, 2025, and 99% funded at December 31, 2024. In the table above, we included both the projected benefit obligation and the fair value of plan assets for our qualified pension plan and our non-qualified supplemental excess benefit retirement plan.
The following table shows the amounts recognized on the Consolidated Balance Sheets (dollars in thousands):
 Pension PlansOther Benefits Plans
 2025202420252024
Noncurrent asset$— $— $399,334 $342,102 
Current liability(12,653)(13,130)— — 
Noncurrent liability(167,636)(139,317)— — 
Net amount recognized (funded status)$(180,289)$(152,447)$399,334 $342,102 
 
The following table shows the details related to accumulated other comprehensive loss (gain) as of December 31, 2025, and 2024 (dollars in thousands): 
 Pension PlansOther Benefits Plans
 2025202420252024
Net actuarial loss (gain)$760,502 $793,421 $(234,958)$(237,889)
Prior service cost (credit)6,752 — — (1,265)
APS’s portion recorded as a regulatory (asset) liability(723,042)(750,976)233,952 238,113 
Income tax expense (benefit)(10,929)(10,354)703 611 
Accumulated other comprehensive loss (gain)$33,283 $32,091 $(303)$(430)
 
The following table shows the weighted-average assumptions used for both the pension and other benefits to determine benefit obligations and net periodic benefit costs:
 Benefit Obligations
As of December 31,		Benefit Costs
Year Ended December 31,
 20252024202520242023
Discount rate – pension plans5.36 %5.68 %5.68 %5.21 %5.56 %
Discount rate – other benefits plans5.43 %5.71 %5.71 %5.23 %5.58 %
Rate of compensation increase4.50 %4.50 %4.50 %4.52 %4.57 %
Expected long-term return on plan assets - pension plansN/AN/A7.05 %6.90 %6.70 %
Expected long-term return on plan assets - other benefit plansN/AN/A7.05 %6.85 %6.80 %
Initial healthcare cost trend rate (pre-65 participants)6.50 %6.50 %6.50 %6.25 %6.50 %
Ultimate healthcare cost trend rate (pre-65 participants)4.50 %4.50 %4.50 %4.75 %4.75 %
Number of years to ultimate trend rate (pre-65 participants)76645
Initial healthcare cost trend rate (post-65 participants) (a)N/A1.00 %1.00 %2.00 %2.00 %
Ultimate healthcare cost trend rate (post-65 participants) (a)N/A— %N/A2.00 %2.00 %
Interest crediting rate – cash balance pension plans4.51 %4.66 %4.66 %4.54 %4.50 %
(a) The Company has decided and has communicated to retirees that the increase in 2026 will be 1% with no further indexation in future years. Therefore, no assumption is being made for the Post-65 HRA subsidy trend rate.

In selecting the pretax expected long-term rate of return on plan assets, we consider past performance and economic forecasts for the types of investments held by the plan.  For 2026, we are assuming a 6.90% long-term rate of return for pension assets and 7.00% (before tax) for other benefit assets, which we believe is reasonable given our asset allocation in relation to historical and expected performance.
In selecting our healthcare trend rates, we consider past performance and forecasts of healthcare costs. 

Plan Assets
 
The Board of Directors has delegated oversight of the pension and other postretirement benefit plans’ assets to an Investment Management Committee (“Committee”).  The Committee has adopted investment policy statements (“IPS”) for the pension and the other postretirement benefit plans’ assets. The investment strategies for these plans include external management of plan assets.
 
The overall strategy of the pension plan’s IPS is to achieve an adequate level of trust assets relative to the benefit obligations.  To achieve this objective, the plan’s investment policy provides for mixes of investments including long-term fixed income assets and return-seeking assets.  The target allocation between return-seeking and long-term fixed income assets is defined in the IPS.  The plan’s funded status is reviewed on at least a monthly basis.
 
Changes in the value of long-term fixed income assets, also known as liability-hedging assets, are intended to offset changes in the benefit obligations due to changes in interest rates.  Long-term fixed income assets consist primarily of fixed income debt securities issued by the U.S. Treasury and other government agencies, U.S. Treasury futures contracts, and fixed income debt securities issued by corporations.  Long-term fixed income assets may also include interest rate swaps, and other instruments.
 
Return-seeking assets are intended to provide a reasonable long-term rate of investment return with a prudent level of volatility.  Return-seeking assets are composed of U.S. equities, international equities, and alternative investments.  International equities include investments in both developed and emerging markets.  Alternative investments may include investments in real estate, private debt and various other strategies.  The plan may also hold investments in return-seeking assets by holding securities in partnerships, common and collective trusts, and mutual funds.

Based on the IPS, the target and actual allocation for the pension plan at December 31, 2025, are as follows:
 Target AllocationActual Allocation
Long-term fixed income assets80 %78 %
Return-seeking assets20 %22 %
Total100 %100 %

The permissible range is within +/-5% of the target allocation shown in the above table, and also considers the plan’s funded status.

The following table presents the additional target allocations, as a percent of total pension plan assets, for the return-seeking assets:
Target Allocation
Equities in US and other developed markets12 %
Equities in emerging markets4 %
Alternative investments4 %
Total20 %
The pension plan IPS does not provide for a specific mix of long-term fixed income assets but does expect the average credit quality of such assets to be investment grade. 

As of December 31, 2025, the asset allocation for other postretirement benefit plan assets is governed by the IPS for those plans, which provides for different asset allocation target mixes depending on the characteristics of the liability. The following table presents the actual allocations of the investment for the other postretirement benefit plan at December 31, 2025:
Actual Allocation
Long-term fixed income assets59 %
Return-seeking assets41 %
Total100 %
See Note 17 for a discussion on the fair value hierarchy and how fair value methodologies are applied.  The plans invest directly in fixed income, U.S. Treasury futures contracts, and equity securities, in addition to investing indirectly in fixed income securities, equity securities and real estate through the use of mutual funds, partnerships and common and collective trusts.  Equity securities held directly by the plans are valued using quoted active market prices from the published exchange on which the equity security trades and are classified as Level 1.  U.S. Treasury futures contracts are valued using the quoted active market prices from the exchange on which they trade and are classified as Level 1. Fixed income securities issued by the U.S. Treasury held directly by the plans are valued using quoted active market prices and are classified as Level 1.  Fixed income securities issued by corporations, municipalities, and other agencies are primarily valued using quoted inactive market prices, or quoted active market prices for similar securities, or by utilizing calculations which incorporate observable inputs such as yield, maturity, and credit quality.  These instruments are classified as Level 2.
 
Mutual funds, partnerships, and common and collective trusts are valued utilizing a net asset value (“NAV”) concept or its equivalent. Mutual funds, which includes exchange traded funds (“ETFs”), are classified as Level 1, and valued using a NAV that is observable and based on the active market in which the fund trades.

Common and collective trusts are maintained by banks or investment companies and hold certain investments in accordance with a stated set of objectives (such as tracking the performance of the S&P 500 Index).  The trust’s shares are offered to a limited group of investors and are not traded in an active market. Investments in common and collective trusts are valued using NAV as a practical expedient and, accordingly, are not classified in the fair value hierarchy. The NAV for trusts investing in exchange traded equities, and fixed income securities is derived from the market prices of the underlying securities held by the trusts. The NAV for trusts investing in real estate is derived from the appraised values of the trust’s underlying real estate assets. 

Investments in partnerships are also valued using the concept of NAV as a practical expedient and, accordingly, are not classified in the fair value hierarchy. The NAV for these investments is derived from the value of the partnerships’ underlying assets. The plan’s partnerships holdings relate to investments in high-yield fixed income instruments. Certain partnerships also include funding commitments that may require the plan to contribute up to $50 million to these partnerships; as of December 31, 2025, approximately $38 million of these commitments have been funded.
 
The plans’ trustee provides valuation of our plan assets by using pricing services that utilize methodologies described to determine fair market value.  We have internal control procedures to ensure this information is consistent with fair value accounting guidance.  These procedures include assessing valuations using an independent pricing source, verifying that pricing can be supported by actual recent market transactions, assessing hierarchy classifications, comparing investment returns with benchmarks, and obtaining and reviewing independent audit reports on the trustee’s internal operating controls and valuation processes.

The fair value of Pinnacle West’s pension plan and other postretirement benefit plan assets at December 31, 2025, by asset category, are as follows (dollars in thousands):
 
 Level 1Level 2Other (a)Total
Pension Plan:   
Cash and cash equivalents$1,756 $— $— $1,756 
Fixed income securities:   
Corporate— 1,300,163 — 1,300,163 
U.S. Treasury607,621 — — 607,621 
Other (b)— 120,483 — 120,483 
Common stock equities (c)73,548 — — 73,548 
Mutual funds (d)115,478 — — 115,478 
Common and collective trusts:
Equities— — 266,624 266,624 
Real estate— — 114,782 114,782 
Other (e)— — 70,066 70,066 
Total$798,403 $1,420,646 $451,472 $2,670,521 
Other Benefits:    
Cash and cash equivalents$475 $— $— $475 
Fixed income securities:   
Corporate— 200,469 — 200,469 
U.S. Treasury165,294 — — 165,294 
Other (b)— 10,997 — 10,997 
Common stock equities (c)98,296 — — 98,296 
Mutual funds (d)27,986 — — 27,986 
Common and collective trusts:   
Equities— — 167,103 167,103 
Real estate— — 20,228 20,228 
Other (e)69,954 — 6,514 76,468 
Total$362,005 $211,466 $193,845 $767,316 
(a)These investments primarily represent assets valued using NAV as a practical expedient and have not been classified in the fair value hierarchy.
(b)This category consists primarily of debt securities issued by municipalities and asset backed securities.
(c)This category primarily consists of U.S. common stock equities.
(d)These funds invest in international common stock equities.
(e)Primarily relates to short-term investment funds and includes plan receivables and payables.

 
The fair value of Pinnacle West’s pension plan and other postretirement benefit plan assets at December 31, 2024, by asset category, are as follows (dollars in thousands):
 Level 1Level 2Other (a)Total
Pension Plan:   
Cash and cash equivalents$9,055 $— $— $9,055 
Fixed income securities:   
Corporate— 1,325,833 — 1,325,833 
U.S. Treasury561,317 — — 561,317 
Other (b)— 133,254 — 133,254 
Common stock equities (c)74,939 — — 74,939 
Mutual funds (d)102,722 — — 102,722 
Common and collective trusts:
   Equities— — 244,734 244,734 
   Real estate— — 127,397 127,397 
Other (e)— — 60,611 60,611 
Total $748,033 $1,459,087 $432,742 $2,639,862 
Other Benefits:    
Cash and cash equivalents$840 $— $— $840 
Fixed income securities:   
Corporate— 186,435 — 186,435 
U.S. Treasury204,274 — — 204,274 
Other (b)— 12,585 — 12,585 
Common stock equities (c)89,685 — — 89,685 
Mutual funds (d)23,415 — — 23,415 
Common and collective trusts:
   Equities— — 140,178 140,178 
   Real estate— — 19,474 19,474 
Other (e)19,145 — 6,161 25,306 
Total $337,359 $199,020 $165,813 $702,192 
(a)These investments primarily represent assets valued using NAV as a practical expedient and have not been classified in the fair value hierarchy.
(b)This category consists primarily of debt securities issued by municipalities and asset backed securities.
(c)This category primarily consists of U.S. common stock equities.
(d)These funds invest in U.S. and international common stock equities.
(e)Primarily relates to short-term investment funds and includes plan receivables and payables.
Contributions
 
Future year contribution amounts are dependent on plan asset performance and plan actuarial assumptions.  In 2025 and 2024, we did not make any contributions to our pension plan. 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.  With regard to contributions to our other postretirement benefit plan, we did not make a contribution in 2025 or 2024 and do not expect to make any contributions in 2026, 2027 or 2028. For retiree medical claims from the other postretirement benefit plan trust assets, there was
not a reimbursement received in 2025. The Company was reimbursed $27 million in 2024, and $23 million in 2023 for prior years retiree medical claims from the other postretirement benefit plan trust assets.
Estimated Future Benefit Payments
 
Benefit payments, which reflect estimated future employee service, for the next five years and the succeeding five years thereafter, are estimated to be as follows (dollars in thousands):
YearPension PlansOther Benefits Plans
2026$244,947 $28,075 
2027232,977 27,751 
2028235,256 27,443 
2029235,980 27,357 
2030235,953 27,206 
Years 2031-20351,149,488 137,689 
 
Electric plant participants contribute to the above amounts in accordance with their respective participation agreements.

Employee Savings Plan Benefits
 
Pinnacle West sponsors a defined contribution savings plan for eligible employees of Pinnacle West and its subsidiaries.  In 2025, costs related to APS’s employees represented 99% of the total cost of this plan.  In a defined contribution savings plan, the benefits a participant receives result from regular contributions participants make to their own individual account, the Company’s matching contributions and earnings or losses on their investments.  Under this plan, the Company matches a percentage of the participants’ contributions in cash which is then invested in the same investment mix as participants elect to invest their own future contributions.  Pinnacle West recorded expenses for this plan of approximately $14 million for 2025, $14 million for 2024, and $12 million for 2023.
v3.25.4
Stock-Based Compensation
 12 Months Ended
Dec. 31, 2025
Share-Based Payment Arrangement [Abstract]  
Stock-Based Compensation Stock-Based Compensation
 
Pinnacle West has incentive compensation plans under which stock-based compensation is granted to officers, key employees, and non-officer members of the Board of Directors. Awards granted under the 2021 Long-Term Incentive Plan, as amended (“2021 Plan”), may be in the form of stock grants, restricted stock units, stock units, performance shares, restricted stock, dividend equivalents, performance share units, performance cash, incentive and non-qualified stock options, and stock appreciation rights.  The 2021 Plan authorizes up to 4.3 million common shares to be available for grant.  As of December 31, 2025, 2.5 million common shares were available for issuance under the 2021 Plan. During 2025, 2024 and 2023, the Company granted awards in the form of restricted stock units, stock units, stock grants, and performance shares. Awards granted from 2012 to May 2021 were issued under the 2012 Long-Term Incentive Plan (“2012 Plan”), and awards granted from 2007 to 2011 were issued under the 2007 Long-Term Incentive Plan (“2007 Plan”). No new awards may be granted under the 2012 or 2007 Plans.
Stock-Based Compensation Expense and Activity
 
Compensation cost included in net income for stock-based compensation plans was $27 million in 2025, $24 million in 2024, and $17 million in 2023.  The compensation cost capitalized is immaterial for all years. Income tax benefits related to stock-based compensation arrangements were $12 million in 2025, $6 million in 2024, and $3 million in 2023.

As of December 31, 2025, there were approximately $42 million of unrecognized compensation costs related to nonvested stock-based compensation arrangements. We expect to recognize these costs over a weighted-average period of 2 years. 

The total fair value of shares vested was $27 million in 2025, $24 million in 2024, and $24 million in 2023.
 
The following table is a summary of awards granted and the weighted-average grant date fair value for each of the last 3 years:
Restricted Stock Units, Stock Grants, and Stock Units (a)Performance Shares (b)
 202520242023202520242023
Units granted204,886 261,808 192,295 164,220 225,516 202,562 
Weighted-average grant date fair value$90.25 $71.10 $74.32 $97.72 $72.89 $79.61 
(a)The units granted do not include awards that will be cash settled in 2025, 2024 or 2023. See below for additional information on restricted stock unit grants.
(b)Reflects the target payout level.
 
The following table shows the change of nonvested awards:

Restricted Stock Units, Stock Grants, and Stock UnitsPerformance Shares
SharesWeighted-Average
Grant Date
Fair Value		Shares (b)Weighted-Average
Grant Date
Fair Value
Nonvested at December 31, 2024
460,791 $71.72 390,551 $77.29 
Granted204,886 90.25 164,220 97.72 
Vested(186,883)73.77 (169,682)77.94 
Forfeited (c)(15,856)79.59 (13,535)85.01 
Nonvested at December 31, 2025
462,938 (a)78.82 371,554 83.48 
Vested Awards Outstanding at December 31, 2025
76,758 169,682 
(a)Includes no awards that will be cash settled.
(b)The performance shares are reflected at target payout level. 
(c)We account for forfeitures as they occur.
Share-based liabilities paid relating to restricted stock units were $14 million, $8 million, and $6 million in 2025, 2024 and 2023, respectively. This includes cash used to settle restricted stock units of $1 million, $2 million, and $3 million in 2025, 2024 and 2023, respectively. Restricted stock units that are cash settled are classified as liability awards. All performance shares are classified as equity awards.
 
Restricted Stock Units, Stock Grants, and Stock Units
 
Restricted stock units are granted to officers and key employees and typically vest and settle in equal annual installments over a 4-year period after the grant date.  Vesting is typically dependent upon continuous service during the vesting period.

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

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

Compensation cost for restricted stock unit awards is based on the fair value of the award, with the fair value being the market price of our stock on the measurement date. Restricted stock unit awards that will be settled in cash are accounted for as liability awards, with compensation cost initially calculated on the date of grant using the Company’s closing stock price and remeasured at each balance sheet date. Restricted stock unit awards that will be settled in shares are accounted for as equity awards, with compensation cost calculated using the Company’s closing stock price on the date of grant. Compensation cost is recognized over the requisite service period based on the fair value of the award.
 
Stock grants are issued to non-officer members of the Board of Directors. They may elect to receive the stock grant, or to defer receipt until a later date and receive stock units in lieu of the stock grant. Beginning in 2023, payments for stock units are issued in stock and include a dividend equivalent feature that allows each award to accrue dividends and treat them as reinvested, from the date of grant until the applicable vesting date. Prior to 2023, members of the Board of Directors who elected to defer could elect to receive payment in either 100% stock, 100% cash, or 50% in cash and 50% in stock.  The stock units prior to 2023 included a dividend equivalent feature that accrues dividend rights from the date of grant to the date of payment, plus interest compounded quarterly.
 
Performance Share Awards
 
Performance share awards are granted to officers and key employees.  The awards contain separate performance metric criteria that affect the number of shares that may be received if, after the end of a 3-year performance period, the performance criteria are met.

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

Prior to 2022, performance share awards had two performance criteria. The first performance criteria was based upon non-financial performance metrics (i.e., the Metric component). The second performance criteria was based upon Pinnacle West’s TSR in relation to the TSR of other companies in a specified utility index (i.e., the TSR component). The exact number of shares issued will vary from 0% to 200% of the target award. Shares received included a dividend equivalent feature that allows accrued dividend rights from the date of grant until the date of payment, plus interest compounded quarterly, equal to the number of vested performance shares. If the award was forfeited, the employee was not entitled to the accrued dividends on those shares. Awards granted to retirement-eligible employees typically vested upon the employee’s retirement.
 
Performance share awards are accounted for as equity awards, with compensation cost based on the fair value of the award on the grant date. Compensation cost relating to the EPS and Clean metric component of the respective awards is based on the Company’s closing stock price on the date of grant, with compensation cost recognized over the requisite service period based on the number of shares expected to vest. Management evaluates the probability of meeting the EPS and Clean metric component at each balance sheet date. If the EPS and Clean metric component criteria are not ultimately achieved, no compensation cost is recognized relating to the EPS and Clean metric component, and any previously recognized compensation cost is reversed. Compensation cost relating to the TSR component of the respective awards is determined using a Monte Carlo simulation valuation model, with compensation cost recognized ratably over the requisite service period, regardless of the number of shares that actually vest.
v3.25.4
Jointly-Owned Facilities
 12 Months Ended
Dec. 31, 2025
Jointly Owned Utility Plant, Net Ownership Amount [Abstract]  
Jointly-Owned Facilities Jointly-Owned Facilities
 
APS shares ownership of some of its generating and transmission facilities with other companies.  We are responsible for our share of operating costs which are included in the corresponding operating expenses on our Consolidated Statements of Income. We are also responsible for providing our own financing.  Our share of operating expenses and utility plant costs related to these facilities is accounted for using proportional consolidation.  The following table shows APS’s interests in those jointly-owned facilities recorded on the Consolidated Balance Sheets at December 31, 2025 (dollars in thousands):
 Percent
Owned		 Plant in
Service		Accumulated
Depreciation		Construction
Work in
Progress
Generating facilities:     
Palo Verde Units 1 and 329.1 %$2,094,060 $1,079,823 $13,230 
Palo Verde Unit 2 (a)23.9 %925,562 567,731 7,343 
Palo Verde Common26.2 %(b)977,526 431,023 58,899 
Palo Verde sale leaseback (a) 142,921 110,886 — 
Four Corners Generating Station 63.0 %1,941,053 747,931 19,378 
Transmission facilities:     
Arizona Nuclear Power Project 500kV System33.1 %(b)141,348 60,579 5,350 
Navajo Southern System25.1 %(b)89,856 40,548 1,645 
Palo Verde — Yuma 500kV System16.1 %(b)44,505 9,060 136 
Four Corners Switchyards56.9 %(b)86,706 25,810 118 
Phoenix — Mead System17.5 %(b)36,290 19,568 609 
Palo Verde — Rudd 500kV System50.0 %96,428 35,842 3,343 
Morgan — Pinnacle Peak System63.2 %(b)119,104 31,283 75 
Round Valley System50.0 %548 224 — 
Palo Verde — Morgan System87.5 %(b)268,202 52,822 392 
Hassayampa — North Gila System80.0 %154,329 31,361 — 
Cholla 500kV Switchyard85.7 %8,456 3,114 190 
Saguaro 500kV Switchyard60.0 %42,795 16,324 800 
Kyrene — Knox System50.0 %578 359 — 
(a)See Note 12 for information related to the Palo Verde sale leaseback purchases.
(b)Weighted-average of interests.
v3.25.4
Variable Interest Entities
 12 Months Ended
Dec. 31, 2025
Variable Interest Entities [Abstract]  
Variable Interest Entities Variable Interest Entities
Pinnacle West

Captive Insurance Cell VIE

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

Under a mutual business program participation agreement between the Captive and EISI, EISI will issue policies, make claim disbursements, claim expenses and other underwriting fees on behalf of the Captive, as necessary.

The Captive insures Pinnacle West and its subsidiaries for terrorism coverage, excess liability including certain wildfire coverage, excess property insurance, and excess employment practice liability. The Captive policies exclude nuclear liability at Palo Verde. See Note 14 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 Consolidated Balance Sheets, and the Captive’s investment gains and losses reflected through earnings on Pinnacle West’s Consolidated Statements of Income.
Consolidation of the Captive resulted in an increase in Pinnacle West net income of the year ended December 31, 2025, 2024, and 2023 of $5 million, $5 million, and zero, respectively. These amounts are fully attributable to Pinnacle West shareholders. Consolidation impacts Pinnacle West Consolidated Income Statement’s operations and maintenance expense, other income and other expense line items.

Pinnacle West’s Consolidated Balance Sheets as of December 31, 2025 and 2024 include $40 million and $34 million of assets relating to the Captive that is reported within the other special use funds line item. See Notes 17 and 18 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. As further described below, 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. As of December 31, 2025, one VIE lease arrangement remains in effect.
In June 2025, APS executed purchase agreements relating to two of the three VIE lease arrangements and subsequently submitted filings with FERC requesting authorization of the acquisitions. On September 10, 2025, FERC issued an order authorizing the APS acquisition of these leased interests. On September 22, 2025, all closing conditions were satisfied and APS acquired the two leased Palo Verde interests from the VIE noncontrolling interest lessor owners for a combined total of approximately $199 million. The two related lease agreements were terminated, and APS no longer has payment obligations to these two VIE noncontrolling interest lessors. As a result of the acquisition and lease terminations, effective September 22, 2025, APS no longer holds a variable interest in these lessor trust entities and therefore no longer consolidates these two lessor VIEs. In accordance with GAAP, the purchase is accounted for as the acquisition of the VIE’s noncontrolling interests. As a result of the purchases, APS’s Consolidated Balance Sheet as of September 30, 2025, included $47 million of property, plant and equipment, net of accumulated depreciation, that was reclassified from the Palo Verde sale leaseback asset line item. The remaining $152 million of the $199 million purchase price represents the incremental market value above the VIE’s net book value included in the consideration to acquire the noncontrolling interest. The $152 million was recorded as a new regulatory asset on the APS Consolidated Balance Sheet as of September 30, 2025.

As a result of these September 2025 purchases, APS’ Consolidated Balance Sheets as of December 31, 2025, includes $47 million of property, plant, and equipment, net of accumulated depreciation; and a $152 million regulatory asset. In the 2025 Rate Case, APS has requested to recover the acquisition of the leased interests in future customer rates as an investment in plant assets, seeking a full cost of capital return on the $199 million investment. See Note 8. APS did not recognize a gain or loss as a result of deconsolidating these two VIE entities; accordingly, for the year ended December 31, 2025, the acquisition of the VIE leased interests had no impact on the APS Consolidated Statements of Income.

As of December 31, 2025, APS 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 as of December 31, 2025, is approximately 5.2%. The VIE lease agreement that was not subject to the purchase agreements remains in effect and is not impacted by the purchase transactions.

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 of the VIEs, we eliminate lease accounting and instead recognize depreciation expense, resulting in an increase in net income of $15 million in 2025 and $17 million for each of 2024 and 2023. The increase in net income is entirely attributable to the noncontrolling interests.  Income attributable to Pinnacle West shareholders is not impacted by the consolidation.
Our Consolidated Balance Sheets include the following amounts relating to these VIEs (dollars in thousands):
 December 31, 2025
December 31, 2024 (a)
Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation$32,035 $82,556 
Equity — Noncontrolling interests40,617 103,167 
(a)    Includes the two VIEs subject to the September 2025 purchase transactions described above.
 
Assets of the VIE are restricted and may only be used for payment to the noncontrolling interest holders.  These assets are reported on our Consolidated Financial Statements.
 
APS is exposed to losses relating to the VIE upon the occurrence of certain events that APS does not consider to be reasonably likely to occur.  Under certain circumstances (for example, the NRC issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), APS would be required to make specified payments to the 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.
v3.25.4
Derivative Accounting
 12 Months Ended
Dec. 31, 2025
Derivative Instruments and Hedging Activities Disclosure [Abstract]  
Derivative Accounting Derivative Accounting
 
Derivative financial instruments are used to manage exposure to commodity price and transportation costs of electricity, natural gas, emissions allowances, and interest rates.  Risks associated with market volatility are managed by utilizing various physical and financial derivative instruments, including futures, forwards, options, and swaps.  As part of our overall risk management program, we may use derivative instruments to hedge purchases and sales of electricity and natural gas.  Derivative instruments that meet certain hedge accounting criteria may be designated as cash flow hedges and are used to limit our exposure to cash flow variability on forecasted transactions.  The changes in market value of such instruments have a high correlation to price changes in the hedged transactions.  Derivative instruments are also entered into for economic hedging purposes.  While economic hedges may mitigate exposure to fluctuations in commodity prices, these instruments have not been designated as accounting hedges.  Contracts that have the same terms (quantities, delivery points and delivery periods) and for which power does not flow are netted, which reduces both revenues and fuel and purchased power costs in our 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 Consolidated Balance Sheets as an asset or liability and are measured at fair value.  See Note 17 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 16 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 8.  Gains and losses from energy derivatives in the following tables represent the amounts reflected in income before the effect of PSA deferrals.

The following table shows the outstanding gross notional volume of energy derivatives, which represent both purchases and sales (does not reflect net position):
Quantity
CommodityUnit of MeasureDecember 31, 2025December 31, 2024
PowerGigawatt-hour542 1,051 
GasBillion cubic feet211 235 
 
Gains and Losses from Energy Derivative Instruments
For the years ended December 31, 2025, 2024 and 2023, APS had no energy derivative instruments in designated accounting hedging relationships.
The following table provides information about gains and losses from energy derivative instruments not designated as accounting hedging instruments (dollars in thousands):
Financial Statement Year Ended December 31,
Commodity ContractsLocation202520242023
Net Loss Recognized in Income
Fuel and purchased power (a)$(50,566)$(88,522)$(370,145)
(a)Amounts are before the effect of PSA deferrals.

Energy Derivative Instruments in the Consolidated Balance Sheets

Our energy derivative transactions are typically executed under standardized or customized agreements, which include collateral requirements and, in the event of a default, would allow for the netting of positive and negative exposures associated with a single counterparty.  Agreements that allow for the offsetting of positive and negative exposures associated with a single counterparty are considered master netting arrangements.  Transactions with counterparties that have master netting arrangements are offset and reported net on the Consolidated Balance Sheets.  Transactions that do not allow for offsetting of positive and negative positions are reported gross on the Consolidated Balance Sheets.
We do not offset a counterparty’s current energy derivative contracts with the counterparty’s non-current energy derivative contracts, although our master netting arrangements would allow current and non-current positions to be offset in the event of a default.  These types of transactions may include non-derivative instruments, derivatives qualifying for scope exceptions, trade receivables and trade payables arising from settled positions, and other forms of non-cash collateral (such as letters of credit).  These types of transactions are excluded from the offsetting tables presented below.

The following tables provide information about the fair value of APS’s risk management activities reported on a gross basis and the impacts of offsetting.  These amounts relate to commodity contracts and are located in the assets and liabilities from risk management activities lines of APS’s Consolidated Balance Sheets (dollars in thousands):
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.
As of December 31, 2024Gross
 Recognized
 Derivatives
 (a)		Amounts
Offset 
(b)		Net
 Recognized
 Derivatives		Other
 (c)		Amounts
 Reported on
 Balance Sheets
Current assets$13,718 $(3,158)$10,560 $18 $10,578 
Investments and other assets6,610 (630)5,980 — 5,980 
Total assets20,328 (3,788)16,540 18 16,558 
Current liabilities(52,527)3,158 (49,369)(2,971)(52,340)
Deferred credits and other(10,076)630 (9,446)— (9,446)
Total liabilities(62,603)3,788 (58,815)(2,971)(61,786)
Total$(42,275)$— $(42,275)$(2,953)$(45,228)
(a)All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)No cash collateral has been provided to 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 $2,971 thousand and cash margin provided to counterparties of $18 thousand.

Credit Risk and Credit Related Contingent Features
 
We are exposed to losses in the event of nonperformance or nonpayment by energy derivative counterparties and have risk management contracts with many energy derivative counterparties. As of December 31, 2025, we have four counterparties for which our exposure represents approximately 73% of Pinnacle West’s $8.4 million of net risk management assets. This exposure relates to ISDA master agreements with the respective counterparties. The ISDA counterparties have an investment grade credit rating by either Standard & Poor’s and/or Moody’s. Our risk management process assesses and monitors the financial exposure of all counterparties.  Despite the fact that the great majority of our trading counterparties’ debt is rated as investment grade by the credit rating agencies, there is still a possibility that one or more of these counterparties could default, resulting in a material impact on consolidated results of operations for a given period. Counterparties in the portfolio consist principally of financial institutions, major energy companies, municipalities and local distribution companies.  We maintain credit policies that we believe minimize overall credit risk within acceptable limits.  Determination of the credit quality of our counterparties is based upon a number of factors, including credit ratings and our evaluation of their financial condition.  To manage credit risk, we employ collateral requirements and standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty.  Valuation adjustments are established representing our estimated credit losses on our overall exposure to counterparties.
 
Certain of our energy derivative instrument contracts contain credit-risk-related contingent features including, among other things, investment grade credit rating provisions, credit-related cross-default provisions, and adequate assurance provisions.  Adequate assurance provisions allow a counterparty with reasonable grounds for uncertainty to demand additional collateral based on subjective events and/or conditions.  For those energy derivative instruments in a net liability position, with investment grade credit contingencies, the counterparties could demand additional collateral if our debt credit rating were to fall below investment grade (below BBB- for Standard & Poor’s or Fitch or Baa3 for Moody’s).
 
The following table provides information about our energy derivative instruments that have credit-risk-related contingent features (dollars in thousands):
 December 31, 2025
Aggregate fair value of derivative instruments in a net liability position$45,035 
Additional collateral in the event credit-risk related contingent features were fully triggered (a)11,171 
(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 December 31, 2025, 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.
v3.25.4
Commitments and Contingencies
 12 Months Ended
Dec. 31, 2025
Commitments and Contingencies Disclosure [Abstract]  
Commitments and Contingencies Commitments and Contingencies
 
Palo Verde Generating Station
 
Spent Nuclear Fuel and Waste Disposal
 
On December 19, 2012, APS, acting on behalf of itself and the participant owners of Palo Verde, filed a second breach of contract lawsuit against the DOE in the United States Court of Federal Claims (“Court of Federal Claims”). The lawsuit sought to recover damages incurred due to DOE’s breach of the Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste (“Standard Contract”) for failing to accept Palo Verde’s spent nuclear fuel and high level waste from January 1, 2007, through June 30, 2011, pursuant to the terms of the Standard Contract and the Nuclear Waste Policy Act. On August 18, 2014, APS and DOE entered into a settlement agreement, which required DOE to pay the Palo Verde owners for certain specified costs 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 evaluating a proposed extension to 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 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 $24.2 million for each retrospective premium assessment declared by NEIL’s Board of Directors due to losses.  Additionally, at the sole discretion of the NEIL Board of Directors, APS would be liable to provide approximately $66.4 million in deposit premium within 20 days of request as assurance to satisfy any site obligation of retrospective premium assessment.  The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions, sublimits, and exclusions.

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 12 for additional details.
Fuel and Purchased Power Commitments and Purchase Obligations

APS is party to various fuel and purchased power contracts and purchase obligations with terms expiring between 2026 and 2054 that include required purchase provisions.  As of December 31, 2025, APS estimates the contract requirements to be approximately $1,811 million in 2026; $1,988 million in 2027; $2,149 million in 2028; $2,146 million in 2029; $2,392 million in 2030; and $32.2 billion thereafter.  Fuel and purchased power commitments include purchases of coal, electricity, natural gas, renewable energy, nuclear fuel, and natural gas transportation.  Purchase obligations may include commitments for capital expenditures and other obligations. However, these amounts may vary significantly pursuant to certain provisions in such contracts that permit us to decrease required purchases under certain circumstances. These amounts include estimated commitments relating to purchased power lease contracts. In January 2026, certain purchased power lease contracts were modified resulting in an additional $694 million of purchase obligations, primarily relating to periods after 2030. See Note 20.
 
Of the various fuel and purchased power contracts mentioned above, some of those contracts for coal supply include take-or-pay provisions.  The current coal contracts with take-or-pay provisions have terms expiring through 2031.
 
The following table summarizes our estimated coal take-or-pay commitments (dollars in thousands):
 
Year Ended December 31,
 20262027202820292030Thereafter (b)
Coal take-or-pay commitments (a)$206,489 $206,813 $213,825 $221,098 $228,639 $236,461 
(a)Total take-or-pay commitments are approximately $1.3 billion.  The total net present value of these commitments using a 4.81% discount rate is approximately $1.1 billion.
(b)Through 2031.
 
    APS may spend more to meet its actual fuel requirements than the minimum purchase obligations in our coal take-or-pay contracts. The following table summarizes actual amounts purchased under the coal contracts which include take-or-pay provisions for each of the last three years (dollars in thousands):
 
Year Ended December 31,
 202520242023
Total purchases$213,113 $237,821 $255,219 
 
Renewable Energy Credits
 
APS has entered into contracts to purchase renewable energy credits to comply with the RES.  APS estimates the contract requirements to be approximately $24 million in 2026; $21 million in 2027; $18 million in 2028; $16 million in 2029; $14 million in 2030; and $21 million thereafter.  These amounts do not include purchases of renewable energy credits that are bundled with energy.
Coal Mine Reclamation Obligations
APS must reimburse certain coal providers for final and contemporaneous coal mine reclamation.  We account for contemporaneous reclamation costs as part of the cost of the delivered coal.  We utilize site-specific studies of costs expected to be incurred in the future to estimate our final reclamation obligation.  These studies utilize various assumptions to estimate the future costs.  Based on the most recent reclamation studies, APS recorded an obligation for the coal mine final reclamation of approximately $160 million at December 31, 2025, and $171 million at December 31, 2024. Under our current coal supply agreements, APS expects to make payments for the final mine reclamation as follows: $21 million in 2026; $22 million in 2027; and $23 million in 2028. These funds are held in an escrow account and will be distributed to certain coal providers under the terms of the applicable coal supply agreements.  Any amendments to current coal supply agreements may change the timing of the contribution or cost of final reclamation. The annual payments to the escrow account and final distribution to certain coal providers may be subject to adjustments based on escrow earnings.
Superfund 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 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 APS’s Ocotillo power plant site located in Tempe, Arizona. In particular, EPA seeks information from APS regarding APS’s use, storage, and disposal of substances containing PFAS at the Ocotillo power plant site in order to aid EPA’s investigation into actual or threatened releases of PFAS into groundwater within the South Indian Bend Wash Superfund site. The South Indian Bend Wash Superfund site includes the
APS Ocotillo power plant site. APS filed its response to this information request on April 29, 2022. On January 17, 2023, EPA contacted APS to inform APS that it would be commencing on-site investigations within the South Indian Bend Wash site, including the Ocotillo power plant, and performing a remedial investigation and feasibility study related to potential PFAS impacts to groundwater over the next two to three years. APS estimates that its costs to oversee and participate in the remedial investigation work will be approximately $1.7 million. At the present time, we are unable to predict the outcome of this matter, and any further expenditures related to necessary remediation, if any, or further investigations cannot be reasonably estimated.

Environmental Matters

APS is subject to numerous environmental laws and regulations affecting many aspects of its present and future operations, including air emissions of both conventional pollutants and 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 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 encompass any location at an operating coal-fired power plant where CCRs would have been placed on land. As proposed, this would include not only historically closed landfills and surface impoundments but also prior applications of CCR beneficial use (with exceptions for historical roadbed and embankment applications). Existing CCR regulatory requirements for groundwater monitoring, corrective action, closure, post-closure care, and other requirements will be imposed on such CCRMUs. Under EPA’s legacy 2024 CCRMU rule, initial CCRMU site surveys 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. On February 9, 2026, EPA sent to the Office of Management and Budget for review a rule proposal that is anticipated to provide more substantive changes to certain aspects of the legacy 2024 CCRMU rule.

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. The Cholla Plant 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 Asset Retirement Obligations, 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. The D.C. Circuit granted EPA’s motion for an indefinite abeyance on April 25, 2025. 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 section 111(d) 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.

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 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 December 31, 2025, standby letters of credit totaled approximately $30.4 million and will expire through 2026, and surety bonds totaled approximately $23.3 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 December 31, 2025. In connection with the sale of Pinnacle West’s wholly-owned subsidiary, 4C Acquisition, LLC’s 7% interest in Units 4 and 5 of Four Corners to 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 December 31, 2025, there is approximately $26.3 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 Pinnacle West’s BCE subsidiary. BCE was sold to Ameresco in 2024 (the “BCE Sale”). See Note 22. 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.
v3.25.4
Other Income and Other Expense
 12 Months Ended
Dec. 31, 2025
Other Income and Expenses [Abstract]  
Other Income and Other Expense Other Income and Other Expense
 
The following table provides detail of Pinnacle West’s consolidated other income and other expense for the years ended 2025, 2024, and 2023 (dollars in thousands):
 202520242023
Other income:   
Interest income $18,037 $24,322 (a)$27,242 (a)
Investment gain — net (b)26,720 — — 
Gain on sale of BCE (Note 22)
— 22,988 6,205 
Miscellaneous4,649 1,304 219 
Total other income$49,406 $48,614 $33,666 
Other expense:
Non-operating costs$(21,332)$(27,370)(c)$(15,260)
Investment losses — net— (1,418)(3,402)
Miscellaneous(8,933)(5,348)(6,394)
Total other expense$(30,265)$(34,136)$(25,056)
(a)2023 and 2024 Interest income is primarily related to PSA interest. See Note 8.
(b)Investment gain is primarily related to El Dorado’s equity investment in SAI. See Note 23.
(c)The 2024 Non-operating cost is primarily related to corporate giving.
The following table provides detail of APS’s other income and other expense for the years ended 2025, 2024, and 2023 (dollars in thousands):
 202520242023
Other income:   
Interest income$15,933 $21,088 (a)$26,853 (a)
Miscellaneous281 6 219 
 Total other income$16,214 $21,094 $27,072 
Other expense:
Non-operating costs$(19,650)$(26,588)(b)$(14,070)
Miscellaneous(6,732)(3,110)(4,194)
Total other expense$(26,382)$(29,698)$(18,264)
(a)2023 and 2024 Interest income is primarily related to PSA interest. See Note 8.
(b)The 2024 Non-operating cost is primarily related to corporate giving.
v3.25.4
Common Stock Equity and Earnings Per Share
 12 Months Ended
Dec. 31, 2025
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 $700 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 December 31, 2025.

As of December 31, 2025, Pinnacle West had four outstanding forward sale agreements under its ATM Program (collectively, the “ATM Forward Sale Agreements”). These agreements relate to approximately $200 million 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. Pinnacle West also entered into a contract to begin a fifth ATM forward sale agreement in December 2025, transacting a total of $10.7 million with an effective date of January 5, 2026, and a maturity date of July 2, 2027.

The following table presents information about the outstanding ATM Forward Sale Agreements, including details of the outstanding forward sale agreements as of December 31, 2025:

ATM Forward Sale AgreementsMaturity DateNumber of SharesForward Sales Price Per Share (a)Aggregate Value
(in thousands)
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 
2,199,415 $90.10 (b)$198,176 
(a)    Subject to certain adjustments.
(b)    Weighted-average price for the total ATM Program.
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 Sales 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 December 31, 2025 (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 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 December 31, 2025, the conditions allowing holders to convert their Convertible Notes were not met, and as a result, the Convertible Notes were classified as long term debt on Pinnacle West’s Consolidated Balance Sheets with a carrying amount of $525 million, net of $4 million in unamortized debt issuance costs. The estimated fair value of the Convertible Notes as of December 31, 2025 was $561 million (Level 2 within the fair value hierarchy).

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

The following table presents the calculation of Pinnacle West’s basic and diluted EPS (dollars in thousands, except earnings per share amounts):
As of December 31,
 202520242023
Net income attributable to common shareholders
$616,531 $608,806 $501,557 
Weighted average common shares outstanding — basic119,687 113,846 113,442 
Net effect of dilutive securities:   
Contingently issuable performance shares and restricted stock units568 480 362 
Dilutive shares related to equity forward sale agreements (a)1,716 1,906 — 
Total contingently issuable shares2,284 2,386 362 
Weighted average common shares outstanding — diluted121,971 116,232 113,804 
Earnings per weighted-average common share outstanding
Net income attributable to common shareholders — basic
$5.15 $5.35 $4.42 
Net income attributable to common shareholders — diluted
$5.05 $5.24 $4.41 
(a)    For the years ended December 31, 2025, 2024 and 2023 the diluted weighted-average common shares excludes 148,098, 1,038,463 and 0 shares, respectively relating to the ATM Program and the Convertible Notes. These potentially issuable shares were excluded from the calculation of diluted shares as their inclusion would have been antidilutive.

Pinnacle West’s forward sale agreements are classified as equity transactions and are not recorded on the Pinnacle West 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.

On May 21, 2025, Pinnacle West shareholders approved an amendment to the Company’s Articles of Incorporation to increase the number of authorized shares of common stock from 150,000,000 to 300,000,000. This amendment was subsequently filed with the ACC on May 22, 2025.
v3.25.4
Fair Value Measurements
 12 Months Ended
Dec. 31, 2025
Fair Value Disclosures [Abstract]  
Fair Value Measurements Fair Value Measurements
 
We classify our assets and liabilities that are carried at fair value within the fair value hierarchy.  This hierarchy ranks the quality and reliability of the inputs used to determine fair values, which are then classified and disclosed in one of three categories.  The three levels of the fair value hierarchy are:
 
Level 1 — Inputs are unadjusted quoted prices in active markets for identical assets or liabilities at the measurement date.
Level 2 — Other significant observable inputs, including quoted prices in active markets for similar assets or liabilities; quoted prices in markets that are not active, and model-derived valuations whose inputs are observable (such as yield curves). 
 
Level 3 — Valuation models with significant unobservable inputs that are supported by little or no market activity.  Instruments in this category may include long-dated derivative transactions where valuations are unobservable due to the length of the transaction, options, and transactions in locations where observable market data does not exist.  The valuation models we employ utilize spot prices, forward prices, historical market data and other factors to forecast future prices.
 
Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  Thus, a valuation may be classified in Level 3 even though the valuation may include significant inputs that are readily observable.  We maximize the use of observable inputs and minimize the use of unobservable inputs.  We rely primarily on the market approach of using prices and other market information for identical and/or comparable assets and liabilities.  If market data is not readily available, inputs may reflect our own assumptions about the inputs market participants would use.  Our assessment of the inputs and the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities as well as their placement within the fair value hierarchy levels.  We assess whether a market is active by obtaining observable broker quotes, reviewing actual market activity, and assessing the volume of transactions.  We consider broker quotes observable inputs when the quote is binding on the broker, we can validate the quote with market activity, or we can determine that the inputs the broker used to arrive at the quoted price are observable.
Certain instruments have been valued using the concept of Net Asset Value (“NAV”) as a practical expedient. These instruments are typically structured as investment companies offering shares or units to multiple investors for the purpose of providing a return. These instruments are similar to mutual funds; however, their NAV is generally not published and publicly available, nor are these instruments traded on an exchange. Instruments valued using NAV as a practical expedient are included in our fair value disclosures; however, in accordance with GAAP are not classified within the fair value hierarchy levels.
Recurring Fair Value Measurements
 
We apply recurring fair value measurements to cash equivalents, derivative instruments, and investments held in the nuclear decommissioning trusts and other special use funds. On an annual basis, we apply fair value measurements to plan assets held in our retirement and other benefit plans. See Note 7 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 18 for additional discussion about our investment accounts.

We value investments in fixed income and equity securities using information provided by our trustees and escrow agent. Our trustees and escrow agent use pricing services that utilize the valuation methodologies described below to determine fair market value. We have internal control procedures designed to ensure this information is consistent with fair value accounting guidance. These procedures include assessing valuations using an independent pricing source, verifying that pricing can be supported by actual recent market transactions, assessing hierarchy classifications, comparing investment returns with benchmarks, and obtaining and reviewing independent audit reports on the trustees’ and escrow agent’s internal operating controls and valuation processes.

Fixed Income Securities

Fixed income securities issued by the U.S. Treasury are valued using quoted active market prices and are typically classified as Level 1.  Fixed income securities issued by corporations, municipalities, and other agencies, including mortgage-backed instruments, are valued using quoted inactive market prices, quoted active market prices for similar securities, or by utilizing calculations which incorporate observable inputs such as yield curves and spreads relative to such yield curves.  These fixed income instruments are classified as Level 2.  Whenever possible, multiple market quotes are obtained which enables a cross-check validation.  A primary price source is identified based on asset type, class, or issue of securities.
Fixed income securities may also include short-term investments in certificates of deposit, variable rate notes, time deposit accounts, U.S. Treasury and Agency obligations, U.S. Treasury repurchase agreements, commercial paper, and other short-term instruments. These instruments are valued using active market prices or utilizing observable inputs described above.

Equity Securities

The nuclear decommissioning trusts’ equity security investments are held indirectly through commingled funds.  The commingled funds are valued using the funds’ NAV as a practical expedient. The funds’ NAV is primarily derived from the quoted active market prices of the underlying equity securities held by the funds. We may transact in these commingled funds on a 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 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 13.
(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 12.
 The following table presents the fair value at December 31, 2024 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):
 
Level 1Level 2Level 3OtherTotal
ASSETS
Cash equivalents$23 $— $— $— $23 
Risk management activities — derivative instruments:
Commodity contracts— 13,152 7,176 (3,770)(a)16,558 
Nuclear decommissioning trusts:
Equity securities11,859 542 — 3,335 (b)15,736 
U.S. commingled equity funds— — — 423,069 (c)423,069 
U.S. Treasury debt367,396 — — — 367,396 
Corporate debt— 203,180 — — 203,180 
Mortgage-backed securities— 208,533 — — 208,533 
Municipal bonds— 37,429 — — 37,429 
Other fixed income— 27,502 — — 27,502 
Subtotal nuclear decommissioning trusts379,255 477,186 — 426,404 1,282,845 
Other special use funds:
Cash equivalents25,000 — — — (d)25,000 
Equity securities24,962 — — 2,851 (b) (d)27,813 
U.S. Treasury debt355,544 — — — 355,544 
Subtotal other special use funds (d)405,506 — — 2,851 408,357 
Total assets$784,784 $490,338 $7,176 $425,485 $1,707,783 
LIABILITIES
Risk management activities — derivative instruments:
Commodity contracts$— $(40,388)$(22,215)$817 (a)$(61,786)
(a)Represents counterparty netting, margin, and collateral. See Note 13.
(b)Represents net pending securities sales and purchases.
(c)Valued using NAV as a practical expedient and, therefore, are not classified in the fair value hierarchy.
(d)All amounts relate to APS, with the exception of $34.2 million related to Pinnacle West’s Captive investments that are classified within Level 1, $25.0 million in cash equivalents and $9.2 million related to equity securities. See Note 12.
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 December 31, 2025 and December 31, 2024 (dollars in thousands):

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 Million British Thermal Units (“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.

December 31, 2024
 Fair Value 		ValuationSignificantWeighted-Average
Commodity ContractsAssetsLiabilitiesTechniqueUnobservable InputRange(b)
Electricity Forward Contracts (a)$708 $21,890 Discounted cash flowsElectricity forward price (per MWh)$25.25 -$151.11$106.06
Natural Gas Forward Contracts (a)6,468 325 Discounted cash flowsNatural gas forward price (per MMBtu)$(0.89)-$1.47$0.71
Total$7,176 $22,215 
(a)Includes swaps and physical and financial contracts.
(b)Unobservable inputs were weighted by the relative fair value of the instrument.
The following table shows the changes in fair value for our risk management activities’ assets and liabilities that are measured at fair value on a recurring basis using Level 3 inputs (dollars in thousands):
 Year Ended December 31,
Commodity Contracts20252024
Balance at beginning of period$(15,039)$4,921 
Total net losses realized/unrealized:
Deferred as a regulatory asset or liability(30,006)(60,965)
Settlements21,907 44,156 
Transfers into Level 3 from Level 2(1,240)(4,635)
Transfers from Level 3 into Level 2668 1,484 
Balance at end of period$(23,710)$(15,039)
Net unrealized gains/losses included in earnings related to instruments still held at end of period$— $— 

             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.
v3.25.4
Investments in Nuclear Decommissioning Trusts and Other Special Use Funds
 12 Months Ended
Dec. 31, 2025
Investments, Debt and Equity Securities [Abstract]  
Investments in Nuclear Decommissioning Trusts and Other Special Use Funds Investments in Nuclear Decommissioning Trusts and Other Special Use Funds
 
We have investments in debt and equity securities held in nuclear decommissioning trusts and other special use funds. Investments in debt securities are classified as available-for-sale securities. We record both debt and equity security investments at their fair value on our Consolidated Balance Sheets. See Note 17 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 2024, APS was reimbursed $14 million for prior year active union employee medical claims from the active union employee medical account. The account is invested primarily in fixed income securities. In accordance with the ratemaking treatment, APS has deferred the unrealized gains and losses (including credit losses) in other regulatory assets. 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): 
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 $(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 and $3.2 million of unrealized gains relating to investments held by the Captive.
December 31, 2024
 Fair ValueTotal
Unrealized
Gains		Total
Unrealized
Losses
Investment Type:Nuclear Decommissioning TrustsOther Special Use FundsTotal
Equity securities$435,470 $24,962 $460,432 $359,127 $(176)
Available for sale-fixed income securities844,040 355,544 1,199,584 (a)7,717 (31,960)
Other3,335 27,851 31,186 (b)— — 
Total$1,282,845 $408,357 $1,691,202 (c)$366,844 $(32,136)
(a)As of December 31, 2024, the amortized cost basis of these available-for-sale investments is $1,224 million.
(b)Represents net pending securities sales and purchases.
(c)All amounts pertain to APS, with the exception of $34.2 million of other special use fund investments in equity securities relating to 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):
 Year Ended December 31,
 Nuclear Decommissioning TrustsOther Special Use FundsTotal
2025
Realized gains$12,826 $242 $13,068 
Realized losses$(11,749)$— $(11,749)
Proceeds from the sale of securities (a)$1,478,088 $377,112 (b)$1,855,200 
2024
Realized gains$75,690 $372 $76,062 
Realized losses$(21,966)$— $(21,966)
Proceeds from the sale of securities (a)$1,330,940 $355,154 $1,686,094 
2023
Realized gains$111,922 $172 $112,094 
Realized losses$(41,212)$(568)$(41,780)
Proceeds from the sale of securities (a)$1,324,978 $354,744 $1,679,722 
(a)Proceeds are reinvested in the nuclear decommissioning trusts and other special use funds, excluding amounts reimbursed to the Company for active union employee medical claims from the active union employee medical account.
(b)All amounts pertain to APS, with the exception of $51.4 million of other special use fund proceeds from the sale of securities relating to investments held by Captive.
Fixed Income Securities Contractual Maturities

The fair value fixed income securities summarized by contractual maturities as of December 31, 2025 is as follows (dollars in thousands):
 
 Nuclear Decommissioning TrustsCoal Reclamation Escrow AccountActive Union Employee Medical AccountTotal
Less than one year$36,726 $87,421 $39,617 $163,764 
1 year – 5 years272,413 68,348 157,116 497,877 
5 years – 10 years173,131 — 16,553 189,684 
Greater than 10 years416,133 — — 416,133 
Total$898,403 $155,769 $213,286 $1,267,458 
v3.25.4
Changes in Accumulated Other Comprehensive Loss
 12 Months Ended
Dec. 31, 2025
Comprehensive Income (Loss), Net of Tax, Attributable to Parent [Abstract]  
Changes in Accumulated Other Comprehensive Loss Changes in Accumulated Other Comprehensive Loss
 
The following table shows the changes in Pinnacle West’s consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component (dollars in thousands): 
 Pension and Other Postretirement BenefitsDerivative InstrumentsTotal
Balance at December 31, 2023
$(34,754)$1,610 $(33,144)
Other comprehensive income/(loss) before reclassifications
1,039 (891)148 
Amounts reclassified from accumulated other comprehensive loss
2,054 (a)— 2,054 
Balance at December 31, 2024
(31,661)719 (30,942)
Other comprehensive loss before reclassifications
(3,210)(147)(3,357)
Amounts reclassified from accumulated other comprehensive loss
1,891 (a)— 1,891 
Balance at December 31, 2025
$(32,980)$572 $(32,408)
(a)These amounts primarily represent amortization of actuarial loss and are included in the computation of net periodic pension cost. See Note 9.
The following table shows the changes in APS’s consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component (dollars in thousands): 
 Pension and Other Postretirement Benefits
Balance at December 31, 2023
$(17,219)
Other comprehensive income before reclassifications
1,255 
Amounts reclassified from accumulated other comprehensive loss
1,848 (a)
Balance at December 31, 2024
(14,116)
Other comprehensive loss before reclassifications
(2,889)
Amounts reclassified from accumulated other comprehensive loss
1,548 (a)
Balance at December 31, 2025
$(15,457)
(a)These amounts primarily represent amortization of actuarial loss and are included in the computation of net periodic pension cost. See Note 9.
v3.25.4
Leases
 12 Months Ended
Dec. 31, 2025
Leases [Abstract]  
Leases Leases
 
We lease certain land, buildings, vehicles, equipment, and other property through operating rental agreements with varying terms, provisions, and expiration dates. APS also has certain 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 December 31, 2025, one VIE lease arrangement remains in effect. See Note 12 for discussion of VIEs and the 2025 acquisition of the VIE’s noncontrolling interest.

APS is a 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.

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):

Year Ended December 31,
202520242023
Operating Lease Cost - PPAs and Energy Storage PPA Lease Contracts$292,625 $147,313 $126,655 
Operating Lease Cost - Land, Property, and Other Equipment22,120 20,120 19,235 
Total Operating Lease Cost314,745 167,433 145,890 
Variable Lease Cost (a)124,707 144,108 135,007 
Short-term Lease Cost2,250 20,653 21,530 
Total Lease Cost$441,702 $332,194 $302,427 
(a)    Primarily relates to PPA lease contracts.

Lease costs are primarily included as a component of operating expenses on our Consolidated Statements of Income. Lease costs relating to PPAs and energy storage PPA lease contracts are recorded in fuel and purchased power on the Consolidated Statements of Income and are subject to recovery under the PSA or RES. See Note 8. 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):
December 31, 2025
YearPPAs and Energy Storage PPA Lease ContractsLand, Property and Equipment LeasesTotal
2026 $364,197 $21,141 $385,338 
2027390,260 18,858 409,118 
2028394,202 16,166 410,368 
2029398,287 14,033 412,320 
2030402,416 9,811 412,227 
Thereafter3,590,042 59,700 3,649,742 
Total lease commitments5,539,404 139,709 5,679,113 
Less imputed interest1,899,993 42,169 1,942,162 
Total lease liabilities$3,639,411 $97,540 $3,736,951 
    
We recognize lease assets and liabilities upon lease commencement. As of December 31, 2025, we have various lease arrangements that have been executed, but have not yet commenced. We expect the total fixed consideration paid for these arrangements, which includes both lease and non-lease payments, will approximate $11.4 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 lease commencement dates for certain arrangements have experienced delays. As a result of these delays and other events, APS has received cash proceeds from certain lessors prior to lease commencement. Proceeds received from lessors relating to energy storage PPA leases are accounted for as lease incentives on our Consolidated Balance Sheets, and upon lease commencement are amortized over the associated lease term. For regulatory purposes, the proceeds received by APS relating to these PPA leases are treated as a reduction to fuel and purchased power costs through the PSA in the period proceeds are received. See Note 8.
The following tables provide other additional information related to operating lease liabilities (dollars in thousands):
Year Ended December 31,
202520242023
Cash paid for amounts included in the measurement of lease liabilities — operating cash flows:$226,484 $143,950 $123,472 
Right-of-use operating lease assets obtained in exchange for operating lease liabilities:$2,195,728 (a)$393,702 (b)602,301 (c)

December 31, 2025December 31, 2024
Weighted average remaining lease term15 years11 years
Weighted average discount rate (d)5.48 %4.90 %
(a)Primarily relates to nine new energy storage PPA operating leases that commenced in 2025.
(b)Primarily relates to the three new energy storage operating lease agreements that commenced in 2024.
(c)Primarily relates to the two purchased power operating lease agreements that were modified in January 2023.
(d)Most of our lease agreements do not contain an implicit rate that is readily determinable. For these agreements we use our incremental borrowing rate to measure the present value of lease liabilities. We determine our incremental borrowing rate at lease commencement based on the rate of interest that we would have to pay to borrow, on a collateralized basis over a similar term, an amount equal to the lease payments in a similar economic environment. We use the implicit rate when it is readily determinable.
v3.25.4
Asset Retirement Obligations
 12 Months Ended
Dec. 31, 2025
Asset Retirement Obligation Disclosure [Abstract]  
Asset Retirement Obligations Asset Retirement Obligations
 
In 2025, the Company revised its cost estimates for existing AROs for the following:

•Cholla coal-fired power plant related to the closure of ponds and facilities, which resulted in an increase to the ARO of approximately $49 million, primarily due to increased cost estimates associated with the CCR Rule.
•Four Corners coal-fired power plant, which resulted in an increase of approximately $16 million.
•Navajo, a decommissioned coal-fired power plant, which resulted in a decrease of approximately $4 million.
•Ironwood, a solar power plant, recorded a new obligation of approximately $15 million.

APS has also recorded the initial investigation and assessment costs related to the newly signed EPA rule for legacy CCR surface impoundments and CCRMUs. At this time, APS is still evaluating the financial impacts of this final regulation on its business, with initial CCRMU site surveys due to be completed by February 2027 and final site investigation reports to be finalized by February 2028 in accordance with the rule published by EPA on February 10, 2026, extending the compliance deadlines. Based on the information available to APS at this time, APS cannot reasonably estimate the fair value of the entire CCRMU ARO. Depending on the outcome of those evaluations and site investigations, the costs associated with APS’s management of CCR could materially increase, which could affect our financial condition, results of operations, or cash flows.
In 2024, the Company revised its cost estimates for existing ARO for the following:

•Cholla coal-fired power plant related to the closure of ponds and facilities, which resulted in an increase to the ARO of approximately $63 million, primarily due to cost estimates associated with the CCR Rule.
•Four Corners coal-fired power plant, which resulted in an increase of approximately $82 million, primarily due to cost estimates associated with the CCR Rule.
•Navajo, a decommissioned coal-fired power plant, which resulted in an increase of approximately $8 million.
•Palo Verde nuclear plant, which resulted in an increase of approximately $1 million.
•Solar, which resulted in a decrease to the ARO of approximately $11 million, primarily due to the reduced cost of solar panel disposal.

See additional details in Notes 8 and 14.
The following table shows the change in our ARO’s (dollars in thousands):

 20252024
Asset retirement obligations at the beginning of year
$1,146,586 $966,001 
Changes attributable to:  
Accretion expense64,552 56,143 
Settlements(16,570)(18,379)
Estimated cash flow revisions61,080 142,821 
Newly incurred obligation14,651 — 
Asset retirement obligations at the end of year
$1,270,299 $1,146,586 
 
In accordance with regulatory accounting, APS accrues removal costs for its regulated utility assets, even if there is no legal obligation for removal.  See Note 8 for detail of regulatory liabilities.
v3.25.4
Sale of Bright Canyon Energy
 12 Months Ended
Dec. 31, 2025
Discontinued Operations and Disposal Groups [Abstract]  
Sale of Bright Canyon Energy Sale of Bright Canyon Energy
On August 4, 2023, Pinnacle West entered into an agreement pursuant to which we agreed to sell all of our equity interest in our wholly-owned subsidiary, BCE. The BCE Sale was accounted for as the sale of a business and was structured to close in multiple stages that were completed on January 12, 2024. Certain investments and assets that BCE previously held, including the TransCanyon joint venture and holdings in the two Tenaska wind farm investments, were not included in the BCE Sale and were instead transferred to PNW Power, a wholly-owned subsidiary of Pinnacle West. The BCE Sale did not include a $31 million equity bridge loan relating to BCE’s Los Alamitos project, which was paid in full by Pinnacle West on August 4, 2023. Other than these retained investments and the debt instrument, all BCE assets and liabilities were included in the BCE Sale and were transferred to Ameresco.

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

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

•The final stage of the BCE Sale was completed on January 12, 2024. In the final stage, the net assets transferred to Ameresco totaled $35 million. The assets transferred in the final stage related primarily to equity method investments in the Kūpono Solar Project and other development stage projects. Our Consolidated Statements of Income for the year ended 2024, included a $23 million gain relating to the final stage of the BCE Sale.

As of January 12, 2024, all stages of the BCE Sale had been completed. As of December 31, 2024 the interest-bearing promissory note had been paid in full.

 On January 30, 2024, Pinnacle West entered into a tax credit transfer agreement to purchase from Ameresco $23 million of investment tax credits from the BCE Los Alamitos project for $21 million.
Additionally, Pinnacle West continues to maintain certain guarantees relating to the Kūpono Solar Project sale-leaseback financing, which were not transferred in the BCE Sale transaction. See Note 14.
v3.25.4
El Dorado Equity Investments
 12 Months Ended
Dec. 31, 2025
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 AZ-VC.

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.

AZ-VC — 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 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 December 31, 2025
December 31, 2025December 31, 2024
SAI (a)17 %$21 $— 
AZ-VC (b)24 %15 11 
Total equity method investments$36 $11 
(a)El Dorado has no further funding commitments to SAI.
(b)El Dorado has a $25.0 million funding commitment to AZ-VC, of which approximately $15.5 million has been funded as of December 31, 2025.

Our share of the investees’ earnings or losses are recognized in other income and other expense on Pinnacle West’s Consolidated Statements of Income. For the year ended December 31, 2025, the net equity method earnings relating to these investments was $29.0 million. For the year ended December 31, 2024, the net equity method earnings relating to these investments was $0.3 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 Consolidated Balance Sheets as of December 31, 2025 and December 31, 2024 include $25.1 million and $23.1 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 December 31, 2025.
v3.25.4
Schedule I - Condensed Financial Information of Registrant
 12 Months Ended
Dec. 31, 2025
Condensed Financial Information Disclosure [Abstract]  
Schedule I - Condensed Financial Information of Registrant
PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY
SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME
(dollars in thousands)
 
 Year Ended December 31,
 202520242023
Operating expenses$9,667 $9,931 $11,249 
Other   
Equity in earnings of subsidiaries699,155 643,703 539,962 
Other income (expense)(1,917)23,835 2,823 
Total697,238 667,538 542,785 
Interest expense90,233 65,261 47,251 
Income before income taxes597,338 592,346 484,285 
Income tax benefit(19,193)(16,460)(17,272)
Net income attributable to common shareholders616,531 608,806 501,557 
Other comprehensive income (loss) — attributable to common shareholders(1,466)2,202 (1,709)
Total comprehensive income — attributable to common shareholders$615,065 $611,008 $499,848 
PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY
SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED BALANCE SHEETS
(dollars in thousands)
 
 December 31,
 20252024
ASSETS  
Current assets  
Cash and cash equivalents$2,461 $23 
Accounts receivable162,006 163,203 
Income tax receivable7,856 6,673 
Other current assets848 434 
Total current assets173,171 170,333 
Investments and other assets  
Investments in subsidiaries9,020,104 8,435,150 
Other assets30,854 21,966 
Total investments and other assets9,050,958 8,457,116 
TOTAL ASSETS$9,224,129 $8,627,449 
  
LIABILITIES AND EQUITY
Current liabilities  
Accounts payable$7,685 $3,471 
Accrued taxes10,013 4,799 
Common dividends payable110,022 106,592 
Short-term borrowings249,700 228,550 
Current maturities of long-term debt350,000 500,000 
Operating lease liabilities 149 138 
Other current liabilities30,282 11,389 
Total current liabilities757,851 854,939 
Long-term debt less current maturities1,315,736 867,770 
Deferred income taxes43,167 24,536 
Pension liabilities2,744 4,462 
Operating lease liabilities1,044 1,194 
Other16,512 17,070 
Total deferred credits and other63,467 47,262 
COMMITMENTS AND CONTINGENCIES
Common stock equity
Common stock3,228,049 3,118,294 
Accumulated other comprehensive loss(32,408)(30,942)
Retained earnings3,850,817 3,666,959 
Total Pinnacle West Shareholders’ equity7,046,458 6,754,311 
Noncontrolling interests40,617 103,167 
Total Equity7,087,075 6,857,478 
TOTAL LIABILITIES AND EQUITY$9,224,129 $8,627,449 
PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY
SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED STATEMENTS OF CASH FLOWS
(dollars in thousands)
 Year Ended December 31,
 202520242023
Cash flows from operating activities   
Net income$616,531 $608,806 $501,557 
Adjustments to reconcile net income to net cash provided by operating activities: 
Equity in earnings of subsidiaries — net(699,155)(643,703)(539,962)
Gain on sale relating to BCE— (22,988)(6,423)
Depreciation and amortization68 75 76 
Deferred income taxes18,675 40,231 (13,955)
Accounts receivable(1,672)15,268 (28,273)
Accounts payable4,213 (4,869)1,839 
Accrued taxes and income tax receivables — net4,030 (4,584)9,505 
Dividends received from subsidiaries429,700 401,400 393,600 
Other30,457 22,959 (14,201)
Net cash provided by operating activities402,847 412,595 303,763 
Cash flows from investing activities   
Proceeds from sale relating to BCE— 84,322 23,400 
Investments in subsidiaries(382,338)(827,752)(119,682)
Repayments of loans from subsidiaries and other13,756 1,132 6,526 
Advances of loans to subsidiaries(10,202)(11,336)(59,349)
Net cash used for investing activities(378,784)(753,634)(149,105)
Cash flows from financing activities   
Issuance of long-term debt795,404 867,387 175,000 
Repayment of long-term debt(500,000)(625,000)— 
Short-term borrowings and (repayments) — net46,150 (48,100)60,930 
Short-term debt borrowings under term loan facility175,000 200,000 — 
Short-term debt repayments under term loan facility(200,000)— — 
Dividends paid on common stock(422,792)(394,663)(386,486)
Common stock equity issuance and purchases — net84,613 341,429 (4,093)
Net cash provided by (used for) financing activities(21,625)341,053 (154,649)
Net increase in cash and cash equivalents2,438 14 9 
Cash and cash equivalents at beginning of year23 9 — 
Cash and cash equivalents at end of year$2,461 $23 $9 
     
PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY
NOTES TO FINANCIAL STATEMENTS OF HOLDING COMPANY

The Combined Notes to Consolidated Financial Statements in Part II, Item 8 should be read in conjunction with the Pinnacle West Capital Corporation Holding Company Financial Statements.

The Pinnacle West Capital Corporation Holding Company Financial Statements have been prepared to present the financial position, results of operations and cash flows of Pinnacle West on a stand-alone basis as a holding company. Investments in subsidiaries are accounted for using the equity method. The noncontrolling interests relate to the Palo Verde sale leaseback VIE.
v3.25.4
Insider Trading Arrangements
 3 Months Ended
Dec. 31, 2025
Trading Arrangements, by Individual  
Rule 10b5-1 Arrangement Adopted false
Non-Rule 10b5-1 Arrangement Adopted false
Rule 10b5-1 Arrangement Terminated false
Non-Rule 10b5-1 Arrangement Terminated false
v3.25.4
Insider Trading Policies and Procedures
 12 Months Ended
Dec. 31, 2025
Insider Trading Policies and Procedures [Line Items]  
Insider Trading Policies and Procedures Adopted true
v3.25.4
Cybersecurity Risk Management and Strategy Disclosure
 12 Months Ended
Dec. 31, 2025
Cybersecurity Risk Management, Strategy, and Governance [Line Items]  
Cybersecurity Risk Management Processes for Assessing, Identifying, and Managing Threats [Text Block]
In fulfilling its responsibility, the Cybersecurity Group manages formal documented internal processes such as risk management and vulnerability scanning, as well as other processes, such as assessing threat intelligence, that include outside partners. Intelligence sharing comes from industry sources such as the Electricity Information Sharing and Analysis Center, government sources, as well as commercially purchased information sources. The Cybersecurity Group also engages third parties for assessments and audits of its systems periodically and as needed. Such assessments and audits may include, among other things, pre-production evaluation of technologies, overall program assessments, and compliance program assessments including audits by our regulators.

Depending on the products and services provided and the potential for data exchange and technology risk, we may require vendors and service providers to pass APS’s vendor risk management program, which sets forth security and data protection requirements, as a condition to doing or continuing to do business with us. For contracts with vendors that will handle or have access to certain sensitive data, APS requires contractual provisions setting forth cybersecurity controls, vulnerability management, secure development practices, and other security and data protection requirements. A subset of vendors that meet a predetermined risk profile due to strategic relationships, technology risk, or other factors is continually monitored by a third-party risk management service, and the Company annually reviews independent assessments of these vendors.
The Cybersecurity Group also has documented processes for identifying, responding to, and internally escalating cybersecurity incidents to management and the Board of Directors. Once an incident meets certain criteria, the Company’s Cybersecurity Incident Command or, in the case of a potentially severe threat that could impact the entire Company, the Corporate Emergency Operations Center is activated and formal response procedures are followed to address the incident. The Cybersecurity Group has a formal incident response plan that details response and escalation procedures, including activation of a Cybersecurity Disclosure Committee, consisting of the Chief Financial Officer and the General Counsel, to assess an incident’s materiality with input as needed from the Director of Cybersecurity, Chief Accounting Officer, Chief Information Officer, and others, including outside advisors.

Cybersecurity risk management has been integrated into the Company’s overall enterprise risk management program (the “Enterprise Risk Management Program”) through policies and processes that implement a risk management framework designed to identify, manage, and monitor business unit risks throughout the organization. The Enterprise Risk Management Program is overseen by an executive committee (the “Executive Risk Committee”), which meets at least quarterly and is comprised of members holding executive leadership positions in the Company, including the Chairman, President, and Chief Executive Officer, and other Executive and Senior Vice Presidents, and is chaired and sponsored by the Chief Financial Officer. Every year, as a part of the Enterprise Risk Management Program, risks affecting the Company are identified. Cybersecurity is among the enterprise risks assessed annually and was identified as a top risk in 2025. The applicable subject matter experts brief the Company’s Board of Directors on the status of all top enterprise risks at least once per year. Finally, the Nuclear and Operating Committee of the Company’s Board of Directors provides ultimate oversight of cybersecurity risk and also receives briefings in-person or virtually at least twice per year from the Cybersecurity Group, and notable
audit findings relating to cybersecurity are aggregated and provided to the Board of Directors’ Audit Committee.

To date, we do not believe there have been any previous cybersecurity incidents that have materially affected or are reasonably likely to materially affect Pinnacle West or APS. However, there is no assurance that will continue to be the case. If a significant cybersecurity event or incident were to occur, our ability to fulfill our critical business functions could be materially impacted, which could materially adversely affect our results of operations and financial conditions. See the risk factor entitled, “We are subject to cybersecurity risks and risks of unauthorized access to our systems that could adversely affect our business and financial condition” in Part I, Item 1A—Risk Factors for more information.
Cybersecurity Risk Management Processes Integrated [Flag] true
Cybersecurity Risk Management Processes Integrated [Text Block] Cybersecurity risk management has been integrated into the Company’s overall enterprise risk management program (the “Enterprise Risk Management Program”) through policies and processes that implement a risk management framework designed to identify, manage, and monitor business unit risks throughout the organization.
Cybersecurity Risk Management Third Party Engaged [Flag] true
Cybersecurity Risk Third Party Oversight and Identification Processes [Flag] true
Cybersecurity Risk Materially Affected or Reasonably Likely to Materially Affect Registrant [Flag] false
Cybersecurity Risk Board of Directors Oversight [Text Block]
Cybersecurity risk management has been integrated into the Company’s overall enterprise risk management program (the “Enterprise Risk Management Program”) through policies and processes that implement a risk management framework designed to identify, manage, and monitor business unit risks throughout the organization. The Enterprise Risk Management Program is overseen by an executive committee (the “Executive Risk Committee”), which meets at least quarterly and is comprised of members holding executive leadership positions in the Company, including the Chairman, President, and Chief Executive Officer, and other Executive and Senior Vice Presidents, and is chaired and sponsored by the Chief Financial Officer. Every year, as a part of the Enterprise Risk Management Program, risks affecting the Company are identified. Cybersecurity is among the enterprise risks assessed annually and was identified as a top risk in 2025. The applicable subject matter experts brief the Company’s Board of Directors on the status of all top enterprise risks at least once per year. Finally, the Nuclear and Operating Committee of the Company’s Board of Directors provides ultimate oversight of cybersecurity risk and also receives briefings in-person or virtually at least twice per year from the Cybersecurity Group, and notable
audit findings relating to cybersecurity are aggregated and provided to the Board of Directors’ Audit Committee.
Cybersecurity Risk Board Committee or Subcommittee Responsible for Oversight [Text Block] The Enterprise Risk Management Program is overseen by an executive committee (the “Executive Risk Committee”), which meets at least quarterly and is comprised of members holding executive leadership positions in the Company, including the Chairman, President, and Chief Executive Officer, and other Executive and Senior Vice Presidents, and is chaired and sponsored by the Chief Financial Officer. Every year, as a part of the Enterprise Risk Management Program, risks affecting the Company are identified. Cybersecurity is among the enterprise risks assessed annually and was identified as a top risk in 2025. The applicable subject matter experts brief the Company’s Board of Directors on the status of all top enterprise risks at least once per year. Finally, the Nuclear and Operating Committee of the Company’s Board of Directors provides ultimate oversight of cybersecurity risk and also receives briefings in-person or virtually at least twice per year from the Cybersecurity Group, and notable
audit findings relating to cybersecurity are aggregated and provided to the Board of Directors’ Audit Committee.
Cybersecurity Risk Process for Informing Board Committee or Subcommittee Responsible for Oversight [Text Block] Every year, as a part of the Enterprise Risk Management Program, risks affecting the Company are identified. Cybersecurity is among the enterprise risks assessed annually and was identified as a top risk in 2025. The applicable subject matter experts brief the Company’s Board of Directors on the status of all top enterprise risks at least once per year. Finally, the Nuclear and Operating Committee of the Company’s Board of Directors provides ultimate oversight of cybersecurity risk and also receives briefings in-person or virtually at least twice per year from the Cybersecurity Group, and notable
audit findings relating to cybersecurity are aggregated and provided to the Board of Directors’ Audit Committee.
Cybersecurity Risk Role of Management [Text Block] To that end, the Company implements a robust risk management, strategy, and governance regime aimed at implementing controls to identify, mitigate, remediate, and communicate cyber threats at appropriate levels within the organization.
APS’s cybersecurity group (the “Cybersecurity Group”) is comprised of cybersecurity analysts, engineers, architects, and others, led by the Director of Cybersecurity, who reports to APS’s Vice President, Operations Support. The Director of Cybersecurity has more than twenty years of experience in
information technology and cybersecurity roles, with more than ten of those years at the Company. The Director of Cybersecurity also holds cybersecurity certifications from multiple certifying bodies and is active in utility cybersecurity professional organizations. The Cybersecurity Group has day-to-day responsibility for safeguarding the Company’s critical assets and assessing, identifying, and managing material risks from cybersecurity threats.

In fulfilling its responsibility, the Cybersecurity Group manages formal documented internal processes such as risk management and vulnerability scanning, as well as other processes, such as assessing threat intelligence, that include outside partners. Intelligence sharing comes from industry sources such as the Electricity Information Sharing and Analysis Center, government sources, as well as commercially purchased information sources. The Cybersecurity Group also engages third parties for assessments and audits of its systems periodically and as needed. Such assessments and audits may include, among other things, pre-production evaluation of technologies, overall program assessments, and compliance program assessments including audits by our regulators.

Depending on the products and services provided and the potential for data exchange and technology risk, we may require vendors and service providers to pass APS’s vendor risk management program, which sets forth security and data protection requirements, as a condition to doing or continuing to do business with us. For contracts with vendors that will handle or have access to certain sensitive data, APS requires contractual provisions setting forth cybersecurity controls, vulnerability management, secure development practices, and other security and data protection requirements. A subset of vendors that meet a predetermined risk profile due to strategic relationships, technology risk, or other factors is continually monitored by a third-party risk management service, and the Company annually reviews independent assessments of these vendors.
The Cybersecurity Group also has documented processes for identifying, responding to, and internally escalating cybersecurity incidents to management and the Board of Directors. Once an incident meets certain criteria, the Company’s Cybersecurity Incident Command or, in the case of a potentially severe threat that could impact the entire Company, the Corporate Emergency Operations Center is activated and formal response procedures are followed to address the incident. The Cybersecurity Group has a formal incident response plan that details response and escalation procedures, including activation of a Cybersecurity Disclosure Committee, consisting of the Chief Financial Officer and the General Counsel, to assess an incident’s materiality with input as needed from the Director of Cybersecurity, Chief Accounting Officer, Chief Information Officer, and others, including outside advisors.
Cybersecurity Risk Management Positions or Committees Responsible [Flag] true
Cybersecurity Risk Management Positions or Committees Responsible [Text Block]
APS’s cybersecurity group (the “Cybersecurity Group”) is comprised of cybersecurity analysts, engineers, architects, and others, led by the Director of Cybersecurity, who reports to APS’s Vice President, Operations Support. The Director of Cybersecurity has more than twenty years of experience in
information technology and cybersecurity roles, with more than ten of those years at the Company.
Cybersecurity Risk Management Expertise of Management Responsible [Text Block] The Director of Cybersecurity has more than twenty years of experience in information technology and cybersecurity roles, with more than ten of those years at the Company. The Director of Cybersecurity also holds cybersecurity certifications from multiple certifying bodies and is active in utility cybersecurity professional organizations.
Cybersecurity Risk Process for Informing Management or Committees Responsible [Text Block] The Cybersecurity Group also has documented processes for identifying, responding to, and internally escalating cybersecurity incidents to management and the Board of Directors. Once an incident meets certain criteria, the Company’s Cybersecurity Incident Command or, in the case of a potentially severe threat that could impact the entire Company, the Corporate Emergency Operations Center is activated and formal response procedures are followed to address the incident. The Cybersecurity Group has a formal incident response plan that details response and escalation procedures, including activation of a Cybersecurity Disclosure Committee, consisting of the Chief Financial Officer and the General Counsel, to assess an incident’s materiality with input as needed from the Director of Cybersecurity, Chief Accounting Officer, Chief Information Officer, and others, including outside advisors.
Cybersecurity Risk Management Positions or Committees Responsible Report to Board [Flag] true
v3.25.4
Summary of Significant Accounting Policies (Policies)
 12 Months Ended
Dec. 31, 2025
Accounting Policies [Abstract]  
Description of Business and Basis of Presentation
Description of Business and Basis of Presentation
 
Pinnacle West is an investor-owned electric utility holding company that conducts business through its subsidiaries, APS, El Dorado and PNW Power. APS, our wholly-owned subsidiary, is a vertically-integrated electric utility that provides either retail or wholesale electric service to substantially all of the state of Arizona, with the major exceptions of about one-half of the Phoenix metropolitan area, the Tucson metropolitan area and Mohave County in northwestern Arizona.  APS accounts for essentially all of our revenues and earnings and is expected to continue to do so.  El Dorado is a wholly-owned subsidiary that invests in energy-related and Arizona community-based ventures. PNW Power, formed in September 2023, is a wholly-owned subsidiary that holds certain wind and transmission joint-venture investments previously held by BCE. BCE was sold on January 12, 2024 and is no longer included in the Company’s consolidated financial statements. See Note 22 for additional information.
 
Pinnacle West’s Consolidated Financial Statements include the accounts of Pinnacle West and our subsidiaries, including APS, El Dorado, and PNW Power, as well as BCE through the date of its sale. Pinnacle West’s Consolidated Financial Statements also include the accounts of a VIE relating to the Captive. APS’s Consolidated Financial Statements include the accounts of APS and certain VIEs relating to the Palo Verde sale leaseback.  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. See Note 12 for additional information. Intercompany accounts and transactions between the consolidated companies have been eliminated.
 
We consolidate VIEs for which we are the primary beneficiary.  We determine whether we are the primary beneficiary of a VIE through a qualitative analysis that identifies which variable interest holder has the controlling financial interest in the VIE.  In performing our primary beneficiary analysis, we consider all relevant facts and circumstances, including the design and activities of the VIE, the terms of the contracts the VIE has entered into, and which parties participated significantly in the design or redesign of the entity.  We continually evaluate our primary beneficiary conclusions to determine if changes have occurred which would impact our primary beneficiary assessments.  We have determined that APS is the primary beneficiary of a VIE lessor trust relating to the Palo Verde sale leaseback, and therefore APS consolidates this entity. We have also determined that Pinnacle West is the primary beneficiary of a protected captive insurance cell VIE, and therefore Pinnacle West consolidates this insurance cell.
Accounting Records and Use of Estimates
Accounting Records and Use of Estimates
 
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.
Regulatory Accounting
Regulatory Accounting
 
APS is regulated by the ACC and FERC.  The accompanying financial statements reflect the rate-making policies of these commissions.  As a result, we capitalize certain costs that would be included as expense in the current period by unregulated companies.  Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in customer rates. Regulatory liabilities generally represent amounts collected in rates to recover costs expected to be incurred in the future or amounts collected in excess of costs incurred and are refundable to customers.
 
Management judgments include continually assessing the likelihood of future recovery of regulatory assets and/or a disallowance of part of the cost of recently completed plant, by considering factors such as applicable regulatory environment changes and recent rate orders to other regulated entities in the same jurisdiction.  This determination reflects the current political and regulatory climate in Arizona and is subject to change in the future.  If future recovery of costs ceases to be probable, the assets would be written off as a charge in current period earnings. Management judgments also include assessing the impact of potential commission-ordered refunds to customers on regulatory liabilities.
Electric Revenues
Electric Revenues
 
Revenues primarily consist of activities that are classified as revenues from contracts with customers. Our electric revenues generally represent a single performance obligation delivered over time. We have elected to apply the practical expedient that allows us to recognize revenue based on the amount to which we have a right to invoice for services performed.

We derive electric revenues primarily from sales of electricity to our regulated retail customers. Revenues related to the sale of electricity are generally recognized when service is rendered or electricity is delivered to customers. Unbilled revenues are estimated by applying an average revenue/kWh by customer class to the number of estimated kWhs delivered but not billed. Differences historically between the actual and estimated unbilled revenues are immaterial. We exclude sales taxes and franchise fees on electric revenues from both revenue and taxes other than income taxes.
 
Revenues from our regulated retail customers and non-derivative instruments are reported on a gross basis on Pinnacle West’s Consolidated Statements of Income. In the electricity business, some contracts to purchase electricity are netted against other contracts to sell electricity. This is called a “book-out” and usually occurs for contracts that have the same terms (quantities, delivery points and delivery periods) and for which power does not flow. We net these book-outs, which reduces both wholesale revenues and fuel and purchased power costs.
Certain cost recovery mechanisms may qualify as alternative revenue programs. For alternative revenue programs that meet specified accounting criteria, we recognize revenues when the specific events permitting billing of the additional revenues have been completed.
Allowance for Doubtful Accounts
Allowance for Doubtful Accounts
 
The allowance for doubtful accounts represents our best estimate of accounts receivable and accrued unbilled revenues that will ultimately be uncollectible due to credit loss risk. The allowance includes a write-off component that is calculated by applying an estimated write-off factor to retail electric revenues. The write-off factor used to estimate uncollectible accounts is based upon consideration of historical collections experience, the current and forecasted economic environment, changes to our collection policies, and management’s best estimate of future collections success.
Property, Plant and Equipment
Property, Plant and Equipment
 
Utility plant is the term we use to describe the business property and equipment that supports electric service, consisting primarily of generation, transmission, and distribution facilities.  We report utility plant at its original cost, which includes:

•material and labor;
•contractor costs;
•capitalized leases;
•construction overhead costs (where applicable); and
•AFUDC.
Property, plant and equipment balances and classes for APS are not materially different than Pinnacle West.

We expense the costs of plant outages, major maintenance and routine maintenance as incurred.  We charge retired utility plant to accumulated depreciation.  Liabilities associated with the retirement of
tangible long-lived assets are recognized at fair value as incurred and capitalized as part of the related tangible long-lived assets.  Accretion of the liability due to the passage of time is an operating expense, and the capitalized cost is depreciated over the useful life of the long-lived asset.  See Note 21 for additional information.

APS records a regulatory liability for the excess that has been recovered in regulated rates over the amount calculated in accordance with guidance on accounting for AROs.  APS believes it is probable it will recover in regulated rates, the costs calculated in accordance with this accounting guidance.
 
We record depreciation and amortization on utility plant on a straight-line basis over the remaining useful life of the related assets.  The approximate remaining average useful lives of our utility property at December 31, 2025, were as follows:

•Steam generation — 21 years;
•Nuclear plant — 30 years;
•Other generation — 16 years;
•Transmission — 34 years;
•Distribution — 33 years;
•Energy storage — 19 years;
•Solar plant — 28 years; and
•General plant — 10 years.
 
Depreciation of utility property, plant and equipment is computed on a straight-line, remaining-life basis.
Asset Retirement Obligations
Asset Retirement Obligations
APS has AROs for its Palo Verde nuclear facilities and certain other generation assets.  The Palo Verde ARO primarily relates to final plant decommissioning.  This obligation is based on the NRC’s requirements for disposal of irradiated property or plant and agreements APS reached with the ACC for final decommissioning of the plant.  The non-nuclear generation AROs primarily relate to requirements for removing portions of those plants at the end of the plant life or lease term and coal ash pond closures. Some of APS’s transmission and distribution assets have AROs because they are subject to right of way and easement agreements that require final removal.  These agreements have a history of uninterrupted renewal that APS expects to continue.  As a result, APS cannot reasonably estimate the fair value of the ARO related to such transmission and distribution assets. Additionally, APS has aquifer protection permits for some of its generation sites that require the closure of certain facilities at those sites.
Allowance for Funds Used During Construction
Allowance for Funds Used During Construction
 
AFUDC represents the approximate net composite interest cost of borrowed funds and an allowed return on the equity funds used for construction of regulated utility plant.  Both the debt and equity components of AFUDC are non-cash amounts within the Consolidated Statements of Income.  Plant
construction costs, including AFUDC, are recovered in authorized rates through depreciation when completed projects are placed into commercial operation.
 
AFUDC was calculated by using a composite rate of 6.67% for 2025, 6.23% for 2024, and 6.29% for 2023.  APS compounds AFUDC semi-annually and ceases to accrue AFUDC when construction work is completed and the property is placed in service.
Materials and Supplies
Materials and Supplies
 
APS values materials, supplies and fossil fuel inventory using a weighted-average cost method.  APS materials, supplies and fossil fuel inventories are carried at the lower of weighted-average cost or net realizable value, unless evidence indicates that the weighted-average cost (even if in excess of market) will be recovered.
Fair Value Measurements
Fair Value Measurements
 
We apply recurring fair value measurements to cash equivalents, derivative instruments, investments held in the nuclear decommissioning trust and other special use funds. On an annual basis, we apply fair value measurements to plan assets held in our retirement and other benefits plans. Due to the nature of short-term borrowings, the carrying values of these instruments approximate fair value.  Fair value measurements may also be applied on a nonrecurring basis to other assets and liabilities in certain circumstances such as impairments.  We also disclose fair value information for our long-term debt, which is carried at amortized cost. See Note 7 for additional information.
 
Fair value is the price that would be received for an asset or paid to transfer a liability (exit price) in the principal or most advantageous market which we can access for the asset or liability in an orderly transaction between willing market participants on the measurement date.  Inputs to fair value may include observable and unobservable data.  We maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.
 
We determine fair market value using observable inputs such as actively-quoted prices for identical instruments when available.  When actively-quoted prices are not available for the identical instruments, we use other observable inputs, such as prices for similar instruments, other corroborative market information, or prices provided by other external sources.  For options, long-term contracts, and other contracts for which observable price data are not available, we use models and other valuation methods, which may incorporate unobservable inputs to determine fair market value.
The use of models and other valuation methods to determine fair market value often requires subjective and complex judgment.  Actual results could differ from the results estimated through application of these methods.
Derivative Accounting
Derivative Accounting
 
We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas, coal and in interest rates.  We manage risks associated with market volatility by utilizing various physical and financial instruments including futures, forwards, options, and swaps.  As part of our overall risk management program, we may use derivative instruments to hedge purchases and sales of electricity and natural gas as well as interest rate risk.  The changes in market value
of such contracts have a high correlation to price changes in the hedged transactions.  We also enter into derivative instruments for economic hedging purposes.  Contracts that have the same terms (quantities, delivery points and delivery periods) and for which power does not flow are netted, which reduces both revenues and fuel and purchased power expenses in our Consolidated Statements of Income, but does not impact our financial condition, net income, or cash flows.
 
We account for our derivative contracts in accordance with derivatives and hedging guidance, which requires all derivatives not qualifying for a scope exception to be measured at fair value on the balance sheet as either assets or liabilities.  Transactions with counterparties that have master netting arrangements are reported net on the balance sheet.
Loss Contingencies and Environmental Liabilities
Loss Contingencies and Environmental Liabilities
 
Pinnacle West and APS are involved in certain legal and environmental matters that arise in the normal course of business.  Contingent losses and environmental liabilities are recorded when it is determined that it is probable that a loss has occurred, and the amount of the loss can be reasonably estimated.  When a range of the probable loss exists and no amount within the range is a better estimate than any other amount, Pinnacle West and APS record a loss contingency at the minimum amount in the range.  Unless otherwise required by GAAP, legal fees are expensed as incurred.
 
The Captive’s contingent losses may include an amount for losses incurred but not reported (“IBNR”). A reserve for IBNR is based upon a loss analysis prepared using actuarial assumptions and techniques. Such liabilities are necessarily based on estimates and the ultimate obligation may be in excess of or less than the estimated liability. The methods for making such estimates and for establishing the resulting liability are continually reviewed, and any adjustments for the review process as well as differences between estimates and ultimate payments are reflected in earnings currently.
Retirement Plans and Other Postretirement Benefits
Retirement Plans and Other Postretirement Benefits
 
Pinnacle West sponsors a qualified defined benefit and account balance pension plan for the employees of Pinnacle West and its subsidiaries, in addition to a non-qualified pension plan.  We also sponsor another postretirement benefit plan for the employees of Pinnacle West and its subsidiaries that provides medical and life insurance benefits to retired employees.  Pension and other postretirement benefit expense are determined by actuarial valuations, based on assumptions that are evaluated annually.
Nuclear Fuel
Nuclear Fuel
 
APS amortizes nuclear fuel by using the unit-of-production method.  The unit-of-production method is based on actual physical usage.  APS divides the cost of the fuel by the estimated number of thermal units it expects to produce with that fuel.  APS then multiplies that rate by the number of thermal units produced within the current period.  This calculation determines the current period nuclear fuel expense.
 
APS also charges nuclear fuel expense for the interim storage and permanent disposal of spent nuclear fuel.  The DOE is responsible for the permanent disposal of spent nuclear fuel and charged APS
$0.001 per kWh of nuclear generation through May 2014, at which point the DOE reduced the fee to zero.  In accordance with a settlement agreement with the DOE in August 2014 for interim storage, we accrued a receivable and an offsetting regulatory liability through the settlement period ended December of 2025.
Income Taxes
Income Taxes
 
Income taxes are provided using the asset and liability approach prescribed by guidance relating to accounting for income taxes and are based on currently enacted tax rates.  We file our federal income tax return on a consolidated basis, and we file our state income tax returns on a consolidated or unitary basis.  In accordance with our intercompany tax sharing agreement, federal and state income taxes are allocated to each first-tier subsidiary as though each first-tier subsidiary filed a separate income tax return.  Any difference between that method and the consolidated (and unitary) income tax liability is attributed to the parent company.  The income tax accounts reflect the tax and interest associated with management’s estimate of the largest amount of tax benefit that is greater than 50% likely of being realized upon settlement for all known and measurable tax exposures.
Intangible Assets
Intangible Assets
 
We have separately disclosed intangible assets on Pinnacle West’s Consolidated Balance Sheets. The intangible assets relate primarily to APS’s internal-use software. We have no goodwill recorded. The intangible assets are amortized over their finite useful lives.
Investments
Investments
 
El Dorado holds investments in both debt and equity securities.  Investments in debt securities are generally accounted for as held-to-maturity and investments in equity securities are accounted for using either the equity method (if significant influence) or the measurement alternative for investments without readily determinable fair values (if less than 3-5% ownership and no significant influence). See Note 23 for additional information.

PNW Power holds investments in equity securities. Investments in equity securities are accounted for using either the equity method (if significant influence) or the measurement alternative for investments without readily determinable fair values (if less than 3-5% ownership and no significant influence).
 
Our investments in the nuclear decommissioning trusts, and other special use funds, are accounted for in accordance with guidance on accounting for investments in debt and equity securities.
Leases
Leases

We determine if an agreement is a lease at contract inception. A lease is defined as a contract, or part of a contract, that conveys the right to control the use of an identified asset for a period of time in exchange for consideration. To control the use of an identified asset an entity must have both a right to obtain substantially all of the benefits from the use of the asset and the right to direct the use of the asset. If we determine an agreement is a lease, and we are the lessee, we recognize a right-of-use lease asset and a lease liability at the lease commencement date. Lease liabilities are recognized based on the present value of the fixed lease payments over the lease term. To present value lease liabilities we use the implicit rate in the lease if the information is readily available, otherwise we use our incremental borrowing rate determined at lease commencement. Our incremental borrowing rate is based on the rate of interest we would have to borrow on a collateralized basis over a similar term an amount equal to the lease payments in a similar economic environment. When measuring right-of-use assets and lease liabilities we exclude variable lease payments, other than those that depend on an index or rate or are in-substance fixed payments. For short-term leases with terms of 12 months or less, we do not recognize a right-of-use lease asset or lease liability. We recognize operating lease expense using a straight-line pattern over the periods of use.

APS enters into purchased power contracts that may contain leases. This occurs when a PPA designates a specific power plant or facility, APS obtains substantially all of the economic benefits from the use of the facility and has the right to direct the use of the facility. Purchased power lease contracts may also include energy storage facilities. Lease costs relating to purchased power lease contracts are
reported in fuel and purchased power on the Consolidated Statements of Income and are subject to recovery under the PSA or RES. See Note 8 for additional information. We also may enter into lease agreements related to vehicles, office space, land, and other equipment. See Note 20 for additional information.
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 Consolidated Statements of Income, APS Consolidated Balance Sheets, and APS Consolidated Statements of Cash Flows.
New Accounting Standards New Accounting Standards
 
ASU 2023-09, Income Taxes: Improvements to Income Tax Disclosures

In December 2023, a new accounting standard was issued that expands disclosures relating to income taxes. The expanded disclosures include a tabular income tax rate reconciliation, disclosure of specific reconciliation categories and reconciling items, the amount of income taxes paid by jurisdiction, and other disclosures. We adopted this standard on December 31, 2025, using a retrospective approach. The adoption of the new standard results in changes to our income tax disclosures, but did not impact our accounting for income taxes or our financial statement results. See Note 5.

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 2025-03, Business Combinations and Consolidation: Determining the Accounting Acquirer in the Acquisition of a Variable Interest Entity

In May 2025, a new accounting standard was issued that revises the guidance on identifying the accounting acquirer in a business combination in which the acquiree is a VIE that meets the definition of a business. Prior to the issuance of the amended guidance, for certain transactions, the primary beneficiary of the VIE was always required to be deemed the acquirer in the transaction. Under the amended guidance, an entity will now need to complete an assessment of the transaction to determine the acquiring entity and is no longer required to assume that the primary beneficiary is the acquirer in the transaction.

The standard will become effective for us on January 1, 2027, with early adoption permitted. We expect to adopt this guidance on January 1, 2027, and will apply the guidance prospectively to acquisition transactions occurring on and after the adoption date. Upon adoption, we do not expect the guidance will have a material impact on our financial statements. The adoption of this guidance will not impact the APS purchase transactions relating to the Palo Verde sale leaseback VIEs. See Note 12.

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 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.
v3.25.4
Summary of Significant Accounting Policies (Tables)
 12 Months Ended
Dec. 31, 2025
Accounting Policies [Abstract]  
Schedule of Property, Plant and Equipment
Pinnacle West’s property, plant and equipment included in the December 31, 2025, and 2024 Consolidated Balance Sheets is composed of the following (dollars in thousands):

Property, Plant and Equipment:20252024
Generation$9,687,466 $9,675,576 
Transmission4,451,936 4,135,970 
Distribution9,626,629 9,016,843 
Energy storage515,935 276,954 
Solar plant1,501,301 1,159,385 
General plant1,587,029 1,596,222 
Plant in service and held for future use27,370,296 25,860,950 
Accumulated depreciation and amortization(9,012,021)(9,027,426)
Net18,358,275 16,833,524 
Construction work in progress1,649,542 1,592,659 
Palo Verde sale leaseback, net of accumulated depreciation32,035 82,556 
Intangible assets, net of accumulated amortization575,978 591,310 
Nuclear fuel, net of accumulated amortization104,274 97,850 
Total property, plant and equipment$20,720,104 $19,197,899 
Schedule of Supplemental Cash Flow Information
The following table summarizes supplemental Pinnacle West cash flow information for each of the last three years (dollars in thousands):
Year Ended December 31,
202520242023
Cash paid during the period for:
Income taxes, net of refunds/credits$22,754 $133,968 $8,788 
Interest, net of amounts capitalized388,540 360,349 310,996 
Significant non-cash investing and financing activities:
Accrued capital expenditures$281,133 $257,494 $206,269 
Dividends accrued but not yet paid110,022 106,592 99,813 
BCE Sale non-cash consideration (Note 22)
— — 28,262 

The following table summarizes supplemental APS cash flow information for each of the last three years (dollars in thousands):
Year Ended December 31,
202520242023
Cash paid during the period for:
Income taxes, net of refunds/credits$53,638 $179,013 $21,734 
Interest, net of amounts capitalized307,520 299,799 267,261 
Significant non-cash investing and financing activities:
Accrued capital expenditures$281,133 $257,494 $206,269 
Dividends accrued but not yet paid110,000 107,200 99,800 
The following table presents the income taxes paid for Pinnacle West and APS on a retrospective basis (dollars in thousands):
Pinnacle West ConsolidatedAPS Consolidated
 Year Ended December 31,Year Ended December 31,
 202520242023202520242023
Federal$20,894 $112,870 $8,609 $30,207 $156,112 $21,438 
State1,860 128 179 23,431 22,901 296 
Total$22,754 $112,998 $8,788 $53,638 $179,013 $21,734 
    
State income taxes paid (net of refunds) exceed 5 percent of total income taxes paid (net of refunds) in the following jurisdictions (dollars in thousands):
Pinnacle West ConsolidatedAPS Consolidated
 Year Ended December 31,Year Ended December 31,
 202520242023202520242023
Arizona$2,000 $— (a)$— (a)$23,423 $22,788 $— (a)

(a)    Jurisdiction below the threshold for the period presented.
v3.25.4
Business Segments (Tables)
 12 Months Ended
Dec. 31, 2025
Segment Reporting [Abstract]  
Schedule of Reportable Segment’s Revenues, Significant Expenses, Net Income, and Assets
The following table reconciles our reportable segment’s revenues, significant expenses, and net income (loss) to the Pinnacle West consolidated amounts (dollars in millions):
Year Ended December 31,
202520242023
Regulated Electricity SegmentOtherPinnacle West ConsolidatedRegulated Electricity SegmentOtherPinnacle West ConsolidatedRegulated Electricity SegmentOther Pinnacle West Consolidated
Operating revenues$5,340 $— $5,340 $5,125 $— $5,125 $4,696 $— $4,696 
Fuel and purchased power (1,933)— (1,933)(1,823)— (1,823)(1,793)— (1,793)
Operations and maintenance(1,177)(8)(1,185)(1,159)(6)(1,165)(1,044)(15)(1,059)
Depreciation and amortization (915)— (915)(895)— (895)(794)— (794)
Taxes other than income taxes (235)— (235)(227)— (227)(224)— (224)
Allowance for equity funds used during construction61 — 61 39 — 39 53 — 53 
Pension and other postretirement non-service credits, net13 (1)12 49 — 49 42 (1)41 
Other income and (expense), net(14)30 16 (11)22 11 7 — 7 
Interest charges, net of allowance for borrowed funds used during construction(332)(90)(422)(312)(65)(377)(285)(46)(331)
Income taxes(126)19 (107)(127)16 (111)(94)17 (77)
Less: Net income attributable to noncontrolling interests(15)— (15)(17)— (17)(17)— (17)
Net Income (Loss) $667 $(50)$617 $642 $(33)$609 $547 $(45)$502 
The following table reconciles our reportable segment’s assets to the Pinnacle West consolidated amount (dollars in millions):
December 31, 2025December 31, 2024
Regulated Electricity SegmentOtherPinnacle West ConsolidatedRegulated Electricity SegmentOtherPinnacle West Consolidated
Total Assets$29,886 $146 $30,032 $25,988 $115 $26,103 
v3.25.4
Revenue (Tables)
 12 Months Ended
Dec. 31, 2025
Revenue from Contract with Customer [Abstract]  
Schedule of Disaggregation of Revenue
The following table provides detail of Pinnacle West’s consolidated revenues disaggregated by revenue sources (dollars in thousands):

Year Ended December 31,
202520242023
Retail Electric Service
Residential$2,541,320 $2,562,822 $2,289,196 
Non-Residential2,542,936 2,334,925 2,048,416 
Wholesale Energy Sales108,661 96,857 208,985 
Transmission Services for Others129,667 119,038 138,631 
Other Sources17,355 11,273 10,763 
Total Operating Revenues$5,339,939 $5,124,915 $4,695,991 
Schedule of Allowance for Doubtful Accounts
The following table provides a rollforward of Pinnacle West’s allowance for doubtful accounts (dollars in thousands):

Year Ended December 31,
202520242023
Balance at beginning of period$24,849 $22,433 $23,778 
Bad debt expense28,603 35,799 23,399 
Actual write-offs(27,957)(33,383)(24,744)
Balance at end of period$25,495 $24,849 $22,433 
v3.25.4
Income Taxes (Tables)
 12 Months Ended
Dec. 31, 2025
Income Tax Disclosure [Abstract]  
Schedule of Components of Income Tax Expense
The components of income tax expense are as follows (dollars in thousands):
Pinnacle West ConsolidatedAPS Consolidated
 Year Ended December 31,Year Ended December 31,
 202520242023202520242023
Current:   
Federal$87,913 $137,342 $21,272 $94,207 $165,653 $26,405 
State10,892 2,392 2,854 31,424 26,054 1,027 
Total current98,805 139,734 24,126 125,631 191,707 27,432 
Deferred:
Federal(11,073)(53,228)37,273 (2,902)(69,075)44,922 
State18,994 24,023 15,513 3,190 4,361 21,830 
Total deferred7,921 (29,205)52,786 288 (64,714)66,752 
Income tax expense
106,726 110,529 76,912 125,919 126,993 94,184 
Schedule of Comparison of Pretax Income from Federal Income Tax Rate to Income Tax Expense
The following table compares Pinnacle West Consolidated pretax income at the 21% statutory federal income tax rate to income tax expense (dollars in thousands) and effective tax rates:
Pinnacle West Consolidated
 Year Ended December 31,
202520242023
 AmountPercentAmountPercentAmountPercent
Income before income taxes (a)$738,369 $736,559 $595,693 
Federal income tax expense at statutory rate155,057 21.00 %154,677 21.00 %125,095 21.00 %
State income tax net of federal income tax benefit (b)23,610 3.20 %23,735 3.22 %17,832 2.99 %
Changes in Valuation Allowance— — %— — %— — %
Nontaxable or Nondeductible Items
Share based compensation(4,062)(0.55)%(421)(0.06)%1,346 0.23 %
Palo Verde VIE noncontrolling interest (Note 12)
(3,173)(0.43)%(3,617)(0.49)%(3,617)(0.61)%
Other Nontaxable or Nondeductible Items5,896 0.80 %3,667 0.50 %2,405 0.40 %
Effect of changes in tax laws or rates enacted in the current period— — %— — %— — %
Tax Credits
Solar or Wind Production Tax Credit(14,698)(1.99)%(15,206)(2.07)%(8,441)(1.42)%
Other Federal Income Tax Credits(19)— %(242)(0.03)%(650)(0.11)%
Investment credit amortization – deferral method(12,625)(1.71)%(9,425)(1.28)%(9,495)(1.59)%
Changes in Unrecognized Tax Benefits1,523 0.21 %(28)— %(1,961)(0.33)%
Effects of Utility Ratemaking
Excess deferred income taxes — Tax Cuts and Jobs Act(36,558)(4.95)%(36,559)(4.96)%(36,558)(6.14)%
Allowance for equity funds used during construction (Note 1)
(7,005)(0.95)%(2,545)(0.35)%(5,964)(1.00)%
Other regulatory amortization(2,758)(0.38)%(1,796)(0.24)%(1,828)(0.31)%
Other Adjustments1,538 0.20 %(1,711)(0.23)%(1,252)(0.20)%
Income tax expense
$106,726 14.45 %$110,529 15.01 %$76,912 12.91 %
(a)     Income before income taxes is from continuing operations and is entirely domestic.
(b)     The State of Arizona makes up the majority (greater than 50 percent) of the effect of the state and local income tax category.
The following table compares APS Consolidated pretax income at the 21% statutory federal income tax rate to income tax expense (dollars in thousands) and effective tax rates:
APS Consolidated
 Year Ended December 31,
202520242023
 AmountPercentAmountPercentAmountPercent
Income before income taxes (a)$808,346 $786,142 $658,745 
Federal income tax expense at statutory rate169,753 21.00 %165,090 21.00 %138,337 21.00 %
State income tax net of federal income tax benefit (b)27,345 3.38 %26,824 3.41 %21,453 3.26 %
Changes in Valuation Allowance— — %— — %— — %
Nontaxable or Nondeductible Items
Share based compensation(2,482)(0.31)%23 — %997 0.15 %
Palo Verde VIE noncontrolling interest (Note 12)
(3,173)(0.39)%(3,617)(0.46)%(3,617)(0.55)%
Other Nontaxable or Nondeductible Items1,727 0.21 %694 0.09 %263 0.04 %
Effect of changes in tax laws or rates enacted in the current period— — %— — %— — %
Tax Credits
Solar or Wind Production Tax Credit(11,254)(1.39)%(12,110)(1.54)%(5,460)(0.83)%
Other Federal Income Tax Credits(19)— %(242)(0.03)%(650)(0.10)%
Investment credit amortization – deferral method(12,625)(1.56)%(9,425)(1.20)%(9,495)(1.44)%
Changes in Unrecognized Tax Benefits1,483 0.18 %(107)(0.01)%(1,946)(0.30)%
Effects of Utility Ratemaking
Excess deferred income taxes — Tax Cuts and Jobs Act(36,558)(4.52)%(36,559)(4.65)%(36,558)(5.55)%
Allowance for equity funds used during construction (Note 1)
(7,005)(0.87)%(2,545)(0.32)%(5,964)(0.91)%
Other regulatory amortization(2,758)(0.34)%(1,796)(0.23)%(1,828)(0.28)%
Other Adjustments1,485 0.19 %763 0.09 %(1,348)(0.19)%
Income tax expense
$125,919 15.58 %$126,993 16.15 %$94,184 14.30 %
(a)     Income before income taxes is from continuing operations and is entirely domestic.
(b)     The State of Arizona makes up the majority (greater than 50 percent) of the effect of the state and local income tax category.
Schedule of Income Taxes Paid
The following table summarizes supplemental Pinnacle West cash flow information for each of the last three years (dollars in thousands):
Year Ended December 31,
202520242023
Cash paid during the period for:
Income taxes, net of refunds/credits$22,754 $133,968 $8,788 
Interest, net of amounts capitalized388,540 360,349 310,996 
Significant non-cash investing and financing activities:
Accrued capital expenditures$281,133 $257,494 $206,269 
Dividends accrued but not yet paid110,022 106,592 99,813 
BCE Sale non-cash consideration (Note 22)
— — 28,262 

The following table summarizes supplemental APS cash flow information for each of the last three years (dollars in thousands):
Year Ended December 31,
202520242023
Cash paid during the period for:
Income taxes, net of refunds/credits$53,638 $179,013 $21,734 
Interest, net of amounts capitalized307,520 299,799 267,261 
Significant non-cash investing and financing activities:
Accrued capital expenditures$281,133 $257,494 $206,269 
Dividends accrued but not yet paid110,000 107,200 99,800 
The following table presents the income taxes paid for Pinnacle West and APS on a retrospective basis (dollars in thousands):
Pinnacle West ConsolidatedAPS Consolidated
 Year Ended December 31,Year Ended December 31,
 202520242023202520242023
Federal$20,894 $112,870 $8,609 $30,207 $156,112 $21,438 
State1,860 128 179 23,431 22,901 296 
Total$22,754 $112,998 $8,788 $53,638 $179,013 $21,734 
    
State income taxes paid (net of refunds) exceed 5 percent of total income taxes paid (net of refunds) in the following jurisdictions (dollars in thousands):
Pinnacle West ConsolidatedAPS Consolidated
 Year Ended December 31,Year Ended December 31,
 202520242023202520242023
Arizona$2,000 $— (a)$— (a)$23,423 $22,788 $— (a)

(a)    Jurisdiction below the threshold for the period presented.
Schedule of Unrecognized Tax Benefits Roll Forward
The following is a tabular reconciliation of the total amounts of unrecognized tax benefits, excluding interest and penalties, at the beginning and end of the year that are included in accrued taxes and unrecognized tax benefits (dollars in thousands):

Pinnacle West ConsolidatedAPS Consolidated
 202520242023202520242023
Total unrecognized tax benefits, January 1$44,349 $44,274 $43,097 $44,349 $44,274 $43,097 
Additions for tax positions of the current year81,286 1,271 1,473 81,286 1,271 1,473 
Additions for tax positions of prior years2,818 2,031 419 2,818 2,031 419 
Reductions for tax positions of prior years for:000000
Changes in judgment(2,044)(2,043)661 (2,044)(2,043)661 
Settlements with taxing authorities— — — — — — 
Lapses of applicable statute of limitations(970)(1,184)(1,376)(970)(1,184)(1,376)
Total unrecognized tax benefits, December 31$125,439 $44,349 $44,274 $125,439 $44,349 $44,274 
Schedule of Unrecognized Tax Benefits
Included in the balances of unrecognized tax benefits are the following tax positions that, if recognized, would decrease our effective tax rate (dollars in thousands):

Pinnacle West ConsolidatedAPS Consolidated
 202520242023202520242023
Tax positions, that if recognized, would decrease our effective tax rate$103,785 $27,899 $28,762 $103,785 $27,899 $28,762 
The amount of interest expense or benefit recognized related to unrecognized tax benefits are as follows (dollars in thousands):
Pinnacle West ConsolidatedAPS Consolidated
 202520242023202520242023
Unrecognized tax benefit interest expense recognized
$3,610 $2,743 $452 $3,610 $2,743 $452 

Following are the total amounts of accrued liabilities for interest recognized related to unrecognized benefits that could reverse and decrease our effective tax rate to the extent matters are settled favorably (dollars in thousands):

Pinnacle West ConsolidatedAPS Consolidated
 202520242023202520242023
Unrecognized tax benefit interest accrued $7,986 $4,376 $1,633 $7,986 $4,376 $1,633 
Schedule of Components of the Net Deferred Income Tax Liability
The components of the net deferred income tax liability were as follows (dollars in thousands):

Pinnacle West ConsolidatedAPS Consolidated
 December 31,December 31,
 2025202420252024
DEFERRED TAX ASSETS 
Risk management activities$8,422 $14,539 $8,422 $14,539 
Regulatory liabilities:
Excess deferred income taxes — Tax Cuts and Jobs Act259,000 271,004 259,000 271,004 
Asset retirement obligation and removal costs66,031 81,308 66,031 81,308 
Unamortized investment tax credits81,949 66,327 81,949 66,327 
Other postretirement benefits57,833 58,862 57,833 58,862 
Other50,611 47,671 50,611 47,671 
Operating lease liabilities923,774 400,771 923,479 400,442 
Pension liabilities46,613 39,070 43,422 36,100 
Coal reclamation liabilities39,450 42,391 39,450 42,391 
Renewable energy incentives11,908 14,571 11,908 14,571 
Credit and loss carryforwards— 7,682 — — 
Employee benefit liabilities56,447 57,853 55,243 56,561 
Other49,098 44,412 49,098 44,412 
Total deferred tax assets1,651,136 1,146,461 1,646,446 1,134,188 
DEFERRED TAX LIABILITIES   
Plant-related(2,595,668)(2,562,990)(2,595,668)(2,562,990)
Risk management activities(2,072)(4,089)(2,072)(4,089)
Pension and other postretirement assets(97,557)(83,401)(96,988)(82,925)
Other special use funds(58,175)(55,146)(58,175)(55,146)
Operating lease right-of-use assets(923,774)(400,771)(923,479)(400,443)
Regulatory assets:
Allowance for equity funds used during construction(50,402)(47,694)(50,402)(47,694)
Deferred fuel and purchased power(45,504)(84,393)(45,504)(84,393)
Pension benefits(178,736)(185,641)(178,736)(185,641)
Ocotillo deferral(24,703)(28,372)(24,703)(28,372)
SCR deferral(19,080)(20,548)(19,080)(20,548)
Retired power plant costs (13,157)(16,904)(13,157)(16,904)
Other(58,822)(57,602)(58,822)(57,602)
Other(54,418)(43,383)(7,425)(7,378)
Total deferred tax liabilities(4,122,068)(3,590,934)(4,074,211)(3,554,125)
Deferred income taxes — net$(2,470,932)$(2,444,473)$(2,427,765)$(2,419,937)
v3.25.4
Lines of Credit and Short-Term Borrowings (Tables)
 12 Months Ended
Dec. 31, 2025
Debt Disclosure [Abstract]  
Schedule of Consolidated Credit Facilities and Amounts Available and Outstanding
The table below presents the consolidated credit and term loan facilities and the amounts available and outstanding (dollars in thousands): 
December 31, 2025December 31, 2024
Pinnacle West ConsolidatedAPS ConsolidatedTotalPinnacle West ConsolidatedAPS ConsolidatedTotal
Commitments under Revolving Credit and Term Loan Facilities$375,000 $1,250,000 $1,625,000 $400,000 $1,650,000 $2,050,000 
Outstanding short-term borrowings(249,700)(507,305)(757,005)(228,550)(339,900)(568,450)
Amount available under Revolving Credit and Term Loan Facilities$125,300 $742,695 $867,995 $171,450 $1,310,100 $1,481,550 
Weighted-Average Commitment Fees0.225%0.175%0.225%0.175%
v3.25.4
Long-Term Debt and Liquidity Matters (Tables)
 12 Months Ended
Dec. 31, 2025
Debt Disclosure [Abstract]  
Schedule of Components of Long-Term Debt on the Consolidated Balance Sheets The following table presents the components of long-term debt on the Consolidated Balance Sheets outstanding (dollars in thousands):
 MaturityInterestDecember 31,
 Dates (a)Rates20252024
APS    
Pollution control bonds:    
Variable2029(b)$163,975 $163,975 
Total pollution control bonds  163,975 163,975 
Senior unsecured notes2026-2055
2.20%-6.88%
8,030,000 7,380,000 
Unamortized discount  (16,796)(14,252)
Unamortized premium  17,144 9,955 
Unamortized debt issuance cost(54,383)(48,800)
Total APS long-term debt  8,139,940 7,490,878 
Less current maturities 250,000 300,000 
Total APS long-term debt less current maturities  7,889,940 7,190,878 
Pinnacle West    
Senior unsecured notes2027-2030
4.75%-5.15%
1,325,000 1,025,000 
Floating rate note2026(c)350,000 350,000 
Unamortized discount(681)(5)
Unamortized debt issuance cost(8,583)(7,225)
Total Pinnacle West long-term debt1,665,736 1,367,770 
Less current maturities350,000 500,000 
Total Pinnacle West long-term debt less current maturities1,315,736 867,770 
TOTAL LONG-TERM DEBT LESS CURRENT MATURITIES
$9,205,676 $8,058,648 
(a)    This schedule does not reflect the timing of redemptions that may occur prior to scheduled maturity.
(b)    The weighted-average interest rate for the variable rate pollution control bonds was 3.52% at December 31, 2025, and 4.01% at December 31, 2024.
(c)    The weighted-average interest rate was 5.10% at December 31, 2025, and was 5.88% at December 31, 2024. See additional details below.
Schedule of Principal Payments Due on Pinnacle West's and APS's Total Long-Term Debt
The following table shows principal payments due on Pinnacle West’s and APS’s total long-term debt (dollars in thousands):
YearPinnacle West ConsolidatedAPS Consolidated
2026$600,000 $250,000 
2027825,000 300,000 
2028400,000 — 
2029568,975 568,975 
2030400,000 — 
Thereafter7,075,000 7,075,000 
Total$9,868,975 $8,193,975 
Schedule of Estimated Fair Value of Long-Term Debt, Including Current Maturities The following table represents the estimated fair value of our long-term debt, including current maturities (dollars in thousands):
 As of December 31, 2025As of December 31, 2024
 Carrying
Amount		Fair ValueCarrying
Amount		Fair Value
Pinnacle West$1,665,736 $1,731,388 $1,367,770 $1,393,744 
APS8,139,940 7,433,142 7,490,878 6,525,248 
Total$9,805,676 $9,164,530 $8,858,648 $7,918,992 
v3.25.4
Regulatory Matters (Tables)
 12 Months Ended
Dec. 31, 2025
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):
 Year Ended December 31,
 20252024
Balance at beginning of period$287,597 $463,195 
Deferred fuel and purchased power costs324,482 250,288 
Amounts charged to customers
(463,011)(425,886)
Balance at end of period$149,068 $287,597 
Schedule of Regulatory Assets
The detail of regulatory assets is as follows (dollars in thousands):
Amortization ThroughDecember 31,
2025		December 31,
2024
Pension(a)$723,042 $750,976 
Income taxes — AFUDC equity2054203,890 192,936 
Palo Verde sale leaseback noncontrolling interests’ acquisition (b)N/A151,506 — 
Deferred fuel and purchased power (c) (d)2026149,068 287,597 
Ocotillo deferral203499,931 114,775 
Lease incentive (Note 20)
204590,005 70,541 
SCR deferral (c)203877,186 83,123 
Retired power plant costs203156,809 68,380 
Income taxes — investment tax credit basis adjustment (Note 5)
205642,459 34,834 
Deferred compensation203632,204 33,108 
Deferred fuel and purchased power — mark-to-market (Note 13)
202629,330 42,275 
FERC transmission true up202721,471 35,159 
DSM (c)202515,706 — 
Deferred property taxes202715,349 23,918 
Palo Verde VIEs (Note 12)
20468,582 20,611 
Mead-Phoenix transmission line — contributions in aid of construction20508,052 8,384 
PSA - interest20265,679 11,525 
Loss on reacquired debt20385,653 6,682 
TEAM (c)20313,879 4,534 
Active union medical trust(e)3,696 9,673 
Navajo coal reclamation20262,516 7,905 
OtherVarious3,353 3,522 
Total regulatory assets (f)$1,749,366 $1,810,458 
Less: current regulatory assets$286,009 $420,969 
Total non-current regulatory assets$1,463,357 $1,389,489 
(a)This asset represents the future recovery of pension benefit obligations and expense through retail rates.  If these costs are disallowed by the ACC, this regulatory asset would be charged to other comprehensive income/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 9 for further discussion.
(b)This asset relates to the acquisition of previously leased interest in Palo Verde Unit 2. See Note 12.
(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, TCA, and Other Transmission Matters.”
Schedule of Regulatory Liabilities
The detail of regulatory liabilities is as follows (dollars in thousands):
Amortization ThroughDecember 31,
2025		December 31,
2024
Excess deferred income taxes - ACC — Tax Cuts and Jobs Act (a)2046$847,572 $888,896 
Excess deferred income taxes - FERC — Tax Cuts and Jobs Act (a)2058200,161 207,400 
AROs and removal costs(b)286,907 358,403 
Other postretirement benefits(c)233,952 238,113 
Four Corners coal reclamation203897,988 77,532 
Income taxes — deferred investment tax credit205681,949 66,327 
Income taxes — change in rates205456,260 59,133 
RES (d)202654,551 68,523 
DSM (d)202526,228 23,927 
Sundance maintenance203125,668 23,086 
Spent nuclear fuel202720,492 26,818 
TCA Balancing Account (d)20274,860 14,834 
TEAM (d) 20323,738 4,343 
Deferred fuel and purchased power — mark-to-market (Note 13)
20283,641 — 
OtherVarious3,063 4,898 
Total regulatory liabilities$1,947,030 $2,062,233 
Less: current regulatory liabilities$210,909 $206,955 
Total non-current regulatory liabilities$1,736,121 $1,855,278 
(a)For purposes of presentation on the Statements of Cash Flows, amortization of the regulatory liabilities for excess deferred income taxes are reflected as “Deferred income taxes” under Cash Flows From Operating Activities.
(b)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 9.
(d)See “Cost Recovery Mechanisms” discussion above.
v3.25.4
Retirement Plans and Other Postretirement Benefits (Tables)
 12 Months Ended
Dec. 31, 2025
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
 202520242023202520242023
Service cost-benefits earned during the period$44,153 $43,641 $39,461 $8,081 $9,955 $8,567 
Non-service costs (credits):
Interest cost on benefit obligation155,121 148,643 153,561 20,345 22,169 22,509 
Expected return on plan assets(178,793)(188,651)(182,938)(48,569)(46,834)(43,486)
Amortization of:
Prior service credit (a)— — — (1,265)(37,789)(37,789)
Net actuarial loss (gain)
46,731 41,915 38,420 (11,727)(8,676)(9,614)
Net periodic benefit costs (credits)
$67,212 $45,548 $48,504 $(33,135)$(61,175)$(59,813)
Portion of costs (credits) charged to expense
$38,977 $23,652 $27,029 $(25,736)$(45,557)$(43,408)
(a)    Prior-service costs or credits reflect the impact of modifications to the pension or postretirement plan benefits. The impact of these modifications is amortized over a period which reflects the demographics of the impacted population. In 2014, Pinnacle West made changes to the postretirement benefits offered to Medicare eligible retirees which resulted in prior-service credits. We have been amortizing these prior-serviced credits since 2015, and they became fully amortized as of January 31, 2025.
Schedule of Changes in the Benefit Obligations and Funded Status
The following table shows the plans’ changes in the benefit obligations and funded status (dollars in thousands):
 Pension PlansOther Benefits Plans
 2025202420252024
Change in Benefit Obligation    
Benefit obligation at January 1$2,792,309 $2,908,063 $360,090 $430,434 
Service cost44,153 43,641 8,081 9,955 
Interest cost155,121 148,643 20,345 22,169 
Benefit payments(226,888)(216,238)(28,293)(30,516)
Actuarial (gain) loss79,363 (91,800)7,759 (71,952)
Other plan changes6,752 — — — 
Benefit obligation at December 312,850,810 2,792,309 367,982 360,090 
Change in Plan Assets    
Fair value of plan assets at January 12,639,862 2,835,549 702,192 696,494 
Actual return on plan assets244,343 4,518 65,124 32,816 
Benefit payments(213,684)(200,205)— (27,118)
Fair value of plan assets at December 312,670,521 2,639,862 767,316 702,192 
Funded (Underfunded) Status at December 31$(180,289)$(152,447)$399,334 $342,102 
Schedule of Projected Benefit Obligation and the Accumulated Benefit Obligation for Pension Plans with an Accumulated Obligation in Excess of Plan Assets
The following table shows information for pension plans with an accumulated obligation in excess of plan assets (dollars in thousands):
As of December 31,
 20252024
Accumulated benefit obligation$113,245 $113,541 
Fair value of plan assets— — 
The following table shows information for pension plans with a projected benefit obligation in excess of plan assets (dollars in thousands):
As of December 31,
 20252024
Projected benefit obligation$2,850,810 $2,792,309 
Fair value of plan assets2,670,521 2,639,862 
Schedule of Amounts Recognized on the Consolidated Balance Sheets
The following table shows the amounts recognized on the Consolidated Balance Sheets (dollars in thousands):
 Pension PlansOther Benefits Plans
 2025202420252024
Noncurrent asset$— $— $399,334 $342,102 
Current liability(12,653)(13,130)— — 
Noncurrent liability(167,636)(139,317)— — 
Net amount recognized (funded status)$(180,289)$(152,447)$399,334 $342,102 
Schedule of Accumulated Other Comprehensive Loss
The following table shows the details related to accumulated other comprehensive loss (gain) as of December 31, 2025, and 2024 (dollars in thousands): 
 Pension PlansOther Benefits Plans
 2025202420252024
Net actuarial loss (gain)$760,502 $793,421 $(234,958)$(237,889)
Prior service cost (credit)6,752 — — (1,265)
APS’s portion recorded as a regulatory (asset) liability(723,042)(750,976)233,952 238,113 
Income tax expense (benefit)(10,929)(10,354)703 611 
Accumulated other comprehensive loss (gain)$33,283 $32,091 $(303)$(430)
Schedule of Weighted-Average Assumptions Used for Both the Pension and Other Benefits to Determine Benefit Obligations and Net Periodic Benefit Costs
The following table shows the weighted-average assumptions used for both the pension and other benefits to determine benefit obligations and net periodic benefit costs:
 Benefit Obligations
As of December 31,		Benefit Costs
Year Ended December 31,
 20252024202520242023
Discount rate – pension plans5.36 %5.68 %5.68 %5.21 %5.56 %
Discount rate – other benefits plans5.43 %5.71 %5.71 %5.23 %5.58 %
Rate of compensation increase4.50 %4.50 %4.50 %4.52 %4.57 %
Expected long-term return on plan assets - pension plansN/AN/A7.05 %6.90 %6.70 %
Expected long-term return on plan assets - other benefit plansN/AN/A7.05 %6.85 %6.80 %
Initial healthcare cost trend rate (pre-65 participants)6.50 %6.50 %6.50 %6.25 %6.50 %
Ultimate healthcare cost trend rate (pre-65 participants)4.50 %4.50 %4.50 %4.75 %4.75 %
Number of years to ultimate trend rate (pre-65 participants)76645
Initial healthcare cost trend rate (post-65 participants) (a)N/A1.00 %1.00 %2.00 %2.00 %
Ultimate healthcare cost trend rate (post-65 participants) (a)N/A— %N/A2.00 %2.00 %
Interest crediting rate – cash balance pension plans4.51 %4.66 %4.66 %4.54 %4.50 %
(a) The Company has decided and has communicated to retirees that the increase in 2026 will be 1% with no further indexation in future years. Therefore, no assumption is being made for the Post-65 HRA subsidy trend rate.
Schedule of Fair Value of Pension Plan and Other Postretirement Benefit Plan Assets, by Asset Category
Based on the IPS, the target and actual allocation for the pension plan at December 31, 2025, are as follows:
 Target AllocationActual Allocation
Long-term fixed income assets80 %78 %
Return-seeking assets20 %22 %
Total100 %100 %
The following table presents the additional target allocations, as a percent of total pension plan assets, for the return-seeking assets:
Target Allocation
Equities in US and other developed markets12 %
Equities in emerging markets4 %
Alternative investments4 %
Total20 %
The following table presents the actual allocations of the investment for the other postretirement benefit plan at December 31, 2025:
Actual Allocation
Long-term fixed income assets59 %
Return-seeking assets41 %
Total100 %
The fair value of Pinnacle West’s pension plan and other postretirement benefit plan assets at December 31, 2025, by asset category, are as follows (dollars in thousands):
 
 Level 1Level 2Other (a)Total
Pension Plan:   
Cash and cash equivalents$1,756 $— $— $1,756 
Fixed income securities:   
Corporate— 1,300,163 — 1,300,163 
U.S. Treasury607,621 — — 607,621 
Other (b)— 120,483 — 120,483 
Common stock equities (c)73,548 — — 73,548 
Mutual funds (d)115,478 — — 115,478 
Common and collective trusts:
Equities— — 266,624 266,624 
Real estate— — 114,782 114,782 
Other (e)— — 70,066 70,066 
Total$798,403 $1,420,646 $451,472 $2,670,521 
Other Benefits:    
Cash and cash equivalents$475 $— $— $475 
Fixed income securities:   
Corporate— 200,469 — 200,469 
U.S. Treasury165,294 — — 165,294 
Other (b)— 10,997 — 10,997 
Common stock equities (c)98,296 — — 98,296 
Mutual funds (d)27,986 — — 27,986 
Common and collective trusts:   
Equities— — 167,103 167,103 
Real estate— — 20,228 20,228 
Other (e)69,954 — 6,514 76,468 
Total$362,005 $211,466 $193,845 $767,316 
(a)These investments primarily represent assets valued using NAV as a practical expedient and have not been classified in the fair value hierarchy.
(b)This category consists primarily of debt securities issued by municipalities and asset backed securities.
(c)This category primarily consists of U.S. common stock equities.
(d)These funds invest in international common stock equities.
(e)Primarily relates to short-term investment funds and includes plan receivables and payables.
The fair value of Pinnacle West’s pension plan and other postretirement benefit plan assets at December 31, 2024, by asset category, are as follows (dollars in thousands):
 Level 1Level 2Other (a)Total
Pension Plan:   
Cash and cash equivalents$9,055 $— $— $9,055 
Fixed income securities:   
Corporate— 1,325,833 — 1,325,833 
U.S. Treasury561,317 — — 561,317 
Other (b)— 133,254 — 133,254 
Common stock equities (c)74,939 — — 74,939 
Mutual funds (d)102,722 — — 102,722 
Common and collective trusts:
   Equities— — 244,734 244,734 
   Real estate— — 127,397 127,397 
Other (e)— — 60,611 60,611 
Total $748,033 $1,459,087 $432,742 $2,639,862 
Other Benefits:    
Cash and cash equivalents$840 $— $— $840 
Fixed income securities:   
Corporate— 186,435 — 186,435 
U.S. Treasury204,274 — — 204,274 
Other (b)— 12,585 — 12,585 
Common stock equities (c)89,685 — — 89,685 
Mutual funds (d)23,415 — — 23,415 
Common and collective trusts:
   Equities— — 140,178 140,178 
   Real estate— — 19,474 19,474 
Other (e)19,145 — 6,161 25,306 
Total $337,359 $199,020 $165,813 $702,192 
(a)These investments primarily represent assets valued using NAV as a practical expedient and have not been classified in the fair value hierarchy.
(b)This category consists primarily of debt securities issued by municipalities and asset backed securities.
(c)This category primarily consists of U.S. common stock equities.
(d)These funds invest in U.S. and international common stock equities.
(e)Primarily relates to short-term investment funds and includes plan receivables and payables.
Schedule of Estimated Future Benefit Payments, which Reflect Estimated Future Employee Service, for the Next Five Years and the Succeeding Five Years Thereafter
Benefit payments, which reflect estimated future employee service, for the next five years and the succeeding five years thereafter, are estimated to be as follows (dollars in thousands):
YearPension PlansOther Benefits Plans
2026$244,947 $28,075 
2027232,977 27,751 
2028235,256 27,443 
2029235,980 27,357 
2030235,953 27,206 
Years 2031-20351,149,488 137,689 
v3.25.4
Stock-Based Compensation (Tables)
 12 Months Ended
Dec. 31, 2025
Share-Based Payment Arrangement [Abstract]  
Schedule of Restricted Stock Units, Stock Grants and Stock Units
The following table is a summary of awards granted and the weighted-average grant date fair value for each of the last 3 years:
Restricted Stock Units, Stock Grants, and Stock Units (a)Performance Shares (b)
 202520242023202520242023
Units granted204,886 261,808 192,295 164,220 225,516 202,562 
Weighted-average grant date fair value$90.25 $71.10 $74.32 $97.72 $72.89 $79.61 
(a)The units granted do not include awards that will be cash settled in 2025, 2024 or 2023. See below for additional information on restricted stock unit grants.
(b)Reflects the target payout level.
Schedule of Nonvested Performance Shares
The following table shows the change of nonvested awards:

Restricted Stock Units, Stock Grants, and Stock UnitsPerformance Shares
SharesWeighted-Average
Grant Date
Fair Value		Shares (b)Weighted-Average
Grant Date
Fair Value
Nonvested at December 31, 2024
460,791 $71.72 390,551 $77.29 
Granted204,886 90.25 164,220 97.72 
Vested(186,883)73.77 (169,682)77.94 
Forfeited (c)(15,856)79.59 (13,535)85.01 
Nonvested at December 31, 2025
462,938 (a)78.82 371,554 83.48 
Vested Awards Outstanding at December 31, 2025
76,758 169,682 
(a)Includes no awards that will be cash settled.
(b)The performance shares are reflected at target payout level. 
(c)We account for forfeitures as they occur.
v3.25.4
Jointly-Owned Facilities (Tables)
 12 Months Ended
Dec. 31, 2025
Jointly Owned Utility Plant, Net Ownership Amount [Abstract]  
Schedule Of APS's Interests In Jointly-owned Facilities Recorded On The Consolidated Balance Sheets The following table shows APS’s interests in those jointly-owned facilities recorded on the Consolidated Balance Sheets at December 31, 2025 (dollars in thousands):
 Percent
Owned		 Plant in
Service		Accumulated
Depreciation		Construction
Work in
Progress
Generating facilities:     
Palo Verde Units 1 and 329.1 %$2,094,060 $1,079,823 $13,230 
Palo Verde Unit 2 (a)23.9 %925,562 567,731 7,343 
Palo Verde Common26.2 %(b)977,526 431,023 58,899 
Palo Verde sale leaseback (a) 142,921 110,886 — 
Four Corners Generating Station 63.0 %1,941,053 747,931 19,378 
Transmission facilities:     
Arizona Nuclear Power Project 500kV System33.1 %(b)141,348 60,579 5,350 
Navajo Southern System25.1 %(b)89,856 40,548 1,645 
Palo Verde — Yuma 500kV System16.1 %(b)44,505 9,060 136 
Four Corners Switchyards56.9 %(b)86,706 25,810 118 
Phoenix — Mead System17.5 %(b)36,290 19,568 609 
Palo Verde — Rudd 500kV System50.0 %96,428 35,842 3,343 
Morgan — Pinnacle Peak System63.2 %(b)119,104 31,283 75 
Round Valley System50.0 %548 224 — 
Palo Verde — Morgan System87.5 %(b)268,202 52,822 392 
Hassayampa — North Gila System80.0 %154,329 31,361 — 
Cholla 500kV Switchyard85.7 %8,456 3,114 190 
Saguaro 500kV Switchyard60.0 %42,795 16,324 800 
Kyrene — Knox System50.0 %578 359 — 
(a)See Note 12 for information related to the Palo Verde sale leaseback purchases.
(b)Weighted-average of interests.
v3.25.4
Variable Interest Entities (Tables)
 12 Months Ended
Dec. 31, 2025
Variable Interest Entities [Abstract]  
Schedule of Amounts Relating to the VIEs Included in Consolidated Balance Sheets
Our Consolidated Balance Sheets include the following amounts relating to these VIEs (dollars in thousands):
 December 31, 2025
December 31, 2024 (a)
Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation$32,035 $82,556 
Equity — Noncontrolling interests40,617 103,167 
(a)    Includes the two VIEs subject to the September 2025 purchase transactions described above.
v3.25.4
Derivative Accounting (Tables)
 12 Months Ended
Dec. 31, 2025
Derivative Instruments and Hedging Activities Disclosure [Abstract]  
Schedule of Outstanding Gross Notional Amount of Derivatives, which Represents Both Purchases and Sales
The following table shows the outstanding gross notional volume of energy derivatives, which represent both purchases and sales (does not reflect net position):
Quantity
CommodityUnit of MeasureDecember 31, 2025December 31, 2024
PowerGigawatt-hour542 1,051 
GasBillion cubic feet211 235 
Schedule of Gains and Losses from Derivative Instruments Not Designated as Accounting Hedges Instruments The following table provides information about gains and losses from energy derivative instruments not designated as accounting hedging instruments (dollars in thousands):
Financial Statement Year Ended December 31,
Commodity ContractsLocation202520242023
Net Loss Recognized in Income
Fuel and purchased power (a)$(50,566)$(88,522)$(370,145)
(a)Amounts are before the effect of PSA deferrals.
Schedule of the Entity's Fair Value of Risk Management Activities Reported on a Gross Basis and the Impacts on Offsetting Liabilities
The following tables provide information about the fair value of APS’s risk management activities reported on a gross basis and the impacts of offsetting.  These amounts relate to commodity contracts and are located in the assets and liabilities from risk management activities lines of APS’s Consolidated Balance Sheets (dollars in thousands):
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.
As of December 31, 2024Gross
 Recognized
 Derivatives
 (a)		Amounts
Offset 
(b)		Net
 Recognized
 Derivatives		Other
 (c)		Amounts
 Reported on
 Balance Sheets
Current assets$13,718 $(3,158)$10,560 $18 $10,578 
Investments and other assets6,610 (630)5,980 — 5,980 
Total assets20,328 (3,788)16,540 18 16,558 
Current liabilities(52,527)3,158 (49,369)(2,971)(52,340)
Deferred credits and other(10,076)630 (9,446)— (9,446)
Total liabilities(62,603)3,788 (58,815)(2,971)(61,786)
Total$(42,275)$— $(42,275)$(2,953)$(45,228)
(a)All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)No cash collateral has been provided to 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 $2,971 thousand and cash margin provided to counterparties of $18 thousand.
Schedule of the Entity's Fair Value of Risk Management Activities Reported on a Gross Basis and the Impacts on Offsetting Assets
The following tables provide information about the fair value of APS’s risk management activities reported on a gross basis and the impacts of offsetting.  These amounts relate to commodity contracts and are located in the assets and liabilities from risk management activities lines of APS’s Consolidated Balance Sheets (dollars in thousands):
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.
As of December 31, 2024Gross
 Recognized
 Derivatives
 (a)		Amounts
Offset 
(b)		Net
 Recognized
 Derivatives		Other
 (c)		Amounts
 Reported on
 Balance Sheets
Current assets$13,718 $(3,158)$10,560 $18 $10,578 
Investments and other assets6,610 (630)5,980 — 5,980 
Total assets20,328 (3,788)16,540 18 16,558 
Current liabilities(52,527)3,158 (49,369)(2,971)(52,340)
Deferred credits and other(10,076)630 (9,446)— (9,446)
Total liabilities(62,603)3,788 (58,815)(2,971)(61,786)
Total$(42,275)$— $(42,275)$(2,953)$(45,228)
(a)All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)No cash collateral has been provided to 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 $2,971 thousand and cash margin provided to counterparties of $18 thousand.
Schedule of Information about Derivative Instruments that have Credit-Risk-Related Contingent Features
The following table provides information about our energy derivative instruments that have credit-risk-related contingent features (dollars in thousands):
 December 31, 2025
Aggregate fair value of derivative instruments in a net liability position$45,035 
Additional collateral in the event credit-risk related contingent features were fully triggered (a)11,171 
(a)This amount is after counterparty netting and includes those contracts which qualify for scope exceptions, which are excluded from the derivative details above.
v3.25.4
Commitments and Contingencies (Tables)
 12 Months Ended
Dec. 31, 2025
Commitments and Contingencies Disclosure [Abstract]  
Schedule of Estimated Coal Take-or-pay Commitments
The following table summarizes our estimated coal take-or-pay commitments (dollars in thousands):
 
Year Ended December 31,
 20262027202820292030Thereafter (b)
Coal take-or-pay commitments (a)$206,489 $206,813 $213,825 $221,098 $228,639 $236,461 
(a)Total take-or-pay commitments are approximately $1.3 billion.  The total net present value of these commitments using a 4.81% discount rate is approximately $1.1 billion.
(b)Through 2031.
Schedule of Actual Take-or-pay Commitments The following table summarizes actual amounts purchased under the coal contracts which include take-or-pay provisions for each of the last three years (dollars in thousands):
 
Year Ended December 31,
 202520242023
Total purchases$213,113 $237,821 $255,219 
v3.25.4
Other Income and Other Expense (Tables)
 12 Months Ended
Dec. 31, 2025
Other Income and Expenses [Abstract]  
Schedule of Other Income and Other Expense
The following table provides detail of Pinnacle West’s consolidated other income and other expense for the years ended 2025, 2024, and 2023 (dollars in thousands):
 202520242023
Other income:   
Interest income $18,037 $24,322 (a)$27,242 (a)
Investment gain — net (b)26,720 — — 
Gain on sale of BCE (Note 22)
— 22,988 6,205 
Miscellaneous4,649 1,304 219 
Total other income$49,406 $48,614 $33,666 
Other expense:
Non-operating costs$(21,332)$(27,370)(c)$(15,260)
Investment losses — net— (1,418)(3,402)
Miscellaneous(8,933)(5,348)(6,394)
Total other expense$(30,265)$(34,136)$(25,056)
(a)2023 and 2024 Interest income is primarily related to PSA interest. See Note 8.
(b)Investment gain is primarily related to El Dorado’s equity investment in SAI. See Note 23.
(c)The 2024 Non-operating cost is primarily related to corporate giving.
The following table provides detail of APS’s other income and other expense for the years ended 2025, 2024, and 2023 (dollars in thousands):
 202520242023
Other income:   
Interest income$15,933 $21,088 (a)$26,853 (a)
Miscellaneous281 6 219 
 Total other income$16,214 $21,094 $27,072 
Other expense:
Non-operating costs$(19,650)$(26,588)(b)$(14,070)
Miscellaneous(6,732)(3,110)(4,194)
Total other expense$(26,382)$(29,698)$(18,264)
(a)2023 and 2024 Interest income is primarily related to PSA interest. See Note 8.
(b)The 2024 Non-operating cost is primarily related to corporate giving.
v3.25.4
Common Stock Equity and Earnings Per Share (Tables)
 12 Months Ended
Dec. 31, 2025
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, including details of the outstanding forward sale agreements as of December 31, 2025:

ATM Forward Sale AgreementsMaturity DateNumber of SharesForward Sales Price Per Share (a)Aggregate Value
(in thousands)
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 
2,199,415 $90.10 (b)$198,176 
(a)    Subject to certain adjustments.
(b)    Weighted-average price for the total ATM Program.
The following table presents information about the outstanding February 2024 Forward Sale Agreements as of December 31, 2025 (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 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 in thousands, except earnings per share amounts):
As of December 31,
 202520242023
Net income attributable to common shareholders
$616,531 $608,806 $501,557 
Weighted average common shares outstanding — basic119,687 113,846 113,442 
Net effect of dilutive securities:   
Contingently issuable performance shares and restricted stock units568 480 362 
Dilutive shares related to equity forward sale agreements (a)1,716 1,906 — 
Total contingently issuable shares2,284 2,386 362 
Weighted average common shares outstanding — diluted121,971 116,232 113,804 
Earnings per weighted-average common share outstanding
Net income attributable to common shareholders — basic
$5.15 $5.35 $4.42 
Net income attributable to common shareholders — diluted
$5.05 $5.24 $4.41 
(a)    For the years ended December 31, 2025, 2024 and 2023 the diluted weighted-average common shares excludes 148,098, 1,038,463 and 0 shares, respectively relating to the ATM Program and the Convertible Notes. These potentially issuable shares were excluded from the calculation of diluted shares as their inclusion would have been antidilutive.
v3.25.4
Fair Value Measurements (Tables)
 12 Months Ended
Dec. 31, 2025
Fair Value Disclosures [Abstract]  
Schedule of Fair Value of Assets and Liabilities Measured at Fair Value on a Recurring Basis
The following table presents the fair value as of 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 13.
(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 12.
 The following table presents the fair value at December 31, 2024 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):
 
Level 1Level 2Level 3OtherTotal
ASSETS
Cash equivalents$23 $— $— $— $23 
Risk management activities — derivative instruments:
Commodity contracts— 13,152 7,176 (3,770)(a)16,558 
Nuclear decommissioning trusts:
Equity securities11,859 542 — 3,335 (b)15,736 
U.S. commingled equity funds— — — 423,069 (c)423,069 
U.S. Treasury debt367,396 — — — 367,396 
Corporate debt— 203,180 — — 203,180 
Mortgage-backed securities— 208,533 — — 208,533 
Municipal bonds— 37,429 — — 37,429 
Other fixed income— 27,502 — — 27,502 
Subtotal nuclear decommissioning trusts379,255 477,186 — 426,404 1,282,845 
Other special use funds:
Cash equivalents25,000 — — — (d)25,000 
Equity securities24,962 — — 2,851 (b) (d)27,813 
U.S. Treasury debt355,544 — — — 355,544 
Subtotal other special use funds (d)405,506 — — 2,851 408,357 
Total assets$784,784 $490,338 $7,176 $425,485 $1,707,783 
LIABILITIES
Risk management activities — derivative instruments:
Commodity contracts$— $(40,388)$(22,215)$817 (a)$(61,786)
(a)Represents counterparty netting, margin, and collateral. See Note 13.
(b)Represents net pending securities sales and purchases.
(c)Valued using NAV as a practical expedient and, therefore, are not classified in the fair value hierarchy.
(d)All amounts relate to APS, with the exception of $34.2 million related to Pinnacle West’s Captive investments that are classified within Level 1, $25.0 million in cash equivalents and $9.2 million related to equity securities. See Note 12.
The following table shows the changes in fair value for our risk management activities’ assets and liabilities that are measured at fair value on a recurring basis using Level 3 inputs (dollars in thousands):
 Year Ended December 31,
Commodity Contracts20252024
Balance at beginning of period$(15,039)$4,921 
Total net losses realized/unrealized:
Deferred as a regulatory asset or liability(30,006)(60,965)
Settlements21,907 44,156 
Transfers into Level 3 from Level 2(1,240)(4,635)
Transfers from Level 3 into Level 2668 1,484 
Balance at end of period$(23,710)$(15,039)
Net unrealized gains/losses included in earnings related to instruments still held at end of period$— $— 
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 December 31, 2025 and December 31, 2024 (dollars in thousands):

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 Million British Thermal Units (“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.

December 31, 2024
 Fair Value 		ValuationSignificantWeighted-Average
Commodity ContractsAssetsLiabilitiesTechniqueUnobservable InputRange(b)
Electricity Forward Contracts (a)$708 $21,890 Discounted cash flowsElectricity forward price (per MWh)$25.25 -$151.11$106.06
Natural Gas Forward Contracts (a)6,468 325 Discounted cash flowsNatural gas forward price (per MMBtu)$(0.89)-$1.47$0.71
Total$7,176 $22,215 
(a)Includes swaps and physical and financial contracts.
(b)Unobservable inputs were weighted by the relative fair value of the instrument.
v3.25.4
Investments in Nuclear Decommissioning Trusts and Other Special Use Funds (Tables)
 12 Months Ended
Dec. 31, 2025
Investments, Debt and Equity Securities [Abstract]  
Schedule of Fair Value of APS's Nuclear Decommissioning Trust Fund Assets
The following tables present the unrealized gains and losses based on the original cost of the investment and summarize the fair value of the nuclear decommissioning trusts and other special use fund assets (dollars in thousands): 
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 $(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 and $3.2 million of unrealized gains relating to investments held by the Captive.
December 31, 2024
 Fair ValueTotal
Unrealized
Gains		Total
Unrealized
Losses
Investment Type:Nuclear Decommissioning TrustsOther Special Use FundsTotal
Equity securities$435,470 $24,962 $460,432 $359,127 $(176)
Available for sale-fixed income securities844,040 355,544 1,199,584 (a)7,717 (31,960)
Other3,335 27,851 31,186 (b)— — 
Total$1,282,845 $408,357 $1,691,202 (c)$366,844 $(32,136)
(a)As of December 31, 2024, the amortized cost basis of these available-for-sale investments is $1,224 million.
(b)Represents net pending securities sales and purchases.
(c)All amounts pertain to APS, with the exception of $34.2 million of other special use fund investments in equity securities relating to 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):
 Year Ended December 31,
 Nuclear Decommissioning TrustsOther Special Use FundsTotal
2025
Realized gains$12,826 $242 $13,068 
Realized losses$(11,749)$— $(11,749)
Proceeds from the sale of securities (a)$1,478,088 $377,112 (b)$1,855,200 
2024
Realized gains$75,690 $372 $76,062 
Realized losses$(21,966)$— $(21,966)
Proceeds from the sale of securities (a)$1,330,940 $355,154 $1,686,094 
2023
Realized gains$111,922 $172 $112,094 
Realized losses$(41,212)$(568)$(41,780)
Proceeds from the sale of securities (a)$1,324,978 $354,744 $1,679,722 
(a)Proceeds are reinvested in the nuclear decommissioning trusts and other special use funds, excluding amounts reimbursed to the Company for active union employee medical claims from the active union employee medical account.
(b)All amounts pertain to APS, with the exception of $51.4 million of other special use fund proceeds from the sale of securities relating to investments held by 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 December 31, 2025 is as follows (dollars in thousands):
 
 Nuclear Decommissioning TrustsCoal Reclamation Escrow AccountActive Union Employee Medical AccountTotal
Less than one year$36,726 $87,421 $39,617 $163,764 
1 year – 5 years272,413 68,348 157,116 497,877 
5 years – 10 years173,131 — 16,553 189,684 
Greater than 10 years416,133 — — 416,133 
Total$898,403 $155,769 $213,286 $1,267,458 
v3.25.4
Changes in Accumulated Other Comprehensive Loss (Tables)
 12 Months Ended
Dec. 31, 2025
Comprehensive Income (Loss), Net of Tax, Attributable to Parent [Abstract]  
Schedule of Changes in Accumulated Other Comprehensive Loss Including Reclassification Adjustments, by Component
The following table shows the changes in Pinnacle West’s consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component (dollars in thousands): 
 Pension and Other Postretirement BenefitsDerivative InstrumentsTotal
Balance at December 31, 2023
$(34,754)$1,610 $(33,144)
Other comprehensive income/(loss) before reclassifications
1,039 (891)148 
Amounts reclassified from accumulated other comprehensive loss
2,054 (a)— 2,054 
Balance at December 31, 2024
(31,661)719 (30,942)
Other comprehensive loss before reclassifications
(3,210)(147)(3,357)
Amounts reclassified from accumulated other comprehensive loss
1,891 (a)— 1,891 
Balance at December 31, 2025
$(32,980)$572 $(32,408)
(a)These amounts primarily represent amortization of actuarial loss and are included in the computation of net periodic pension cost. See Note 9.
The following table shows the changes in APS’s consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component (dollars in thousands): 
 Pension and Other Postretirement Benefits
Balance at December 31, 2023
$(17,219)
Other comprehensive income before reclassifications
1,255 
Amounts reclassified from accumulated other comprehensive loss
1,848 (a)
Balance at December 31, 2024
(14,116)
Other comprehensive loss before reclassifications
(2,889)
Amounts reclassified from accumulated other comprehensive loss
1,548 (a)
Balance at December 31, 2025
$(15,457)
(a)These amounts primarily represent amortization of actuarial loss and are included in the computation of net periodic pension cost. See Note 9.
v3.25.4
Leases (Tables)
 12 Months Ended
Dec. 31, 2025
Leases [Abstract]  
Schedule of Lease Costs
The following table provides information related to our lease costs (dollars in thousands):

Year Ended December 31,
202520242023
Operating Lease Cost - PPAs and Energy Storage PPA Lease Contracts$292,625 $147,313 $126,655 
Operating Lease Cost - Land, Property, and Other Equipment22,120 20,120 19,235 
Total Operating Lease Cost314,745 167,433 145,890 
Variable Lease Cost (a)124,707 144,108 135,007 
Short-term Lease Cost2,250 20,653 21,530 
Total Lease Cost$441,702 $332,194 $302,427 
(a)    Primarily relates to PPA lease contracts.
The following tables provide other additional information related to operating lease liabilities (dollars in thousands):
Year Ended December 31,
202520242023
Cash paid for amounts included in the measurement of lease liabilities — operating cash flows:$226,484 $143,950 $123,472 
Right-of-use operating lease assets obtained in exchange for operating lease liabilities:$2,195,728 (a)$393,702 (b)602,301 (c)

December 31, 2025December 31, 2024
Weighted average remaining lease term15 years11 years
Weighted average discount rate (d)5.48 %4.90 %
(a)Primarily relates to nine new energy storage PPA operating leases that commenced in 2025.
(b)Primarily relates to the three new energy storage operating lease agreements that commenced in 2024.
(c)Primarily relates to the two purchased power operating lease agreements that were modified in January 2023.
(d)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):
December 31, 2025
YearPPAs and Energy Storage PPA Lease ContractsLand, Property and Equipment LeasesTotal
2026 $364,197 $21,141 $385,338 
2027390,260 18,858 409,118 
2028394,202 16,166 410,368 
2029398,287 14,033 412,320 
2030402,416 9,811 412,227 
Thereafter3,590,042 59,700 3,649,742 
Total lease commitments5,539,404 139,709 5,679,113 
Less imputed interest1,899,993 42,169 1,942,162 
Total lease liabilities$3,639,411 $97,540 $3,736,951 
v3.25.4
Asset Retirement Obligations (Tables)
 12 Months Ended
Dec. 31, 2025
Asset Retirement Obligation Disclosure [Abstract]  
Schedule of Change in Asset Retirement Obligations
The following table shows the change in our ARO’s (dollars in thousands):

 20252024
Asset retirement obligations at the beginning of year
$1,146,586 $966,001 
Changes attributable to:  
Accretion expense64,552 56,143 
Settlements(16,570)(18,379)
Estimated cash flow revisions61,080 142,821 
Newly incurred obligation14,651 — 
Asset retirement obligations at the end of year
$1,270,299 $1,146,586 
v3.25.4
El Dorado Equity Investments (Tables)
 12 Months Ended
Dec. 31, 2025
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 December 31, 2025
December 31, 2025December 31, 2024
SAI (a)17 %$21 $— 
AZ-VC (b)24 %15 11 
Total equity method investments$36 $11 
(a)El Dorado has no further funding commitments to SAI.
(b)El Dorado has a $25.0 million funding commitment to AZ-VC, of which approximately $15.5 million has been funded as of December 31, 2025.
v3.25.4
Summary of Significant Accounting Policies - Additional Information (Details)
$ / shares in Units, $ in Millions
 1 Months Ended 12 Months Ended 36 Months Ended
May 31, 2014
$ / kWh
Dec. 31, 2025
USD ($)
trust
$ / shares
shares
Dec. 31, 2024
USD ($)
Dec. 31, 2023
USD ($)
Dec. 31, 2025
USD ($)
trust
$ / shares
shares
Sep. 30, 2025
trust
Sep. 22, 2025
trust
Jun. 30, 2025
trust
Dec. 31, 1986
trust
Approximate remaining average useful lives of utility property                  
Depreciation   $ 732 $ 723 $ 669          
Depreciation rates (as a percent)   3.06% 3.13% 2.98%          
Allowance for Funds Used During Construction                  
Composite rate used to calculate AFUDC (as a percent)   6.67% 6.23% 6.29%          
Income Taxes                  
Percent likelihood largest tax benefit amount is realized (greater than)   50.00%              
Intangible Assets                  
Amortization expense   $ 157 $ 136 $ 90          
Estimated amortization expense on existing intangible assets over the next five years                  
2026   109     $ 109        
2027   75     75        
2028   45     45        
2029   26     26        
2030   $ 14     $ 14        
Remaining amortization period for intangible assets   6 years     6 years        
Minimum                  
Approximate remaining average useful lives of utility property                  
Depreciation rates (as a percent)         1.37%        
Investments                  
Ownership percentage for classification as cost method investments by El Dorado   3.00%              
Maximum                  
Approximate remaining average useful lives of utility property                  
Depreciation rates (as a percent)         12.37%        
Investments                  
Ownership percentage for classification as cost method investments by El Dorado   5.00%              
Steam Generation                  
Approximate remaining average useful lives of utility property                  
Average useful life   21 years     21 years        
Nuclear Plant                  
Approximate remaining average useful lives of utility property                  
Average useful life   30 years     30 years        
Other Generation                  
Approximate remaining average useful lives of utility property                  
Average useful life   16 years     16 years        
Transmission                  
Approximate remaining average useful lives of utility property                  
Average useful life   34 years     34 years        
Distribution                  
Approximate remaining average useful lives of utility property                  
Average useful life   33 years     33 years        
Energy Storage                  
Approximate remaining average useful lives of utility property                  
Average useful life   19 years     19 years        
Solar Plant                  
Approximate remaining average useful lives of utility property                  
Average useful life   28 years     28 years        
General Plant                  
Approximate remaining average useful lives of utility property                  
Average useful life   10 years     10 years        
Pinnacle West Consolidated                  
Preferred Stock                  
Preferred stock, shares authorized (in shares) | shares   10,000,000     10,000,000        
Preferred stock, shares outstanding (in shares) | shares   0     0        
APS                  
Nuclear Fuel                  
Charges for the permanent disposal of spent nuclear fuel (in dollars per kWh) | $ / kWh 0.001                
Preferred Stock                  
Preferred stock, shares authorized (in shares) | shares   15,535,000     15,535,000        
Preferred stock, shares outstanding (in shares) | shares   0     0        
Preferred stock par or stated value per share 1 (in dollars per share) | $ / shares   $ 25     $ 25        
Preferred stock par or stated value per share 2 (in dollars per share) | $ / shares   50     50        
Preferred stock par or stated value per share 3 (in dollars per share) | $ / shares   $ 100     $ 100        
APS | Variable Interest Entity                  
Utility Plant and Depreciation [Line Items]                  
Number of VIE lessor trusts acquired | trust           2 2    
Number of VIE lessor trusts | trust   1     1     2 3
v3.25.4
Summary of Significant Accounting Policies - Schedule of Property, Plant and Equipment (Details) - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Utility Plant and Depreciation [Line Items]    
Net $ 18,358,275 $ 16,833,524
Construction work in progress 1,649,542 1,592,659
Intangible assets, net of accumulated amortization 575,978 591,310
Nuclear fuel, net of accumulated amortization 104,274 97,850
Total property, plant and equipment 20,720,104 19,197,899
Electric Service    
Utility Plant and Depreciation [Line Items]    
Generation 9,687,466 9,675,576
Transmission 4,451,936 4,135,970
Distribution 9,626,629 9,016,843
Energy storage 515,935 276,954
Solar plant 1,501,301 1,159,385
General plant 1,587,029 1,596,222
Plant in service and held for future use 27,370,296 25,860,950
Accumulated depreciation and amortization (9,012,021) (9,027,426)
Net 18,358,275 16,833,524
Construction work in progress 1,649,542 1,592,659
Intangible assets, net of accumulated amortization 575,978 591,310
Nuclear fuel, net of accumulated amortization 104,274 97,850
Total property, plant and equipment 20,720,104 19,197,899
Electric Service | Variable Interest Entity    
Utility Plant and Depreciation [Line Items]    
Total property, plant and equipment $ 32,035 $ 82,556
v3.25.4
Summary of Significant Accounting Policies - Schedule of Supplemental Cash Flow Information (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Cash and Cash Equivalents [Line Items]      
Income taxes, net of refunds/credits $ 22,754 $ 112,998 $ 8,788
Income taxes, net of refunds/credits   133,968  
Interest, net of amounts capitalized 388,540 360,349 310,996
Significant non-cash investing and financing activities:      
Accrued capital expenditures 281,133 257,494 206,269
Dividends accrued but not yet paid 110,022 106,592 99,813
BCE Sale non-cash consideration (Note 22) 0 0 28,262
APS      
Cash and Cash Equivalents [Line Items]      
Income taxes, net of refunds/credits 53,638 179,013 21,734
Interest, net of amounts capitalized 307,520 299,799 267,261
Significant non-cash investing and financing activities:      
Accrued capital expenditures 281,133 257,494 206,269
Dividends accrued but not yet paid $ 110,000 $ 107,200 $ 99,800
v3.25.4
Business Segments (Details)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
USD ($)
segment
Dec. 31, 2024
USD ($)
Dec. 31, 2023
USD ($)
Revenue from External Customer [Line Items]      
Operating revenues $ 5,339,939 $ 5,124,915 $ 4,695,991
Fuel and purchased power 1,933,420 1,822,566 1,792,657
Operations and maintenance 1,185,065 1,165,156 1,058,725
Depreciation and amortization 915,343 895,346 794,043
Taxes other than income taxes 234,797 227,395 224,013
Allowance for equity funds used during construction 61,146 38,620 53,118
Pension and other postretirement non-service credits, net 12,420 48,870 40,648
Interest charges, net of allowance for borrowed funds used during construction (421,968) (377,472) (331,323)
Income Taxes (Note 5) 106,726 110,529 76,912
Less: Net income attributable to noncontrolling interests (Note 12) 15,112 17,224 17,224
Net Income (Loss) Attributable to Common Shareholders 616,531 608,806 501,557
Total Assets $ 30,031,599 26,102,760  
Number of reportable segments | segment 1    
Pinnacle West Consolidated      
Revenue from External Customer [Line Items]      
Other income and (expense), net $ (1,917) 23,835 2,823
Income Taxes (Note 5) (19,193) (16,460) (17,272)
Net Income (Loss) Attributable to Common Shareholders 616,531 608,806 501,557
Total Assets 9,224,129 8,627,449  
Pinnacle West Consolidated | Pinnacle West Consolidated      
Revenue from External Customer [Line Items]      
Operating revenues 5,340,000 5,125,000 4,696,000
Fuel and purchased power (1,933,000) (1,823,000) (1,793,000)
Operations and maintenance (1,185,000) (1,165,000) (1,059,000)
Depreciation and amortization (915,000) (895,000) (794,000)
Taxes other than income taxes (235,000) (227,000) (224,000)
Allowance for equity funds used during construction 61,000 39,000 53,000
Pension and other postretirement non-service credits, net 12,000 49,000 41,000
Other income and (expense), net 16,000 11,000 7,000
Interest charges, net of allowance for borrowed funds used during construction (422,000) (377,000) (331,000)
Income Taxes (Note 5) (107,000) (111,000) (77,000)
Less: Net income attributable to noncontrolling interests (Note 12) (15,000) (17,000) (17,000)
Net Income (Loss) Attributable to Common Shareholders 617,000 609,000 502,000
Total Assets 30,032,000 26,103,000  
Regulated Electricity Segment      
Revenue from External Customer [Line Items]      
Operating revenues 5,340,000 5,125,000 4,696,000
Fuel and purchased power (1,933,000) (1,823,000) (1,793,000)
Operations and maintenance (1,177,000) (1,159,000) (1,044,000)
Depreciation and amortization (915,000) (895,000) (794,000)
Taxes other than income taxes (235,000) (227,000) (224,000)
Allowance for equity funds used during construction 61,000 39,000 53,000
Pension and other postretirement non-service credits, net 13,000 49,000 42,000
Other income and (expense), net (14,000) (11,000) 7,000
Interest charges, net of allowance for borrowed funds used during construction (332,000) (312,000) (285,000)
Income Taxes (Note 5) (126,000) (127,000) (94,000)
Less: Net income attributable to noncontrolling interests (Note 12) (15,000) (17,000) (17,000)
Net Income (Loss) Attributable to Common Shareholders 667,000 642,000 547,000
Total Assets 29,886,000 25,988,000  
Other      
Revenue from External Customer [Line Items]      
Operating revenues 0 0 0
Fuel and purchased power 0 0 0
Operations and maintenance (8,000) (6,000) (15,000)
Depreciation and amortization 0 0 0
Taxes other than income taxes 0 0 0
Allowance for equity funds used during construction 0 0 0
Pension and other postretirement non-service credits, net (1,000) 0 (1,000)
Other income and (expense), net 30,000 22,000 0
Interest charges, net of allowance for borrowed funds used during construction (90,000) (65,000) (46,000)
Income Taxes (Note 5) 19,000 16,000 17,000
Less: Net income attributable to noncontrolling interests (Note 12) 0 0 0
Net Income (Loss) Attributable to Common Shareholders (50,000) (33,000) $ (45,000)
Total Assets $ 146,000 $ 115,000  
v3.25.4
Revenue - Schedule of Disaggregation of Revenue (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Disaggregation of Revenue [Line Items]      
Total Operating Revenues $ 5,339,939 $ 5,124,915 $ 4,695,991
Wholesale Energy Sales      
Disaggregation of Revenue [Line Items]      
Total Operating Revenues 108,661 96,857 208,985
Transmission Services for Others      
Disaggregation of Revenue [Line Items]      
Total Operating Revenues 129,667 119,038 138,631
Other Sources      
Disaggregation of Revenue [Line Items]      
Total Operating Revenues 17,355 11,273 10,763
Residential | Retail Electric Service      
Disaggregation of Revenue [Line Items]      
Total Operating Revenues 2,541,320 2,562,822 2,289,196
Non-Residential | Retail Electric Service      
Disaggregation of Revenue [Line Items]      
Total Operating Revenues $ 2,542,936 $ 2,334,925 $ 2,048,416
v3.25.4
Revenue - Additional Information (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Disaggregation of Revenue [Line Items]      
Operating revenues $ 5,339,939 $ 5,124,915 $ 4,695,991
Regulatory cost recovery revenue $ 21,000 52,000 45,000
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 $ 5,319,000 $ 5,073,000 $ 4,651,000
v3.25.4
Revenue - Schedule of Allowance for Doubtful Accounts (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Accounts Receivable, Allowance for Credit Loss [Roll Forward]      
Balance at beginning of period $ 24,849 $ 22,433 $ 23,778
Bad debt expense 28,603 35,799 23,399
Actual write-offs (27,957) (33,383) (24,744)
Balance at end of period $ 25,495 $ 24,849 $ 22,433
v3.25.4
Income Taxes - Additional Information (Details) - USD ($)
$ in Thousands
 12 Months Ended
Jan. 30, 2024
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Income Taxes        
Income tax benefits   $ 14,698 $ 15,206 $ 8,441
Income tax benefit   106,726 110,529 76,912
Interest expense to be received on the underpayment of income taxes   2,800    
Decrease in deferred income taxes due to regulation adoption   27,900    
APS        
Income Taxes        
Income tax benefits   11,254 12,110 5,460
Income tax benefit   125,919 $ 126,993 $ 94,184
Decrease in deferred income taxes due to regulation adoption   12,400    
Federal        
Income Taxes        
State credit carryforwards net of federal benefit   27,900    
Federal | APS        
Income Taxes        
State credit carryforwards net of federal benefit   12,400    
Tax Year 2024        
Income Taxes        
Income tax benefits   33,400    
Tax Year 2025        
Income Taxes        
Income tax benefits   39,600    
Variable Interest Entity, Not Primary Beneficiary | Palo Verde sale leaseback        
Income Taxes        
Income tax benefit   $ 0    
Discontinued Operations, Disposed of by Sale | Bright Canyou Energy Corportion        
Income Taxes        
Investment tax credits $ 23,000      
Payments to acquire investment tax credits $ 21,000      
v3.25.4
Income Taxes - Schedule of Components of Income Tax Expense (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Current:      
Federal $ 87,913 $ 137,342 $ 21,272
State 10,892 2,392 2,854
Total current 98,805 139,734 24,126
Deferred:      
Federal (11,073) (53,228) 37,273
State 18,994 24,023 15,513
Total deferred 7,921 (29,205) 52,786
Income tax expense 106,726 110,529 76,912
APS      
Current:      
Federal 94,207 165,653 26,405
State 31,424 26,054 1,027
Total current 125,631 191,707 27,432
Deferred:      
Federal (2,902) (69,075) 44,922
State 3,190 4,361 21,830
Total deferred 288 (64,714) 66,752
Income tax expense $ 125,919 $ 126,993 $ 94,184
v3.25.4
Income Taxes - Schedule of Comparison of Pretax Income from Federal Income Tax Rate to Income Tax Expense (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Effective Income Tax Rate Reconciliation [Line Items]      
Income before income taxes $ 738,369 $ 736,559 $ 595,693
Amount      
Federal income tax expense at statutory rate 155,057 154,677 125,095
State income tax net of federal income tax benefit 23,610 23,735 17,832
Changes in Valuation Allowance 0 0 0
Share based compensation (4,062) (421)  
Share based compensation     1,346
Palo Verde VIE noncontrolling interest (Note 12) (3,173) (3,617) (3,617)
Other Nontaxable or Nondeductible Items 5,896 3,667 2,405
Effect of changes in tax laws or rates enacted in the current period 0 0 0
Solar or Wind Production Tax Credit (14,698) (15,206) (8,441)
Other Federal Income Tax Credits (19) (242) (650)
Investment credit amortization – deferral method (12,625) (9,425) (9,495)
Changes in Unrecognized Tax Benefits 1,523 (28) (1,961)
Excess deferred income taxes — Tax Cuts and Jobs Act (36,558) (36,559) (36,558)
Allowance for equity funds used during construction (Note 1) (7,005) (2,545) (5,964)
Other regulatory amortization (2,758) (1,796) (1,828)
Other Adjustments 1,538 (1,711) (1,252)
Income tax expense $ 106,726 $ 110,529 $ 76,912
Percent      
Federal income tax expense at statutory rate 21.00% 21.00% 21.00%
State income tax net of federal income tax benefit 3.20% 3.22% 2.99%
Changes in Valuation Allowance 0.00% 0.00% 0.00%
Share based compensation (0.55%) (0.06%)  
Share based compensation     0.23%
Palo Verde VIE noncontrolling interest (Note 12) (0.43%) (0.49%) (0.61%)
Other Nontaxable or Nondeductible Items 0.80% 0.50% 0.40%
Effect of changes in tax laws or rates enacted in the current period 0.00% 0.00% 0.00%
Solar or Wind Production Tax Credit (1.99%) (2.07%) (1.42%)
Other Federal Income Tax Credits 0.00% (0.03%) (0.11%)
Investment credit amortization – deferral method (1.71%) (1.28%) (1.59%)
Changes in Unrecognized Tax Benefits 0.21% 0.00% (0.33%)
Excess deferred income taxes — Tax Cuts and Jobs Act (4.95%) (4.96%) (6.14%)
Allowance for equity funds used during construction (Note 1) (0.95%) (0.35%) (1.00%)
Other regulatory amortization (0.38%) (0.24%) (0.31%)
Other Adjustments 0.20% (0.23%) (0.20%)
Income tax expense 14.45% 15.01% 12.91%
APS      
Effective Income Tax Rate Reconciliation [Line Items]      
Income before income taxes $ 808,346 $ 786,142 $ 658,745
Amount      
Federal income tax expense at statutory rate 169,753 165,090 138,337
State income tax net of federal income tax benefit 27,345 26,824 21,453
Changes in Valuation Allowance 0 0 0
Share based compensation (2,482)    
Share based compensation   23 997
Palo Verde VIE noncontrolling interest (Note 12) (3,173) (3,617) (3,617)
Other Nontaxable or Nondeductible Items 1,727 694 263
Effect of changes in tax laws or rates enacted in the current period 0 0 0
Solar or Wind Production Tax Credit (11,254) (12,110) (5,460)
Other Federal Income Tax Credits (19) (242) (650)
Investment credit amortization – deferral method (12,625) (9,425) (9,495)
Changes in Unrecognized Tax Benefits 1,483 (107) (1,946)
Excess deferred income taxes — Tax Cuts and Jobs Act (36,558) (36,559) (36,558)
Allowance for equity funds used during construction (Note 1) (7,005) (2,545) (5,964)
Other regulatory amortization (2,758) (1,796) (1,828)
Other Adjustments 1,485 763 (1,348)
Income tax expense $ 125,919 $ 126,993 $ 94,184
Percent      
Federal income tax expense at statutory rate 21.00% 21.00% 21.00%
State income tax net of federal income tax benefit 3.38% 3.41% 3.26%
Changes in Valuation Allowance 0.00% 0.00% 0.00%
Share based compensation (0.31%)    
Share based compensation   0.00% 0.15%
Palo Verde VIE noncontrolling interest (Note 12) (0.39%) (0.46%) (0.55%)
Other Nontaxable or Nondeductible Items 0.21% 0.09% 0.04%
Effect of changes in tax laws or rates enacted in the current period 0.00% 0.00% 0.00%
Solar or Wind Production Tax Credit (1.39%) (1.54%) (0.83%)
Other Federal Income Tax Credits 0.00% (0.03%) (0.10%)
Investment credit amortization – deferral method (1.56%) (1.20%) (1.44%)
Changes in Unrecognized Tax Benefits 0.18% (0.01%) (0.30%)
Excess deferred income taxes — Tax Cuts and Jobs Act (4.52%) (4.65%) (5.55%)
Allowance for equity funds used during construction (Note 1) (0.87%) (0.32%) (0.91%)
Other regulatory amortization (0.34%) (0.23%) (0.28%)
Other Adjustments 0.19% 0.09% (0.19%)
Income tax expense 15.58% 16.15% 14.30%
v3.25.4
Income Taxes - Schedule of Income Taxes Paid (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Income Tax [Line Items]      
Federal $ 20,894 $ 112,870 $ 8,609
State 1,860 128 179
Total 22,754 112,998 8,788
Arizona      
Income Tax [Line Items]      
State 2,000 0 0
APS      
Income Tax [Line Items]      
Federal 30,207 156,112 21,438
State 23,431 22,901 296
Total 53,638 179,013 21,734
APS | Arizona      
Income Tax [Line Items]      
State $ 23,423 $ 22,788 $ 0
v3.25.4
Income Taxes - Schedule of Unrecognized Tax Benefits Roll Forward (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Tabular reconciliation of the total amounts of unrecognized tax benefits, excluding interest and penalties, at the beginning and end of the year      
Total unrecognized tax benefits, beginning of the year $ 44,349 $ 44,274 $ 43,097
Additions for tax positions of the current year 81,286 1,271 1,473
Additions for tax positions of prior years 2,818 2,031 419
Reductions for tax positions of prior years for:      
Changes in judgment (2,044) (2,043) 661
Settlements with taxing authorities 0 0 0
Lapses of applicable statute of limitations (970) (1,184) (1,376)
Total unrecognized tax benefits, end of the year 125,439 44,349 44,274
APS      
Tabular reconciliation of the total amounts of unrecognized tax benefits, excluding interest and penalties, at the beginning and end of the year      
Total unrecognized tax benefits, beginning of the year 44,349 44,274 43,097
Additions for tax positions of the current year 81,286 1,271 1,473
Additions for tax positions of prior years 2,818 2,031 419
Reductions for tax positions of prior years for:      
Changes in judgment (2,044) (2,043) 661
Settlements with taxing authorities 0 0 0
Lapses of applicable statute of limitations (970) (1,184) (1,376)
Total unrecognized tax benefits, end of the year $ 125,439 $ 44,349 $ 44,274
v3.25.4
Income Taxes - Schedule of Unrecognized Tax Benefits (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Income Tax [Line Items]      
Tax positions, that if recognized, would decrease our effective tax rate $ 103,785 $ 27,899 $ 28,762
Unrecognized tax benefit interest expense recognized 3,610 2,743 452
Unrecognized tax benefit interest accrued 7,986 4,376 1,633
APS      
Income Tax [Line Items]      
Tax positions, that if recognized, would decrease our effective tax rate 103,785 27,899 28,762
Unrecognized tax benefit interest expense recognized 3,610 2,743 452
Unrecognized tax benefit interest accrued $ 7,986 $ 4,376 $ 1,633
v3.25.4
Income Taxes - Schedule of Components of the Net Deferred Income Tax Liability (Details) - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
DEFERRED TAX ASSETS    
Risk management activities $ 8,422 $ 14,539
Regulatory liabilities:    
Excess deferred income taxes — Tax Cuts and Jobs Act 259,000 271,004
Asset retirement obligation and removal costs 66,031 81,308
Unamortized investment tax credits 81,949 66,327
Other postretirement benefits 57,833 58,862
Other 50,611 47,671
Operating lease liabilities 923,774 400,771
Pension liabilities 46,613 39,070
Coal reclamation liabilities 39,450 42,391
Renewable energy incentives 11,908 14,571
Credit and loss carryforwards 0 7,682
Employee benefit liabilities 56,447 57,853
Other 49,098 44,412
Total deferred tax assets 1,651,136 1,146,461
DEFERRED TAX LIABILITIES    
Plant-related (2,595,668) (2,562,990)
Risk management activities (2,072) (4,089)
Pension and other postretirement assets (97,557) (83,401)
Other special use funds (58,175) (55,146)
Operating lease right-of-use assets (923,774) (400,771)
Regulatory assets:    
Allowance for equity funds used during construction (50,402) (47,694)
Deferred fuel and purchased power (45,504) (84,393)
Pension benefits (178,736) (185,641)
Retired power plant costs (13,157) (16,904)
Other (58,822) (57,602)
Other (54,418) (43,383)
Total deferred tax liabilities (4,122,068) (3,590,934)
Deferred income taxes — net (2,470,932) (2,444,473)
Ocotillo deferral    
Regulatory assets:    
Deferral (24,703) (28,372)
SCR deferral    
Regulatory assets:    
Deferral (19,080) (20,548)
APS    
DEFERRED TAX ASSETS    
Risk management activities 8,422 14,539
Regulatory liabilities:    
Excess deferred income taxes — Tax Cuts and Jobs Act 259,000 271,004
Asset retirement obligation and removal costs 66,031 81,308
Unamortized investment tax credits 81,949 66,327
Other postretirement benefits 57,833 58,862
Other 50,611 47,671
Operating lease liabilities 923,479 400,442
Pension liabilities 43,422 36,100
Coal reclamation liabilities 39,450 42,391
Renewable energy incentives 11,908 14,571
Credit and loss carryforwards 0 0
Employee benefit liabilities 55,243 56,561
Other 49,098 44,412
Total deferred tax assets 1,646,446 1,134,188
DEFERRED TAX LIABILITIES    
Plant-related (2,595,668) (2,562,990)
Risk management activities (2,072) (4,089)
Pension and other postretirement assets (96,988) (82,925)
Other special use funds (58,175) (55,146)
Operating lease right-of-use assets (923,479) (400,443)
Regulatory assets:    
Allowance for equity funds used during construction (50,402) (47,694)
Deferred fuel and purchased power (45,504) (84,393)
Pension benefits (178,736) (185,641)
Retired power plant costs (13,157) (16,904)
Other (58,822) (57,602)
Other (7,425) (7,378)
Total deferred tax liabilities (4,074,211) (3,554,125)
Deferred income taxes — net $ (2,427,765) $ (2,419,937)
v3.25.4
Lines of Credit and Short-Term Borrowings - Schedule of Consolidated Credit Facilities and Amounts Available and Outstanding (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
APS Consolidated    
Schedule of Debt Instruments [Line Items]    
Commitment fees (as a percent) 0.175% 0.175%
Commercial paper    
Schedule of Debt Instruments [Line Items]    
Commitments under Revolving Credit and Term Loan Facilities $ 1,625,000 $ 2,050,000
Outstanding short-term borrowings (757,005) (568,450)
Amount available under Revolving Credit and Term Loan Facilities 867,995 1,481,550
Commercial paper | APS Consolidated    
Schedule of Debt Instruments [Line Items]    
Commitments under Revolving Credit and Term Loan Facilities 1,250,000 1,650,000
Outstanding short-term borrowings (507,305) (339,900)
Amount available under Revolving Credit and Term Loan Facilities $ 742,695 $ 1,310,100
Pinnacle West Consolidated    
Schedule of Debt Instruments [Line Items]    
Commitment fees (as a percent) 0.225% 0.225%
Pinnacle West Consolidated | Commercial paper    
Schedule of Debt Instruments [Line Items]    
Commitments under Revolving Credit and Term Loan Facilities $ 375,000 $ 400,000
Outstanding short-term borrowings (249,700) (228,550)
Amount available under Revolving Credit and Term Loan Facilities $ 125,300 $ 171,450
v3.25.4
Lines of Credit and Short-Term Borrowings - Additional Information (Details)
$ in Thousands
 12 Months Ended
Feb. 18, 2026
USD ($)
extensionOption
Dec. 03, 2025
USD ($)
Aug. 15, 2025
Apr. 29, 2025
USD ($)
Dec. 20, 2024
USD ($)
Dec. 05, 2024
USD ($)
Dec. 31, 2025
USD ($)
Dec. 31, 2024
USD ($)
Dec. 31, 2023
USD ($)
Dec. 17, 2024
USD ($)
Long-Term Debt and Liquidity Matters [Line Items]                    
Short-term debt repayments under term loan facility             $ 600,000 $ 350,000 $ 0  
APS                    
Long-Term Debt and Liquidity Matters [Line Items]                    
Short-term debt repayments under term loan facility             400,000 350,000 0  
Requested equity contributions limit                   $ 9,500,000
APS | ACC                    
Long-Term Debt and Liquidity Matters [Line Items]                    
Percentage of APS's capitalization used in calculation of short-term debt authorization                   7.00%
Required amount to be used in purchases of natural gas and power which is used in calculation of short-term debt authorization                   $ 500,000
Term loans | APS                    
Long-Term Debt and Liquidity Matters [Line Items]                    
Debt instrument term     364 days     364 days        
Notes issued           $ 400,000        
Debt instrument, basis spread on variable rate           0.90%        
Proceeds from issuance of unsecured debt       $ 400,000            
Revolving credit facility | Revolving Credit Facility Maturing April 2029 | APS                    
Long-Term Debt and Liquidity Matters [Line Items]                    
Current borrowing capacity on credit facility             1,250,000      
Long-term line of credit             $ 0      
Debt, weighted average interest rate             3.83%      
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders             $ 1,650,000      
Revolving credit facility | Revolving Credit Facility Maturing April 2029 | Subsequent Event | APS                    
Long-Term Debt and Liquidity Matters [Line Items]                    
Current borrowing capacity on credit facility $ 1,700,000                  
Accordion feature, increase limit $ 2,100,000                  
Number of extension options | extensionOption 2                  
Debt instrument, extension option period 1 year                  
Letter of Credit | APS                    
Long-Term Debt and Liquidity Matters [Line Items]                    
Outstanding letters of credit             30,400      
Letter of Credit | Revolving Credit Facility Maturing April 2029 | APS                    
Long-Term Debt and Liquidity Matters [Line Items]                    
Outstanding letters of credit             0      
Commercial paper                    
Long-Term Debt and Liquidity Matters [Line Items]                    
Current borrowing capacity on credit facility             1,625,000 2,050,000    
Long-term line of credit             757,005 568,450    
Commercial paper | APS                    
Long-Term Debt and Liquidity Matters [Line Items]                    
Current borrowing capacity on credit facility             1,250,000 1,650,000    
Long-term line of credit             507,305 339,900    
Maximum commercial paper support available under credit facility             1,000,000      
Commercial paper | Revolving Credit Facility Maturing April 2029 | APS                    
Long-Term Debt and Liquidity Matters [Line Items]                    
Commercial paper             507,000      
Commercial paper | Revolving Credit Facility Maturing April 2029 | Subsequent Event | APS                    
Long-Term Debt and Liquidity Matters [Line Items]                    
Current borrowing capacity on credit facility $ 1,500,000                  
Pinnacle West Consolidated                    
Long-Term Debt and Liquidity Matters [Line Items]                    
Short-term debt repayments under term loan facility             $ 200,000 0 $ 0  
Pinnacle West Consolidated | Term loans                    
Long-Term Debt and Liquidity Matters [Line Items]                    
Debt instrument term             364 days      
Notes issued             $ 200,000      
Debt instrument, basis spread on variable rate             0.95%      
Loan amount drawn         $ 200,000          
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             $ 175,000      
Debt instrument, basis spread on variable rate             0.80%      
Loan amount drawn   $ 175,000                
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             $ 200,000      
Accordion feature, increase limit             300,000      
Long-term line of credit             0      
Pinnacle West Consolidated | Revolving credit facility | Revolving Credit Facility Maturing February 2031 | Subsequent Event                    
Long-Term Debt and Liquidity Matters [Line Items]                    
Current borrowing capacity on credit facility 300,000                  
Accordion feature, increase limit $ 400,000                  
Number of extension options | extensionOption 2                  
Debt instrument, extension option period 1 year                  
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      
Pinnacle West Consolidated | Commercial paper                    
Long-Term Debt and Liquidity Matters [Line Items]                    
Current borrowing capacity on credit facility             375,000 400,000    
Long-term line of credit             249,700 $ 228,550    
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             200,000      
Commercial paper             $ 75,000      
Debt, weighted average interest rate             3.81%      
Pinnacle West Consolidated | Commercial paper | Revolving Credit Facility Maturing February 2031 | Subsequent Event                    
Long-Term Debt and Liquidity Matters [Line Items]                    
Current borrowing capacity on credit facility $ 300,000                  
v3.25.4
Long-Term Debt and Liquidity Matters - Schedule of Components of Long-Term Debt on the Consolidated Balance Sheets (Details) - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Long-Term Debt and Liquidity Matters [Line Items]    
Total long-term debt $ 9,805,676 $ 8,858,648
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 7) 9,205,676 8,058,648
Pinnacle West Consolidated    
Long-Term Debt and Liquidity Matters [Line Items]    
Total 9,868,975  
Unamortized discount (681) (5)
Unamortized debt issuance cost (8,583) (7,225)
Total long-term debt 1,665,736 1,367,770
Less current maturities 350,000 500,000
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 7) 1,315,736 867,770
APS    
Long-Term Debt and Liquidity Matters [Line Items]    
Total 8,193,975  
Unamortized discount (16,796) (14,252)
Unamortized premium 17,144 9,955
Unamortized debt issuance cost (54,383) (48,800)
Total long-term debt 8,139,940 7,490,878
Less current maturities 250,000 300,000
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 7) 7,889,940 7,190,878
Pollution Control Bonds - Variable | APS    
Long-Term Debt and Liquidity Matters [Line Items]    
Total $ 163,975 $ 163,975
Weighted-average interest rate 3.52% 4.01%
Total pollution control bonds | APS    
Long-Term Debt and Liquidity Matters [Line Items]    
Total $ 163,975 $ 163,975
Senior unsecured notes | Pinnacle West Consolidated    
Long-Term Debt and Liquidity Matters [Line Items]    
Total $ 1,325,000 1,025,000
Senior unsecured notes | Minimum | Pinnacle West Consolidated    
Long-Term Debt and Liquidity Matters [Line Items]    
Interest rate 4.75%  
Senior unsecured notes | Maximum | Pinnacle West Consolidated    
Long-Term Debt and Liquidity Matters [Line Items]    
Interest rate 5.15%  
Senior unsecured notes | APS    
Long-Term Debt and Liquidity Matters [Line Items]    
Total $ 8,030,000 7,380,000
Senior unsecured notes | APS | Minimum    
Long-Term Debt and Liquidity Matters [Line Items]    
Interest rate 2.20%  
Senior unsecured notes | APS | Maximum    
Long-Term Debt and Liquidity Matters [Line Items]    
Interest rate 6.88%  
Floating Rate Notes Due 2026 | Pinnacle West Consolidated | Unsecured Debt    
Long-Term Debt and Liquidity Matters [Line Items]    
Total $ 350,000 $ 350,000
Weighted-average interest rate 5.10% 5.88%
v3.25.4
Long-Term Debt and Liquidity Matters - Schedule of Principal Payments Due on Pinnacle West's and APS's Total Long-Term Debt (Details)
$ in Thousands
Dec. 31, 2025
USD ($)
APS  
Long-Term Debt and Liquidity Matters [Line Items]  
2026 $ 250,000
2027 300,000
2028 0
2029 568,975
2030 0
Thereafter 7,075,000
Total 8,193,975
Pinnacle West Consolidated  
Long-Term Debt and Liquidity Matters [Line Items]  
2026 600,000
2027 825,000
2028 400,000
2029 568,975
2030 400,000
Thereafter 7,075,000
Total $ 9,868,975
v3.25.4
Long-Term Debt and Liquidity Matters - Schedule of Estimated Fair Value of Long-Term Debt, Including Current Maturities (Details) - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Long-Term Debt and Liquidity Matters [Line Items]    
Carrying Amount $ 9,805,676 $ 8,858,648
Fair Value 9,164,530 7,918,992
APS    
Long-Term Debt and Liquidity Matters [Line Items]    
Carrying Amount 8,139,940 7,490,878
Fair Value 7,433,142 6,525,248
Pinnacle West Consolidated    
Long-Term Debt and Liquidity Matters [Line Items]    
Carrying Amount 1,665,736 1,367,770
Fair Value $ 1,731,388 $ 1,393,744
v3.25.4
Long-Term Debt and Liquidity Matters - Additional Information (Details) - USD ($)
$ in Thousands
 1 Months Ended 12 Months Ended
Dec. 18, 2025
Sep. 04, 2025
Aug. 15, 2025
May 15, 2025
Dec. 23, 2024
Dec. 05, 2024
Dec. 31, 2025
Sep. 30, 2025
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Jun. 30, 2024
Lines of Credit and Short-Term Borrowings                        
Number of shares issued in transaction (in shares)                 2,199,415      
Proceeds from issuance of common stock                 $ 198,176      
Maximum                        
Lines of Credit and Short-Term Borrowings                        
Ratio of consolidated debt to consolidated capitalization (as a percent)             65.00%   65.00%      
APS                        
Lines of Credit and Short-Term Borrowings                        
Equity infusion from Pinnacle West $ 75,000     $ 300,000         $ 375,000 $ 795,000 $ 150,000  
Actual ratio of consolidated debt to total consolidated capitalization required to be maintained as per the debt covenant (as a percent)             50.00%   50.00%      
Public utilities, request to permanently modify permitted yearly equity infusions                 2.50%      
Public utilities, number of basis point of approved rate             0.0050   0.0050      
Senior Unsecured Notes Maturing May 2025 | Senior Notes | APS                        
Lines of Credit and Short-Term Borrowings                        
Interest rate       3.15%                
Term loans | APS                        
Lines of Credit and Short-Term Borrowings                        
Notes issued           $ 400,000            
Repayments of unsecured debt     $ 400,000                  
Debt instrument term     364 days     364 days            
Term loans | Senior Notes | APS                        
Lines of Credit and Short-Term Borrowings                        
Repayments of unsecured debt       $ 300,000                
Senior Unsecured Notes Maturing August 2055 | Senior Notes | APS                        
Lines of Credit and Short-Term Borrowings                        
Notes issued     $ 700,000                  
Interest rate     5.90%                  
Senior Unsecured Notes Maturing August 2034 | Senior Notes                        
Lines of Credit and Short-Term Borrowings                        
Interest rate     5.70%                  
Senior Unsecured Notes Maturing August 2034 | Senior Notes | APS                        
Lines of Credit and Short-Term Borrowings                        
Debt instrument, increase (decrease), net     $ 250,000                  
Pinnacle West Consolidated                        
Lines of Credit and Short-Term Borrowings                        
Actual ratio of consolidated debt to total consolidated capitalization required to be maintained as per the debt covenant (as a percent)             60.00%   60.00%      
Pinnacle West Consolidated | Senior Unsecured Notes Maturing May 2028 | Senior Notes                        
Lines of Credit and Short-Term Borrowings                        
Notes issued       $ 400,000                
Interest rate       4.90%                
Pinnacle West Consolidated | Senior Unsecured Notes Maturing May 2025 | Senior Notes                        
Lines of Credit and Short-Term Borrowings                        
Notes issued       $ 400,000                
Interest rate       5.15%                
Pinnacle West Consolidated | Senior Notes Maturing May 2025 | Senior Notes                        
Lines of Credit and Short-Term Borrowings                        
Interest rate       1.30%                
Repayments of unsecured debt       $ 500,000                
Pinnacle West Consolidated | Convertible Notes Due Maturing June 2027 | Convertible Debt                        
Lines of Credit and Short-Term Borrowings                        
Notes issued             $ 525,000   $ 525,000     $ 525,000
Interest rate             4.75%   4.75%     4.75%
Pinnacle West Consolidated | Term loans                        
Lines of Credit and Short-Term Borrowings                        
Notes issued             $ 200,000   $ 200,000      
Debt instrument term                 364 days      
February 2024 Forward Sale Agreements                        
Lines of Credit and Short-Term Borrowings                        
Number of shares issued in transaction (in shares) 1,193,950 243,186     5,377,115   1,193,950 243,186        
Proceeds from issuance of common stock $ 75,004 $ 15,350     $ 345,049   $ 75,000 $ 15,000        
v3.25.4
Regulatory Matters - ACC General Retail Rate Cases (Details)
$ in Millions
Jun. 13, 2025
USD ($)
$ / KWH_Kilowatt_hour
Feb. 22, 2024
USD ($)
Public Utilities, General Disclosures [Line Items]    
Revenue increase (decrease)   $ 491.7
ACC    
Public Utilities, General Disclosures [Line Items]    
Recommended return on equity, percentage   9.55%
Increment of fair value rate, percentage   0.25%
ACC | Rate Case Filing with Arizona Corporation Commission | ACC    
Public Utilities, General Disclosures [Line Items]    
Base fuel and purchased power costs rate (in dollars per kWh) | $ / KWH_Kilowatt_hour 0.043881  
APS | ACC    
Public Utilities, General Disclosures [Line Items]    
Proposed base rate increase $ 579.5  
Total revenue deficiency $ 662.4  
APS | Rate Case Filing with Arizona Corporation Commission | ACC    
Public Utilities, General Disclosures [Line Items]    
Approximate percentage of increase in average residential customer bill 13.99%  
Rate matter, cost base rate $ 12,500.0  
Effective fair value percentage   4.39%
v3.25.4
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%
v3.25.4
Regulatory Matters - Cost Recovery Mechanisms (Details)
 12 Months Ended
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
Aug. 25, 2023
$ / kWh
Jul. 31, 2023
USD ($)
Jul. 01, 2023
USD ($)
$ / KWH_Kilowatt_hour
Jun. 01, 2023
USD ($)
Feb. 01, 2023
$ / kWh
Feb. 01, 2022
$ / kWh
Dec. 31, 2025
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                        
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                                    
Reporting threshold of balancing account                 $ 100,000,000                                    
Overall approved PSA rate (in dollars per kWh) | $ / kWh                 0.011977                                    
Transition component of PSA rate | $ / kWh 0.0       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                                 $ 43,200,000                    
Net Metering | ACC | APS                                                      
Public Utilities, General Disclosures [Line Items]                                                      
Rate matters, cost of service, resource comparison proxy method, maximum annual percentage decrease   10.00%       10.00%       10.00% 10.00%           10.00%                    
Third-year export energy price (in dollars per kWh) | $ / kWh   0.06171       0.06857         0.07619                                
Rate lock period                   10 years                                  
v3.25.4
Regulatory Matters - Schedule of Changes in The Deferred Fuel and Purchased Power Regulatory Asset (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Change in regulatory asset      
Deferred fuel and purchased power costs $ 324,482 $ 250,288 $ 549,877
Amounts charged to customers (463,011) (425,886) (547,243)
APS      
Change in regulatory asset      
Deferred fuel and purchased power costs 324,482 250,288 549,877
Amounts charged to customers (463,011) (425,886) (547,243)
Power Supply Adjustor (PSA) | ACC | APS      
Change in regulatory asset      
Balance at beginning of period 287,597 463,195  
Deferred fuel and purchased power costs 324,482 250,288  
Amounts charged to customers (463,011) (425,886)  
Balance at end of period $ 149,068 $ 287,597 $ 463,195
v3.25.4
Regulatory Matters - Cholla and Navajo Plant (Details) - APS - USD ($)
$ in Millions
Dec. 31, 2025
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 $ 23.6  
Navajo Plant    
Acquisition    
Net book value 23.8  
Navajo Plant, Coal Reclamation Regulatory Asset    
Acquisition    
Net book value $ 2.5  
v3.25.4
Regulatory Matters - Schedule of Regulatory Assets (Details) - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Detail of regulatory assets    
Total regulatory assets $ 1,749,366 $ 1,810,458
Less: current regulatory assets 286,009 420,969
Total non-current regulatory assets 1,463,357 1,389,489
Pension    
Detail of regulatory assets    
Total regulatory assets 723,042 750,976
Income taxes — AFUDC equity    
Detail of regulatory assets    
Total regulatory assets 203,890 192,936
Palo Verde sale leaseback noncontrolling interests acquisition    
Detail of regulatory assets    
Total regulatory assets   0
Deferred fuel and purchased power    
Detail of regulatory assets    
Total regulatory assets 149,068 287,597
Ocotillo deferral    
Detail of regulatory assets    
Total regulatory assets 99,931 114,775
Lease incentive (Note 20)    
Detail of regulatory assets    
Total regulatory assets 90,005 70,541
SCR deferral    
Detail of regulatory assets    
Total regulatory assets 77,186 83,123
Retired power plant costs    
Detail of regulatory assets    
Total regulatory assets 56,809 68,380
Income taxes — investment tax credit basis adjustment (Note 5)    
Detail of regulatory assets    
Total regulatory assets 42,459 34,834
Deferred compensation    
Detail of regulatory assets    
Total regulatory assets 32,204 33,108
Deferred fuel and purchased power — mark-to-market (Note 13)    
Detail of regulatory assets    
Total regulatory assets 29,330 42,275
FERC transmission true up    
Detail of regulatory assets    
Total regulatory assets 21,471 35,159
DSM    
Detail of regulatory assets    
Total regulatory assets 15,706 0
Deferred property taxes    
Detail of regulatory assets    
Total regulatory assets 15,349 23,918
Palo Verde VIEs (Note 12)    
Detail of regulatory assets    
Total regulatory assets 8,582 20,611
Mead-Phoenix transmission line — contributions in aid of construction    
Detail of regulatory assets    
Total regulatory assets 8,052 8,384
PSA - interest    
Detail of regulatory assets    
Total regulatory assets 5,679 11,525
Loss on reacquired debt    
Detail of regulatory assets    
Total regulatory assets 5,653 6,682
TEAM    
Detail of regulatory assets    
Total regulatory assets 3,879 4,534
Active union medical trust    
Detail of regulatory assets    
Total regulatory assets 3,696 9,673
Navajo coal reclamation    
Detail of regulatory assets    
Total regulatory assets 2,516 7,905
Other    
Detail of regulatory assets    
Total regulatory assets $ 3,353 $ 3,522
v3.25.4
Regulatory Matters - Schedule of Regulatory Liabilities (Details) - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Detail of regulatory liabilities    
Total regulatory liabilities $ 1,947,030 $ 2,062,233
Less: current regulatory liabilities 210,909 206,955
Total non-current regulatory liabilities 1,736,121 1,855,278
AROs and removal costs    
Detail of regulatory liabilities    
Total regulatory liabilities 286,907 358,403
Other postretirement benefits    
Detail of regulatory liabilities    
Total regulatory liabilities 233,952 238,113
Four Corners coal reclamation    
Detail of regulatory liabilities    
Total regulatory liabilities 97,988 77,532
Income taxes — deferred investment tax credit    
Detail of regulatory liabilities    
Total regulatory liabilities 81,949 66,327
Income taxes — change in rates    
Detail of regulatory liabilities    
Total regulatory liabilities 56,260 59,133
RES    
Detail of regulatory liabilities    
Total regulatory liabilities 54,551 68,523
DSM    
Detail of regulatory liabilities    
Total regulatory liabilities 26,228 23,927
Sundance maintenance    
Detail of regulatory liabilities    
Total regulatory liabilities 25,668 23,086
Spent nuclear fuel    
Detail of regulatory liabilities    
Total regulatory liabilities 20,492 26,818
TCA Balancing Account    
Detail of regulatory liabilities    
Total regulatory liabilities 4,860 14,834
TEAM    
Detail of regulatory liabilities    
Total regulatory liabilities 3,738 4,343
Deferred fuel and purchased power — mark-to-market (Note 13)    
Detail of regulatory liabilities    
Total regulatory liabilities 3,641 0
Other    
Detail of regulatory liabilities    
Total regulatory liabilities 3,063 4,898
ACC | Excess deferred income taxes - Tax Cuts and Jobs Act    
Detail of regulatory liabilities    
Total regulatory liabilities 847,572 888,896
FERC | Excess deferred income taxes - Tax Cuts and Jobs Act    
Detail of regulatory liabilities    
Total regulatory liabilities $ 200,161 $ 207,400
v3.25.4
Retirement Plans and Other Postretirement Benefits - Schedule of Net Periodic Benefit Costs and Portion including Portion Charged to Expense (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Amortization of:      
Portion of costs (credits) charged to expense $ (12,420) $ (48,870) $ (40,648)
Pension Plans      
Defined Benefit Plan Disclosure [Line Items]      
Service cost-benefits earned during the period 44,153 43,641 39,461
Non-service costs (credits):      
Interest cost on benefit obligation 155,121 148,643 153,561
Expected return on plan assets (178,793) (188,651) (182,938)
Amortization of:      
Prior service credit 0 0 0
Net actuarial loss (gain) 46,731 41,915 38,420
Net periodic benefit costs (credits) 67,212 45,548 48,504
Portion of costs (credits) charged to expense 38,977 23,652 27,029
Other Benefits Plans      
Defined Benefit Plan Disclosure [Line Items]      
Service cost-benefits earned during the period 8,081 9,955 8,567
Non-service costs (credits):      
Interest cost on benefit obligation 20,345 22,169 22,509
Expected return on plan assets (48,569) (46,834) (43,486)
Amortization of:      
Prior service credit (1,265) (37,789) (37,789)
Net actuarial loss (gain) (11,727) (8,676) (9,614)
Net periodic benefit costs (credits) (33,135) (61,175) (59,813)
Portion of costs (credits) charged to expense $ (25,736) $ (45,557) $ (43,408)
v3.25.4
Retirement Plans and Other Postretirement Benefits - Schedule of Changes Benefit Obligations and Funded Status (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Pension Plans      
Change in Benefit Obligation      
Benefit obligation at the beginning of the period $ 2,792,309 $ 2,908,063  
Service cost 44,153 43,641 $ 39,461
Interest cost 155,121 148,643 153,561
Benefit payments (226,888) (216,238)  
Actuarial (gain) loss 79,363 (91,800)  
Other plan changes 6,752 0  
Benefit obligation at the end of the period 2,850,810 2,792,309 2,908,063
Change in Plan Assets      
Balance at the beginning of the period 2,639,862 2,835,549  
Actual return on plan assets 244,343 4,518  
Benefit payments (213,684) (200,205)  
Balance at the end of the period 2,670,521 2,639,862 2,835,549
Funded/(Underfunded) Status at the end of the period (180,289) (152,447)  
Other Benefits Plans      
Change in Benefit Obligation      
Benefit obligation at the beginning of the period 360,090 430,434  
Service cost 8,081 9,955 8,567
Interest cost 20,345 22,169 22,509
Benefit payments (28,293) (30,516)  
Actuarial (gain) loss 7,759 (71,952)  
Other plan changes 0 0  
Benefit obligation at the end of the period 367,982 360,090 430,434
Change in Plan Assets      
Balance at the beginning of the period 702,192 696,494  
Actual return on plan assets 65,124 32,816  
Benefit payments 0 (27,118)  
Balance at the end of the period 767,316 702,192 $ 696,494
Funded/(Underfunded) Status at the end of the period $ 399,334 $ 342,102  
v3.25.4
Retirement Plans and Other Postretirement Benefits - Schedule of Projected Benefit Obligation for Pension Plans (Details) - Pension Plans - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Projected benefit obligation and the accumulated benefit obligation for pension plans with an accumulated obligation in excess of plan assets    
Accumulated benefit obligation $ 113,245 $ 113,541
Fair value of plan assets 0 0
Projected benefit obligation 2,850,810 2,792,309
Fair value of plan assets $ 2,670,521 $ 2,639,862
v3.25.4
Retirement Plans and Other Postretirement Benefits - Additional Information (Details) - USD ($)
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Defined Benefit Plan Disclosure [Line Items]      
Funded percentage 98.00% 99.00%  
Partnership funding commitments, contribution amount (up to) $ 50,000,000    
Partnership funding commitments, funded amount 38,000,000    
Pinnacle West Consolidated      
Defined Benefit Plan Disclosure [Line Items]      
Expenses recorded for the defined contribution savings plan $ 14,000,000 $ 14,000,000 $ 12,000,000
APS      
Defined Benefit Plan Disclosure [Line Items]      
APS's employees share of total cost of the plans (as a percent) 99.00%    
Pension Plans      
Defined Benefit Plan Disclosure [Line Items]      
Expected long-term return on plan assets for next fiscal year (as a percent) 6.90%    
Minimum contributions under MAP-21 $ 0    
Other Benefits Plans      
Defined Benefit Plan Disclosure [Line Items]      
Expected long-term return on plan assets for next fiscal year (as a percent) 7.00%    
Retiree medical cost reimbursement   $ 27,000,000 $ 23,000,000
v3.25.4
Retirement Plans and Other Postretirement Benefits - Schedule of Amounts Recognized on the Consolidated Balance Sheets (Details) - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Amounts recognized on the Consolidated Balance Sheets    
Noncurrent asset $ 399,334 $ 342,102
Pension Plans    
Amounts recognized on the Consolidated Balance Sheets    
Noncurrent asset 0 0
Current liability (12,653) (13,130)
Noncurrent liability (167,636) (139,317)
Net amount recognized (funded status) (180,289) (152,447)
Other Benefits Plans    
Amounts recognized on the Consolidated Balance Sheets    
Noncurrent asset 399,334 342,102
Current liability 0 0
Noncurrent liability 0 0
Net amount recognized (funded status) $ 399,334 $ 342,102
v3.25.4
Retirement Plans and Other Postretirement Benefits - Schedule of Impact to Accumulated Other Comprehensive Loss (Details) - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Pension Plans    
Details related to accumulated other comprehensive loss    
Net actuarial loss (gain) $ 760,502 $ 793,421
Prior service cost (credit) 6,752 0
APS’s portion recorded as a regulatory (asset) liability (723,042) (750,976)
Income tax expense (benefit) (10,929) (10,354)
Accumulated other comprehensive loss (gain) 33,283 32,091
Other Benefits Plans    
Details related to accumulated other comprehensive loss    
Net actuarial loss (gain) (234,958) (237,889)
Prior service cost (credit) 0 (1,265)
APS’s portion recorded as a regulatory (asset) liability 233,952 238,113
Income tax expense (benefit) 703 611
Accumulated other comprehensive loss (gain) $ (303) $ (430)
v3.25.4
Retirement Plans and Other Postretirement Benefits - Schedule of Weighted-Average Assumptions for Pensions and Other Benefits (Details)
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Weighted-average assumptions used to determine benefit obligations      
Rate of compensation increase 4.50% 4.50%  
Initial healthcare cost trend rate (pre-65 participants) 6.50% 6.50%  
Ultimate healthcare cost trend rate (pre-65 participants) 4.50% 4.50%  
Number of years to ultimate trend rate (pre-65 participants) 7 years 6 years  
Initial healthcare cost trend rate (post-65 participants)   1.00%  
Ultimate healthcare cost trend rate (post-65 participants)   0.00%  
Interest crediting rate – cash balance pension plans 4.51% 4.66%  
Weighted-average assumptions used to determine net periodic benefit costs      
Initial healthcare cost trend rate (pre-65 participants) 6.50% 6.25% 6.50%
Ultimate healthcare cost trend rate (pre-65 participants) 4.50% 4.75% 4.75%
Number of years to ultimate trend rate (pre-65 participants) 6 years 4 years 5 years
Initial healthcare cost trend rate (post-65 participants) 1.00% 2.00% 2.00%
Ultimate healthcare cost trend rate (post-65 participants)   2.00% 2.00%
Interest crediting rate – cash balance pension plans 4.66% 4.54% 4.50%
Pension Plans      
Weighted-average assumptions used to determine benefit obligations      
Discount rate 5.36% 5.68%  
Weighted-average assumptions used to determine net periodic benefit costs      
Discount rate 5.68% 5.21% 5.56%
Rate of compensation increase 4.50% 4.52% 4.57%
Expected long-term return on plan assets 7.05% 6.90% 6.70%
Other Benefits Plans      
Weighted-average assumptions used to determine benefit obligations      
Discount rate 5.43% 5.71%  
Weighted-average assumptions used to determine net periodic benefit costs      
Discount rate 5.71% 5.23% 5.58%
Expected long-term return on plan assets 7.05% 6.85% 6.80%
Increase in post-65 health care cost trend rate assumed for next fiscal year 1.00%    
v3.25.4
Retirement Plans and Other Postretirement Benefits - Schedule of Fair Value of Pension Plan and Other Postretirement Benefit Plan Assets, by Asset Category (Details)
Dec. 31, 2025
Pension Plans  
Defined Benefit Plan Disclosure [Line Items]  
Target Allocation 100.00%
Actual Allocation 100.00%
Pension Plans | Long-term fixed income assets  
Defined Benefit Plan Disclosure [Line Items]  
Target Allocation 80.00%
Actual Allocation 78.00%
Pension Plans | Return-seeking assets  
Defined Benefit Plan Disclosure [Line Items]  
Target Allocation 20.00%
Actual Allocation 22.00%
Target Allocation 20.00%
Pension Plans | Equities in US and other developed markets  
Defined Benefit Plan Disclosure [Line Items]  
Target Allocation 12.00%
Pension Plans | Equities in emerging markets  
Defined Benefit Plan Disclosure [Line Items]  
Target Allocation 4.00%
Pension Plans | Alternative investments  
Defined Benefit Plan Disclosure [Line Items]  
Target Allocation 4.00%
Other Benefits Plans  
Defined Benefit Plan Disclosure [Line Items]  
Actual Allocation 100.00%
Other Benefits Plans | Long-term fixed income assets  
Defined Benefit Plan Disclosure [Line Items]  
Actual Allocation 59.00%
Other Benefits Plans | Return-seeking assets  
Defined Benefit Plan Disclosure [Line Items]  
Actual Allocation 41.00%
v3.25.4
Retirement Plans and Other Postretirement Benefits - Schedule of Fair Value of Pinnacle West's Pension Plan (Details) - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Pension Plans      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Other $ 451,472 $ 432,742  
Fair value of plan assets 2,670,521 2,639,862 $ 2,835,549
Pension Plans | Level 1      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Gross fair value of plan assets 798,403 748,033  
Pension Plans | Level 2      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Gross fair value of plan assets 1,420,646 1,459,087  
Other Benefits Plans      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Other 193,845 165,813  
Fair value of plan assets 767,316 702,192 $ 696,494
Other Benefits Plans | Level 1      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Gross fair value of plan assets 362,005 337,359  
Other Benefits Plans | Level 2      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Gross fair value of plan assets 211,466 199,020  
Cash and cash equivalents | Pension Plans      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Other 0 0  
Fair value of plan assets 1,756 9,055  
Cash and cash equivalents | Pension Plans | Level 1      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Gross fair value of plan assets 1,756 9,055  
Cash and cash equivalents | Pension Plans | Level 2      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Gross fair value of plan assets 0 0  
Cash and cash equivalents | Other Benefits Plans      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Other 0 0  
Fair value of plan assets 475 840  
Cash and cash equivalents | Other Benefits Plans | Level 1      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Gross fair value of plan assets 475 840  
Cash and cash equivalents | Other Benefits Plans | Level 2      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Gross fair value of plan assets 0 0  
Corporate | Pension Plans      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Other 0 0  
Fair value of plan assets 1,300,163 1,325,833  
Corporate | Pension Plans | Level 1      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Gross fair value of plan assets 0 0  
Corporate | Pension Plans | Level 2      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Gross fair value of plan assets 1,300,163 1,325,833  
Corporate | Other Benefits Plans      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Other 0 0  
Fair value of plan assets 200,469 186,435  
Corporate | Other Benefits Plans | Level 1      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Gross fair value of plan assets 0 0  
Corporate | Other Benefits Plans | Level 2      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Gross fair value of plan assets 200,469 186,435  
U.S. Treasury | Pension Plans      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Other 0 0  
Fair value of plan assets 607,621 561,317  
U.S. Treasury | Pension Plans | Level 1      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Gross fair value of plan assets 607,621 561,317  
U.S. Treasury | Pension Plans | Level 2      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Gross fair value of plan assets 0 0  
U.S. Treasury | Other Benefits Plans      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Other 0 0  
Fair value of plan assets 165,294 204,274  
U.S. Treasury | Other Benefits Plans | Level 1      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Gross fair value of plan assets 165,294 204,274  
U.S. Treasury | Other Benefits Plans | Level 2      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Gross fair value of plan assets 0 0  
Other | Pension Plans      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Other 0 0  
Fair value of plan assets 120,483 133,254  
Other | Pension Plans | Level 1      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Gross fair value of plan assets 0 0  
Other | Pension Plans | Level 2      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Gross fair value of plan assets 120,483 133,254  
Other | Other Benefits Plans      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Other 0 0  
Fair value of plan assets 10,997 12,585  
Other | Other Benefits Plans | Level 1      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Gross fair value of plan assets 0 0  
Other | Other Benefits Plans | Level 2      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Gross fair value of plan assets 10,997 12,585  
Common stock equities | Pension Plans      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Other 0 0  
Fair value of plan assets 73,548 74,939  
Common stock equities | Pension Plans | Level 1      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Gross fair value of plan assets 73,548 74,939  
Common stock equities | Pension Plans | Level 2      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Gross fair value of plan assets 0 0  
Common stock equities | Other Benefits Plans      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Other 0 0  
Fair value of plan assets 98,296 89,685  
Common stock equities | Other Benefits Plans | Level 1      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Gross fair value of plan assets 98,296 89,685  
Common stock equities | Other Benefits Plans | Level 2      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Gross fair value of plan assets 0 0  
Mutual funds | Pension Plans      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Other 0 0  
Fair value of plan assets 115,478 102,722  
Mutual funds | Pension Plans | Level 1      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Gross fair value of plan assets 115,478 102,722  
Mutual funds | Pension Plans | Level 2      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Gross fair value of plan assets 0 0  
Mutual funds | Other Benefits Plans      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Other 0 0  
Fair value of plan assets 27,986 23,415  
Mutual funds | Other Benefits Plans | Level 1      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Gross fair value of plan assets 27,986 23,415  
Mutual funds | Other Benefits Plans | Level 2      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Gross fair value of plan assets 0 0  
Equities | Pension Plans      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Other 266,624 244,734  
Fair value of plan assets 266,624 244,734  
Equities | Pension Plans | Level 1      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Gross fair value of plan assets 0 0  
Equities | Pension Plans | Level 2      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Gross fair value of plan assets 0 0  
Equities | Other Benefits Plans      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Other 167,103 140,178  
Fair value of plan assets 167,103 140,178  
Equities | Other Benefits Plans | Level 1      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Gross fair value of plan assets 0 0  
Equities | Other Benefits Plans | Level 2      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Gross fair value of plan assets 0 0  
Real estate | Pension Plans      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Other 114,782 127,397  
Fair value of plan assets 114,782 127,397  
Real estate | Pension Plans | Level 1      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Gross fair value of plan assets 0 0  
Real estate | Pension Plans | Level 2      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Gross fair value of plan assets 0 0  
Real estate | Other Benefits Plans      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Other 20,228 19,474  
Fair value of plan assets 20,228 19,474  
Real estate | Other Benefits Plans | Level 1      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Gross fair value of plan assets 0 0  
Real estate | Other Benefits Plans | Level 2      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Gross fair value of plan assets 0 0  
Other | Pension Plans      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Other 70,066 60,611  
Fair value of plan assets 70,066 60,611  
Other | Pension Plans | Level 1      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Gross fair value of plan assets 0 0  
Other | Pension Plans | Level 2      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Gross fair value of plan assets 0 0  
Other | Other Benefits Plans      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Other 6,514 6,161  
Fair value of plan assets 76,468 25,306  
Other | Other Benefits Plans | Level 1      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Gross fair value of plan assets 69,954 19,145  
Other | Other Benefits Plans | Level 2      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Gross fair value of plan assets $ 0 $ 0  
v3.25.4
Retirement Plans and Other Postretirement Benefits - Schedule of Estimated Future Benefit Payments (Details)
$ in Thousands
Dec. 31, 2025
USD ($)
Pension Plans  
Estimated Future Benefit Payments  
2026 $ 244,947
2027 232,977
2028 235,256
2029 235,980
2030 235,953
Years 2031-2035 1,149,488
Other Benefits Plans  
Estimated Future Benefit Payments  
2026 28,075
2027 27,751
2028 27,443
2029 27,357
2030 27,206
Years 2031-2035 $ 137,689
v3.25.4
Stock-Based Compensation - Additional Information (Details)
shares in Millions, $ in Millions
 12 Months Ended
Dec. 31, 2025
USD ($)
criteria
shares
Dec. 31, 2024
USD ($)
Dec. 31, 2023
USD ($)
Dec. 31, 2022
Dec. 31, 2021
performanceCriterion
Stock-Based Compensation          
Compensation cost that has been charged against income $ 27 $ 24 $ 17    
Total income tax benefit recognized 12 6 3    
Total unrecognized compensation cost related to nonvested share-based compensation arrangements granted $ 42        
Expected weighted-average period of recognition of unrecognized compensation cost 2 years        
Total fair value of shares vested $ 27 24 24    
Performance Share Awards          
Performance period 3 years        
Number of unrelated performance element criteria | criteria 3        
Number of performance element criteria | performanceCriterion         2
Minimum          
Performance Share Awards          
Exact number of shares issued as a percentage of the target award 0.00%       0.00%
Maximum          
Performance Share Awards          
Exact number of shares issued as a percentage of the target award 200.00%       200.00%
Restricted Stock Units          
Stock-Based Compensation          
Share-based liabilities paid $ 14 8 6    
Cash flow effect, cash used to settle awards $ 1 $ 2 $ 3    
Restricted Stock Units, Stock Grants and Stock Units          
Vesting period 4 years        
Percentage of cash that the participant may elect as a dividend for the first option available under the plan         50.00%
Percentage of stock that the participant may elect as dividend under second option of plan         50.00%
Officers and Key Employees | Restricted Stock Units          
Restricted Stock Units, Stock Grants and Stock Units          
Percentage of fully transferable shares of stock that the participant may elect as a deferral for the first option available under the plan         100.00%
Percentage of fully transferable shares of stock in that participant may receive cash         100.00%
Non-Officer Board of Director Member | Restricted Stock Units          
Restricted Stock Units, Stock Grants and Stock Units          
Percentage of fully transferable shares of stock that the participant may elect as a deferral for the first option available under the plan       100.00%  
Percentage of cash that the participant may elect as a dividend for the first option available under the plan       100.00%  
Percentage of stock that the participant may elect as dividend under second option of plan       50.00%  
Percentage of fully transferable shares of stock that the participant may elect as a dividend equivalent deferral for the first option available under the plan       50.00%  
2021 Plan          
Stock-Based Compensation          
Common shares authorized for issuance (in shares) | shares 4.3        
Common shares available for grant (in shares) | shares 2.5        
v3.25.4
Stock-Based Compensation - Schedule of Restricted Stock Units, Stock Grants and Stock Units (Details) - $ / shares
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Restricted Stock Units, Stock Grants, and Stock Units      
Stocks granted and the weighted average fair value      
Units granted (in shares) 204,886 261,808 192,295
Weighted-average grant date fair value (in dollars per share) $ 90.25 $ 71.10 $ 74.32
Performance Shares      
Stocks granted and the weighted average fair value      
Units granted (in shares) 164,220 225,516 202,562
Weighted-average grant date fair value (in dollars per share) $ 97.72 $ 72.89 $ 79.61
v3.25.4
Stock-Based Compensation - Schedule of Nonvested Performance Shares (Details) - $ / shares
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Restricted Stock Units, Stock Grants, and Stock Units      
Shares      
Balance at the beginning of the period (in shares) 460,791    
Granted (in shares) 204,886 261,808 192,295
Vested (in shares) (186,883)    
Forfeited (in shares) (15,856)    
Balance at the end of the period (in shares) 462,938 460,791  
Weighted-Average Grant Date Fair Value      
Balance at the beginning of the period (in dollars per share) $ 71.72    
Granted (in dollars per share) 90.25 $ 71.10 $ 74.32
Vested (in dollars per share) 73.77    
Forfeited (in dollars per share) 79.59    
Balance at the end of the period (in dollars per share) $ 78.82 $ 71.72  
Vested awards outstanding at end of year (in shares) 76,758    
Number of nonvested awards to be settled in cash (in shares) 0    
Performance Shares      
Shares      
Balance at the beginning of the period (in shares) 390,551    
Granted (in shares) 164,220 225,516 202,562
Vested (in shares) (169,682)    
Forfeited (in shares) (13,535)    
Balance at the end of the period (in shares) 371,554 390,551  
Weighted-Average Grant Date Fair Value      
Balance at the beginning of the period (in dollars per share) $ 77.29    
Granted (in dollars per share) 97.72 $ 72.89 $ 79.61
Vested (in dollars per share) 77.94    
Forfeited (in dollars per share) 85.01    
Balance at the end of the period (in dollars per share) $ 83.48 $ 77.29  
Vested awards outstanding at end of year (in shares) 169,682    
v3.25.4
Jointly-Owned Facilities (Details) - APS
$ in Thousands
Dec. 31, 2025
USD ($)
Palo Verde Units 1 and 3  
Interests in jointly-owned facilities  
Percent Owned 29.10%
Plant in Service $ 2,094,060
Accumulated Depreciation 1,079,823
Construction Work in Progress $ 13,230
Palo Verde Unit 2  
Interests in jointly-owned facilities  
Percent Owned 23.90%
Plant in Service $ 925,562
Accumulated Depreciation 567,731
Construction Work in Progress $ 7,343
Palo Verde Common  
Interests in jointly-owned facilities  
Percent Owned 26.20%
Plant in Service $ 977,526
Accumulated Depreciation 431,023
Construction Work in Progress 58,899
Palo Verde sale leaseback  
Interests in jointly-owned facilities  
Plant in Service 142,921
Accumulated Depreciation 110,886
Construction Work in Progress $ 0
Four Corners Generating Station  
Interests in jointly-owned facilities  
Percent Owned 63.00%
Plant in Service $ 1,941,053
Accumulated Depreciation 747,931
Construction Work in Progress $ 19,378
Arizona Nuclear Power Project 500kV System  
Interests in jointly-owned facilities  
Percent Owned 33.10%
Plant in Service $ 141,348
Accumulated Depreciation 60,579
Construction Work in Progress $ 5,350
Navajo Southern System  
Interests in jointly-owned facilities  
Percent Owned 25.10%
Plant in Service $ 89,856
Accumulated Depreciation 40,548
Construction Work in Progress $ 1,645
Palo Verde — Yuma 500kV System  
Interests in jointly-owned facilities  
Percent Owned 16.10%
Plant in Service $ 44,505
Accumulated Depreciation 9,060
Construction Work in Progress $ 136
Four Corners Switchyards  
Interests in jointly-owned facilities  
Percent Owned 56.90%
Plant in Service $ 86,706
Accumulated Depreciation 25,810
Construction Work in Progress $ 118
Phoenix — Mead System  
Interests in jointly-owned facilities  
Percent Owned 17.50%
Plant in Service $ 36,290
Accumulated Depreciation 19,568
Construction Work in Progress $ 609
Palo Verde — Rudd 500kV System  
Interests in jointly-owned facilities  
Percent Owned 50.00%
Plant in Service $ 96,428
Accumulated Depreciation 35,842
Construction Work in Progress $ 3,343
Morgan — Pinnacle Peak System  
Interests in jointly-owned facilities  
Percent Owned 63.20%
Plant in Service $ 119,104
Accumulated Depreciation 31,283
Construction Work in Progress $ 75
Round Valley System  
Interests in jointly-owned facilities  
Percent Owned 50.00%
Plant in Service $ 548
Accumulated Depreciation 224
Construction Work in Progress $ 0
Palo Verde — Morgan System  
Interests in jointly-owned facilities  
Percent Owned 87.50%
Plant in Service $ 268,202
Accumulated Depreciation 52,822
Construction Work in Progress $ 392
Hassayampa — North Gila System  
Interests in jointly-owned facilities  
Percent Owned 80.00%
Plant in Service $ 154,329
Accumulated Depreciation 31,361
Construction Work in Progress $ 0
Cholla 500kV Switchyard  
Interests in jointly-owned facilities  
Percent Owned 85.70%
Plant in Service $ 8,456
Accumulated Depreciation 3,114
Construction Work in Progress $ 190
Saguaro 500kV Switchyard  
Interests in jointly-owned facilities  
Percent Owned 60.00%
Plant in Service $ 42,795
Accumulated Depreciation 16,324
Construction Work in Progress $ 800
Kyrene — Knox System  
Interests in jointly-owned facilities  
Percent Owned 50.00%
Plant in Service $ 578
Accumulated Depreciation 359
Construction Work in Progress $ 0
v3.25.4
Variable Interest Entities - Additional Information (Details)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
USD ($)
trust
Sep. 22, 2025
USD ($)
trust
Dec. 31, 2026
USD ($)
Dec. 31, 2025
USD ($)
trust
Dec. 31, 2024
USD ($)
Dec. 31, 2023
USD ($)
Sep. 30, 2025
USD ($)
trust
Jun. 30, 2025
trust
Dec. 31, 1986
trust
Palo Verde Sale Leaseback Variable Interest Entities                  
Net income attributable to noncontrolling interest       $ 15,112 $ 17,224 $ 17,224      
Regulatory asset $ 1,749,366     1,749,366 1,810,458        
Property plant and equipment 18,358,275     18,358,275 16,833,524        
Palo Verde VIE acquisition (Note 8)                  
Palo Verde Sale Leaseback Variable Interest Entities                  
Regulatory asset         0        
APS                  
Palo Verde Sale Leaseback Variable Interest Entities                  
Net income attributable to noncontrolling interest       15,112 17,224 17,224      
Special use fund         34,200        
Property, plant and equipment, net, reclassified from sale leaseback transaction 47,000     47,000     $ 47,000    
Property plant and equipment 18,358,275     18,358,275 16,833,524        
APS | Palo Verde VIE acquisition (Note 8)                  
Palo Verde Sale Leaseback Variable Interest Entities                  
Regulatory asset $ 151,506     151,506     $ 152,000    
Variable Interest Entity                  
Palo Verde Sale Leaseback Variable Interest Entities                  
Net income attributable to noncontrolling interest       5,000 5,000 0      
Variable Interest Entity | APS                  
Palo Verde Sale Leaseback Variable Interest Entities                  
Net income attributable to noncontrolling interest       $ 15,000 17,000 $ 17,000      
Number of VIE lessor trusts | trust 1     1       2 3
Number of VIE lessor trusts acquired | trust   2         2    
Number of VIE lessor trusts terminated | trust   2         2    
VIE, acquisition price   $ 199,000              
Number of VIE lessor trusts no longer consolidated | 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 | Palo Verde Unit 2                  
Palo Verde Sale Leaseback Variable Interest Entities                  
Ownership percentage       23.90%          
Leased interest percentage 5.20%                
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 | Pinnacle West Captive Insurance Cell                  
Palo Verde Sale Leaseback Variable Interest Entities                  
Special use fund $ 40,000     $ 40,000 $ 34,000        
v3.25.4
Variable Interest Entities - Schedule of Amounts Relating to the VIEs Included in Consolidated Balance Sheets (Details) - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Palo Verde Sale Leaseback Variable Interest Entities    
Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation $ 20,720,104 $ 19,197,899
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets    
Equity — Noncontrolling interests 40,617 103,167
APS    
Palo Verde Sale Leaseback Variable Interest Entities    
Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation 20,719,949 19,197,743
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets    
Equity — Noncontrolling interests 40,617 103,167
Palo Verde VIE | APS    
Palo Verde Sale Leaseback Variable Interest Entities    
Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation 32,035 82,556
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets    
Equity — Noncontrolling interests $ 40,617 $ 103,167
v3.25.4
Derivative Accounting - Additional Information (Details)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
USD ($)
counterparty
Dec. 31, 2024
USD ($)
Derivative [Line Items]    
Number of counterparties | counterparty 4  
Commodity Contracts    
Derivative [Line Items]    
Derivative asset $ 8,387 $ 16,558
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 73.00%  
APS    
Derivative [Line Items]    
Percentage of unrealized gains and losses on certain derivatives deferred for future rate treatment before accounting treatment change 100.00%  
v3.25.4
Derivative Accounting - Schedule of Outstanding Gross Notional Amounts Outstanding (Details) - Commodity Contracts
MWh in Thousands
 12 Months Ended
Dec. 31, 2025
MWh
Bcf
Dec. 31, 2024
MWh
Bcf
Outstanding gross notional amount of derivatives    
Power | MWh 542 1,051
Gas | Bcf 211,000 235,000
v3.25.4
Derivative Accounting - Schedule of Gains and Losses from Derivative Instruments (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Commodity Contracts | Fuel and purchased power | Not Designated as Hedging Instruments      
Derivative Instruments Not Designated as Cash Flows Hedges      
Net Loss Recognized in Income $ (50,566) $ (88,522) $ (370,145)
v3.25.4
Derivative Accounting - Schedule of Derivative Instruments in the Balance Sheet (Details) - Commodity Contracts - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Assets    
Gross Recognized Derivatives $ 19,347 $ 20,328
Amounts Offset (10,965) (3,788)
Net Recognized Derivatives 8,382 16,540
Other 5 18
Derivative asset, total 8,387 16,558
Liabilities    
Gross Recognized Derivatives (45,035) (62,603)
Amounts Offset 10,965 3,788
Net Recognized Derivatives (34,070) (58,815)
Other (2,566) (2,971)
Derivative liability, total (36,636) (61,786)
Assets and Liabilities    
Gross Recognized Derivatives (25,688) (42,275)
Amounts Offset 0 0
Net Recognized Derivatives (25,688) (42,275)
Other (2,561) (2,953)
Amounts  Reported on  Balance Sheets (28,249) (45,228)
Current assets    
Assets    
Gross Recognized Derivatives 12,640 13,718
Amounts Offset (9,395) (3,158)
Net Recognized Derivatives 3,245 10,560
Other 5 18
Derivative asset, total 3,250 10,578
Investments and other assets    
Assets    
Gross Recognized Derivatives 6,707 6,610
Amounts Offset (1,570) (630)
Net Recognized Derivatives 5,137 5,980
Other 0 0
Derivative asset, total 5,137 5,980
Current liabilities    
Liabilities    
Gross Recognized Derivatives (41,970) (52,527)
Amounts Offset 9,395 3,158
Net Recognized Derivatives (32,575) (49,369)
Other (2,566) (2,971)
Derivative liability, total (35,141) (52,340)
Deferred credits and other    
Liabilities    
Gross Recognized Derivatives (3,065) (10,076)
Amounts Offset 1,570 630
Net Recognized Derivatives (1,495) (9,446)
Other 0 0
Derivative liability, total $ (1,495) $ (9,446)
v3.25.4
Derivative Accounting - Schedule of Credit Risk and Related Contingent Features (Details) - Commodity Contracts
$ in Thousands
Dec. 31, 2025
USD ($)
Credit Risk and Credit-Related Contingent Features  
Aggregate fair value of derivative instruments in a net liability position $ 45,035
Additional cash collateral in the event credit-risk related contingent features were fully triggered $ 11,171
v3.25.4
Commitments and Contingencies - Additional Information (Details)
$ in Millions
 1 Months Ended 12 Months Ended 160 Months Ended
Oct. 31, 2025
USD ($)
Jan. 01, 2024
USD ($)
trust
Jan. 17, 2023
USD ($)
Feb. 25, 2026
USD ($)
Dec. 31, 2025
USD ($)
timePeriod
trust
Oct. 31, 2024
claim
Jan. 31, 2026
USD ($)
Jul. 11, 2025
operator
Dec. 31, 2024
USD ($)
Schedule of Commitments and Contingencies [Line Items]                  
Purchase obligations         $ 11,400.0        
Production tax credit guarantees         26.3        
Subsequent Event                  
Schedule of Commitments and Contingencies [Line Items]                  
Purchase obligations             $ 694.0    
Arizona Public Service Company and Palo Verde Owners vs. United States Department of Energy - Spent Nuclear Fuel and Waste Disposal                  
Schedule of Commitments and Contingencies [Line Items]                  
Settlement amount, awarded to company         $ 174.3        
Settlement amount, sought $ 15.4                
Arizona Public Service Company and Palo Verde Owners vs. United States Department of Energy - Spent Nuclear Fuel and Waste Disposal | Subsequent Event                  
Schedule of Commitments and Contingencies [Line Items]                  
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         24.2        
Collateral assurance based on rating triggers         $ 66.4        
Period to provide collateral assurance based on rating triggers         20 days        
Number of power plant operators | operator               25  
2026         $ 1,811.0        
2027         1,988.0        
2028         2,149.0        
2029         2,146.0        
2030         2,392.0        
Thereafter         32,200.0        
APS | Surety Bonds Expiring in 2028                  
Schedule of Commitments and Contingencies [Line Items]                  
Surety bonds expiring, amount         23.3        
APS | Letter of Credit                  
Schedule of Commitments and Contingencies [Line Items]                  
Outstanding letters of credit         30.4        
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 | Renewable Energy Credits                  
Schedule of Commitments and Contingencies [Line Items]                  
2026         24.0        
2027         21.0        
2028         18.0        
2029         16.0        
2030         14.0        
Thereafter         21.0        
APS | Coal Mine Reclamation Balance Sheet Obligations                  
Schedule of Commitments and Contingencies [Line Items]                  
Purchase obligations         160.0       $ 171.0
APS | Coal Mine Reclamation Obligations                  
Schedule of Commitments and Contingencies [Line Items]                  
2026         21.0        
2027         22.0        
2028         $ 23.0        
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%        
v3.25.4
Commitments and Contingencies - Schedule of Estimated Coal Take-or-pay Commitments and Actual Amount Purchased (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Fuel and Purchased Power Commitments and Purchase Obligations [Abstract]      
Lease not yet commenced $ 11,400,000    
APS      
Fuel and Purchased Power Commitments and Purchase Obligations [Abstract]      
2026 1,811,000    
2027 1,988,000    
2028 2,149,000    
2029 2,146,000    
2030 2,392,000    
Thereafter 32,200,000    
APS | Coal Take-or-Pay Commitments      
Fuel and Purchased Power Commitments and Purchase Obligations [Abstract]      
2026 206,489    
2027 206,813    
2028 213,825    
2029 221,098    
2030 228,639    
Thereafter 236,461    
Lease not yet commenced $ 1,300,000    
Present value of commitments discount rate 4.81%    
Present value of commitments $ 1,100,000    
Total purchases $ 213,113 $ 237,821 $ 255,219
v3.25.4
Other Income and Other Expense (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Other income:      
Interest income $ 18,037 $ 24,322 $ 27,242
Investment gain — net 26,720 0 0
Gain on sale of BCE (Note 22) 0 22,988 6,205
Miscellaneous 4,649 1,304 219
Total other income 49,406 48,614 33,666
Other expense:      
Non-operating costs (21,332) (27,370) (15,260)
Investment losses — net 0 (1,418) (3,402)
Miscellaneous (8,933) (5,348) (6,394)
Total other expense (30,265) (34,136) (25,056)
APS      
Other income:      
Interest income 15,933 21,088 26,853
Miscellaneous 281 6 219
Total other income 16,214 21,094 27,072
Other expense:      
Non-operating costs (19,650) (26,588) (14,070)
Miscellaneous (6,732) (3,110) (4,194)
Total other expense $ (26,382) $ (29,698) $ (18,264)
v3.25.4
Common Stock Equity and Earnings Per Share - Additional Information (Details)
$ / shares in Units, $ in Thousands
 1 Months Ended 12 Months Ended
Jun. 30, 2024
USD ($)
day
Dec. 31, 2025
USD ($)
agreement
$ / shares
shares
May 22, 2025
shares
May 21, 2025
shares
Dec. 31, 2024
shares
Nov. 08, 2024
USD ($)
Subsidiary or Equity Method Investee [Line Items]            
Unsettled proceeds   $ 200,000        
Common stock, authorized (in shares) | shares   300,000,000 300,000,000 150,000,000 150,000,000  
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            
Subsidiary or Equity Method Investee [Line Items]            
Long-term debt   $ 9,868,975        
Pinnacle West Consolidated | Convertible Notes Due Maturing June 2027 | Convertible Debt            
Subsidiary or Equity Method Investee [Line Items]            
Notes issued $ 525,000 $ 525,000        
Interest rate 4.75% 4.75%        
Debt instrument, convertible, conversion price (in dollars per share) | $ / shares   $ 92.30        
Debt instrument redemption price percentage   100.00%        
Long-term debt   $ 525,000        
Unamortized debt issuance expense   4,000        
Convertible debt, fair value   561,000        
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   700,000       $ 900,000
Fifth ATM Forward Sale Agreement            
Subsidiary or Equity Method Investee [Line Items]            
Value of shares to be issued under ATM program   $ 10,700        
At the Market Offering            
Subsidiary or Equity Method Investee [Line Items]            
Number of outstanding forward sale agreements | agreement   4        
v3.25.4
Common Stock Equity and Earnings Per Share - Schedule of ATM Program (Details) - USD ($)
$ / shares in Units, $ in Thousands
 1 Months Ended 12 Months Ended
Dec. 18, 2025
Sep. 04, 2025
Dec. 23, 2024
Dec. 31, 2025
Sep. 30, 2025
Feb. 28, 2024
Dec. 31, 2025
Nov. 08, 2024
Subsidiary or Equity Method Investee [Line Items]                
Number of Shares (in shares)             2,199,415  
Forward Sales Price Per Share (in dollars per share)       $ 90.10     $ 90.10  
Aggregate Value (in thousands)             $ 198,176  
ATM Program                
Subsidiary or Equity Method Investee [Line Items]                
Initial Price, Aggregate Value       $ 700,000     $ 700,000 $ 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     $ 89.73  
Aggregate Value (in thousands)             $ 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     $ 90.83  
Aggregate Value (in thousands)             $ 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     $ 91.21  
Aggregate Value (in thousands)             $ 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     $ 88.69  
Aggregate Value (in thousands)             $ 49,544  
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 1,193,950 243,186      
Forward Sales Price Per Share (in dollars per share) $ 62.82 $ 63.12 $ 64.17     $ 64.51    
Aggregate Value (in thousands) $ 75,004 $ 15,350 $ 345,049 $ 75,000 $ 15,000      
v3.25.4
Common Stock Equity and Earnings Per Share - Schedule of Earnings Per Share, Basic and Diluted (Details) - USD ($)
$ / shares in Units, $ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]      
Net income attributable to common shareholders $ 616,531 $ 608,806 $ 501,557
Weighted average common shares outstanding — basic (in shares) 119,687,000 113,846,000 113,442,000
Net effect of dilutive securities:      
Contingently issuable performance shares and restricted stock units (in shares) 568,000 480,000 362,000
Dilutive shares related to equity forward sale agreements (in shares) 1,716,000 1,906,000 0
Total contingently issuable shares (in shares) 2,284,000 2,386,000 362,000
Weighted average common shares outstanding — diluted (in shares) 121,971,000 116,232,000 113,804,000
Earnings per weighted-average common share outstanding      
Net income attributable to common shareholders — basic (in dollars per share) $ 5.15 $ 5.35 $ 4.42
Net income attributable to common shareholders — diluted (in dollars per share) $ 5.05 $ 5.24 $ 4.41
Convertible Notes Payable      
Earnings per weighted-average common share outstanding      
Antidilutive securities excluded from computation of EPS (in shares) 148,098 1,038,463 0
v3.25.4
Fair Value Measurements - Schedule of Assets and Liabilities Measured on a Recurring Basis (Details) - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
ASSETS    
Cash equivalents   $ 23
Nuclear decommissioning trusts: $ 1,414,166 1,282,845
Nuclear decommissioning trust, other 496,793 426,404
Other special use funds: 434,827 408,357
Other special use funds, other 3,199 2,851
Total assets 1,857,380 1,707,783
Total assets, other 489,032 425,485
Commodity contracts    
ASSETS    
Commodity contracts, other (10,960) (3,770)
Derivative asset, total 8,387 16,558
LIABILITIES    
Derivative instruments, other 8,399 817
Derivative liability, total (36,636) (61,786)
Cash equivalents    
ASSETS    
Other special use funds:   25,000
Other special use funds, other   0
Equity securities    
ASSETS    
Nuclear decommissioning trusts: 15,171 15,736
Nuclear decommissioning trust, other (3,799) 3,335
Other special use funds: 65,772 27,813
Other special use funds, other 3,199 2,851
U.S. commingled equity funds    
ASSETS    
Nuclear decommissioning trusts: 500,592 423,069
U.S. Treasury debt    
ASSETS    
Nuclear decommissioning trusts: 364,943 367,396
Other special use funds: 369,055 355,544
Corporate debt    
ASSETS    
Nuclear decommissioning trusts: 242,176 203,180
Mortgage-backed securities    
ASSETS    
Nuclear decommissioning trusts: 230,695 208,533
Municipal bonds    
ASSETS    
Nuclear decommissioning trusts: 37,572 37,429
Other fixed income    
ASSETS    
Nuclear decommissioning trusts: 23,017 27,502
Level 1    
ASSETS    
Cash equivalents   23
Nuclear decommissioning trusts: 383,913 379,255
Other special use funds: 431,628 405,506
Total assets 815,541 784,784
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: 40,300 34,200
Level 1 | Cash equivalents    
ASSETS    
Other special use funds:   25,000
Level 1 | Cash equivalents | Pinnacle West Captive Insurance Cell    
ASSETS    
Other special use funds:   25,000
Level 1 | Equity securities    
ASSETS    
Nuclear decommissioning trusts: 18,970 11,859
Other special use funds: 62,573 24,962
Level 1 | Equity securities | Pinnacle West Captive Insurance Cell    
ASSETS    
Other special use funds:   9,200
Level 1 | U.S. commingled equity funds    
ASSETS    
Nuclear decommissioning trusts: 0 0
Level 1 | U.S. Treasury debt    
ASSETS    
Nuclear decommissioning trusts: 364,943 367,396
Other special use funds: 369,055 355,544
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    
Cash equivalents   0
Nuclear decommissioning trusts: 533,460 477,186
Other special use funds: 0 0
Total assets 552,807 490,338
Level 2 | Commodity contracts    
ASSETS    
Commodity contracts 19,347 13,152
LIABILITIES    
Derivative instruments (21,325) (40,388)
Level 2 | Cash equivalents    
ASSETS    
Other special use funds:   0
Level 2 | Equity securities    
ASSETS    
Nuclear decommissioning trusts: 0 542
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: 242,176 203,180
Level 2 | Mortgage-backed securities    
ASSETS    
Nuclear decommissioning trusts: 230,695 208,533
Level 2 | Municipal bonds    
ASSETS    
Nuclear decommissioning trusts: 37,572 37,429
Level 2 | Other fixed income    
ASSETS    
Nuclear decommissioning trusts: 23,017 27,502
Level 3    
ASSETS    
Cash equivalents   0
Nuclear decommissioning trusts: 0 0
Other special use funds: 0 0
Total assets 0 7,176
Level 3 | Commodity contracts    
ASSETS    
Commodity contracts 0 7,176
LIABILITIES    
Derivative instruments (23,710) (22,215)
Level 3 | Cash equivalents    
ASSETS    
Other special use funds:   0
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:   $ 423,069
Nuclear decommissioning trust, other $ 500,592  
v3.25.4
Fair Value Measurements - Schedule of Significant Unobservable Inputs Used to Value Level 3 Instruments (Details)
$ in Thousands
Dec. 31, 2025
USD ($)
$ / MMBTU
$ / MWh
Dec. 31, 2024
USD ($)
$ / MMBTU
$ / MWh
Commodity Contracts    
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments    
Derivative asset $ 8,387 $ 16,558
Derivative liability 36,636 61,786
Commodity Contracts | Level 3    
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments    
Derivative asset 0 7,176
Derivative liability 23,710 22,215
Electricity Forward Contract | Level 3    
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments    
Derivative asset 0 708
Derivative liability $ 21,913 $ 21,890
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 41.51 25.25
Derivative asset, measurement input | $ / MWh   25.25
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 149.37 151.11
Derivative asset, measurement input | $ / MWh   151.11
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 80.20 106.06
Derivative asset, measurement input | $ / MWh   106.06
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 $ 6,468
Derivative liability $ 1,797 $ 325
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 0.07 (0.89)
Derivative asset, measurement input | $ / MMBTU   (0.89)
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 0.36 1.47
Derivative asset, measurement input | $ / MMBTU   1.47
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 0.04 0.71
Derivative asset, measurement input | $ / MMBTU   0.71
v3.25.4
Fair Value Measurements - Schedule of Fair value for our risk management activities (Details) - Commodity Contracts - Level 3 - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]    
Balance at beginning of period $ (15,039) $ 4,921
Deferred as a regulatory asset or liability (30,006) (60,965)
Settlements 21,907 44,156
Transfers into Level 3 from Level 2 (1,240) (4,635)
Transfers from Level 3 into Level 2 668 1,484
Balance at end of period (23,710) (15,039)
Net unrealized gains/losses included in earnings related to instruments still held at end of period $ 0 $ 0
v3.25.4
Investments in Nuclear Decommissioning Trusts and Other Special Use Funds - Additional Information (Details)
$ in Millions
 12 Months Ended
Dec. 31, 2024
USD ($)
APS  
Schedule of Equity Method Investments [Line Items]  
Employee medical claims amount $ 14
v3.25.4
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
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Variable Interest Entity | Pinnacle West Captive Insurance Cell      
Nuclear decommissioning trust fund assets      
Special use fund $ 40,000 $ 34,000  
APS      
Nuclear decommissioning trust fund assets      
Total 1,848,993 1,691,202  
Total Unrealized Gains 451,809 366,844  
Total Unrealized Losses (14,994) (32,136)  
Amortized cost 1,265,000 1,224,000  
Special use fund   34,200  
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds      
Realized gains 13,068 76,062 $ 112,094
Realized losses (11,749) (21,966) (41,780)
Proceeds from the sale of securities 1,855,200 1,686,094 1,679,722
APS | Nuclear Decommissioning Trusts      
Nuclear decommissioning trust fund assets      
Total 1,414,166 1,282,845  
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds      
Realized gains 12,826 75,690 111,922
Realized losses (11,749) (21,966) (41,212)
Proceeds from the sale of securities 1,478,088 1,330,940 1,324,978
APS | Other Special Use Funds      
Nuclear decommissioning trust fund assets      
Total 434,827 408,357  
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds      
Realized gains 242 372 172
Realized losses 0 0 (568)
Proceeds from the sale of securities 377,112 355,154 $ 354,744
APS | Captive Insurance Cell      
Nuclear decommissioning trust fund assets      
Total Unrealized Gains 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 51,400    
APS | Equity securities      
Nuclear decommissioning trust fund assets      
Equity securities 582,135 460,432  
Total Unrealized Gains 433,044 359,127  
Total Unrealized Losses (1) (176)  
APS | Equity securities | Nuclear Decommissioning Trusts      
Nuclear decommissioning trust fund assets      
Equity securities 519,562 435,470  
APS | Equity securities | Other Special Use Funds      
Nuclear decommissioning trust fund assets      
Equity securities 62,573 24,962  
APS | Available for sale-fixed income securities      
Nuclear decommissioning trust fund assets      
Available for sale-fixed income securities 1,267,458 1,199,584  
Total Unrealized Gains 18,765 7,717  
Total Unrealized Losses (14,993) (31,960)  
Fair value of fixed income securities, summarized by contractual maturities      
Less than one year 163,764    
1 year – 5 years 497,877    
5 years – 10 years 189,684    
Greater than 10 years 416,133    
Total 1,267,458    
APS | Available for sale-fixed income securities | Nuclear Decommissioning Trusts      
Nuclear decommissioning trust fund assets      
Available for sale-fixed income securities 898,403 844,040  
Fair value of fixed income securities, summarized by contractual maturities      
Less than one year 36,726    
1 year – 5 years 272,413    
5 years – 10 years 173,131    
Greater than 10 years 416,133    
Total 898,403    
APS | Available for sale-fixed income securities | Other Special Use Funds      
Nuclear decommissioning trust fund assets      
Available for sale-fixed income securities 369,055 355,544  
APS | Available for sale-fixed income securities | Coal Reclamation Escrow Account      
Fair value of fixed income securities, summarized by contractual maturities      
Less than one year 87,421    
1 year – 5 years 68,348    
5 years – 10 years 0    
Greater than 10 years 0    
Total 155,769    
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 39,617    
1 year – 5 years 157,116    
5 years – 10 years 16,553    
Greater than 10 years 0    
Total 213,286    
APS | Other      
Nuclear decommissioning trust fund assets      
Other (600) 31,186  
Total Unrealized Gains 0 0  
Total Unrealized Losses 0 0  
APS | Other | Nuclear Decommissioning Trusts      
Nuclear decommissioning trust fund assets      
Other (3,799) 3,335  
APS | Other | Other Special Use Funds      
Nuclear decommissioning trust fund assets      
Other 3,199 $ 27,851  
Pinnacle West | Variable Interest Entity | Pinnacle West Captive Insurance Cell      
Nuclear decommissioning trust fund assets      
Special use fund $ 40,300    
v3.25.4
Changes in Accumulated Other Comprehensive Loss (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Changes in accumulated other comprehensive income (loss) by component    
Beginning balance $ 6,857,478 $ 6,284,862
Ending balance 7,087,075 6,857,478
Accumulated Other Comprehensive Loss    
Changes in accumulated other comprehensive income (loss) by component    
Beginning balance (30,942) (33,144)
Other comprehensive income/(loss) before reclassifications (3,357) 148
Amounts reclassified from accumulated other comprehensive loss 1,891 2,054
Ending balance (32,408) (30,942)
Pension and Other Postretirement Benefits    
Changes in accumulated other comprehensive income (loss) by component    
Beginning balance (31,661) (34,754)
Other comprehensive income/(loss) before reclassifications (3,210) 1,039
Amounts reclassified from accumulated other comprehensive loss 1,891 2,054
Ending balance (32,980) (31,661)
Derivative Instruments    
Changes in accumulated other comprehensive income (loss) by component    
Beginning balance 719 1,610
Other comprehensive income/(loss) before reclassifications (147) (891)
Amounts reclassified from accumulated other comprehensive loss 0 0
Ending balance 572 719
APS    
Changes in accumulated other comprehensive income (loss) by component    
Beginning balance 8,376,332 7,349,136
Ending balance 8,922,255 8,376,332
APS | Accumulated Other Comprehensive Loss    
Changes in accumulated other comprehensive income (loss) by component    
Beginning balance (14,116) (17,219)
Ending balance (15,457) (14,116)
APS | Pension and Other Postretirement Benefits    
Changes in accumulated other comprehensive income (loss) by component    
Beginning balance (14,116) (17,219)
Other comprehensive income/(loss) before reclassifications (2,889) 1,255
Amounts reclassified from accumulated other comprehensive loss 1,548 1,848
Ending balance $ (15,457) $ (14,116)
v3.25.4
Leases - Additional Information (Details)
$ in Billions
Dec. 31, 2025
USD ($)
trust
Sep. 30, 2025
trust
Sep. 22, 2025
trust
Jun. 30, 2025
trust
Dec. 31, 1986
trust
lease
Lessee, Lease, Description [Line Items]          
Number of lease agreements, sell and lease back | lease         3
Term of contract 20 years        
Lease not yet commenced | $ $ 11.4        
Variable Interest Entity | APS          
Leases [Abstract]          
Number of VIE lessor trusts acquired   2 2    
Lessee, Lease, Description [Line Items]          
Number of VIE lessor trusts acquired   2 2    
Number of VIE lessor trusts 1     2 3
v3.25.4
Leases - Schedule of Lease costs (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Lessee, Lease, Description [Line Items]      
Total Operating Lease Cost $ 314,745 $ 167,433 $ 145,890
Variable Lease Cost 124,707 144,108 135,007
Short-term Lease Cost 2,250 20,653 21,530
Operating Lease Cost - PPAs and Energy Storage PPA Lease Contracts      
Lessee, Lease, Description [Line Items]      
Total Operating Lease Cost 292,625 147,313 126,655
Operating Lease Cost - Land, Property, and Other Equipment      
Lessee, Lease, Description [Line Items]      
Total Operating Lease Cost 22,120 20,120 19,235
Total Lease Cost $ 441,702 $ 332,194 $ 302,427
v3.25.4
Leases - Schedule of Maturity of our operating lease liabilities (Details)
$ in Thousands
Dec. 31, 2025
USD ($)
Lessee, Lease, Description [Line Items]  
2026 $ 385,338
2027 409,118
2028 410,368
2029 412,320
2030 412,227
Thereafter 3,649,742
Total lease commitments 5,679,113
Less imputed interest 1,942,162
Total lease liabilities 3,736,951
PPAs and Energy Storage PPA Lease Contracts  
Lessee, Lease, Description [Line Items]  
2026 364,197
2027 390,260
2028 394,202
2029 398,287
2030 402,416
Thereafter 3,590,042
Total lease commitments 5,539,404
Less imputed interest 1,899,993
Total lease liabilities 3,639,411
Land, Property and Equipment Leases  
Lessee, Lease, Description [Line Items]  
2026 21,141
2027 18,858
2028 16,166
2029 14,033
2030 9,811
Thereafter 59,700
Total lease commitments 139,709
Less imputed interest 42,169
Total lease liabilities $ 97,540
v3.25.4
Leases - Schedule of Other Additional Information Related to Operating Lease Liabilities (Details)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
USD ($)
lease
Dec. 31, 2024
USD ($)
lease
Dec. 31, 2023
USD ($)
Jan. 31, 2023
lease
Leases [Abstract]        
Cash paid for amounts included in the measurement of lease liabilities — operating cash flows: | $ $ 226,484 $ 143,950 $ 123,472  
Right-of-use operating lease assets obtained in exchange for operating lease liabilities: | $ $ 2,195,728 $ 393,702 $ 602,301  
Weighted average remaining lease term 15 years 11 years    
Weighted average discount rate 5.48% 4.90%    
Number of new energy storage operating lease agreement | lease 9 3    
Number of purchase power operating lease agreements | lease       2
v3.25.4
Asset Retirement Obligations - Additional information (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Schedule of Asset Retirement Obligations [Line Items]      
Asset retirement obligation $ 1,270,299 $ 1,146,586 $ 966,001
Cholla | APS      
Schedule of Asset Retirement Obligations [Line Items]      
Increase (decrease) in asset retirement obligation 49,000 63,000  
Four Corners Coal-Fired Power Plant | APS      
Schedule of Asset Retirement Obligations [Line Items]      
Increase (decrease) in asset retirement obligation 16,000 82,000  
Navajo Coal-Fired Power Plant | APS      
Schedule of Asset Retirement Obligations [Line Items]      
Increase (decrease) in asset retirement obligation (4,000) 8,000  
Ironwood Solar Power Plant | APS      
Schedule of Asset Retirement Obligations [Line Items]      
Asset retirement obligation $ 15,000    
Palo Verde Nuclear Plant | APS      
Schedule of Asset Retirement Obligations [Line Items]      
Increase (decrease) in asset retirement obligation   1,000  
Solar | APS      
Schedule of Asset Retirement Obligations [Line Items]      
Increase (decrease) in asset retirement obligation   $ (11,000)  
v3.25.4
Asset Retirement Obligations - Schedule of Change in Asset Retirement Obligations (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Change in asset retirement obligations    
Asset retirement obligations at the beginning of year $ 1,146,586 $ 966,001
Changes attributable to:    
Accretion expense 64,552 56,143
Settlements (16,570) (18,379)
Estimated cash flow revisions 61,080 142,821
Newly incurred obligation 14,651 0
Asset retirement obligations at the end of year $ 1,270,299 $ 1,146,586
v3.25.4
Sale of Bright Canyon Energy (Details)
$ in Thousands
 5 Months Ended 12 Months Ended
Jan. 30, 2024
USD ($)
Jan. 12, 2024
USD ($)
Dec. 31, 2025
USD ($)
Dec. 31, 2024
USD ($)
Dec. 31, 2023
USD ($)
Aug. 04, 2023
USD ($)
investment
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]            
Number of wind farm investments | investment           2
Gain on sale relating to BCE     $ 0 $ 22,988 $ 6,423  
Discontinued Operations, Disposed of by Sale | Bright Canyon Energy Corporation            
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]            
Assets held-for-sale   $ 35,000        
Consideration received   108,000       $ 44,000
Gain on sale relating to BCE   29,000   $ 23,000 $ 6,000  
Investment tax credits $ 23,000          
Payments to acquire investment tax credits $ 21,000          
Discontinued Operations, Disposed of by Sale | Bright Canyon Energy Corporation | Ameresco, Inc.            
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]            
Assets held-for-sale   79,000        
Liabilities transferred   $ 41,000        
Bridge Loan | Equity Bridge Loan Facility | Bright Canyon Energy Corporation            
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]            
Debt instrument, face amount           31,000
Term loans | Non-Recourse Construction Term Loan Facility | Bright Canyon Energy Corporation            
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]            
Debt instrument, face amount           $ 36,000
v3.25.4
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
Dec. 31, 2025
Dec. 31, 2024
Schedule of Equity Method Investments [Line Items]    
Total equity method investments $ 36,000 $ 11,000
SAI    
Schedule of Equity Method Investments [Line Items]    
Pinnacle West Ownership Percentage as of December 31, 2025 17.00%  
Total equity method investments $ 21,000 0
AZ-VC    
Schedule of Equity Method Investments [Line Items]    
Pinnacle West Ownership Percentage as of December 31, 2025 24.00%  
Total equity method investments $ 15,000 $ 11,000
Funding commitment 25,000  
Funding commitment, amount funded $ 15,500  
v3.25.4
El Dorado Equity Investments - Additional Information (Details) - SAI & AZ-VC - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Schedule of Equity Method Investments [Line Items]    
Income (loss) from equity method investments $ 29.0 $ 0.3
Equity investments $ 25.1 $ 23.1
v3.25.4
Schedule I - Condensed Financial Information of Registrant - Comprehensive Income (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
CONDENSED FINANCIAL STATEMENTS      
Operating expenses $ 4,272,309 $ 4,112,852 $ 3,871,351
Other      
Total 92,707 101,968 102,376
Interest expense 469,701 425,742 374,887
Income before income taxes 738,369 736,559 595,693
Income tax benefit 106,726 110,529 76,912
Net Income (Loss) Attributable to Common Shareholders 616,531 608,806 501,557
Other comprehensive income (loss) — attributable to common shareholders (1,466) 2,202 (1,709)
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS 615,065 611,008 499,848
Pinnacle West Consolidated      
CONDENSED FINANCIAL STATEMENTS      
Operating expenses 9,667 9,931 11,249
Other      
Equity in earnings of subsidiaries 699,155 643,703 539,962
Other income and (expense), net (1,917) 23,835 2,823
Total 697,238 667,538 542,785
Interest expense 90,233 65,261 47,251
Income before income taxes 597,338 592,346 484,285
Income tax benefit (19,193) (16,460) (17,272)
Net Income (Loss) Attributable to Common Shareholders 616,531 608,806 501,557
Other comprehensive income (loss) — attributable to common shareholders (1,466) 2,202 (1,709)
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS $ 615,065 $ 611,008 $ 499,848
v3.25.4
Schedule I - Condensed Financial Information of Registrant - Balance Sheets (Details) - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Current assets        
Cash and cash equivalents $ 6,604 $ 3,838    
Accounts receivable 579,831 525,608    
Income tax receivable 5,979 0    
Other current assets 108,686 74,915    
Total current assets 1,703,709 1,689,404    
Investments and other assets        
Other assets 144,997 115,095    
Total investments and other assets 1,999,127 1,812,277    
TOTAL ASSETS 30,031,599 26,102,760    
Current liabilities        
Accounts payable 680,203 485,426    
Accrued taxes 186,605 175,863    
Common dividends payable 110,022 106,592    
Short-term borrowings 757,005 568,450    
Operating lease liabilities 188,586 100,367    
Other current liabilities 151,444 171,651    
Total current liabilities 3,161,026 2,843,797    
Deferred credits and other        
Long-term debt less current maturities 9,205,676 8,058,648    
Deferred income taxes (Note 5) 2,470,932 2,444,473    
Operating lease liabilities 3,548,365 1,520,877    
Other 249,171 242,320    
Total deferred credits and other 10,577,822 8,342,837    
COMMITMENTS AND CONTINGENCIES    
Common stock equity        
Common stock 3,231,372 3,121,617    
Accumulated other comprehensive loss (32,408) (30,942)    
Retained earnings 3,850,817 3,666,959    
Total shareholder equity 7,046,458 6,754,311    
Noncontrolling interests 40,617 103,167    
Total equity 7,087,075 6,857,478 $ 6,284,862 $ 6,159,876
TOTAL LIABILITIES AND EQUITY 30,031,599 26,102,760    
Pinnacle West Consolidated        
Current assets        
Cash and cash equivalents 2,461 23    
Accounts receivable 162,006 163,203    
Income tax receivable 7,856 6,673    
Other current assets 848 434    
Total current assets 173,171 170,333    
Investments and other assets        
Investments in subsidiaries 9,020,104 8,435,150    
Other assets 30,854 21,966    
Total investments and other assets 9,050,958 8,457,116    
TOTAL ASSETS 9,224,129 8,627,449    
Current liabilities        
Accounts payable 7,685 3,471    
Accrued taxes 10,013 4,799    
Common dividends payable 110,022 106,592    
Short-term borrowings 249,700 228,550    
Current maturities of long-term debt 350,000 500,000    
Operating lease liabilities 149 138    
Other current liabilities 30,282 11,389    
Total current liabilities 757,851 854,939    
Deferred credits and other        
Long-term debt less current maturities 1,315,736 867,770    
Deferred income taxes (Note 5) 43,167 24,536    
Pension liabilities 2,744 4,462    
Operating lease liabilities 1,044 1,194    
Other 16,512 17,070    
Total deferred credits and other 63,467 47,262    
COMMITMENTS AND CONTINGENCIES    
Common stock equity        
Common stock 3,228,049 3,118,294    
Accumulated other comprehensive loss (32,408) (30,942)    
Retained earnings 3,850,817 3,666,959    
Total shareholder equity 7,046,458 6,754,311    
Noncontrolling interests 40,617 103,167    
Total equity 7,087,075 6,857,478    
TOTAL LIABILITIES AND EQUITY $ 9,224,129 $ 8,627,449    
v3.25.4
Schedule I - Condensed Financial Information of Registrant - Cash Flows (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Cash flows from operating activities      
Net income $ 631,643 $ 626,030 $ 518,781
Adjustments to reconcile net income to net cash provided by operating activities:      
Depreciation and amortization 969,615 956,184 854,136
Deferred income taxes (50,850) (20,923) (24,310)
Accounts receivable (51,275) (12,696) (61,983)
Accounts payable 171,138 (7,214) (75,623)
Net cash provided by operating activities 1,805,095 1,609,823 1,207,697
Cash flows from investing activities      
Proceeds from sale relating to BCE 0 84,322 23,400
Net cash used for investing activities (2,378,674) (1,933,630) (1,694,249)
Cash flows from financing activities      
Issuance of long-term debt 1,742,754 1,313,229 689,349
Repayment of long-term debt (800,000) (875,000) (32,740)
Short-term borrowings and (repayments) — net 213,555 (241,050) 241,900
Short-term debt borrowings under term loan facility 575,000 550,000 0
Short-term debt repayments under term loan facility (600,000) (350,000) 0
Dividends paid on common stock (422,792) (394,663) (386,486)
Net cash provided by financing activities 576,345 322,690 486,675
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 2,766 (1,117) 123
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 3,838 4,955 4,832
CASH AND CASH EQUIVALENTS AT END OF PERIOD 6,604 3,838 4,955
Pinnacle West Consolidated      
Cash flows from operating activities      
Net income 616,531 608,806 501,557
Adjustments to reconcile net income to net cash provided by operating activities:      
Equity in earnings of subsidiaries — net (699,155) (643,703) (539,962)
Gain on sale relating to BCE 0 (22,988) (6,423)
Depreciation and amortization 68 75 76
Deferred income taxes 18,675 40,231 (13,955)
Accounts receivable (1,672) 15,268 (28,273)
Accounts payable 4,213 (4,869) 1,839
Accrued taxes and income tax receivables — net 4,030 (4,584) 9,505
Dividends received from subsidiaries 429,700 401,400 393,600
Other 30,457 22,959 (14,201)
Net cash provided by operating activities 402,847 412,595 303,763
Cash flows from investing activities      
Proceeds from sale relating to BCE 0 84,322 23,400
Investments in subsidiaries (382,338) (827,752) (119,682)
Repayments of loans from subsidiaries and other 13,756 1,132 6,526
Advances of loans to subsidiaries (10,202) (11,336) (59,349)
Net cash used for investing activities (378,784) (753,634) (149,105)
Cash flows from financing activities      
Issuance of long-term debt 795,404 867,387 175,000
Repayment of long-term debt (500,000) (625,000) 0
Short-term borrowings and (repayments) — net 46,150 (48,100) 60,930
Short-term debt borrowings under term loan facility 175,000 200,000 0
Short-term debt repayments under term loan facility (200,000) 0 0
Dividends paid on common stock (422,792) (394,663) (386,486)
Common stock equity issuance and purchases — net 84,613 341,429 (4,093)
Net cash provided by financing activities (21,625) 341,053 (154,649)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 2,438 14 9
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 23 9 0
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 2,461 $ 23 $ 9