PINNACLE WEST CAPITAL CORP, 10-K filed on 2/27/2024
Annual Report
v3.24.0.1
Cover Page - USD ($)
 12 Months Ended
Dec. 31, 2023
Feb. 21, 2024
Jun. 30, 2023
Entity Information [Line Items]      
Document Type 10-K    
Document Annual Report true    
Document Period End Date Dec. 31, 2023    
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     $ 9,215,155,738
Entity Common Stock, Shares Outstanding   113,427,367  
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 22, 2024 are incorporated by reference into Part III hereof.
    
Entity Central Index Key 0000764622    
Amendment Flag false    
Document Fiscal Year Focus 2023    
Document Fiscal Period Focus FY    
Arizona Public Service Company      
Entity Information [Line Items]      
Document Type 10-K    
Document Period End Date Dec. 31, 2023    
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 that General Instruction.
    
Entity Central Index Key 0000007286    
Amendment Flag false    
Document Fiscal Year Focus 2023    
Document Fiscal Period Focus FY    
v3.24.0.1
Audit Information
 12 Months Ended
Dec. 31, 2023
Auditor [Line Items]  
Auditor Name Deloitte & Touche LLP
Auditor Location Tempe, Arizona
Auditor Firm ID 34
Arizona Public Service Company  
Auditor [Line Items]  
Auditor Name Deloitte & Touche LLP
Auditor Location Tempe, Arizona
Auditor Firm ID 34
v3.24.0.1
CONSOLIDATED STATEMENTS OF INCOME - USD ($)
shares in Thousands, $ in Thousands
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Income Statement [Abstract]      
OPERATING REVENUES (Note 2) $ 4,695,991 $ 4,324,385 $ 3,803,835
OPERATING EXPENSES      
Fuel and purchased power 1,792,657 1,629,343 1,152,551
Operations and maintenance 1,058,725 987,072 954,067
Depreciation and amortization 794,043 753,195 650,875
Taxes other than income taxes 224,013 220,370 234,639
Other expenses 1,913 2,494 6,393
Total 3,871,351 3,592,474 2,998,525
OPERATING INCOME 824,640 731,911 805,310
OTHER INCOME (DEDUCTIONS)      
Allowance for equity funds used during construction (Note 1) 53,118 45,263 41,737
Pension and other postretirement non-service credits, net (Note 7) 40,648 98,487 112,541
Other income (Note 16) 33,666 7,916 45,100
Other expense (Note 16) (25,056) (52,385) (25,396)
Total 102,376 99,281 173,982
INTEREST EXPENSE      
Interest charges 374,887 283,569 254,314
Allowance for borrowed funds used during construction (Note 1) (43,564) (28,030) (21,052)
Total 331,323 255,539 233,262
INCOME BEFORE INCOME TAXES 595,693 575,653 746,030
INCOME TAXES (Note 4) 76,912 74,827 110,086
NET INCOME 518,781 500,826 635,944
Less: Net income attributable to noncontrolling interests (Note 17) 17,224 17,224 17,224
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS $ 501,557 $ 483,602 $ 618,720
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — BASIC (in shares) 113,442 113,196 112,910
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — DILUTED (in shares) 113,804 113,416 113,192
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING      
Net income attributable to common shareholders - basic (in dollars per share) $ 4.42 $ 4.27 $ 5.48
Net income attributable to common shareholders — diluted (in dollars per share) $ 4.41 $ 4.26 $ 5.47
v3.24.0.1
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Statement of Comprehensive Income [Abstract]      
NET INCOME $ 518,781 $ 500,826 $ 635,944
Derivative instruments:      
Net unrealized gain, net of tax expense of $234, $615, and $360 713 1,873 1,095
Pension and other postretirement benefits activity, net of tax benefit (expense) of $801, $(7,078), and $(2,256) (Note 7) (2,422) 21,553 6,840
Total other comprehensive income (loss) (1,709) 23,426 7,935
COMPREHENSIVE INCOME 517,072 524,252 643,879
Less: Comprehensive income attributable to noncontrolling interests 17,224 17,224 17,224
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS $ 499,848 $ 507,028 $ 626,655
v3.24.0.1
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Statement of Comprehensive Income [Abstract]      
Net unrealized gain, net of tax expense $ 234 $ 615 $ 360
Pension and other postretirement benefits activity, tax benefit (expense) $ 801 $ (7,078) $ (2,256)
v3.24.0.1
CONSOLIDATED BALANCE SHEETS - USD ($)
$ in Thousands
Dec. 31, 2023
Dec. 31, 2022
CURRENT ASSETS    
Cash and cash equivalents $ 4,955 $ 4,832
Customer and other receivables 513,892 453,209
Accrued unbilled revenues 167,553 164,764
Allowance for doubtful accounts (Note 2) (22,433) (23,778)
Materials and supplies (at average cost) 444,344 410,481
Fossil fuel (at average cost) 49,203 40,155
Income tax receivable (Note 4) 332 14,086
Assets from risk management activities (Note 15) 6,808 87,835
Assets held for sale (Note 20) 35,139 0
Deferred fuel and purchased power regulatory asset (Note 3) 463,195 460,561
Other regulatory assets (Note 3) 162,562 78,318
Other current assets 101,417 60,091
Total current assets 1,926,967 1,750,554
INVESTMENTS AND OTHER ASSETS    
Nuclear decommissioning trusts (Notes 12 and 18) 1,201,246 1,073,410
Other special use funds (Notes 12 and 18) 362,781 347,231
Assets from risk management activities (Note 15) 0 44,394
Other assets 102,845 125,672
Total investments and other assets 1,666,872 1,590,707
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6 and 9)    
Plant in service and held for future use 24,211,167 22,452,146
Accumulated depreciation and amortization (8,408,040) (7,929,878)
Net 15,803,127 14,522,268
Construction work in progress 1,724,004 1,882,791
Palo Verde sale leaseback, net of accumulated depreciation of $264,624 and $260,754 (Note 17) 86,426 90,296
Intangible assets, net of accumulated amortization of $885,505 and $817,961 267,110 258,880
Nuclear fuel, net of accumulated amortization of $118,074 and $126,157 99,490 100,119
Total property, plant and equipment 17,980,157 16,854,354
DEFERRED DEBITS    
Regulatory assets (Notes 1, 3, 4 and 7) 1,390,279 1,283,221
Operating lease right-of-use assets (Note 8) 1,309,975 801,688
Assets for pension and other postretirement benefits (Note 7) 323,438 396,599
Other 63,465 46,282
Total deferred debits 3,087,157 2,527,790
TOTAL ASSETS 24,661,153 22,723,405
CURRENT LIABILITIES    
Accounts payable 442,455 430,425
Accrued taxes 166,833 164,440
Accrued interest 72,916 61,217
Common dividends payable 99,813 97,895
Short-term borrowings (Note 5) 609,500 340,720
Current maturities of long-term debt (Note 6) 875,000 50,685
Customer deposits 42,037 41,769
Liabilities from risk management activities (Note 15) 80,913 37,697
Liabilities for asset retirements (Note 11) 28,550 12,232
Operating lease liabilities (Note 8) 67,883 105,210
Regulatory liabilities (Note 3) 209,923 271,575
Other current liabilities 193,524 148,276
Total current liabilities 2,889,347 1,762,141
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 6) 7,540,622 7,741,286
DEFERRED CREDITS AND OTHER    
Deferred income taxes (Note 4) 2,416,480 2,384,421
Regulatory liabilities (Notes 1, 3, 4 and 7) 1,965,865 2,061,776
Liabilities for asset retirements (Note 11) 937,451 785,530
Liabilities for pension benefits (Note 7) 112,702 116,286
Liabilities from risk management activities (Note 15) 42,975 4,749
Customer advances 533,580 422,103
Coal mine reclamation 184,007 179,255
Deferred investment tax credit 257,743 180,677
Unrecognized tax benefits (Note 4) 33,861 38,658
Operating lease liabilities (Note 8) 1,210,189 639,247
Other 251,469 247,400
Total deferred credits and other 7,946,322 7,060,102
COMMITMENTS AND CONTINGENCIES (Note 10)
EQUITY    
Common stock, no par value; authorized 150,000,000 shares, 113,537,689 and 113,247,189 issued at respective dates 2,752,676 2,724,740
Treasury stock at cost; 113,272 and 73,613 shares at respective dates (8,185) (5,005)
Total common stock 2,744,491 2,719,735
Retained earnings 3,466,317 3,360,347
Accumulated other comprehensive loss (Note 19) (33,144) (31,435)
Total shareholders’ equity 6,177,664 6,048,647
Noncontrolling interests (Note 17) 107,198 111,229
Total equity 6,284,862 6,159,876
TOTAL LIABILITIES AND EQUITY $ 24,661,153 $ 22,723,405
v3.24.0.1
CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($)
$ in Thousands
Dec. 31, 2023
Dec. 31, 2022
PROPERTY, PLANT AND EQUIPMENT    
Accumulated depreciation of Palo Verde sale leaseback $ 264,624 $ 260,754
Accumulated amortization on intangible assets 885,505 817,961
Accumulated amortization on nuclear fuel $ 118,074 $ 126,157
EQUITY    
Common stock, authorized shares (in shares) 150,000,000 150,000,000
Common stock, issued shares (in shares) 113,537,689 113,247,189
Treasury stock (in shares) 113,272 73,613
v3.24.0.1
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
CASH FLOWS FROM OPERATING ACTIVITIES      
Net income $ 518,781 $ 500,826 $ 635,944
Adjustments to reconcile net income to net cash provided by operating activities:      
Gain on sale relating to BCE (6,423) 0 0
Depreciation and amortization including nuclear fuel 854,136 817,814 719,141
Deferred fuel and purchased power (549,877) (291,992) (256,871)
Deferred fuel and purchased power amortization 547,243 219,579 44,557
Allowance for equity funds used during construction (53,118) (45,263) (41,737)
Deferred income taxes (24,310) 43,202 117,471
Deferred investment tax credit 77,065 (5,893) (4,802)
Change in derivative instruments fair value (777) 777 0
Stock compensation 17,341 15,942 18,460
Changes in current assets and liabilities:      
Customer and other receivables (61,983) (63,869) (72,559)
Accrued unbilled revenues (2,789) (30,784) (1,783)
Materials, supplies and fossil fuel (42,911) (83,469) (32,870)
Income tax receivable 13,754 (6,572) (722)
Other current assets (19,550) 76,089 (22,770)
Accounts payable (75,623) 90,076 20,267
Accrued taxes 2,393 (4,205) 9,094
Other current liabilities 40,510 (1,856) (51,736)
Change in long-term regulatory assets 53,112 12,432 (17,012)
Change in long-term regulatory liabilities 28,495 (332,470) 57,549
Change in other long-term assets (195,598) 159,030 (345,470)
Change in operating lease assets 90,525 105,359 116,009
Change in other long-term liabilities 63,080 170,359 78,219
Change in operating lease liabilities (65,779) (103,671) (108,365)
Net cash provided by operating activities 1,207,697 1,241,441 860,014
CASH FLOWS FROM INVESTING ACTIVITIES      
Capital expenditures (1,846,370) (1,707,490) (1,473,475)
Contributions in aid of construction 180,866 137,436 105,654
Proceeds from sale relating to BCE 23,400 0 0
Allowance for borrowed funds used during construction (43,564) (28,030) (21,052)
Proceeds from nuclear decommissioning trust sales and other special use funds 1,679,722 1,207,713 1,720,966
Investment in nuclear decommissioning trust and other special use funds (1,681,845) (1,212,063) (1,725,480)
Other (6,458) (15,612) 6,458
Net cash used for investing activities (1,694,249) (1,618,046) (1,386,929)
CASH FLOWS FROM FINANCING ACTIVITIES      
Issuance of long-term debt 689,349 875,537 746,999
Repayment of long-term debt (32,740) (150,000) 0
Short-term borrowings and (repayments) — net 241,900 48,720 142,000
Short-term debt repayments under revolving credit facility 0 0 (19,000)
Dividends paid on common stock (386,486) (378,881) (369,478)
Common stock equity issuance and purchases — net (4,093) (2,653) (2,350)
Distributions to noncontrolling interests (21,255) (21,255) (21,255)
Net cash provided by financing activities 486,675 371,468 476,916
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 123 (5,137) (49,999)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 4,832 9,969 59,968
CASH AND CASH EQUIVALENTS AT END OF YEAR $ 4,955 $ 4,832 $ 9,969
v3.24.0.1
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, 2020   112,760,051        
Beginning balance at Dec. 31, 2020 $ 5,752,793 $ 2,677,482 $ (6,289) $ 3,025,106 $ (62,796) $ 119,290
Beginning balance (in shares) at Dec. 31, 2020     (72,006)      
Increase (Decrease) in Shareholders' Equity            
Net income 635,944     618,720   17,224
Other comprehensive income 7,935       7,935  
Dividends on common stock (379,108)     (379,108)    
Issuance of common stock (in shares)   254,477        
Issuance of common stock 25,261 $ 25,261        
Purchase of treasury stock (in shares) [1]     (68,892)      
Purchase of treasury stock [1] (4,655)   $ (4,655)      
Reissuance of treasury stock for stock-based compensation and other (in shares)     53,290      
Reissuance of treasury stock for stock-based compensation and other 4,543   $ 4,543      
Capital activities by noncontrolling interests (21,255)         (21,255)
Other 2     1   1
Ending balance (in shares) at Dec. 31, 2021   113,014,528        
Ending balance at Dec. 31, 2021 6,021,460 $ 2,702,743 $ (6,401) 3,264,719 (54,861) 115,260
Ending balance (in shares) at Dec. 31, 2021     (87,608)      
Increase (Decrease) in Shareholders' Equity            
Net income 500,826     483,602   17,224
Other comprehensive income 23,426       23,426  
Dividends on common stock (387,975)     (387,975)    
Issuance of common stock (in shares)   232,661        
Issuance of common stock 21,996 $ 21,996        
Purchase of treasury stock (in shares) [1]     (77,152)      
Purchase of treasury stock [1] (5,152)   $ (5,152)      
Reissuance of treasury stock for stock-based compensation and other (in shares)     91,147      
Reissuance of treasury stock for stock-based compensation and other 6,548   $ 6,548      
Capital activities by noncontrolling interests (21,255)         (21,255)
Other $ 2 $ 1   1    
Ending balance (in shares) at Dec. 31, 2022 113,247,189 113,247,189        
Ending balance at Dec. 31, 2022 $ 6,159,876 $ 2,724,740 $ (5,005) 3,360,347 (31,435) 111,229
Ending balance (in shares) at Dec. 31, 2022 (73,613)   (73,613)      
Increase (Decrease) in Shareholders' Equity            
Net income $ 518,781     501,557   17,224
Other comprehensive 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 113,537,689 113,537,689        
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)   (113,272)      
[1] Primarily represents shares of common stock withheld from certain stock awards for tax purposes.
v3.24.0.1
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Parenthetical) - $ / shares
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Statement of Stockholders' Equity [Abstract]      
Dividends declared per common share (in dollars per share) $ 3.49 $ 3.43 $ 3.36
v3.24.0.1
APS - CONSOLIDATED STATEMENTS OF INCOME - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
OPERATING REVENUES (Note 2) $ 4,695,991 $ 4,324,385 $ 3,803,835
OPERATING EXPENSES      
Fuel and purchased power 1,792,657 1,629,343 1,152,551
Operations and maintenance 1,058,725 987,072 954,067
Depreciation and amortization 794,043 753,195 650,875
Taxes other than income taxes 224,013 220,370 234,639
Other expenses 1,913 2,494 6,393
Total 3,871,351 3,592,474 2,998,525
OPERATING INCOME 824,640 731,911 805,310
OTHER INCOME (DEDUCTIONS)      
Allowance for equity funds used during construction (Note 1) 53,118 45,263 41,737
Pension and other postretirement non-service credits, net (Note 7) 40,648 98,487 112,541
Other income (Note 16) 33,666 7,916 45,100
Other expense (Note 16) (25,056) (52,385) (25,396)
Total 102,376 99,281 173,982
INTEREST EXPENSE      
Interest charges 374,887 283,569 254,314
Allowance for borrowed funds used during construction (Note 1) (43,564) (28,030) (21,052)
Total 331,323 255,539 233,262
INCOME BEFORE INCOME TAXES 595,693 575,653 746,030
INCOME TAXES (Note 4) 76,912 74,827 110,086
NET INCOME 518,781 500,826 635,944
Less: Net income attributable to noncontrolling interests (Note 17) 17,224 17,224 17,224
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS 501,557 483,602 618,720
Arizona Public Service Company      
OPERATING REVENUES (Note 2) 4,695,991 4,324,385 3,803,835
OPERATING EXPENSES      
Fuel and purchased power 1,792,657 1,629,343 1,152,551
Operations and maintenance 1,043,570 974,220 940,588
Depreciation and amortization 793,958 753,110 650,773
Taxes other than income taxes 223,962 220,277 234,569
Other expenses 1,913 2,494 6,393
Total 3,856,060 3,579,444 2,984,874
OPERATING INCOME 839,931 744,941 818,961
OTHER INCOME (DEDUCTIONS)      
Allowance for equity funds used during construction (Note 1) 53,118 45,263 41,737
Pension and other postretirement non-service credits, net (Note 7) 41,577 98,945 112,742
Other income (Note 16) 27,072 5,888 43,053
Other expense (Note 16) (18,264) (26,108) (18,897)
Total 103,503 123,988 178,635
INTEREST EXPENSE      
Interest charges 323,719 262,815 243,592
Allowance for borrowed funds used during construction (Note 1) (39,030) (26,839) (21,052)
Total 284,689 235,976 222,540
INCOME BEFORE INCOME TAXES 658,745 632,953 775,056
INCOME TAXES (Note 4) 94,184 90,800 125,553
NET INCOME 564,561 542,153 649,503
Less: Net income attributable to noncontrolling interests (Note 17) 17,224 17,224 17,224
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS $ 547,337 $ 524,929 $ 632,279
v3.24.0.1
APS - CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
NET INCOME $ 518,781 $ 500,826 $ 635,944
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX      
Pension and other postretirement benefits activity, net of tax benefit (expense) of $536, $(6,332), and $(1,990) (Note 7) (2,422) 21,553 6,840
Total other comprehensive income (loss) (1,709) 23,426 7,935
COMPREHENSIVE INCOME 517,072 524,252 643,879
Less: Comprehensive income attributable to noncontrolling interests 17,224 17,224 17,224
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS 499,848 507,028 626,655
Arizona Public Service Company      
NET INCOME 564,561 542,153 649,503
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX      
Pension and other postretirement benefits activity, net of tax benefit (expense) of $536, $(6,332), and $(1,990) (Note 7) (1,623) 19,284 6,038
Total other comprehensive income (loss) (1,623) 19,284 6,038
COMPREHENSIVE INCOME 562,938 561,437 655,541
Less: Comprehensive income attributable to noncontrolling interests 17,224 17,224 17,224
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS $ 545,714 $ 544,213 $ 638,317
v3.24.0.1
APS - CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Pension and other postretirement benefits activity, tax benefit (expense) $ 801 $ (7,078) $ (2,256)
Arizona Public Service Company      
Pension and other postretirement benefits activity, tax benefit (expense) $ 536 $ (6,332) $ (1,990)
v3.24.0.1
APS - CONSOLIDATED BALANCE SHEETS - USD ($)
$ in Thousands
Dec. 31, 2023
Dec. 31, 2022
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6 and 9)    
Plant in service and held for future use $ 24,211,167 $ 22,452,146
Accumulated depreciation and amortization (8,408,040) (7,929,878)
Net 15,803,127 14,522,268
Construction work in progress 1,724,004 1,882,791
Palo Verde sale leaseback, net of accumulated depreciation of $264,624 and $260,754 (Note 17) 86,426 90,296
Intangible assets, net of accumulated amortization of $884,371 and $816,827 267,110 258,880
Nuclear fuel, net of accumulated amortization of $118,074 and $126,157 99,490 100,119
Total property, plant and equipment 17,980,157 16,854,354
INVESTMENTS AND OTHER ASSETS    
Nuclear decommissioning trusts (Notes 12 and 18) 1,201,246 1,073,410
Other special use funds (Notes 12 and 18) 362,781 347,231
Assets from risk management activities (Note 15) 0 44,394
Other assets 102,845 125,672
Total investments and other assets 1,666,872 1,590,707
CURRENT ASSETS    
Cash and cash equivalents 4,955 4,832
Customer and other receivables 513,892 453,209
Accrued unbilled revenues 167,553 164,764
Allowance for doubtful accounts (Note 2) (22,433) (23,778)
Materials and supplies (at average cost) 444,344 410,481
Fossil fuel (at average cost) 49,203 40,155
Income tax receivable (Note 4) 332 14,086
Assets from risk management activities (Note 15) 6,808 87,835
Deferred fuel and purchased power regulatory asset (Note 3) 463,195 460,561
Other regulatory assets (Note 3) 162,562 78,318
Other current assets 101,417 60,091
Total current assets 1,926,967 1,750,554
DEFERRED DEBITS    
Regulatory assets (Notes 1, 3, 4 and 7) 1,390,279 1,283,221
Operating lease right-of-use assets (Note 8) 1,309,975 801,688
Assets for pension and other postretirement benefits (Note 7) 323,438 396,599
Other 63,465 46,282
Total deferred debits 3,087,157 2,527,790
TOTAL ASSETS 24,661,153 22,723,405
CAPITALIZATION    
Retained earnings 3,466,317 3,360,347
Accumulated other comprehensive loss (Note 19) (33,144) (31,435)
Total shareholders’ equity 6,177,664 6,048,647
Noncontrolling interests (Note 17) 107,198 111,229
Total equity 6,284,862 6,159,876
Long-term debt less current maturities (Note 6) 7,540,622 7,741,286
CURRENT LIABILITIES    
Short-term borrowings (Note 5) 609,500 340,720
Accounts payable 442,455 430,425
Accrued taxes 166,833 164,440
Accrued interest 72,916 61,217
Common dividends payable 99,813 97,895
Customer deposits 42,037 41,769
Liabilities from risk management activities (Note 15) 80,913 37,697
Liabilities for asset retirements (Note 11) 28,550 12,232
Operating lease liabilities (Note 8) 67,883 105,210
Regulatory liabilities (Note 3) 209,923 271,575
Other current liabilities 193,524 148,276
Total current liabilities 2,889,347 1,762,141
DEFERRED CREDITS AND OTHER    
Deferred income taxes (Note 4) 2,416,480 2,384,421
Regulatory liabilities (Notes 1, 3, 4 and 7) 1,965,865 2,061,776
Liabilities for asset retirements (Note 11) 937,451 785,530
Liabilities for pension benefits (Note 7) 112,702 116,286
Customer advances 533,580 422,103
Coal mine reclamation 184,007 179,255
Deferred investment tax credit 257,743 180,677
Unrecognized tax benefits (Note 4) 33,861 38,658
Operating lease liabilities (Note 8) 1,210,189 639,247
Other 251,469 247,400
Total deferred credits and other 7,946,322 7,060,102
COMMITMENTS AND CONTINGENCIES (Note 10)
TOTAL LIABILITIES AND EQUITY 24,661,153 22,723,405
Current maturities of long-term debt (Note 6) 875,000 50,685
Liabilities from risk management activities (Note 15) 42,975 4,749
Arizona Public Service Company    
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6 and 9)    
Plant in service and held for future use 24,207,706 22,448,685
Accumulated depreciation and amortization (8,404,721) (7,926,575)
Net 15,802,985 14,522,110
Construction work in progress 1,724,004 1,829,004
Palo Verde sale leaseback, net of accumulated depreciation of $264,624 and $260,754 (Note 17) 86,426 90,296
Intangible assets, net of accumulated amortization of $884,371 and $816,827 266,955 258,725
Nuclear fuel, net of accumulated amortization of $118,074 and $126,157 99,490 100,119
Total property, plant and equipment 17,979,860 16,800,254
INVESTMENTS AND OTHER ASSETS    
Nuclear decommissioning trusts (Notes 12 and 18) 1,201,246 1,073,410
Other special use funds (Notes 12 and 18) 362,781 347,231
Assets from risk management activities (Note 15) 0 44,394
Other assets 43,625 43,344
Total investments and other assets 1,607,652 1,508,379
CURRENT ASSETS    
Cash and cash equivalents 4,549 4,042
Customer and other receivables 510,296 448,880
Accrued unbilled revenues 167,553 164,764
Allowance for doubtful accounts (Note 2) (22,433) (23,778)
Materials and supplies (at average cost) 444,344 410,481
Fossil fuel (at average cost) 49,203 40,155
Income tax receivable (Note 4) 0 1,102
Assets from risk management activities (Note 15) 6,808 87,704
Deferred fuel and purchased power regulatory asset (Note 3) 463,195 460,561
Other regulatory assets (Note 3) 162,562 78,318
Other current assets 64,311 50,043
Total current assets 1,850,388 1,722,272
DEFERRED DEBITS    
Regulatory assets (Notes 1, 3, 4 and 7) 1,390,279 1,283,221
Operating lease right-of-use assets (Note 8) 1,308,611 796,544
Assets for pension and other postretirement benefits (Note 7) 316,606 389,142
Other 63,059 44,040
Total deferred debits 3,078,555 2,512,947
TOTAL ASSETS 24,516,455 22,543,852
CAPITALIZATION    
Common stock 178,162 178,162
Additional paid-in capital 3,321,696 3,171,696
Retained earnings 3,759,299 3,607,464
Accumulated other comprehensive loss (Note 19) (17,219) (15,596)
Total shareholders’ equity 7,241,938 6,941,726
Noncontrolling interests (Note 17) 107,198 111,229
Total equity 7,349,136 7,052,955
Long-term debt less current maturities (Note 6) 7,041,891 6,793,529
Total capitalization 14,391,027 13,846,484
CURRENT LIABILITIES    
Short-term borrowings (Note 5) 532,850 325,000
Accounts payable 433,229 417,732
Accrued taxes 162,288 156,746
Accrued interest 72,548 60,518
Common dividends payable 99,800 97,900
Customer deposits 42,037 41,769
Liabilities from risk management activities (Note 15) 80,913 37,697
Liabilities for asset retirements (Note 11) 28,550 12,232
Operating lease liabilities (Note 8) 67,608 104,728
Regulatory liabilities (Note 3) 209,923 271,575
Other current liabilities 211,773 144,733
Total current liabilities 2,191,519 1,670,630
DEFERRED CREDITS AND OTHER    
Deferred income taxes (Note 4) 2,431,697 2,385,647
Regulatory liabilities (Notes 1, 3, 4 and 7) 1,965,865 2,061,776
Liabilities for asset retirements (Note 11) 937,451 785,530
Liabilities for pension benefits (Note 7) 106,215 108,068
Customer advances 533,580 422,103
Coal mine reclamation 184,007 179,255
Deferred investment tax credit 257,743 180,677
Unrecognized tax benefits (Note 4) 33,861 38,658
Operating lease liabilities (Note 8) 1,208,857 634,199
Other 231,658 226,985
Total deferred credits and other 7,933,909 7,026,738
COMMITMENTS AND CONTINGENCIES (Note 10)
TOTAL LIABILITIES AND EQUITY 24,516,455 22,543,852
Current maturities of long-term debt (Note 6) 250,000 0
Liabilities from risk management activities (Note 15) $ 42,975 $ 3,840
v3.24.0.1
APS - CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($)
$ in Thousands
Dec. 31, 2023
Dec. 31, 2022
PROPERTY, PLANT AND EQUIPMENT    
Accumulated depreciation of Palo Verde sale leaseback $ 264,624 $ 260,754
Accumulated amortization on intangible assets 885,505 817,961
Accumulated amortization on nuclear fuel 118,074 126,157
Arizona Public Service Company    
PROPERTY, PLANT AND EQUIPMENT    
Accumulated depreciation of Palo Verde sale leaseback 264,624 260,754
Accumulated amortization on intangible assets 884,371 816,827
Accumulated amortization on nuclear fuel $ 118,074 $ 126,157
v3.24.0.1
APS - CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
CASH FLOWS FROM OPERATING ACTIVITIES      
Net income $ 518,781 $ 500,826 $ 635,944
Adjustments to reconcile net income to net cash provided by operating activities:      
Depreciation and amortization including nuclear fuel 854,136 817,814 719,141
Deferred fuel and purchased power (549,877) (291,992) (256,871)
Deferred fuel and purchased power amortization 547,243 219,579 44,557
Allowance for equity funds used during construction (53,118) (45,263) (41,737)
Deferred income taxes (24,310) 43,202 117,471
Deferred investment tax credit 77,065 (5,893) (4,802)
Changes in current assets and liabilities:      
Customer and other receivables (61,983) (63,869) (72,559)
Accrued unbilled revenues (2,789) (30,784) (1,783)
Materials, supplies and fossil fuel (42,911) (83,469) (32,870)
Income tax receivable 13,754 (6,572) (722)
Other current assets (19,550) 76,089 (22,770)
Accounts payable (75,623) 90,076 20,267
Accrued taxes 2,393 (4,205) 9,094
Other current liabilities 40,510 (1,856) (51,736)
Change in long-term regulatory assets (53,112) (12,432) 17,012
Change in long-term regulatory liabilities 28,495 (332,470) 57,549
Change in other long-term assets (195,598) 159,030 (345,470)
Change in operating lease assets 90,525 105,359 116,009
Change in other long-term liabilities 63,080 170,359 78,219
Change in operating lease liabilities (65,779) (103,671) (108,365)
Net cash provided by operating activities 1,207,697 1,241,441 860,014
CASH FLOWS FROM INVESTING ACTIVITIES      
Capital expenditures (1,846,370) (1,707,490) (1,473,475)
Contributions in aid of construction 180,866 137,436 105,654
Allowance for borrowed funds used during construction (43,564) (28,030) (21,052)
Proceeds from nuclear decommissioning trust sales and other special use funds 1,679,722 1,207,713 1,720,966
Investment in nuclear decommissioning trust and other special use funds (1,681,845) (1,212,063) (1,725,480)
Other (6,458) (15,612) 6,458
Net cash used for investing activities (1,694,249) (1,618,046) (1,386,929)
CASH FLOWS FROM FINANCING ACTIVITIES      
Issuance of long-term debt 689,349 875,537 746,999
Short-term borrowings and (repayments) — net 241,900 48,720 142,000
Dividends paid on common stock (386,486) (378,881) (369,478)
Noncontrolling interests (21,255) (21,255) (21,255)
Net cash provided by financing activities 486,675 371,468 476,916
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 123 (5,137) (49,999)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 4,832 9,969 59,968
CASH AND CASH EQUIVALENTS AT END OF YEAR 4,955 4,832 9,969
Arizona Public Service Company      
CASH FLOWS FROM OPERATING ACTIVITIES      
Net income 564,561 542,153 649,503
Adjustments to reconcile net income to net cash provided by operating activities:      
Depreciation and amortization including nuclear fuel 854,051 817,729 719,039
Deferred fuel and purchased power (549,877) (291,992) (256,871)
Deferred fuel and purchased power amortization 547,243 219,579 44,557
Allowance for equity funds used during construction (53,118) (45,263) (41,737)
Deferred income taxes (10,314) (6,817) 128,852
Deferred investment tax credit 77,065 (5,893) (4,802)
Changes in current assets and liabilities:      
Customer and other receivables (62,716) (60,930) (72,101)
Accrued unbilled revenues (2,789) (30,784) (1,783)
Materials, supplies and fossil fuel (42,911) (83,469) (32,870)
Income tax receivable 1,102 9,654 (10,756)
Other current assets (20,243) 59,970 (25,637)
Accounts payable (70,622) 79,492 23,510
Accrued taxes 5,542 4,734 3,042
Other current liabilities 62,212 1,190 (61,297)
Change in long-term regulatory assets 53,112 12,432 (17,012)
Change in long-term regulatory liabilities 28,495 (332,470) 57,549
Change in other long-term assets (188,483) 170,587 (330,642)
Change in operating lease assets 90,234 105,058 115,850
Change in other long-term liabilities 58,574 168,503 87,376
Change in operating lease liabilities (65,482) (103,361) (108,216)
Net cash provided by operating activities 1,275,636 1,230,102 865,554
CASH FLOWS FROM INVESTING ACTIVITIES      
Capital expenditures (1,825,585) (1,655,051) (1,471,795)
Contributions in aid of construction 180,866 137,436 105,654
Allowance for borrowed funds used during construction (39,030) (26,839) (21,052)
Proceeds from nuclear decommissioning trust sales and other special use funds 1,679,722 1,207,713 1,720,966
Investment in nuclear decommissioning trust and other special use funds (1,681,845) (1,212,063) (1,725,480)
Other (1,397) (727) 273
Net cash used for investing activities (1,687,269) (1,549,531) (1,391,434)
CASH FLOWS FROM FINANCING ACTIVITIES      
Issuance of long-term debt 496,025 524,852 446,999
Short-term borrowings and (repayments) — net 180,970 46,300 278,700
Dividends paid on common stock (393,600) (385,800) (376,500)
Equity infusion from Pinnacle West 150,000 150,000 150,000
Noncontrolling interests (21,255) (21,255) (21,255)
Net cash provided by financing activities 412,140 314,097 477,944
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 507 (5,332) (47,936)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 4,042 9,374 57,310
CASH AND CASH EQUIVALENTS AT END OF YEAR $ 4,549 $ 4,042 $ 9,374
v3.24.0.1
APS - CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY - USD ($)
$ in Thousands
Total
Common Stock
Retained Earnings
Accumulated Other Comprehensive Income (Loss)
Noncontrolling Interests
Arizona Public Service Company
Arizona Public Service Company
Common Stock
Arizona Public Service Company
Additional Paid-In Capital
Arizona Public Service Company
Retained Earnings
Arizona Public Service Company
Accumulated Other Comprehensive Income (Loss)
Arizona Public Service Company
Noncontrolling Interests
Beginning balance (in shares) at Dec. 31, 2020   112,760,051         71,264,947        
Beginning balance at Dec. 31, 2020 $ 5,752,793 $ 2,677,482 $ 3,025,106 $ (62,796) $ 119,290 $ 6,345,185 $ 178,162 $ 2,871,696 $ 3,216,955 $ (40,918) $ 119,290
Increase (Decrease) in Shareholders' Equity                      
Equity infusion from Pinnacle West           150,000   150,000      
Net income 635,944   618,720   17,224 649,503     632,279   17,224
Other comprehensive income 7,935     7,935   6,038       6,038  
Dividends on common stock (379,108)   (379,108)     (379,000)     (379,000)    
Capital activities by noncontrolling interests (21,255)       (21,255) (21,255)         (21,255)
Other 2   1   1 2     1   1
Ending balance (in shares) at Dec. 31, 2021   113,014,528         71,264,947        
Ending balance at Dec. 31, 2021 6,021,460 $ 2,702,743 3,264,719 (54,861) 115,260 6,750,473 $ 178,162 3,021,696 3,470,235 (34,880) 115,260
Increase (Decrease) in Shareholders' Equity                      
Equity infusion from Pinnacle West           150,000   150,000      
Net income 500,826   483,602   17,224 542,153     524,929   17,224
Other comprehensive income 23,426     23,426   19,284       19,284  
Dividends on common stock (387,975)   (387,975)     (387,700)     (387,700)    
Capital activities by noncontrolling interests (21,255)       (21,255) (21,255)         (21,255)
Other $ 2 $ 1 1                
Ending balance (in shares) at Dec. 31, 2022 113,247,189 113,247,189         71,264,947        
Ending 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 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 113,537,689 113,537,689         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
v3.24.0.1
Summary of Significant Accounting Policies
 12 Months Ended
Dec. 31, 2023
Accounting Policies [Abstract]  
Summary of Significant Accounting Policies Summary of Significant Accounting Policies
Description of Business and Basis of Presentation
 
Pinnacle West is a 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 is a wholly-owned subsidiary that was created in September 2023 to hold certain investments in wind and transmission joint projects. See Note 20 for more information on PNW Power.
 
BCE was a Pinnacle West subsidiary that was formed in 2014. On August 4, 2023, Pinnacle West entered into a purchase and sale agreement pursuant to which all of our equity interest in BCE was sold. The sale was completed on January 12, 2024. See Note 20 for more information relating to the sale of BCE.

Pinnacle West’s Consolidated Financial Statements include the accounts of Pinnacle West and our subsidiaries: APS, El Dorado, BCE and PNW Power. APS’s Consolidated Financial Statements include the accounts of APS and certain VIEs relating to the Palo Verde sale leaseback.  Intercompany accounts and transactions between the consolidated companies have been eliminated.
 
We consolidate Variable Interest Entities (each a “VIE”) 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 certain VIE lessor trusts relating to the Palo Verde sale leaseback, and therefore APS consolidates these entities. See Note 17 for additional information. We have determined that Pinnacle West is the primary beneficiary of a captive insurance protected cell VIE. As of December 31, 2023, the captive cell’s activities are insignificant to our consolidated financial statements.
 
Our consolidated financial statements reflect all adjustments (consisting only of normal recurring adjustments, except as otherwise disclosed in the notes) that we believe are necessary for the fair presentation of our financial position, results of operations and cash flows for the periods presented.

Accounting Records and Use of Estimates
 
Our accounting records are maintained in accordance with accounting principles generally accepted in the United States of America (“GAAP”).  The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period.  Actual results could differ from
those estimates. To conform with the current year’s disaggregated presentation of significant changes in assets and liabilities and the aggregation of less significant changes in assets and liabilities, we made certain reclassifications for the year ended December 31, 2022, within the operating activities section of our Consolidated Statements of Cash Flows.

Regulatory Accounting
 
APS is regulated by the ACC and the 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 3 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 2 and 3 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 2.
 
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, 2023, and 2022 Consolidated Balance Sheets is composed of the following (dollars in thousands):

Property, Plant and Equipment:20232022
Generation$10,446,291 $9,563,145 
Transmission3,773,253 3,589,456 
Distribution8,448,293 7,951,867 
General plant1,543,330 1,347,678 
Plant in service and held for future use
24,211,167 22,452,146 
Accumulated depreciation and amortization(8,408,040)(7,929,878)
Net
15,803,127 14,522,268 
Construction work in progress1,724,004 1,882,791 
Palo Verde sale leaseback, net of accumulated depreciation86,426 90,296 
Intangible assets, net of accumulated amortization267,110 258,880 
Nuclear fuel, net of accumulated amortization99,490 100,119 
Total property, plant and equipment$17,980,157 $16,854,354 

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 11 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, 2023, were as follows:

•Steam generation — 11 years;
•Nuclear plant — 25 years;
•Other generation — 18 years;
•Transmission — 38 years;
•Distribution — 33 years; and
•General plant — 7 years.
 
Depreciation of utility property, plant and equipment is computed on a straight-line, remaining-life basis. Depreciation expense was $669 million in 2023, $632 million in 2022, and $575 million in 2021. For the years 2021 through 2023, the depreciation rates ranged from a low of 1.37% to a high of 12.15%.  The weighted-average depreciation rate was 2.98% in 2023, 3.03% in 2022, and 2.87% in 2021.

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 radiated 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 11 for further information on Asset Retirement Obligations.

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 6.29% for 2023, 5.75% for 2022, and 6.75% for 2021.  APS compounds AFUDC semi-annually and ceases to accrue AFUDC when construction work is completed and the property is placed in service.

On June 30, 2020, FERC issued an order granting a waiver request related to the existing AFUDC rate calculation beginning March 1, 2020, through February 28, 2021.  On February 23, 2021, this waiver was extended until September 30, 2021. On September 21, 2021, it was further extended until March 31, 2022. The order provided a simplified approach that companies may elect to implement in order to minimize the significant distorted effect on the AFUDC formula resulting from increased short-term debt financing during the COVID-19 pandemic.  APS adopted this simplified approach to computing the AFUDC composite rate by using a simple average of the actual historical short-term debt balances for 2019, instead of current period short-term debt balances, and left all other aspects of the AFUDC formula composite rate calculation unchanged. This change impacted the AFUDC composite rate in 2021 and for the three-month period ended March 31, 2022.  Furthermore, the change in the composite rate calculation did not impact our accounting treatment for these costs. The change did not have a material impact on our financial statements.

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 short-term 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 6 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 12 for additional information about fair value measurements.
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 15 for additional information about our derivative instruments.
 
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.
 
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 7 for additional information on pension and other postretirement benefits.
 
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 2023. See Note 10 for information on spent nuclear fuel disposal costs.
 
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 4 for additional discussion.
 
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,
 202320222021
Cash paid during the period for:   
Income taxes, net of refunds$8,788 $46,227 $229 
Interest, net of amounts capitalized310,996 245,271 227,584 
Significant non-cash investing and financing activities:   
Accrued capital expenditures$206,269 $114,999 $167,733 
Dividends declared but not paid99,813 97,895 95,988 
BCE Sale non-cash consideration (Note 20)
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,
 202320222021
Cash paid during the period for:   
Income taxes, net of refunds$21,734 $95,985 $19,783 
Interest, net of amounts capitalized267,261 227,159 217,749 
Significant non-cash investing and financing activities:   
Accrued capital expenditures$206,269 $116,533 $167,657 
Dividends declared but not paid99,800 97,900 96,000 

Intangible Assets
 
We have no goodwill recorded and have separately disclosed other intangible assets, primarily APS’s software, on Pinnacle West’s Consolidated Balance Sheets. The intangible assets are amortized over their finite useful lives.  Amortization expense was $90 million in 2023, $84 million in 2022, and $80 million in 2021.  Estimated amortization expense on existing intangible assets over the next five years is $90 million in 2024, $75 million in 2025, $49 million in 2026, $23 million in 2027, and $11 million in 2028.  At December 31, 2023, the weighted-average remaining amortization period for intangible assets was 5 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 20% ownership and no significant influence).

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 20% ownership and no significant influence).
 
Our investments in the nuclear decommissioning trusts, coal reclamation escrow accounts and active union employee medical account, are accounted for in accordance with guidance on accounting for investments in debt and equity securities. See Notes 12 and 18 for more information on these investments.

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 purchased power agreement 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 3. We also may enter into lease agreements related to vehicles, office space, land, and other equipment. See Note 8 for information on our lease agreements.

Business Segments
 
Pinnacle West’s reportable business segment is our regulated electricity segment, which consists of traditional regulated retail and wholesale electricity businesses (primarily electricity service to Native Load customers) and related activities and includes electricity generation, transmission, and distribution. All other segment activities are insignificant.

Preferred Stock

At December 31, 2023, 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.
v3.24.0.1
Revenue
 12 Months Ended
Dec. 31, 2023
Revenue from Contract with Customer [Abstract]  
Revenue Revenue
Sources of Revenue

The following table provides detail of Pinnacle West’s consolidated revenue disaggregated by revenue sources (dollars in thousands):
Year Ended December 31,
202320222021
Retail Electric Service
Residential$2,289,196 $2,046,111 $1,913,324 
Non-Residential2,048,416 1,767,616 1,586,940 
Wholesale Energy Sales208,985 383,126 187,640 
Transmission Services for Others138,631 116,628 99,285 
Other Sources10,763 10,904 16,646 
Total Operating Revenues$4,695,991 $4,324,385 $3,803,835 
Retail Electric Revenue. All of Pinnacle West’s retail electric revenue is generated by APS. Retail electric revenue is generated by the sale of electricity to our regulated customers within the authorized service territory at tariff rates approved by the ACC and based on customer usage. Revenues related to the sale of electricity are generally recognized when service is rendered, or electricity is delivered to customers. The billing of electricity sales to individual customers is based on the reading of their meters. We obtain customers’ meter data on a systematic basis throughout the month, and generally bill customers within a month from when service was provided. Customers are generally required to pay for services within 21 days of when the services are billed. See “Allowance for Doubtful Accounts” discussion below for additional details regarding payment terms.

Wholesale Energy Sales and Transmission Services for Others. Revenues from wholesale energy sales and transmission services for others represent energy and transmission sales to wholesale customers. These activities primarily consist of managing fuel and purchased power risks in connection with the cost of serving our retail customers’ energy requirements. We may also sell into the wholesale markets generation that is not needed for APS’s retail load. Our wholesale activities and tariff rates are regulated by 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 years ended December 31, 2023, 2022 and 2021 were $4,651 million, $4,302 million, and $3,760 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 years ended December 31, 2023, 2022 and 2021, our revenues that do not qualify as revenue from contracts with customers were $45 million, $22 million and $44 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 3 for a discussion of our regulatory cost recovery mechanisms.

Contract Assets and Liabilities from Contracts with Customers

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

Allowance for Doubtful Accounts
The allowance for doubtful accounts represents our best estimate of accounts receivable and accrued unbilled revenues that will ultimately be uncollectible due to credit loss risk. The allowance includes a write-off component that is calculated by applying an estimated write-off factor to retail electric revenues. The write-off factor used to estimate uncollectible accounts is based upon consideration of historical collections experience, the current and forecasted economic environment, changes to our
collection policies, and management’s best estimate of future collections success. We continue to monitor the impacts of our disconnection policies, payment arrangements, among other considerations impacting our estimated write-off factor, and allowance for doubtful accounts.

The following table provides a rollforward of Pinnacle West’s allowance for doubtful accounts (dollars in thousands):
Year Ended December 31,
202320222021
Allowance for doubtful accounts, balance at beginning of period$23,778 $25,354 $19,782 
Bad debt expense23,399 17,006 22,251 
Actual write-offs(24,744)(18,582)(16,679)
Allowance for doubtful accounts, balance at end of period$22,433 $23,778 $25,354 
v3.24.0.1
Regulatory Matters
 12 Months Ended
Dec. 31, 2023
Regulated Operations [Abstract]  
Regulatory Matters Regulatory Matters
2022 Retail Rate Case

APS filed an application with the ACC on October 28, 2022 (the “2022 Rate Case”) seeking an increase in annual retail base rates on the date rates become effective (“Day 1”) of a net $460 million. This Day 1 net impact represents a total base revenue deficiency of $772 million offset by proposed adjustor transfers of cost recovery to annual retail rates and adjustor mechanism modifications. The average annual customer bill impact of APS’s request on Day 1 is an increase of 13.6%.

The principal provisions of APS’s application were:

•a test year comprised of twelve months ended June 30, 2022, adjusted as described below;
•an original cost rate base of $10.5 billion, which approximates the ACC-jurisdictional portion of the book value of utility assets, net of accumulated depreciation and other credits;
•the following proposed capital structure and costs of capital:

Capital StructureCost of Capital
Long-term debt48.07 %3.85 %
Common stock equity51.93 %10.25 %
Weighted-average cost of capital7.17 %

•a 1% return on the increment of fair value rate base above APS’s original cost rate base, as provided for by Arizona law;
•a rate of $0.038321 per kWh for the portion of APS’s retail base rates attributable to fuel and purchased power costs (“Base Fuel Rate”);
•modification of its adjustment mechanisms including:
▪eliminate the Environmental Improvement Surcharge (“EIS”) and collect costs through base rates,
▪eliminate the Lost Fixed Cost Recovery (“LFCR”) mechanism and collect costs through base rates and the Demand Side Management Adjustment Charge (“DSMAC”),
▪maintain as inactive the Tax Expense Adjustor Mechanism (“TEAM”),
▪maintain the Transmission Cost Adjustment (“TCA”) mechanism,
▪modify the performance incentive in the DSMAC, and
▪modify the Renewable Energy Adjustment Charge (“REAC”) to include recovery of capital carrying costs of APS owned renewable and storage resources;
•changes to its limited-income program, including a second tier to provide an additional discount for customers with greater need; and
•twelve months of post-Test Year plant investments to reflect used and useful projects that will be placed into service prior to July 1, 2023.

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

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

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

On July 26, 2023, the ACC Staff, RUCO and other intervenors filed their surrebuttal testimony with the ACC. The ACC Staff adjusted their initial recommendations to, among other things, (i) a $281.9 million revenue increase, (ii) a 9.68% return on equity, (iii) a 0.5% fair value increment, (iv) a continuation of a 12-month post-test year plant that includes the Four Corners ELG project, and (v) support of an increase to the annual PSA increase limit to $0.006/kWh. RUCO maintained their direct position and also recommended further review of the PSA in a second phase of the 2022 Rate Case.
On August 4, 2023, APS filed rejoinder testimony addressing the ACC Staff and intervenors’ surrebuttal testimonies. APS’s rejoinder testimony included final post-Test Year Plant values, reducing the revenue requirement increase to $377.7 million from $383.1 million, which reduced the average annual customer bill impact to an increase of 11.2%. All other major provisions from APS’s rebuttal testimony were maintained in its rejoinder testimony.

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

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

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

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

The ACC’s decision results in an expected total net annual revenue increase for APS of approximately $253.4 million and a roughly 8% increase to the typical residential customer’s bill. The ACC is expected to issue the final order for the 2022 Rate Case in March 2024 with the new rates to become effective for all service rendered on or after March 8, 2024.
2019 Retail Rate Case

On October 31, 2019, APS filed an application with the ACC for an annual increase in retail base rates (the “2019 Rate Case”). On August 2, 2021, an Administrative Law Judge issued a Recommended Opinion and Order in the 2019 Rate Case (the “2019 Rate Case ROO”) and issued corrections on September 10 and September 20, 2021.

The 2019 Rate Case ROO recommended, among other things, (i) a $111 million decrease in annual revenue requirements, (ii) a return on equity of 9.16%, (iii) a 0.30% return on the increment of fair value rate base greater than original cost, with total fair value rate of return further adjusted to include a 0.03% reduction to return on equity resulting in an effective fair value rate of return of 4.95%, (iv) the nonrecovery of the deferral and rate base effects of the operating costs and construction of the Four Corners Power Plant (“Four Corners”) selective catalytic reduction (“SCR”) project (see “Four Corners SCR Cost Recovery” below for additional information), (v) the recovery of the deferral and rate base effects of the operating costs and construction of the Ocotillo modernization project, which includes a reduction in the return on the deferral, (vi) a 15% disallowance of annual amortization of the Navajo Generating Station (the “Navajo Plant”) regulatory asset recovery related to the closure of the Navajo Plant (see “Navajo Plant” below), (vii) the denial of the request to defer, until APS’s next general rate case, the increase or decrease in its Arizona property taxes attributable to tax rate changes, and (viii) a collaborative process to review and recommend revisions to APS’s adjustment mechanisms within 12 months after the date of the decision. The 2019 Rate Case ROO also recommended that the CCT plan related to the closure or future closure of coal-fired generation facilities include the following components: (i) $50 million that will be paid over 10 years to the Navajo Nation, (ii) $5 million that will be paid over five years to the Navajo County Communities surrounding Cholla Power Plant (“Cholla”), and (iii) $1.675 million that will be paid to the Hopi Tribe related to APS’s ownership interests in the Navajo Plant. These amounts would be recoverable from APS’s customers through the Arizona Renewable Energy Standard and Tariff (“RES”) adjustment mechanism. APS filed exceptions on September 13, 2021, regarding the disallowance of the SCR cost deferrals and plant investments that was recommended in the 2019 Rate Case ROO, among other issues.

On October 6, 2021, and October 27, 2021, the ACC voted on various amendments to the 2019 Rate Case ROO that would result in, among other things, (i) a return on equity of 8.70%, which includes a 20-basis point penalty, (ii) the recovery of the deferral and rate base effects of the operating costs and construction of the Four Corners SCR project, with the exception of $215.5 million (see “Four Corners SCR Cost Recovery” below), (iii) that the CCT plan include the following components: (a) a payment of $1 million to the Hopi Tribe within 60 days of the 2019 Rate Case decision, (b) a payment of $10 million over three years to the Navajo Nation, (c) a payment of $0.5 million to the Navajo County communities within 60 days of the 2019 Rate Case decision, (d) up to $1.25 million for electrification of homes and businesses on the Hopi reservation, and (e) up to $1.25 million for the electrification of homes and businesses on the Navajo Nation reservation. These payments and expenditures are attributable to the future closures of Four Corners and Cholla, along with the prior closure of the Navajo Plant and all ordered payments and expenditures would be recoverable through rates, and (iv) a change in the residential on-peak time-of-use period from 3 p.m. to 8 p.m. to 4 p.m. to 7 p.m. Monday through Friday, excluding holidays. The 2019 Rate Case ROO, as amended, resulted in a total annual revenue decrease for APS of $4.8 million, excluding temporary payments and expenditures, under the CCT plan. On November 2, 2021, the ACC approved the 2019 Rate Case ROO, as amended.
Consistent with the 2019 Rate Case decision, APS implemented the new rates effective as of December 1, 2021. In addition, the ACC ordered extensive compliance and reporting obligations. APS completed the implementation of the new on-peak hours for residential customers before the September 1, 2022, deadline.

Additionally, consistent with the 2019 Rate Case decision, as of February 2024, APS completed the following payments that will be recoverable through rates related to the CCT: (i) $6.66 million to the Navajo Nation; (ii) $0.5 million to the Navajo County communities; and (iii) $1 million to the Hopi Tribe. Consistent with APS’s commitment to the impacted communities, APS has also completed the following payments: (i) $1 million to the Navajo Nation for CCT; (ii) $1.1 million to the Navajo County communities for CCT and economic development; and (iii) $1.25 million to the Hopi Tribe for CCT and economic development. The ACC has also authorized $1.25 million to be recovered through rates for electrification of homes and businesses on both the Navajo Nation and Hopi reservation. Expenditure of the recoverable funds for electrification of homes and businesses on the Navajo Nation and the Hopi reservations is contingent upon completion of a census of the unelectrified homes and businesses in each that are also within APS service territory. The census work was completed in November 2022 and disbursement of the $1.25 million for electrification of homes and businesses is planned to be finalized after discussions with the Navajo Nation and the Hopi Tribe are completed. On February 22, 2024, the ACC voted to not approve any further CCT funding.

On November 24, 2021, APS filed an application for rehearing of the 2019 Rate Case with the ACC and the application was deemed denied on December 15, 2021, as the ACC did not act upon it. On December 17, 2021, APS filed its Notice of Direct Appeal at the Arizona Court of Appeals and a Petition for Special Action with the Arizona Supreme Court, requesting review of the disallowance of $215.5 million of Four Corners SCR plant investments and deferrals (see “Four Corners SCR Cost Recovery” below for additional information) and the 20-basis-point penalty reduction to the return on equity, among other things. On February 8, 2022, the Arizona Supreme Court declined to accept jurisdiction on APS’s Petition for Special Action. The Arizona Court of Appeals heard oral arguments on November 30, 2022. On March 6, 2023, the Court issued its opinion in this matter, affirming in part and reversing in part the ACC’s decision in the 2019 Rate Case. The Court vacated the 20-basis-point penalty included in the ACC’s allowed return on equity, as the Court determined the use of customer service metrics to justify the reduction exceeded the ACC’s ratemaking authority. Additionally, the Court vacated the disallowance of $215.5 million of APS’s Four Corners SCR investment. The Court remanded the issue to the ACC for further proceedings. The ACC requested an extension of the 30-day deadline to appeal the matter to the Arizona Supreme Court, and the Arizona Supreme Court granted the extension of the deadline to May 8, 2023. The ACC filed an appeal on May 8, 2023, and on May 15, 2023, requested a suspension of the case to allow for settlement discussions between the parties, which was approved by the Court.

On June 14, 2023, APS and the ACC Legal Division filed a joint resolution with the ACC to allow recovery of the $215.5 million in costs related to the installation of the Four Corners SCR, a reversal of the 20-basis point reduction to APS’s return on equity from 8.9% to 8.7% as a result of the 2019 Rate Case Decision, and recovery of $59.6 million in revenue lost by APS between December of 2021 and June 20, 2023. On June 21, 2023, the ACC approved the joint resolution and proposals therein for recovery through the Court Resolution Surcharge (“CRS”) mechanism, which became effective on July 1, 2023. See “Court Resolution Surcharge” below for more information. On July 18, 2023, the Sierra Club filed an application for rehearing of the ACC’s decision. However, the ACC did not act upon the application within 20 days,
and it was therefore denied by operation of law. Subsequently, the Sierra Club did not file a notice of appeal to the Arizona Court of Appeals, and the time for an appeal has expired.

Matter of Impact of the Closures of Fossil-Based Generation Plan on Impacted Communities

On September 28, 2022, ACC Staff filed their staff report in the Matter of Impact of the Closures of Fossil-Based Generation Plan on Impacted Communities. APS and other interested parties filed comments on the report. On October 21, 2022, ACC Staff filed a revised report and proposed order. The revised report and proposed order recommended that funds for CCT shall not be collected from rate payers. On December 8, 2022, the ACC voted against ACC Staff’s proposed order, and on April 17, 2023, the ACC closed the docket. On February 22, 2024, the ACC voted to not approve any further CCT funding.

Information Technology ACC Investigation

On December 16, 2021, the ACC opened an investigation into various matters related to APS’s Information Technology department, including information about technology projects, costs, vendor management leadership and decision making. APS is cooperating with the investigation. APS cannot predict the outcome of this matter.

Regulatory Lag Docket

On January 5, 2023, the ACC opened a new docket to explore the possibility of modifications to the ACC’s historical test year rules. The ACC requested comments from utilities and interested parties on ways to reduce regulatory lag, including alternative ratemaking structures such as future test years and hybrid test years. APS filed comments on June 1, 2023. APS cannot predict the outcome of this matter.

Cost Recovery Mechanisms
 
APS has received regulatory decisions that allow for more timely recovery of certain costs outside of a general retail rate case through the following recovery mechanisms. See “2022 Retail Rate Case” above for modifications of adjustment mechanisms in the 2022 Rate Case.
 
Renewable Energy Standard. In 2006, the ACC approved the RES. Under the RES, electric utilities that are regulated by the ACC must supply an increasing percentage of their retail electric energy sales from eligible renewable resources, including solar, wind, biomass, biogas and geothermal technologies. In order to achieve these requirements, the ACC allows APS to include a RES surcharge as part of customer bills to recover the approved amounts for use on renewable energy projects. Each year, APS is required to file a five-year implementation plan with the ACC and seek approval for funding the upcoming year’s RES budget. In 2015, the ACC revised the RES rules to allow the ACC to consider all available information, including the number of rooftop solar arrays in a utility’s service territory, to determine compliance with the RES.

In June 2021, the ACC adopted a clean energy rules package which would require APS to meet certain clean energy standards and technology procurement mandates, obtain approval for its action plan included in its IRP, and seek cost recovery in a rate process. Since the adopted clean energy rules differed substantially from the original Recommended Order and Opinion, supplemental rulemaking procedures were required before the rules could become effective. On January 26, 2022, the ACC reversed its prior
decision and declined to send the final draft energy rules through the rulemaking process. Instead, the ACC opened a new docket to consider all-source RFP requirements and the IRP process. See “Energy Modernization Plan” below for more information.

On July 1, 2021, APS filed its 2022 RES Implementation Plan and proposed a budget of approximately $93.1 million. APS filed an amended 2022 RES Implementation Plan on December 9, 2021, with a proposed budget of $100.5 million. This budget included funding for programs to comply with the decision in the 2019 Rate Case, including the ACC authorizing spending $20 million to $30 million in capital costs for the continuation of the APS Solar Communities program each year for a period of three years from the effective date of the 2019 Rate Case decision. APS’s budget proposal supported existing approved projects and commitments and requested a waiver of the RES residential and non-residential distributed energy requirements for 2022. On May 18, 2022, the ACC approved the 2022 RES Implementation Plan, including an amendment requiring a stakeholder working group convene to develop a community solar program for the ACC’s consideration at a future date. On September 23, 2022, APS filed a community solar proposal in compliance with the ACC order that was informed by a stakeholder working group. APS proposed a small, pilot-scale program size of up to 140 MW that would be selected through a competitive RFP. The ACC has not yet ruled on the proposal. However, on November 10, 2022, the ACC approved a bifurcated community solar process, directing ACC Staff to develop a statewide policy through additional stakeholder involvement and establishing a separate evidentiary hearing to define other policy components. On March 23, 2023, the ACC approved a policy statement that included information on how statewide community solar and storage programs should be structured, their location, and inclusion in RFPs. The remainder of the community solar program policy components were deferred to the ACC’s Hearing Division so that a formal evidentiary hearing could be held to consider issues of substance related to community solar. APS cannot predict the outcomes of these future activities.

On July 1, 2022, APS filed its 2023 RES Implementation Plan and proposed a budget of approximately $86.2 million, excluding any funding offsets. This budget contained funding for programs to comply with ACC-approved initiatives, including the 2019 Rate Case decision. APS’s budget proposal supported existing approved projects and commitments and requested a waiver of the RES residential and non-residential distributed energy requirements for 2022. On November 10, 2022, the ACC approved the 2023 RES Implementation Plan, including APS’s requested waiver of the distributed energy requirement for 2023.

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

Demand Side Management Adjustor Charge. The ACC Electric Energy Efficiency Standards require APS to submit a DSM Plan annually for review and approval by the ACC. Verified energy savings from APS’s resource savings projects can be counted toward compliance with the Electric Energy Efficiency Standards; however, APS is not allowed to count savings from systems savings projects toward determination of the achievement of performance incentives, nor may APS include savings from these system savings projects in the calculation of its LFCR mechanism. See below for discussion of the LFCR.
On December 17, 2021, APS filed its 2022 DSM Implementation Plan in accordance with an extension granted in 2021. The 2022 DSM Plan requested a budget of $78.4 million and represents an increase of approximately $14 million in DSM spending above 2021. On November 10, 2022, the ACC approved the 2022 DSM Implementation Plan, including a proposed performance incentive.

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

On November 30, 2022, APS filed its 2023 DSM Implementation Plan, which requested a budget of $88 million. On May 31, 2023, APS filed an amended 2023 DSM Implementation Plan. The amended plan maintained the originally proposed budget of $88 million. Subsequent to filing the amended 2023 DSM Implementation Plan and prior to the ACC approving it, on November 30, 2023, APS filed its 2024 DSM Implementation Plan. The 2024 DSM Implementation Plan requested a total budget of $91.5 million and incorporated all elements of the amended 2023 DSM Implementation Plan as well as the 2024 TE Implementation Plan. The ACC has not yet ruled on the 2024 DSM Implementation Plan. APS cannot predict the outcome of this proceeding.

Power Supply Adjustor Mechanism and Balance. The PSA provides for the adjustment of retail rates to reflect variations primarily in retail fuel and purchased power costs. The PSA is subject to specified parameters and procedures, including the following:

•APS records deferrals for recovery or refund to the extent actual retail fuel and purchased power costs vary from the Base Fuel Rate;
•an adjustment to the PSA rate is made annually each February 1 (unless otherwise approved by the ACC) and goes into effect automatically unless suspended by the ACC;
•the PSA uses a forward-looking estimate of fuel and purchased power costs to set the annual PSA rate, which is reconciled to actual costs experienced for each PSA Year (February 1 through January 31) (see the following bullet point);
•the PSA rate includes (a) a “forward component,” under which APS recovers or refunds differences between expected fuel and purchased power costs for the upcoming calendar year and those embedded in the Base Fuel Rate; (b) a “historical component,” under which differences between actual fuel and purchased power costs and those recovered or refunded through the combination of the Base Fuel Rate and the Forward Component are recovered during the next PSA Year; and (c) a “transition component,” under which APS may seek mid-year PSA changes due to large variances between actual fuel and purchased power costs and the combination of the Base Fuel Rate and the Forward Component; and
•the PSA rate may not be increased or decreased more than $0.004 per kWh in a year without permission of the ACC.
The following table shows the changes in the deferred fuel and purchased power regulatory asset for 2023 and 2022 (dollars in thousands):
 Twelve Months Ended
December 31,
 20232022
Beginning balance$460,561 $388,148 
Deferred fuel and purchased power costs — current period549,877 291,992 
Amounts charged to customers(547,243)(219,579)
Ending balance$463,195 $460,561 

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

On April 1, 2022, the ACC filed a final report of its third-party audit findings regarding APS’s fuel and purchased power costs for the period January 2019 through January 2021. The report contains an in-depth review of APS’s fuel and purchased power contracts, its monthly fuel accounting activities, its forecasting and dispatching procedures, and its monthly PSA filings, among other fuel-related activities. The report finds that APS’s fuel processing accounting practices, dispatching procedures, and procedures for hedging activity are reasonable and appropriate. The report includes several recommendations for the ACC’s consideration, including review of current contracts, maintenance schedules, and certain changes and improvements to the schedules in APS’s monthly PSA filings. On December 27, 2022, ACC Staff filed a proposed order supporting adoption of the recommendations in the third-party audit report, and the ACC approved the proposed order on February 22, 2023.

On November 30, 2022, APS filed its PSA rate for the PSA year beginning February 1, 2023. To address the growing under-collected PSA balance, APS also requested that one of three different options be adopted, including a temporary or permanent increase of the annual cap to $0.006 per kWh. On February 23, 2023, the ACC approved an overall PSA rate of $0.019074 per kWh, which consisted of a forward component of $(0.005527) per kWh, a historical component of $0.013071 per kWh and a transition component of $0.011530 per kWh, that will continue until further notice of the ACC. The rate became effective with the first billing cycle in March 2023 and is designed to bring the PSA balancing account to near-zero over a 24-month period. APS is also required to notify the ACC when the PSA balancing account approaches $0.5 million. In its 2022 Rate Case, APS proposed a permanent increase in the annual PSA adjustor rate cap, which would increase the amount the rate can change in any given year from the currently effective $0.004 per kWh to $0.006 per kWh. On February 22, 2024, the ACC voted to approve this request.

On November 30, 2023, APS notified the ACC that it will be maintaining the current PSA rate of $0.019074 per kWh and an updated PSA adjustment schedule would not be filed at this time.

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

Environmental Improvement Surcharge (“EIS”). The EIS permits APS to recover the capital carrying costs (rate of return, depreciation and taxes) plus incremental operations and maintenance expenses associated with environmental improvements made outside of a test year to comply with environmental standards set by federal, state, tribal, or local laws and regulations. A filing is made on or before February 1 each year for qualified environmental improvements since the prior rate case test year, and the new charge becomes effective April 1 unless suspended by the ACC. The EIS includes an overall cap of $0.0005 per kWh (approximately $13 million to $15 million per year).  APS’s February 1, 2023, application requested an increase in the charge to $14.7 million, or $3.3 million over the prior-period charge. On March 10, 2023, APS filed an amended application requesting an EIS charge of $4.0 million, a decrease of $10.7 million from the February EIS request, and a decrease of $7.5 million from the prior-period charge. The revised 2023 EIS became effective with the first billing cycle in April 2023. On February 1, 2024, APS filed an application requesting an increase in the charge to $15.3 million, or $11.3 million over the prior-period charge. The 2022 Rate Case ROO has recommended eliminating the EIS. On February 22, 2024, the ACC approved the elimination of the EIS as recommended in the 2022 Rate Case ROO. With the elimination of the EIS, the surcharge will no longer be in effect.
 
Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters. In July 2008, FERC approved a modification to APS’s Open Access Transmission Tariff to allow APS to move from fixed rates to a formula rate-setting methodology in order to more accurately reflect and recover the costs that APS incurs in providing transmission services. A large portion of the rate represents charges for transmission services to serve APS’s retail customers (“Retail Transmission Charges”). In order to recover the Retail Transmission Charges, APS was previously required to file an application with, and obtain approval from, the ACC to reflect changes in Retail Transmission Charges through the TCA. Under the terms of the settlement agreement entered into in 2012 regarding APS’s rate case (“2012 Settlement Agreement”), however, an adjustment to rates to recover the Retail Transmission Charges will be made annually each June 1 and will go into effect automatically unless suspended by the ACC.
 
The formula rate is updated each year effective June 1 on the basis of APS’s actual cost of service, as disclosed in APS’s FERC Form 1 report for the previous fiscal year. Items to be updated include actual capital expenditures made as compared with previous projections, transmission revenue credits and other items. APS reviews the proposed formula rate filing amounts with the ACC Staff. Any items or adjustments which are not agreed to by APS and the ACC Staff can remain in dispute until settled or litigated with FERC. Settlement or litigated resolution of disputed issues could require an extended period of time and could have a significant effect on the Retail Transmission Charges because any adjustment, though applied prospectively, may be calculated to account for previously over- or under-collected amounts. The resolution of proposed adjustments can result in significant volatility in the revenues to be collected.

On March 17, 2020, APS submitted a filing to make modifications to its annual transmission formula to provide additional transparency for excess and deficient accumulated deferred income taxes resulting from the Tax Cuts and Job Act (the “Tax Act”), as well as for future local, state, and federal
statutory tax rate changes. APS amended its March 17, 2020, filing on April 28, 2020, September 29, 2021, and October 27, 2021. In January 2022, FERC approved APS’s modifications to its annual transmission formula.

Effective June 1, 2021, APS’s annual wholesale transmission revenue requirement for all users of its transmission system increased by approximately $4 million for the 12-month period beginning June 1, 2021, in accordance with the FERC-approved formula. Of this net amount, wholesale customer rates decreased by approximately $3.2 million and retail customer rates would have increased by approximately $7.2 million. However, since changes in Retail Transmission Charges are reflected through the TCA after consideration of transmission recovery in retail base rates and the ACC-approved balancing account, the retail revenue requirement decreased by $28.4 million, resulting in reductions to both residential and commercial rates. An adjustment to APS’s retail rates to recover FERC-approved transmission charges went into effect automatically on June 1, 2021.

Effective June 1, 2022, APS’s annual wholesale transmission revenue requirement for all users of its transmission system decreased by approximately $33 million for the 12-month period beginning June 1, 2022, in accordance with the FERC-approved formula. Of this net amount, wholesale customer rates decreased by approximately $6.4 million and retail customer rates would have decreased by approximately $26.6 million. However, since changes in Retail Transmission Charges are reflected through the TCA after consideration of transmission recovery in retail base rates and the ACC approved balancing account, the retail revenue requirement decreased by $2.4 million, resulting in a reduction to the residential rate and increases to commercial rates. An adjustment to APS’s retail rates to recover FERC-approved transmission charges went into effect automatically on June 1, 2022.

Effective June 1, 2023, APS’s annual wholesale transmission revenue requirement for all users of its transmission system increased by approximately $34.7 million for the 12-month period beginning June 1, 2023, in accordance with the FERC-approved formula. Of this net amount, wholesale customer rates increased by approximately $20.7 million and retail customer rates would have increased by approximately $14 million. However, since changes in Retail Transmission Charges are reflected through the TCA after consideration of transmission recovery in retail base rates and the ACC approved balancing account, the retail revenue requirement decreased by $10 million, resulting in reductions to the residential and commercial rates. An adjustment to APS’s retail rates to recover FERC-approved transmission charges went into effect automatically on June 1, 2023.

Lost Fixed Cost Recovery Mechanism. The LFCR mechanism permits APS to recover on an after-the-fact basis a portion of its fixed costs that would otherwise have been collected by APS in the kWh sales lost due to APS energy efficiency programs and to DG such as rooftop solar arrays. The fixed costs recoverable by the LFCR mechanism were 2.50 cents for both lost residential and non-residential kWh as set forth in the settlement agreement in the 2017 rate case (the “2017 Settlement Agreement”). The fixed costs recoverable by the LFCR mechanism are currently 2.56 cents for lost residential kWh and 2.68 cents for lost non-residential kWh as set forth in the 2019 Rate Case decision. The adjustment to the LFCR has a year-over-year cap of 1% of retail revenues. Any amounts left unrecovered in a particular year because of this cap can be carried over for recovery in a future year. The kWhs lost from energy efficiency are based on a third-party evaluation of APS’s energy efficiency programs. DG sales losses are determined from the metered output from the DG units.
 
On February 15, 2021, APS filed its 2021 annual LFCR adjustment, requesting that effective May 1, 2021, the annual LFCR recovery amount be increased to $38.5 million (an $11.8 million increase from previous levels). On April 13, 2021, the ACC voted not to approve the requested $11.8 million increase to the annual LFCR adjustment; thus, the previously approved rates continued to remain intact and the $11.8 million increase was reflected in APS’s 2022 filing in accordance with the compliance requirements.

As a result of the 2019 Rate Case decision, APS’s annual LFCR adjustor rate will be dependent on an annual earnings test filing, which will compare APS’s previous year’s rate of return with the related authorized rate of return. If the actual rate of return is higher than the authorized rate of return, the LFCR rate for the subsequent year is set at zero. APS determined that the changes to the LFCR mechanism, as a result of the 2019 Rate Case decision effective on December 1, 2021, did not materially impact its results of operations and financial statements for the year ended December 31, 2021. However, as a result of certain changes made to the LFCR mechanism in the 2019 Rate Case decision, the mechanism no longer qualified for alternative revenue program accounting treatment, which impacts the future timing of related revenue recognition.

On February 15, 2022, APS filed its 2022 annual LFCR adjustment, requesting that effective May 1, 2022, the annual LFCR recovery amount be increased to $59.1 million (a $32.5 million increase from previous levels, which was inclusive of the $11.8 million balance from the 2021 filing). On May 9, 2022, the ACC Staff filed its revised report and proposed order regarding APS’s 2022 LFCR adjustment, concluding that APS calculated the adjustment in accordance with its Plan of Administration. On May 18, 2022, the ACC approved the 2022 LFCR adjustment, with a rate effective date of June 1, 2022.

On February 15, 2023, APS filed a letter to the ACC docket stating that, in accordance with Decision No. 78585, APS and ACC Staff have agreed to move the filing date for the annual LFCR adjustment to July 31 each year. On September 5, 2023, APS filed an updated LFCR Plan of Administration, which was approved by ACC Staff on December 8, 2023. On July 31, 2023, APS filed its 2023 annual LFCR adjustment, requesting that the annual LFCR recovery amount be increased to $68.7 million (a $9.6 million increase from previous levels). On October 19, 2023, a request for intervention was filed, which was granted. Consistent with an October 25, 2023, Procedural Order, the parties met and conferred and conducted limited discovery. Upon conclusion of discovery, ACC Staff will provide a Memorandum and Proposed Order that the parties will have an opportunity to respond to. The ACC has not yet ruled on this application.

Tax Expense Adjustor Mechanism. As part of the 2017 Settlement Agreement, the parties agreed to a rate adjustment mechanism to address potential federal income tax reform and enable the pass-through of certain income tax effects to customers. The TEAM expressly applies to APS’s retail rates with the exception of a small subset of customers taking service under specially-approved tariffs. As part of the 2019 Rate Case decision, the TEAM rates were reset to zero beginning December 31, 2021. The TEAM was retained in the 2022 Rate Case to address potential changes in tax law that may be enacted prior to a decision in a subsequent APS rate case.

Court Resolution Surcharge. The CRS mechanism permits APS to recover certain costs associated with investments and expenses for APS’s purchase and installation of SCR technology for Four Corners Units 4 and 5 and a change in APS’s allowable return on equity as required by the Arizona Court of Appeals and approved by the ACC in Decision No. 78979. The CRS went into effect on July 1, 2023, at
a rate of $0.00175 per kWh. The rate is designed to recover $59.6 million in revenue lost by APS between December of 2021 and June 20, 2023, and the prospective recovery of ongoing costs related to the SCR investments and expense and the allowable return on equity difference in current base rates. The current CRS will be recalculated on the effective date of the 2022 Rate Case to remove the effects of the prospective recovery related to the allowable return on equity difference. The portion of the CRS representing the recovery of the $59.6 million of lost revenue between December of 2021 and June 20, 2023, $9.4 million of which has been collected as of December 31, 2023, will cease upon full collection of the lost revenue. Finally, recovery of ongoing costs related to the SCR investments will continue until the Company’s next rate case in which they can be incorporated therein. On February 22, 2024, the ACC approved the 2022 Rate Case ROO, as amended. The CRS tariff is currently being recalculated to reflect the final decision in that case. See “2019 Retail Rate Case” above for more information.

Net Metering

The ACC’s decision from APS’s 2017 rate case (the “2017 Rate Case Decision”) provides that payments by utilities for energy exported to the grid from residential distributed generation (“DG”) solar facilities will be determined using a Resource Comparison Proxy (“RCP”) methodology as determined in the ACC’s generic Value and Cost of Distributed Generation docket. RCP is a method that is based on the most recent five-year rolling average price that APS incurs for utility-scale solar photovoltaic projects. The price established by this RCP method will be updated annually (between general retail rate cases) but will not be decreased by more than 10% per year. The ACC is no longer pursuing development of a forecasted avoided cost methodology as an option for utilities in place of the RCP. Commercial customers, grandfathered residential solar customers, and residential customers with DG systems other than solar facilities continue to qualify for net metering.

In addition, the ACC made the following determinations in the Value and Cost of Distributed Generation docket:

•RCP customers who have interconnected a DG system or submitted an application for interconnection for DG systems will be grandfathered for a period of 20 years from the date the customer’s interconnection application was accepted by the utility (for APS residential customers, as of September 1, 2017, based on APS’s 2017 Rate Case Decision);
•customers with DG solar systems are to be considered a separate class of customers for ratemaking purposes; and
•once an initial export price is set for utilities, no netting or banking of retail credits will be available for new DG customers, and the then-applicable export price will be guaranteed for new customers for a period of 10 years.

This decision of the ACC addresses policy determinations only. The decision states that its principles will be applied in future general retail rate cases, and the policy determinations themselves may be subject to future change, as are all ACC policies.

On April 29, 2022, APS filed an application to decrease the RCP price from 9.4 cents per kWh, which had been in effect since October 1, 2021, to 8.46 cents per kWh, reflecting a 10% annual reduction, to become effective September 1, 2022. On July 12, 2022, the ACC approved the RCP as filed.
On May 1, 2023, APS filed an application for revisions to the RCP. This application would decrease the RCP price to 7.619 cents per kWh, reflecting a 10% annual reduction, to become effective September 1, 2023. On August 25, 2023, the ACC approved the RCP as filed.

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

Energy Modernization Plan

On May 26, 2023, the ACC opened a new docket to review articles within the Arizona Administrative Code related to Resource Planning, the Renewable Energy Standard and Tariff, and Electric Energy Efficiency Standards. On January 9, 2024, the ACC approved a rulemaking process to begin on this matter. During the ACC Open Meeting on February 6, 2024, the ACC approved motions to direct ACC Staff to include recommendations to repeal the current Electric Energy Efficiency and Renewable Energy Standard rules during the rulemaking process. APS cannot predict the outcome of this matter.

Integrated Resource Planning

ACC rules require utilities to develop triennial 15-year IRPs which describe how the utility plans to serve customer load in the plan timeframe. The ACC reviews each utility’s IRP to determine if it meets the necessary requirements and whether it should be acknowledged. In February 2022, the ACC acknowledged APS’s 2020 IRP filed on June 26, 2020. The ACC also approved certain amendments to the IRP process, including, setting an EES of 1.3% of retail sales annually (averaged over a three-year period) and a demand-side resource capacity of 35% of 2020 peak demand by January 1, 2030.

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

Equity Infusions

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

Under the Public Utility Regulatory Policies Act of 1978 (“PURPA”), qualifying facilities are provided the right to sell energy and/or capacity to utilities and are granted relief from certain regulatory burdens. On December 17, 2019, the ACC mandated a minimum contract length of 18 years for qualifying facilities over 100 kW in Arizona and established that the rate paid to qualifying facilities must be based on the long-term avoided cost. “Avoided cost” is generally defined as the price at which the utility could purchase or produce the same amount of power from sources other than the qualifying facility on a long-term basis. During calendar year 2020, APS entered into two 18-year PPAs with qualified facilities, each for 80 MW solar facilities. In March 2021, the ACC approved these agreements. On July 19, 2023, the agreements for these two PPAs were terminated due to project delays.

Residential Electric Utility Customer Service Disconnections

On June 13, 2019, APS voluntarily suspended electric disconnections for residential customers who had not paid their bills. On June 20, 2019, the ACC voted to enact emergency rule amendments to prevent residential electric utility customer service disconnections during the period June 1 through October 15 (“Summer Disconnection Moratorium”). During the Summer Disconnection Moratorium, APS could not charge late fees and interest on amounts that were past due from customers. Customer deposits must also be used to pay delinquent amounts before disconnection can occur. In accordance with the emergency rules, APS began putting delinquent customers on a mandatory four-month payment plan beginning on October 16, 2019.

In June 2019, the ACC began a formal regular rulemaking process to allow stakeholder input and time for consideration of permanent rule changes. The ACC further ordered that each regulated utility serving retail customers in Arizona update its service conditions by incorporating the emergency rule amendments, restore power to any customers who were disconnected during the month of June 2019 and credit any fees that were charged for a reconnection. The ACC Staff and ACC proposed draft amendments to the customer service disconnections rules. On April 14, 2021, the ACC voted to send to the formal rulemaking process a draft rules package governing customer disconnections that allows utilities to choose between a temperature threshold (above 95 degrees and below 32 degrees) or calendar method (June 1 – October 15) for disconnection moratoriums. On November 2, 2021, the ACC approved the final rules, and on November 23, 2021, the rules were submitted to the Arizona Office of the Attorney General for final review and approval. The new rules became effective on April 18, 2022.

In accordance with the ACC service disconnection rules, APS now uses the calendar-based method to suspend the disconnection of customers for nonpayment from June 1 through October 15 each year (“Annual Disconnection Moratorium”). Customers with past due balances of $75 or greater as of the end of the Annual Disconnection Moratorium are automatically placed on six-month payment arrangements. In addition, APS voluntarily began waiving late payment fees of its customers (“Late Fee Waivers”) on March 13, 2020. Effective February 1, 2023, late payment fees for residential customers were reinstated. Late payment fees for commercial and industrial customers were reinstated effective May 1, 2022. Since the suspensions and moratoriums on disconnections began, APS has experienced an increase in bad debt expense and the related write-offs of delinquent customer accounts.
Retail Electric Competition Rules

On November 17, 2018, the ACC voted to re-examine the facilitation of a deregulated retail electric market in Arizona. On July 1 and July 2, 2019, ACC Staff issued a report and initial proposed draft rules regarding possible modifications to the ACC’s retail electric competition rules. On February 10, 2020, two ACC Commissioners filed two sets of draft proposed retail electric competition rules. On February 12, 2020, ACC Staff issued its second report regarding possible modifications to the ACC’s retail electric competition rules. During a July 15, 2020, ACC Staff meeting, the ACC Commissioners discussed the possible development of a retail competition pilot program, but no action was taken. The ACC continues to discuss matters related to retail electric competition, including the potential for additional buy-through programs or other pilot programs. In April 2022, the Arizona Legislature passed, and the Governor signed, a bill that repealed the electric deregulation law that had been in place in Arizona since 1998. APS cannot predict what impact, if any, this change will have on APS.

On August 4, 2021, Green Mountain Energy filed an application seeking a certificate of convenience and necessity to allow it to provide competitive electric generation service in Arizona. Green Mountain Energy has requested that the ACC grant it the ability to provide competitive service in APS’s and Tucson Electric Power Company’s certificated service territories and proposes to deliver a 100% renewable energy product to residential and general service customers in those service territories. APS opposes Green Mountain Energy’s application. On November 3, 2021, the ACC submitted questions to the Arizona Attorney General requesting legal opinions related to a number of issues surrounding retail electric competition and the ACC’s ability to issue competitive certificates of convenience and necessity. On November 26, 2021, the Administrative Law Judge issued a procedural order indicating it would not be appropriate to set a schedule until the Attorney General has provided insights on the applicable law. As the ACC’s questions pertained to the retail competition law subsequently repealed in April 2022, the Attorney General has not responded to the ACC’s request and the questions are now moot. No action has been taken by the ACC regarding this application since that time. However, on May 17, 2023, the Retail Energy Supply Association filed a motion with the ACC requesting it to re-open the generic docket to re-examine the ACC’s electric competition rules. No action has been taken by the ACC regarding this motion. APS cannot predict the outcome of these matters.

On October 28, 2021, an ACC Commissioner docketed a letter directing ACC Staff and interested stakeholders to design a 200 to 300 MW pilot program that would allow residential and small commercial customers of APS to elect a competitive electricity supplier. The letter also states that similar programs should be designed for other Arizona regulated electric utilities. APS cannot predict the outcome of these future activities.

Four Corners SCR Cost Recovery

On December 29, 2017, in accordance with the 2017 Rate Case Decision, APS filed a Notice of Intent to file its SCR Adjustment to permit recovery of costs associated with the installation of SCR equipment at Four Corners Units 4 and 5. APS filed the SCR Adjustment request in April 2018. The SCR Adjustment request provided that there would be a $67.5 million annual revenue impact that would be applied as a percentage of base rates for all applicable customers. Also, as provided for in the 2017 Rate Case Decision, APS requested that the adjustment become effective no later than January 1, 2019. The hearing for this matter occurred in September 2018. At the hearing, APS accepted ACC Staff’s
recommendation of a lower annual revenue impact of approximately $58.5 million. The Administrative Law Judge issued a Recommended Opinion and Order finding that the costs for the SCR project were prudently incurred and recommending authorization of the $58.5 million annual revenue requirement related to the installation and operation of the SCRs. The ACC did not issue a decision on this matter. APS included the costs for the SCR project in the retail rate base in its 2019 Rate Case filing with the ACC.

On November 2, 2021, the 2019 Rate Case decision was approved by the ACC allowing approximately $194 million of SCR related plant investments and cost deferrals in rate base and to recover, depreciate and amortize in rates based on an end-of-life assumption of July 2031. The decision also included a partial and combined disallowance of $215.5 million on the SCR investments and deferrals. APS believes the SCR plant investments and related SCR cost deferrals were prudently incurred, and on December 17, 2021, APS filed its Notice of Direct Appeal at the Arizona Court of Appeals requesting review of the $215.5 million disallowance. The Arizona Court of Appeals heard oral arguments on November 30, 2022. On March 6, 2023, the Court of Appeals issued its order in the matter, vacating the ACC’s disallowance of the SCR investment and remanding the matter back to the ACC for further review in accordance with ACC rules and the order of the Court of Appeals. On June 21, 2023, the ACC approved a joint settlement filed by APS and the ACC’s Legal Division that resolved all issues relating to the 2019 Rate Case decision, including recovery of the cost of the Four Corners SCRs. See above for further discussion on the 2019 Rate Case decision.

Cholla

On September 11, 2014, APS announced that it would close Unit 2 of the Cholla Power Plant (“Cholla”) and cease burning coal at the other APS-owned units (Units 1 and 3) at the plant by the mid-2020s, if the United States Environmental Protection Agency (“EPA”) approved a compromise proposal offered by APS to meet required environmental and emissions standards and rules. On April 14, 2015, the ACC approved APS’s plan to retire Unit 2, without expressing any view on the future recoverability of APS’s remaining investment in the unit. APS closed Unit 2 on October 1, 2015. In early 2017, EPA approved a final rule incorporating APS’s compromise proposal, which took effect on April 26, 2017. In December 2019, PacifiCorp notified APS that it planned to retire Cholla Unit 4 by the end of 2020 and the unit ceased operation in December 2020. APS is required to cease burning coal at its remaining Cholla units by April 2025.

Previously, APS estimated Cholla Unit 2’s end of life to be 2033. APS has been recovering a return on and of the net book value of the unit in base rates. Pursuant to the 2017 Settlement Agreement described above, APS will be allowed continued recovery of the net book value of the unit and the unit’s decommissioning and other retirement-related costs, $32.7 million as of December 31, 2023, in addition to a return on its investment. In accordance with GAAP, in the third quarter of 2014, Unit 2’s remaining net book value was reclassified from property, plant and equipment to a regulatory asset. In accordance with the 2019 Rate Case decision, the regulatory asset is being amortized through 2033.
Navajo Plant

The Navajo Plant ceased operations in November 2019. The co-owners and the Navajo Nation executed a lease extension on November 29, 2017, that allows for decommissioning activities to begin after the plant ceased operations. In accordance with GAAP, in the second quarter of 2017, APS’s remaining net book value of its interest in the Navajo Plant was reclassified from property, plant and equipment to a regulatory asset.

APS has been recovering a return on and of the net book value of its interest in the Navajo plant in base rates over its previously estimated life through 2026. Pursuant to the 2019 Rate Case decision described above, APS will be allowed continued recovery of the book value of its remaining investment in the Navajo plant, $43.0 million as of December 31, 2023, in addition to a return on the net book value, with the exception of 15% of the annual amortization expense in rates. In addition, APS will be allowed recovery of other costs related to retirement and closure, including the Navajo coal reclamation regulatory asset, $10.9 million as of December 31, 2023. The disallowed recovery of 15% of the annual amortization does not have a material impact on APS financial statements.
Regulatory Assets and Liabilities

The detail of regulatory assets is as follows (dollars in thousands):
SDecember 31,
 Amortization Through20232022
Pension(a)$696,476 $637,656 
Deferred fuel and purchased power (b) (c)2024463,195 460,561 
Income taxes — AFUDC equity2053189,058 179,631 
Ocotillo deferral2031128,636 138,143 
Deferred fuel and purchased power — mark-to-market (Note 16)2026120,214 — 
SCR deferral (e)203889,477 97,624 
Retired power plant costs203383,536 98,692 
Lease incentives (Note 8)(g)46,615 — 
Income taxes — investment tax credit basis adjustment205634,230 23,977 
Deferred compensation203633,972 33,660 
Deferred property taxes202732,488 41,057 
Palo Verde VIEs (Note 17)
204620,772 20,933 
Power supply adjustor-interest202419,416 1,541 
Active union medical trust(f)12,747 18,226 
Navajo coal reclamation202610,883 13,862 
Mead-Phoenix transmission line — contributions in aid of construction20508,716 9,048 
Loss on reacquired debt20387,965 9,468 
Four Corners cost deferral20247,922 15,999 
Tax expense adjustor mechanism (b)20315,190 5,845 
Lost fixed cost recovery (b)2023— 9,547 
OtherVarious4,528 6,630 
Total regulatory assets (d)$2,016,036 $1,822,100 
Less: current regulatory assets$625,757 $538,879 
Total non-current regulatory assets$1,390,279 $1,283,221 
(a)This asset represents the future recovery of pension benefit obligations and expense through retail rates.  If these costs are disallowed by the ACC, this regulatory asset would be charged to OCI and result in lower future revenues.  As a result of the 2019 Rate Case Decision, the amount authorized for inclusion in rate base was determined using an averaging methodology, which resulted in a reduced return in retail rates. The approved 2022 Rate Case ROO, as amended, allows for the full return on the pension asset in rate base. See Note 7 for further discussion.
(b)See “Cost Recovery Mechanisms” discussion above.
(c)Subject to a carrying charge.
(d)There are no regulatory assets for which the ACC has allowed recovery of costs, but not allowed a return by exclusion from rate base. FERC rates are set using a formula rate as described in “Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters.”
(e)See “Four Corners SCR Cost Recovery” discussion above.
(f)Collected in retail rates.
(g)Amortization periods vary based on specific terms of lease contract. See Note 8.

The detail of regulatory liabilities is as follows (dollars in thousands):
 December 31,
 Amortization Through20232022
Excess deferred income taxes - ACC — Tax Cuts and Jobs Act (a)2046$930,344 $971,545 
Excess deferred income taxes - FERC — Tax Cuts and Jobs Act (a)2058214,667 221,877 
Asset retirement obligations2057392,383 354,002 
Other postretirement benefits(d)226,726 270,604 
Removal costs (c) 94,368 106,889 
Income taxes — deferred investment tax credit205668,521 48,035 
Income taxes — change in rates205160,667 64,806 
Four Corners coal reclamation203855,917 52,592 
Renewable energy standard (b)202443,251 35,720 
Spent nuclear fuel202733,154 39,217 
Sundance maintenance203119,989 16,893 
Demand side management (b)202314,374 8,461 
Property tax deferral (e)202410,850 15,521 
Tax expense adjustor mechanism (b)20314,835 4,835 
FERC transmission true up (b)20251,869 22,895 
Deferred fuel and purchased power — mark-to-market (Note 15)
2026— 96,367 
OtherVarious3,873 3,092 
Total regulatory liabilities$2,175,788 $2,333,351 
Less: current regulatory liabilities$209,923 $271,575 
Total non-current regulatory liabilities$1,965,865 $2,061,776 
(a)For purposes of presentation on the Statement of Cash Flows, amortization of the regulatory liabilities for excess deferred income taxes are reflected as “Deferred income taxes” under Cash Flows From Operating Activities.
(b)See “Cost Recovery Mechanisms” discussion above.
(c)In accordance with regulatory accounting, APS accrues removal costs for its regulated assets, even if there is no legal obligation for removal.
(d)See Note 7.
v3.24.0.1
Income Taxes
 12 Months Ended
Dec. 31, 2023
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, investment tax credit (“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.    

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.

Net income associated with the 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 17 for additional details related to the Palo Verde sale leaseback VIEs.

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
 202320222021202320222021
Total unrecognized tax benefits, January 1$43,097 $45,086 $45,655 $43,097 $45,086 $45,655 
Additions for tax positions of the current year1,473 1,399 3,305 1,473 1,399 3,305 
Additions for tax positions of prior years419 2,069 1,449 419 2,069 1,449 
Reductions for tax positions of prior years for:      
Changes in judgment661 (3,495)(2,659)661 (3,495)(2,659)
Settlements with taxing authorities— — — — — — 
Lapses of applicable statute of limitations(1,376)(1,962)(2,664)(1,376)(1,962)(2,664)
Total unrecognized tax benefits, December 31$44,274 $43,097 $45,086 $44,274 $43,097 $45,086 

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
 202320222021202320222021
Tax positions, that if recognized, would decrease our effective tax rate$28,762 $28,246 $26,300 $28,762 $28,246 $26,300 

As of the balance sheet date, the tax year ended December 31, 2020, 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 2019.
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
 202320222021202320222021
Unrecognized tax benefit interest expense/(benefit) recognized$452 $(139)$(535)$452 $(139)$(535)

Following are the total amount 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
 202320222021202320222021
Unrecognized tax benefit interest accrued $1,633 $1,181 $1,320 $1,633 $1,181 $1,320 

Additionally, as of December 31, 2023, we have recognized less than $1 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 income tax expense are as follows (dollars in thousands):
Pinnacle West ConsolidatedAPS Consolidated
 Year Ended December 31,Year Ended December 31,
 202320222021202320222021
Current:   
Federal$21,272 $35,617 $(5,041)$26,405 $103,349 $1,514 
State2,854 1,950 2,458 1,027 161 (11)
Total current24,126 37,567 (2,583)27,432 103,510 1,503 
Deferred:      
Federal37,273 23,693 95,327 44,922 (31,860)101,175 
State15,513 13,567 17,342 21,830 19,150 22,875 
Total deferred52,786 37,260 112,669 66,752 (12,710)124,050 
Income tax expense/(benefit)$76,912 $74,827 $110,086 $94,184 $90,800 $125,553 
The following chart compares pretax income at the 21% statutory federal income tax rate to income tax expense (dollars in thousands):
Pinnacle West ConsolidatedAPS Consolidated
 Year Ended December 31,Year Ended December 31,
 202320222021202320222021
Federal income tax expense at statutory rate$125,095 $120,887 $156,666 $138,337 $132,920 $162,762 
Increases (reductions) in tax expense resulting from:      
State income tax net of federal income tax benefit18,024 17,740 22,656 19,832 19,000 23,339 
State income tax credits net of federal income tax benefit(3,513)(5,482)(7,015)(1,775)(3,744)(5,277)
Net operating loss carryback tax benefit— — (5,915)— — — 
Excess deferred income taxes — Tax Cuts and Jobs Act(36,558)(36,241)(36,558)(36,558)(36,241)(36,558)
Allowance for equity funds used during construction (Note 1)
(5,964)(4,629)(4,180)(5,964)(4,629)(4,180)
Palo Verde VIE noncontrolling interest (Note 17)
(3,617)(3,617)(3,617)(3,617)(3,617)(3,617)
Investment tax credit amortization(9,495)(5,608)(7,620)(9,495)(5,608)(7,620)
   Federal production tax credit(8,441)(3,146)(3,064)(5,460)— — 
   Other federal income tax credits(3,453)(7,721)(3,912)(2,803)(7,721)(3,912)
Other4,834 2,644 2,645 1,687 440 616 
Income tax expense/(benefit)$76,912 $74,827 $110,086 $94,184 $90,800 $125,553 
     The components of the net deferred income tax liability were as follows (dollars in thousands):
Pinnacle West ConsolidatedAPS Consolidated
 December 31,December 31,
 2023202220232022
DEFERRED TAX ASSETS  
Risk management activities$31,411 $8,826 $31,411 $8,826 
Regulatory liabilities:   
Excess deferred income taxes — Tax Cuts and Jobs Act283,161 295,014 283,161 295,014 
Asset retirement obligation and removal costs113,312 107,104 113,312 107,104 
Unamortized investment tax credits68,521 48,035 68,521 48,035 
Other postretirement benefits56,070 66,893 56,070 66,893 
Other39,857 62,915 39,857 62,915 
Operating lease liabilities316,067 184,030 315,670 182,663 
Pension liabilities33,294 33,674 29,918 30,436 
Coal reclamation liabilities45,505 44,312 45,505 44,312 
Renewable energy incentives17,261 19,948 17,261 19,948 
Credit and loss carryforwards43,940 37,647 3,031 13,654 
Other77,865 72,605 77,865 72,605 
Total deferred tax assets1,126,264 981,003 1,081,582 952,405 
DEFERRED TAX LIABILITIES   
Plant-related(2,572,495)(2,518,164)(2,572,495)(2,518,164)
Risk management activities(1,682)(32,648)(1,682)(32,648)
Pension and other postretirement assets(78,853)(96,845)(78,297)(96,196)
Other special use funds(56,550)(57,572)(56,550)(57,572)
Operating lease right-of-use assets(316,067)(184,030)(315,670)(182,663)
Regulatory assets:   
Allowance for equity funds used during construction(46,754)(44,405)(46,754)(44,405)
Deferred fuel and purchased power(149,078)(114,232)(149,078)(114,232)
Pension benefits(172,239)(157,629)(172,239)(157,629)
Retired power plant costs (20,659)(24,397)(20,659)(24,397)
Other(92,260)(103,023)(92,260)(103,023)
Other(36,107)(32,479)(7,595)(7,123)
Total deferred tax liabilities(3,542,744)(3,365,424)(3,513,279)(3,338,052)
Deferred income taxes — net$(2,416,480)$(2,384,421)$(2,431,697)$(2,385,647)
As of December 31, 2023, Pinnacle West consolidated deferred tax assets for credit and loss carryforwards relate to federal and state credit carryforwards, net of federal benefit, of $56 million, which first begin to expire in 2025. Pinnacle West consolidated credit and loss carryforwards amount above has been reduced by $12 million of unrecognized tax benefits.

As of December 31, 2023, APS consolidated deferred tax assets for credit and loss carryforwards relate to federal and state credit carryforwards, net of federal benefit, of $15 million, which first begin to expire in 2028. APS consolidated credit and loss carryforwards amount above has been reduced by $12 million of unrecognized tax benefits.
v3.24.0.1
Lines of Credit and Short-Term Borrowings
 12 Months Ended
Dec. 31, 2023
Lines of Credit and Short-Term Borrowings  
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 facilities and the amounts available and outstanding (dollars in thousands): 
December 31, 2023December 31, 2022
Pinnacle WestAPSTotalPinnacle WestAPSTotal
Commitments under Credit Facilities$200,000 $1,250,000 $1,450,000 $200,000 $1,000,000 $1,200,000 
Outstanding short-term borrowings(76,650)(532,850)(609,500)(15,720)(325,000)(340,720)
Amount of Credit Facilities Available$123,350 $717,150 $840,500 $184,280 $675,000 $859,280 
Weighted-Average Commitment Fees0.170%0.120%0.175%0.125%

Pinnacle West

On April 10, 2023, Pinnacle West replaced its $200 million revolving credit facility that would have matured on May 28, 2026, with a new $200 million revolving credit facility that matures on April 10, 2028. Pinnacle West has the option to increase the amount of the facility up to a total of $300 million upon the satisfaction of certain conditions and with the consent of the lenders. Interest rates are based on Pinnacle West’s senior unsecured debt credit ratings and the agreement includes a sustainability-linked pricing metric which permits an interest rate reduction or increase by meeting or missing targets related to specific environmental and employee health and safety sustainability objectives. The facility is available to support Pinnacle West’s general corporate purposes, including support for Pinnacle West’s $200 million commercial paper program, for bank borrowings or for issuances of letters of credit. At December 31, 2023, Pinnacle West had no outstanding borrowings under its revolving credit facility, no letters of credit outstanding under the credit facility, and $77 million of outstanding commercial paper borrowings. The weighted-average interest rate for the outstanding borrowings on December 31, 2023, was 5.47%.

APS

On April 10, 2023, APS replaced its two $500 million revolving credit facilities that would have matured on May 28, 2026, with a new $1.25 billion revolving credit facility that matures on April 10, 2028. APS has the option to increase the amount of the facility up to a maximum of $400 million, for a total of $1.65 billion, upon the satisfaction of certain conditions and with the consent of the lenders. Interest rates are based on APS’s senior unsecured debt credit ratings and the agreement includes a sustainability-linked pricing metric which permits an interest rate reduction or increase by meeting or missing targets related to specific environmental and employee health and safety sustainability objectives. The facility is available to support APS’s general corporate purposes, including support for APS’s commercial paper program, which was increased from $750 million to $1 billion on April 10, 2023, for bank borrowings or for issuances of letters of credit. At December 31, 2023, APS had no outstanding borrowings under its revolving credit facility, no letters of credit outstanding under the credit facility, and
$533 million of outstanding commercial paper borrowings. The weighted-average interest rate for the outstanding borrowings on December 31, 2023, was 5.46%.

On December 12, 2023, APS entered into an agreement with a new 364-day $350 million term loan facility that matures on December 10, 2024. Borrowings under the facility bear interest at SOFR plus 1.0% per annum. On February 9, 2024, APS drew the full amount of $350 million.

See “Financial Assurances” in Note 10 for a discussion of other outstanding letters of credit.

Debt Provisions
 
On December 15, 2022, the ACC issued a financing order that, among other things, 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). See Note 6 for additional long-term debt provisions.
v3.24.0.1
Long-Term Debt and Liquidity Matters
 12 Months Ended
Dec. 31, 2023
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)Rates20232022
APS    
Pollution control bonds:    
Variable2029(b)$163,975 $163,975 
Total pollution control bonds  163,975 163,975 
Senior unsecured notes2024-2050
2.20%-6.88%
7,180,000 6,680,000 
Unamortized discount  (14,197)(14,548)
Unamortized premium  11,162 12,368 
Unamortized debt issuance cost(49,049)(48,266)
Total APS long-term debt  7,291,891 6,793,529 
Less current maturities 250,000 — 
Total APS long-term debt less current maturities  7,041,891 6,793,529 
BCE
Los Alamitos equity bridge loan(d)(d)— 27,575 
Los Alamitos construction facility(d)(d)— 23,110 
Unamortized debt issuance cost— (135)
Total BCE long-term debt— 50,550 
Less current maturities— 50,685 
Total BCE long-term debt less current maturities— (135)
Pinnacle West    
Senior unsecured notes20251.30%500,000 500,000 
Term loans2024(c)625,000 450,000 
Unamortized discount(15)(25)
Unamortized debt issuance cost(1,254)(2,083)
Total Pinnacle West long-term debt1,123,731 947,892 
Less current maturities625,000 — 
Total Pinnacle West long-term debt less current maturities498,731 947,892 
TOTAL LONG-TERM DEBT LESS CURRENT MATURITIES
$7,540,622 $7,741,286 
(a)    This schedule does not reflect the timing of redemptions that may occur prior to maturities.
(b)    The weighted-average interest rate for the variable rate pollution control bonds was 4.11% at December 31, 2023, and 3.96% at December 31, 2022.
(c)    The weighted-average interest rate was 6.20% at December 31, 2023, and 5.10% at December 31, 2022. See additional details below.
(d)    On August 4, 2023, concurrent with the BCE Sale, the construction facility was transferred to Ameresco and the equity bridge loan was paid in full by Pinnacle West. See Note 20 and discussion 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
2024$875,000 $250,000 
2025800,000 300,000 
2026250,000 250,000 
2027300,000 300,000 
2028— — 
Thereafter6,243,975 6,243,975 
Total$8,468,975 $7,343,975 
 
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, 2023		As of
December 31, 2022
 Carrying
Amount		Fair ValueCarrying
Amount		Fair Value
Pinnacle West$1,123,731 $1,095,935 $947,892 $905,525 
APS7,291,891 6,459,718 6,793,529 5,629,491 
BCE— — 50,550 50,685 
Total$8,415,622 $7,555,653 $7,791,971 $6,585,701 
 
Credit Facilities and Debt Issuances

Pinnacle West

On December 16, 2022, Pinnacle West entered into a $175 million term loan facility that matures December 16, 2024. The proceeds were received on January 6, 2023, and used for general corporate purposes. We recognized the term loan facility as long-term debt upon settlement on January 6, 2023.
 
APS

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

On January 6, 2023, Pinnacle West contributed $150 million into APS in the form of an equity infusion. APS used this contribution to repay short-term indebtedness.

On June 30, 2023, APS issued $500 million of 5.55% unsecured senior notes that mature August 1, 2033. The net proceeds from the sale were used to repay short-term indebtedness consisting of commercial paper and for general corporate purposes.
See “Lines of Credit and Short-Term Borrowings” in Note 5 and “Financial Assurances” in Note 10 for discussion of APS’s separate outstanding letters of credit.

BCE

On February 11, 2022, a special purpose subsidiary of BCE entered into a credit agreement to finance capital expenditures and related costs for the development of a 31 megawatt (“MW”) solar and 20 megawatt hour (“MWh”) battery storage project in Los Alamitos, California (“Los Alamitos”). The credit agreement consisted of an equity bridge loan facility, a non-recourse construction facility, a letter of credit facility, and a related interest rate swap. On August 4, 2023, Pinnacle West entered into a purchase and sale agreement with Ameresco, Inc. (“Ameresco”), pursuant to which we agreed to sell all our equity interest in BCE to Ameresco (the “BCE Sale”). See Note 20. As a part of the BCE Sale closing, the $36 million construction facility, the letter of credit facility, and the interest rate swap were transferred to Ameresco. On August 4, 2023, concurrent with the BCE Sale, Pinnacle West paid in full the outstanding $31 million equity bridge loan balance. As of December 31, 2023, there is no outstanding balance on our Consolidated Balance Sheets relating to this credit agreement.

On April 18, 2023, and on December 29, 2023, Pinnacle West issued performance guarantees in connection with BCE’s Kūpono Solar investment project financing. BCE held an equity method investment relating to the Kūpono Solar project that was included in the BCE Sale relating to the stage of the BCE Sale that closed on January 12, 2024. The performance guarantees did not transfer in the BCE Sale, and Pinnacle West continues to retain these performance guarantees. See Note 10.
 
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 this covenant.  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, 2023, the ratio was approximately 60% for Pinnacle West and 52% 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 loan agreements contain “cross-default” provisions that would result in defaults and the potential acceleration of payment under these loan agreements if Pinnacle West or APS were to default under certain other material agreements.  All of APS’s bank agreements contain “cross-default” provisions that would result in defaults and the potential acceleration of payment under these bank agreements if APS were to default under certain other material agreements.  Pinnacle West and APS do not have a material adverse change restriction 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. On December 15, 2022, the ACC issued a financing order approving APS’s application filed on April 6, 2022, requesting to increase the long-term debt limit from $7.5 billion to $8.0 billion and to exclude financing lease PPAs from the definition of long-term indebtedness for purposes of the ACC financing orders. See Note 5 for additional short-term debt provisions.
v3.24.0.1
Retirement Plans and Other Postretirement Benefits
 12 Months Ended
Dec. 31, 2023
Retirement Benefits [Abstract]  
Retirement Plans and Other Postretirement Benefits Retirement Plans and Other Postretirement Benefits
Pinnacle West sponsors a qualified defined benefit and account balance pension plan (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 12 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 3.
 
The following table provides details of the plans’ net periodic benefit costs and the portion of these costs charged to expense (including administrative costs and excluding amounts capitalized as overhead construction or billed to electric plant participants) (dollars in thousands):
 Pension PlansOther Benefits Plans
 202320222021202320222021
Service cost-benefits earned during the period$39,461 $55,473 $61,236 $8,567 $16,470 $17,796 
Non-service costs (credits):
Interest cost on benefit obligation153,561 107,492 98,566 22,509 17,491 16,513 
Expected return on plan assets(182,938)(185,775)(202,628)(43,486)(46,042)(41,444)
Amortization of:      
Prior service credit (a)— — — (37,789)(37,789)(37,705)
Net actuarial (gain)/loss38,420 17,515 15,948 (9,614)(12,835)(10,093)
Net periodic benefit cost/(benefit)$48,504 $(5,295)$(26,878)$(59,813)$(62,705)$(54,933)
Portion of cost/(benefit) charged to expense$27,029 $(16,431)$(32,743)$(43,408)$(45,042)$(38,657)
(a)    Prior-service costs or credits reflect the impact of modifications to the pension or postretirement plan benefits. The impact of these modifications is amortized over a period which reflects the demographics of the impacted population. In 2014, Pinnacle West made changes to the postretirement benefits offered to Medicare eligible retirees which resulted in prior-service credits. We have been amortizing these prior-serviced credits since 2015 with the last full-year amortization occurring in 2024.
 
The following table shows the plans’ changes in the benefit obligations and funded status (dollars in thousands):
 Pension PlansOther Benefits Plans
 2023202220232022
Change in Benefit Obligation    
Benefit obligation at January 1$2,809,529 $3,716,824 $409,461 $591,841 
Service cost39,461 55,473 8,567 16,470 
Interest cost153,561 107,492 22,509 17,491 
Benefit payments(210,737)(212,565)(30,784)(30,913)
Actuarial (gain) loss116,249 (857,695)20,681 (185,428)
Benefit obligation at December 312,908,063 2,809,529 430,434 409,461 
Change in Plan Assets    
Fair value of plan assets at January 12,829,485 3,812,041 652,287 872,435 
Actual return/(loss) on plan assets199,098 (787,874)67,317 (193,807)
Benefit payments(193,034)(194,682)(23,110)(26,341)
Fair value of plan assets at December 312,835,549 2,829,485 696,494 652,287 
Funded/(Underfunded) Status at December 31$(72,514)$19,956 $266,060 $242,826 
The following table shows information for pension plans with an accumulated obligation in excess of plan assets (dollars in thousands):
As of December 31,
 20232022
Accumulated benefit obligation$123,701 $126,759 
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, 2023, and December 31, 2022, therefore, the only pension plan with an accumulated benefit obligation in excess of plan assets in 2023 and 2022 is a 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,
 20232022
Projected benefit obligation$129,891 $133,818 
Fair value of plan assets— — 

The Pinnacle West Capital Corporation Retirement Plan is more than 100% funded on a projected benefit obligation basis at December 31, 2023, and December 31, 2022, therefore the only pension plan with a projected benefit obligation in excess of plan assets in 2023 and 2022 is a 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
 2023202220232022
Noncurrent asset$57,378 $153,773 $266,060 $242,826 
Current liability(17,190)(17,531)— — 
Noncurrent liability(112,702)(116,286)— — 
Net amount recognized (funded status)$(72,514)$19,956 $266,060 $242,826 
 
The following table shows the details related to accumulated other comprehensive loss (gain) as of December 31, 2023, and 2022 (dollars in thousands): 
 Pension PlansOther Benefits Plans
 2023202220232022
Net actuarial loss (gain)$743,003 $681,335 $(188,630)$(195,095)
Prior service credit— — (39,054)(76,843)
APS’s portion recorded as a regulatory (asset) liability(696,476)(637,656)226,726 270,604 
Income tax expense (benefit)(11,506)(10,797)691 784 
Accumulated other comprehensive loss (gain)$35,021 $32,882 $(267)$(550)
 
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,
 20232022202320222021
Discount rate – pension plans5.21 %5.56 %5.56 %2.92 %2.53 %
Discount rate – other benefits plans5.23 %5.58 %5.58 %2.98 %2.63 %
Rate of compensation increase4.52 %4.57 %4.57 %4.00 %4.00 %
Expected long-term return on plan assets - pension plansN/AN/A6.70 %5.00 %5.30 %
Expected long-term return on plan assets - other benefit plansN/AN/A6.80 %5.35 %4.90 %
Initial healthcare cost trend rate (pre-65 participants)6.25 %6.50 %6.50 %6.00 %6.50 %
Ultimate healthcare cost trend rate (pre-65 participants)4.75 %4.75 %4.75 %4.75 %4.75 %
Number of years to ultimate trend rate (pre-65 participants)56534
Initial and ultimate healthcare cost trend rate (post-65 participants)2.00 %2.00 %2.00 %2.00 %2.00 %
Interest crediting rate – cash balance pension plans4.54 %4.50 %4.50 %4.50 %4.50 %

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 2024, 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, 2023, 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, 2023, 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, 2023:
Actual Allocation
Long-term fixed income assets62 %
Return-seeking assets38 %
Total100 %
See Note 12 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, 2023, 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, 2023, by asset category, are as follows (dollars in thousands):
 
 Level 1Level 2Other (a)Total
Pension Plan:   
Fixed income securities:   
Corporate$— $1,415,346 $— $1,415,346 
U.S. Treasury622,273 — — 622,273 
Other (b)— 135,184 — 135,184 
Common stock equities (c)150,657 — — 150,657 
Mutual funds (d)112,791 — — 112,791 
Common and collective trusts:
Equities— — 192,945 192,945 
Real estate— — 140,613 140,613 
Short-term investments and other (e)— — 65,740 65,740 
Total$885,721 $1,550,530 $399,298 $2,835,549 
Other Benefits:    
Fixed income securities:   
Corporate$— $189,902 $— $189,902 
U.S. Treasury207,665 — — 207,665 
Other (b)— 8,372 — 8,372 
Common stock equities (c)139,952 — — 139,952 
Mutual funds (d)22,256 — — 22,256 
Common and collective trusts:   
Equities— — 81,724 81,724 
Real estate— — 20,001 20,001 
Short-term investments and other (e)21,146 — 5,476 26,622 
Total$391,019 $198,274 $107,201 $696,494 
(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)This category includes plan receivables and payables.


 
The fair value of Pinnacle West’s pension plan and other postretirement benefit plan assets at December 31, 2022, by asset category, are as follows (dollars in thousands):
 Level 1Level 2Other (a)Total
Pension Plan:   
Cash and cash equivalents$1,252 $— $— $1,252 
Fixed income securities:   
Corporate— 1,374,810 — 1,374,810 
U.S. Treasury635,245 — — 635,245 
Other (b)— 131,999 — 131,999 
Common stock equities (c)155,231 — — 155,231 
Mutual funds (d)101,557 — — 101,557 
Common and collective trusts:
   Equities— — 181,912 181,912 
   Real estate— — 174,228 174,228 
Partnerships— — 13,359 13,359 
Short-term investments and other (e)— — 59,892 59,892 
Total $893,285 $1,506,809 $429,391 $2,829,485 
Other Benefits:    
Cash and cash equivalents$204 $— $— $204 
Fixed income securities:   
Corporate— 166,879 — 166,879 
U.S. Treasury221,936 — — 221,936 
Other (b)— 7,321 — 7,321 
Common stock equities (c)127,493 — — 127,493 
Mutual funds (d)18,824 — — 18,824 
Common and collective trusts:
   Equities— — 73,956 73,956 
   Real estate— — 23,541 23,541 
Short-term investments and other (e)3,274 — 8,859 12,133 
Total $371,731 $174,200 $106,356 $652,287 
(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.
(c)This category primarily consists of U.S. common stock equities.
(d)These funds invest in U.S. and international common stock equities.
(e)This category includes plan receivables and payables.

Contributions
 
Future year contribution amounts are dependent on plan asset performance and plan actuarial assumptions.  In 2023 and 2022, we did not make any contributions to our pension plan. In 2021, we made contributions to our pension plan totaling $100 million.  The minimum required contributions for the pension plan are zero for the next three years and we do not expect to make any voluntary contributions in 2024, 2025, or 2026.  With regard to contributions to our other postretirement benefit plan, we did not make a contribution in 2023 or 2022 and do not expect to make any contributions in 2024, 2025 or 2026.
The Company was reimbursed $23 million in 2023, $26 million in 2022, and $24 million in 2021 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
2024$244,772 $31,024 
2025226,748 30,446 
2026229,322 30,396 
2027226,906 30,024 
2028229,397 29,741 
Years 2029-20331,136,944 149,312 
 
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 2023, 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 $12 million for 2023, $12 million for 2022, and $12 million for 2021.
v3.24.0.1
Leases
 12 Months Ended
Dec. 31, 2023
Leases [Abstract]  
Leases Leases
 
We lease certain land, buildings, vehicles, equipment, and other property through operating rental agreements with varying terms, provisions, and expiration dates. APS also has certain purchased power and energy storage agreements that qualify as lease arrangements. Our leases have remaining terms that expire in 2024 through 2073. Substantially all of our leasing activities relate to APS.

In 1986, APS entered into agreements with three separate lessor trust entities in order to sell and lease back interests in Palo Verde Unit 2 and related common facilities.  These lessor trust entities have been deemed VIEs for which APS is the primary beneficiary.  As the primary beneficiary, APS consolidated these lessor trust entities.  The impacts of these sale leaseback transactions are excluded from our lease disclosures as lease accounting is eliminated upon consolidation.  See Note 17 for a discussion of VIEs.

APS has purchased power lease agreements that allow APS the right to the generation capacity from certain natural-gas fueled generators during certain months of each year throughout the term of the arrangements. As APS only has rights to use the assets during certain periods of each year, the leases have
non-consecutive periods of use. APS does not operate or maintain the leased assets. APS controls the dispatch of the leased assets during the months of use and is required to pay a fixed monthly capacity payment during these periods of use.  For these types of leased assets, APS has elected to combine both the lease and non-lease payment components and accounts for the entire fixed payment as a lease obligation. In addition to the fixed monthly capacity payments, APS must also pay variable charges based on the actual production volume of the assets.  The variable consideration is not included in the measurement of our lease obligation.

In January 2023, APS modified two existing purchase power operating lease agreements. Among other changes, the modifications extend the expiration dates of these contracts from October 2027 to October 2032 for one of the leases, and from September 2026 to October 2034 for the other lease. These lease agreements previously commenced in 2020 and 2021.

APS has executed various energy storage purchased power lease agreements that allow APS the right to charge and discharge energy storage facilities. The first of these energy storage leases commenced in September 2023, and is classified as an operating lease. This agreement provides APS the use of the energy storage facility through May 2043. APS pays a fixed monthly capacity price for rights to use the leased asset. APS does not operate or maintain the energy storage facility, and has no purchase options or residual value guarantees relating to the lease asset. For this class of energy storage lease assets, APS has elected to separate the lease and non-lease components.

The following table provides information related to our lease costs (dollars in thousands):
Year Ended December 31,
202320222021
Operating Lease Cost - Purchased Power & Energy Storage Lease Contracts$126,655 $104,001 $105,762 
Operating Lease Cost - Land, Property, and Other Equipment19,235 18,061 18,498 
Total Operating Lease Cost145,890 122,062 124,260 
Variable Lease Cost (a)135,007 122,040 118,969 
Short-term Lease Cost21,530 9,928 3,872 
Total Lease Cost$302,427 $254,030 $247,101 
(a)     Primarily relates to purchased power lease contracts.

Lease costs are primarily included as a component of operating expenses on our Consolidated Statements of Income. Lease costs relating to purchased power and energy storage 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 3. The tables above reflect the lease cost amounts before the effect of regulatory deferral under the PSA and RES. Variable lease costs are recognized in the period the costs are incurred, and primarily relate to renewable purchased power lease contracts. Payments under most renewable purchased power lease contracts are dependent upon environmental factors, and due to the inherent uncertainty associated with the reliability of the fuel source, the payments are considered variable and are excluded from the measurement of lease liabilities and right-of-use lease assets. Certain of our lease agreements have lease terms with non-consecutive periods of use. For these agreements we recognize lease costs during the periods of use. Leases with initial terms of 12 months or less are considered short-term leases and are not recorded on the balance sheet.
The following table provides information related to the maturity of our operating lease liabilities (dollars in thousands):
December 31, 2023
YearPurchased Power & Energy Storage Lease ContractsLand, Property & Equipment LeasesTotal
2024$108,201 $14,750 $122,951 
2025124,968 12,148 137,116 
2026138,692 9,826 148,518 
2027164,613 7,731 172,344 
2028168,410 5,401 173,811 
Thereafter835,813 64,090 899,903 
Total lease commitments1,540,697 113,946 1,654,643 
Less imputed interest334,693 41,878 376,571 
Total lease liabilities$1,206,004 $72,068 $1,278,072 
    
We recognize lease assets and liabilities upon lease commencement. At December 31, 2023, 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 $7.1 billion over the terms of the agreements. These arrangements primarily relate to energy storage assets. The lease commencement dates for these arrangements have experienced delays. APS continues to work with the lessors to determine revised commencement dates. We expect lease commencement dates ranging from April 2024 through June 2025, with lease terms expiring through May 2045. As a result of these delays and other events, APS has received cash proceeds from the 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 3.
The following tables provide other additional information related to operating lease liabilities (dollars in thousands):
Year Ended December 31,
202320222021
Cash paid for amounts included in the measurement of lease liabilities — operating cash flows:$123,472 $118,463 $116,661 
Right-of-use operating lease assets obtained in exchange for operating lease liabilities602,301 (a)16,990 500,582 


December 31, 2023December 31, 2022
Weighted average remaining lease term10 years7 years
Weighted average discount rate (b)4.53 %2.21 %

(a)Primarily relates to the two purchased power operating lease agreements that were modified in January 2023.
(b)Most of our lease agreements do not contain an implicit rate that is readily determinable. For these agreements we use our incremental borrowing rate to measure the present value of lease liabilities. We determine our incremental borrowing rate at lease commencement based on the rate of interest that we would have to pay to borrow, on a collateralized basis over a similar term, an amount equal to the lease payments in a similar economic environment. We use the implicit rate when it is readily determinable.
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Jointly-Owned Facilities
 12 Months Ended
Dec. 31, 2023
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, 2023 (dollars in thousands):

 Percent
Owned		 Plant in
Service		Accumulated
Depreciation		Construction
Work in
Progress
Generating facilities:     
Palo Verde Units 1 and 329.1 %$1,990,237 $1,087,614 $21,442 
Palo Verde Unit 2 (a)16.8 %681,483 387,485 12,700 
Palo Verde Common28.0 %(b)857,807 356,962 65,911 
Palo Verde Sale Leaseback (a)351,050 264,624 — 
Four Corners Generating Station 63.0 %1,748,436 659,780 29,586 
Cholla Common Facilities (c)50.5 %250,994 167,357 7,487 
Transmission facilities:     
ANPP 500kV System33.4 %(b)136,145 58,252 4,801 
Navajo Southern System25.2 %(b)87,185 36,743 550 
Palo Verde — Yuma 500kV System25.3 %(b)24,057 7,912 432 
Four Corners Switchyards57.5 %(b)84,279 21,918 161 
Phoenix — Mead System17.1 %(b)39,772 20,679 257 
Palo Verde — Rudd 500kV System50.0 %95,736 32,665 731 
Morgan — Pinnacle Peak System63.2 %(b)117,080 26,990 229 
Round Valley System50.0 %548 205 — 
Palo Verde — Morgan System87.5 %(b)268,629 40,962 8,053 
Hassayampa — North Gila System80.0 %151,684 24,618 — 
Cholla 500kV Switchyard85.7 %8,445 2,760 — 
Saguaro 500kV Switchyard60.0 %21,627 14,060 17 
Kyrene — Knox System50.0 %578 340 — 
Agua Fria Switchyard10.0 %— — 77 
(a)See Note 17.
(b)Weighted-average of interests.
(c)PacifiCorp owns Cholla Unit 4 (see Note 3 for additional information), and APS operated the unit for PacifiCorp.  Cholla Unit 4 was retired on December 24, 2020. The common facilities at Cholla are jointly-owned.
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Commitments and Contingencies
 12 Months Ended
Dec. 31, 2023
Commitments and Contingencies Disclosure [Abstract]  
Commitments and Contingencies Commitments and Contingencies
 
Palo Verde Generating Station
 
Spent Nuclear Fuel and Waste Disposal
 
On December 19, 2012, APS, acting on behalf of itself and the participant owners of Palo Verde, filed a second breach of contract lawsuit against 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 incurred by Palo Verde during the period January 1, 2007, through June 30, 2011. In addition, the settlement agreement provided APS with a method for submitting claims and getting recovery for costs incurred through December 31, 2016, which was extended to December 31, 2025.

APS has submitted nine claims pursuant to the terms of the August 18, 2014 settlement agreement, for nine separate time periods during July 1, 2011 through October 31, 2022. The DOE has approved and paid $138.2 million for these claims (APS’s share is $40.2 million). The amounts recovered were primarily recorded as adjustments to a regulatory liability and had no impact on reported net income. In accordance with the 2017 Rate Case Decision, this regulatory liability is being refunded to customers. See Note 3. On October 31, 2023, APS filed its tenth claim pursuant to the terms of the August 18, 2014, settlement agreement in the amount of $18.46 million (APS’s share is $5.4 million). In February 2024, the DOE approved $18.39 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 Nuclear Electric Insurance Limited (“NEIL”).  APS is subject to retrospective premium adjustments under all NEIL policies if NEIL’s losses in any policy year exceed accumulated funds. The maximum amount APS could incur under the current NEIL policies totals approximately $22.4 million for each retrospective premium assessment declared by NEIL’s Board of Directors due to losses.  Additionally, at the sole discretion of the NEIL Board of Directors, APS would be liable to provide approximately $62.6 million in deposit premium within 20 days of request as assurance to satisfy any site obligation of retrospective premium assessment.  The insurance coverage discussed in this, and the previous paragraph, is subject to certain policy conditions, sublimits, and exclusions.
 
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 2024 and 2045 that include required purchase provisions.  APS estimates the contract requirements to be approximately $1,034 million in 2024; $1,190 million in 2025; $1,310 million in 2026; $1,284 million in 2027; $1,292 million in 2028; and $14.7 billion thereafter.  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. See Note 8.
 
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,
 20242025202620272028Thereafter
Coal take-or-pay commitments (a)$208,694 $229,111 $221,122 $200,256 $205,237 $647,377 
 
(a)Total take-or-pay commitments are approximately $1.7 billion.  The total net present value of these commitments is approximately $1.4 billion.
 
    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,
 202320222021
Total purchases$255,219 $305,502 $219,958 
 
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 $29 million in 2024; $27 million in 2025; $24 million in 2026; $20 million in 2027; $17 million in 2028; and $52 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 $184 million at December 31, 2023, and $179 million at December 31, 2022. Under our current coal supply agreements, APS expects to make payments for the final mine reclamation as follows: $19 million in 2024; $20 million in 2025; $21 million in 2026; $22 million in 2027; $23 million in 2028; and $2 million thereafter. 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
 
The Comprehensive Environmental Response Compensation and Liability Act (“Superfund” or “CERCLA”) establishes liability for the cleanup of hazardous substances found contaminating the soil, water or air. Those who released, generated, transported to or disposed of hazardous substances at a contaminated site are among the parties who are potentially responsible (each a “PRP”). PRPs may be strictly, jointly, and severally liable for clean-up. On September 3, 2003, EPA advised APS that EPA considers APS to be a PRP in the Motorola 52nd Street Superfund Site, Operable Unit 3 (“OU3”) in Phoenix, Arizona. APS has facilities that are within this Superfund site. APS and Pinnacle West have agreed with EPA to perform certain investigative activities of the APS facilities within OU3. In addition, on September 23, 2009, APS agreed with EPA and one other PRP to voluntarily assist with the funding and management of the site-wide groundwater remedial investigation and feasibility study (“RI/FS”). The RI/FS for OU3 was finalized and submitted to EPA at the end of 2022. APS cannot predict the EPA’s timing with respect to this matter. APS’s estimated costs related to this investigation and study is approximately $3 million. APS anticipates incurring additional expenditures in the future, but because the ultimate remediation requirements are not yet finalized by EPA, at the present time expenditures related to this matter cannot be reasonably estimated.
 
In connection with APS’s status as a PRP for OU3, since 2013, APS and at least two dozen other parties have been defendants in various CERCLA lawsuits stemming from allegations that contamination from OU3 and elsewhere has impacted groundwater wells operated by the Roosevelt Irrigation District (“RID”). At this time, only one active lawsuit remains pending, which is on appeal to the U.S. Court of Appeals for the Ninth Circuit based on a U.S. District Court order dismissing cost recovery claims of approximately $20.7 million by a service provider for RID. APS is unable to predict the outcome of any
further litigation related to this claim or APS’s share of liability related to that claim; however, APS does not expect the outcome to have a material impact on our financial position, results of operations or cash flows.

In addition, as part of a state governmental investigation into groundwater contamination in this area, on January 25, 2015, the ADEQ sent a letter to APS seeking information concerning the degree to which, if any, APS’s current and former ownership of these facilities may have contributed to groundwater contamination in this area. APS responded to ADEQ on May 4, 2015. Since that time, ADEQ has taken no action based on the information provided by APS.

On February 28, 2022, EPA provided APS with a request for information under CERCLA related to APS’s Ocotillo power plant site located in Tempe, Arizona. In particular, EPA seeks information from APS regarding APS’s use, storage, and disposal of substances containing per-and polyfluoroalkyl (“PFAS”) compounds at the Ocotillo power plant site in order to aid EPA’s investigation into actual or threatened releases of PFAS into groundwater within the South Indian Bend Wash (“SIBW”) Superfund site. The SIBW Superfund site includes the APS Ocotillo power plant site. APS filed its response to this information request on April 29, 2022. On January 17, 2023, EPA contacted APS to inform the Company that it would be commencing on-site investigations within the SIBW site, including the Ocotillo power plant, and performing a remedial investigation and feasibility study related to potential PFAS impacts to groundwater over the next two to three years. APS estimates that its costs to oversee and participate in the remedial investigation work will be approximately $1.7 million. At the present time, we are unable to predict the outcome of this matter and any further expenditures related to necessary remediation, if any, or further investigations cannot be reasonably estimated.

Four Corners SCR Cost Recovery

As part of APS’s 2019 Rate Case, APS included recovery of the deferral and rate base effects of the Four Corners SCR project. On November 2, 2021, the 2019 Rate Case decision was approved by the ACC allowing approximately $194 million of SCR related plant investments and cost deferrals in rate base and to recover, depreciate and amortize in rates based on an end-of-life assumption of July 2031. The decision also included a partial and combined disallowance of $215.5 million on the SCR investments and deferrals. APS believes the SCR plant investments and related SCR cost deferrals were prudently incurred, and on December 17, 2021, APS filed its Notice of Direct Appeal at the Arizona Court of Appeals requesting review of the $215.5 million disallowance. The Arizona Court of Appeals heard oral arguments on November 30, 2022. On March 6, 2023, the Court of Appeals issued its order in the matter, vacating the ACC’s disallowance of the SCR investment and remanding the matter back to the ACC for further review in accordance with ACC rules and the order of the Court of Appeals. On June 21, 2023, the ACC approved a joint settlement filed by APS and the ACC’s Legal Division that resolved all issues relating to the 2019 Rate Case decision, including recovery of the cost of the Four Corners SCRs. See Note 3 for additional information regarding the Four Corners SCR cost recovery and the 2019 Rate Case.
 
Environmental Matters

APS is subject to numerous environmental laws and regulations affecting many aspects of its present and future operations, including air emissions of both conventional pollutants and greenhouse gases, water quality, wastewater discharges, solid waste, hazardous waste, and coal combustion residuals (“CCRs”). These laws and regulations can change from time to time, imposing new obligations on APS
resulting in increased capital, operating, and other costs. Associated capital expenditures or operating costs could be material. APS intends to seek recovery of any such environmental compliance costs through our rates but cannot predict whether it will obtain such recovery. The following proposed and final rules could involve material compliance costs to APS.
 
Coal Combustion Waste. On December 19, 2014, EPA issued its final regulations governing the handling and disposal of CCR, such as fly ash and bottom ash. The rule regulates CCR as a non-hazardous waste under Subtitle D of the Resource Conservation and Recovery Act (“RCRA”) and establishes national minimum criteria for existing and new CCR landfills and surface impoundments and all lateral expansions. These criteria include standards governing location restrictions, design and operating criteria, groundwater monitoring and corrective action, closure requirements and post closure care, and recordkeeping, notification, and internet posting requirements. The rule generally requires any existing unlined CCR surface impoundment to stop receiving CCR and either retrofit or close, and further requires the closure of any CCR landfill or surface impoundment that cannot meet the applicable performance criteria for location restrictions or structural integrity. Such closure requirements are deemed “forced closure” or “closure for cause” of unlined surface impoundments and are the subject of the regulatory and judicial activities described below.

Since these regulations were finalized, EPA has taken steps to substantially modify the federal rules governing CCR disposal. While certain changes have been prompted by utility industry petitions, others have resulted from judicial review, court-approved settlements with environmental groups, and statutory changes to RCRA. The following lists the pending regulatory changes that, if finalized, could have a material impact as to how APS manages CCR at its coal-fired power plants:

•Following the passage of the Water Infrastructure Improvements for the Nation Act in 2016, EPA possesses authority to either authorize states to develop their own permit programs for CCR management or issue federal permits governing CCR disposal both in states without their own permit programs and on tribal lands. Although ADEQ has taken steps to develop a CCR permitting program, and new state legislation has been adopted providing ADEQ with appropriate permitting authority for CCR under the state solid waste management program, it is not clear when that program will be put into effect. On December 19, 2019, EPA proposed its own set of regulations governing the issuance of CCR management permits, which would impact facilities like Four Corners located on the Navajo Nation. The proposal remains pending.

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

•With respect to APS’s Cholla facility, APS’s application for alternative closure was submitted to EPA on November 30, 2020. While EPA has deemed APS’s application administratively “complete,” the Agency’s approval remains pending. If granted, this application would allow the continued disposal of CCR within Cholla’s existing unlined CCR surface impoundments until the required date for ceasing coal-fired boiler operations in April 2025. This application
will be subject to public comment and, potentially, judicial review. We expect to have a proposed decision from EPA regarding Cholla sometime in 2024.

•On May 18, 2023, EPA published a proposal that expands the scope of federal CCR regulations to address the impacts from historical CCR disposal activities that would have ceased prior to 2015. EPA proposes to define a new class of CCR management units (“CCRMUs”) that broadly encompass any location at an operating coal-fired power plant where CCR would have been placed on land. As proposed, this would include not only historically closed landfills and surface impoundments but also prior applications of CCR beneficial use. EPA expects to finalize this proposal by spring of 2024.

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

APS currently disposes of CCR in ash ponds and dry storage areas at Cholla and Four Corners. The Navajo Plant disposed of CCR only in a dry landfill storage area. Additionally, the CCR rule requires ongoing, phased groundwater monitoring. As of October 2018, APS has completed the statistical analyses for its CCR disposal units that triggered assessment monitoring. APS determined that several of its CCR disposal units at Cholla and Four Corners will need to undergo corrective action. In addition, under the current regulations, all such disposal units must have ceased operating and initiated closure by April 11, 2021, at the latest (except for those disposal units subject to alternative closure). APS completed the assessments of corrective measures on June 14, 2019; however, additional investigations and engineering analyses that will support the remedy selection are still underway. In addition, APS will also solicit input from the public and host public hearings as part of this process. APS’s estimates for its share of corrective action and monitoring costs at Four Corners and Cholla are captured within the Asset Retirement Obligations. See Note 11. As APS continues to implement the CCR rule’s corrective action assessment process, the current cost estimates may change. Given uncertainties that may exist until we have fully completed the corrective action assessment and final remedy selection process, APS cannot predict any ultimate impacts to APS; however, at this time APS does not believe that any potential changes to the cost estimate for Four Corners or Cholla would have a material impact on its financial condition, results of operations, or cash flows.

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

In the latest set of proposed rules, released on May 23, 2023, EPA contemplates 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, the most recent proposal is limited to measures that can be installed at individual power plants to limit planet-warming emissions.

As such, for new natural gas-fired combustion turbine power plants, EPA is proposing that carbon emission performance standards apply based on the annual capacity factors. For the highest utilization combustion turbines, EPA is therefore proposing that such facilities be retrofitted for carbon capture and sequestration or utilization controls (“CCS”) or varying levels of hydrogen gas (“H2”) co-firing. As for existing natural gas-fired combustion turbines, EPA is imposing similar control requirements at large, high utilization generating units, but is otherwise not proceeding at this time with further regulation. As such, under EPA’s proposal, this means that both new and existing peaking gas-fired combustion turbines (i.e., those with a 20% or less annual capacity factor) are effectively unregulated under the proposed regulations.

For coal-fired power plants, instead of imposing regulations based on capacity and utilization, EPA has developed subcategories based on planned retirement dates. This means that facilities retiring between 2030 and before 2040 must meet increasingly stringent emission limits up to natural-gas co-firing starting in 2030. However, for those facilities with no planned retirement date prior to 2040, EPA is requiring those plants to be retrofitted with CCS controls by 2030.

EPA expects to take final action on this proposal by spring or summer of 2024. At this time, APS cannot predict the outcome of this rulemaking or when EPA will take final action. In addition, APS is continuing to evaluate this proposal and its potential impact on APS’s operations. Depending on the eventual outcome, the costs associated with APS’s operation of its current and future thermal power plants could materially increase, which could affect our financial condition, results of operations, or cash flows.

Other environmental rules that could involve material compliance costs include those related to effluent limitations, the ozone national ambient air quality standard and other rules or matters involving the Clean Air Act, Clean Water Act, Endangered Species Act, RCRA, Superfund, the Navajo Nation, and water supplies for our power plants. The financial impact of complying with current and future environmental rules could jeopardize the economic viability of APS’s fossil-fuel powered plants or the willingness or ability of power plant participants to fund any required equipment upgrades or continue their participation in these plants. The economics of continuing to own certain resources, particularly our coal plants, may deteriorate, warranting early retirement of those plants, which may result in asset impairments. APS would seek recovery in rates for the book value of any remaining investments in the plants, as well as other costs related to early retirement, but cannot predict whether it would obtain such recovery.
 
Four Corners National Pollutant Discharge Elimination System (“NPDES”) Permit

The latest NPDES permit for Four Corners was issued on September 30, 2019. Based upon a November 1, 2019, filing by several environmental groups, the Environmental Appeals Board (“EAB”) took up review of the Four Corners NPDES Permit. The EAB denied the environmental group petition on September 30, 2020. While on January 22, 2021, the environmental groups filed a petition for review of the EAB’s decision with the U.S. Court of Appeals for the Ninth Circuit, the parties to the litigation (including APS) finalized a settlement on May 2, 2022. This settlement requires investigation of thermal wastewater discharges from Four Corners, administratively closes the litigation filed in January of 2021, and APS does not expect the outcome to have a material impact on our financial condition, results
of operations, or cash flows.
Four Corners — 4CA Matter

On July 6, 2016, 4CA purchased El Paso Electric Company’s 7% interest in Four Corners. NTEC purchased this 7% interest on July 3, 2018, from 4CA. NTEC purchased the 7% interest at 4CA’s book value, approximately $70 million, and paid 4CA the purchase price over a period of four years pursuant to a secured interest-bearing promissory note, which was paid in full as of June 30, 2022.

In connection with the sale, Pinnacle West guaranteed certain obligations that NTEC will have to the other owners of Four Corners, such as NTEC’s 7% share of capital expenditures and operating and maintenance expenses. Pinnacle West’s guarantee is secured by a portion of APS’s payments to be owed to NTEC under the 2016 Coal Supply Agreement.

PNW Power Wind Projects

In October 2023, the Tenaska wind farm investments were reorganized such that they are no longer held by BCE, rather they are now held under the new Pinnacle West subsidiary, PNW Power. See Notes 1 and 20 for more information.

Tenaska Clear Creek Wind, LLC, the developer, owner, and operator of the Clear Creek wind farm, has disputed the proposed cost allocation of system upgrades related to connecting the Clear Creek wind farm to the transmission system. Tenaska Clear Creek Wind, LLC, filed complaints with FERC on this matter on May 21, 2021, and May 25, 2022, both of which FERC has denied. In April 2023, Tenaska Clear Creek Wind, LLC filed Petitions for Review of the relevant FERC orders with the U.S. Court of Appeals for the D.C. Circuit, which are still pending.

Due to disputed system upgrades and curtailment issues, the Clear Creek wind farm has experienced a significant reduction in power generation that has had a material adverse impact on the project’s ability to generate cash flow for investors. During the fourth quarter of 2022, due to these ongoing disputes, cost allocation uncertainties, and no probable favorable resolution, the equity method investment was fully impaired. Prior to the impairment, the investment had a carrying value of $17.1 million, which was written-down to reflect the investment’s estimated fair value of zero as of December 31, 2022. Pinnacle West’s Consolidated Statement of Income for the year ended December 31, 2022, includes an after-tax loss of $12.8 million relating to this impairment.

BCE Kūpono Solar

BCE and Ameresco jointly owned a special purpose entity that is sponsoring the Kūpono Solar project. This project is a 42 MW solar and battery storage facility in Oʻahu, Hawaii that will supply clean renewable energy and capacity under a 20-year power purchase agreement with Hawaiian Electric Company, Inc. The Kūpono Solar project is expected to be completed in 2024. On April 18, 2023, the Kūpono Solar special purpose entity entered into a $140 million non-recourse construction financing agreement. The construction financing will convert into a sale leaseback agreement upon commercial operation of the project. As of December 31, 2023, the construction financing agreement required $40 million of sponsor equity, which has been funded by the project’s equity participants and which is subject to adjustment under the construction financing agreement. In connection with the financing, Pinnacle West has issued performance guarantees relating to the project. Investments in the Kūpono Solar
project are included in the BCE Sale which closed on January 12, 2024. Subsequent to the BCE Sale, Pinnacle West continues to maintain the performance guarantees relating to the Kūpono Solar project financing, see additional information below regarding these guarantees. See Note 20 for information relating to the BCE Sale.

Financial Assurances
 
In the normal course of business, we obtain standby letters of credit and surety bonds from financial institutions and other third parties. These instruments guarantee our own future performance and provide third parties with financial and performance assurance in the event we do not perform. These instruments support commodity contract collateral obligations and other transactions. As of December 31, 2023, standby letters of credit totaled approximately $27 million and will expire in 2024. As of December 31, 2023, surety bonds expiring through 2025 totaled approximately $20 million. The underlying liabilities insured by these instruments are reflected on our balance sheets, where applicable. Therefore, no additional liability is reflected for the letters of credit and surety bonds themselves.
 
We enter into agreements that include indemnification provisions relating to liabilities arising from or related to certain of our agreements. Most significantly, APS has agreed to indemnify the equity participants and other parties in the Palo Verde sale leaseback transactions with respect to certain tax matters. Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnification provisions cannot be reasonably estimated. Based on historical experience and evaluation of the specific indemnities, we do not believe that any material loss related to such indemnification provisions is likely.
 
Pinnacle West has issued parental guarantees and has provided indemnification under certain surety bonds for APS which were not material at December 31, 2023. In connection with the sale of 4CA’s 7% interest to NTEC, Pinnacle West is guaranteeing certain obligations that NTEC will have to the other owners of Four Corners. See “Four Corners — 4CA Matter” above for information related to this guarantee. Pinnacle West has not needed to perform under this guarantee. A maximum obligation is not explicitly stated in the guarantee and, therefore, the overall maximum amount of the obligation under such guarantee cannot be reasonably estimated; however, we consider the fair value of this guarantee, including expected credit losses, to be immaterial.

In connection with PNW Power’s investments in minority ownership positions in the Clear Creek wind farm in Missouri and Nobles 2 wind farm in Minnesota, Pinnacle West has guaranteed the obligations of PNW Power to make production tax credit funding payments to borrowers of the projects (the “PTC Guarantees”). The amounts guaranteed by Pinnacle West are reduced as payments are made under the respective guarantee agreements. As of December 31, 2023, there is approximately $31 million of remaining guarantees relating to these PTC Guarantees that are expected to terminate by 2030.

Pinnacle West has issued various performance guarantees in connection with BCE’s Kūpono Solar project investment financing, and is exposed to losses relating to these guarantees upon the occurrence of certain events that we do not consider to be reasonably likely to occur. Subsequent to the BCE Sale, Pinnacle West continues to maintain these performance guarantees. See Note 20. As of December 31, 2023, these performance guarantees had no significant impact on our Consolidated Balance Sheets or Consolidated Statements of Income. The details of the guarantees are as follows:
•Upon the BCE Sale closing, which occurred on January 12, 2024, Pinnacle West committed to certain performance guarantees tied to the Kūpono project achieving certain construction and operation milestones. These performance guarantees will expire when the Kūpono project achieves commercial operation, which is expected in 2024.
•When the Kūpono financing coverts to a sale leaseback agreement, which is expected to occur upon commercial operation of the project, Pinnacle West has committed to certain performance guarantees that may apply upon the occurrence of specified events (such as uninsured loss events). Ameresco has agreed to make efforts to refinance the project and eliminate these guarantees prior to 2030.
•Ameresco is obligated to reimburse Pinnacle West for any payments made by Pinnacle West under such guarantees.
v3.24.0.1
Asset Retirement Obligations
 12 Months Ended
Dec. 31, 2023
Asset Retirement Obligation Disclosure [Abstract]  
Asset Retirement Obligations Asset Retirement Obligations
 
In 2023, the Company revised its cost estimates for existing Asset Retirement Obligations (“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 $71 million, primarily due to changes in the planned pond closure methodology and increased corrective action cost estimates associated with the CCR Rule. See Note 10.
•Four Corners coal-fired power plant, which resulted in a decrease of approximately $7 million.
•Navajo coal-fired plant, which resulted in an increase of approximately $8 million.
•Palo Verde received a new decommissioning study, which resulted in an increase to the ARO in the amount of $63 million, an increase in the plant in service of $59 million and a decrease in the regulatory liability of $4 million.

In 2022, APS did not revise any cost estimates related to existing AROs, and no new AROs were necessary.

See additional details in Notes 3 and 10.

The following table shows the change in our AROs (dollars in thousands):

 20232022
Asset retirement obligations at the beginning of year$797,762 $767,382 
Changes attributable to:  
Accretion expense44,269 41,240 
Settlements(14,039)(10,860)
Estimated cash flow revisions135,323 — 
Newly incurred obligation2,686 — 
Asset retirement obligations at the end of year$966,001 $797,762 
 
In accordance with regulatory accounting, APS accrues removal costs for its regulated utility assets, even if there is no legal obligation for removal.  See detail of regulatory liabilities in Note 3.
v3.24.0.1
Fair Value Measurements
 12 Months Ended
Dec. 31, 2023
Fair Value Disclosures [Abstract]  
Fair Value Measurements Fair Value Measurements
 
We classify our assets and liabilities that are carried at fair value within the fair value hierarchy.  This hierarchy ranks the quality and reliability of the inputs used to determine fair values, which are then classified and disclosed in one of three categories.  The three levels of the fair value hierarchy are:
 
Level 1 — Inputs are unadjusted quoted prices in active markets for identical assets or liabilities at the measurement date.

Level 2 — Other significant observable inputs, including quoted prices in active markets for similar assets or liabilities; quoted prices in markets that are not active, and model-derived valuations whose inputs are observable (such as yield curves). 
 
Level 3 — Valuation models with significant unobservable inputs that are supported by little or no market activity.  Instruments in this category may include long-dated derivative transactions where valuations are unobservable due to the length of the transaction, options, and transactions in locations where observable market data does not exist.  The valuation models we employ utilize spot prices, forward prices, historical market data and other factors to forecast future prices.
 
Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  Thus, a valuation may be classified in Level 3 even though the valuation may include significant inputs that are readily observable.  We maximize the use of observable inputs and minimize the use of unobservable inputs.  We rely primarily on the market approach of using prices and other market information for identical and/or comparable assets and liabilities.  If market data is not readily available, inputs may reflect our own assumptions about the inputs market participants would use.  Our assessment of the inputs and the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities as well as their placement within the fair value hierarchy levels.  We assess whether a market is active by obtaining observable broker quotes, reviewing actual market activity, and assessing the volume of transactions.  We consider broker quotes observable inputs when the quote is binding on the broker, we can validate the quote with market activity, or we can determine that the inputs the broker used to arrive at the quoted price are observable.

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. 

Risk Management Activities — Interest Rate Derivatives

Our interest rate derivative instruments related to a BCE interest rate swap, which was valued using financial models that utilize observable inputs for similar instruments and was classified as Level 2. The interest rate swap is no longer held as of December 31, 2023. See Note 20.
 
Investments Held in Nuclear Decommissioning Trusts and Other Special Use Funds
 
The nuclear decommissioning trusts and other special use funds invest in fixed income and equity securities. Other special use funds include the coal reclamation escrow account and the active union employee medical account. See Note 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 semi-monthly basis at the NAV.  The commingled funds are maintained by a bank and hold investments in accordance with the stated objective of tracking the performance of the S&P 500 Index.  Because the commingled funds’ shares are offered to a limited group of investors, they are not considered to be traded in an active market. As these instruments are valued using NAV, as a practical expedient, they have not been classified within the fair value hierarchy.

The nuclear decommissioning trusts and other special use funds may also hold equity securities that include exchange traded mutual funds and money market accounts for short-term liquidity purposes. These short-term, highly-liquid investments are valued using active market prices.
Fair Value Tables

The following table presents the fair value at December 31, 2023, of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):

Balance at December 31, 2023Level 1Level 2Level 3OtherTotal
ASSETS
Cash equivalents$10 $— $— $— $10 
Risk management activities — derivative instruments:
Commodity contracts— 1,881 6,616 (1,689)(a)6,808 
Nuclear decommissioning trust:
Equity securities11,064 — — (767)(b)10,297 
U.S. commingled equity funds— — — 409,616 (c)409,616 
U.S. Treasury debt319,734 — — — 319,734 
Corporate debt— 188,317 — — 188,317 
Mortgage-backed securities— 208,306 — — 208,306 
Municipal bonds— 59,323 — — 59,323 
Other fixed income— 5,653 — — 5,653 
Subtotal nuclear decommissioning trust330,798 461,599 — 408,849 1,201,246 
Other special use funds:
Equity securities40,991 — — 2,196 (b)43,187 
U.S. Treasury debt319,594 — — — 319,594 
Municipal bonds— — — — — 
Subtotal other special use funds360,585 — — 2,196 362,781 
Total assets$691,393 $463,480 $6,616 $409,356 $1,570,845 
LIABILITIES
Risk management activities — derivative instruments:
Commodity contracts$— $(127,016)$(1,695)$4,823 (a)$(123,888)
(a)Represents counterparty netting, margin, and collateral. See Note 15.
(b)Represents net pending securities sales and purchases.
(c)Valued using NAV as a practical expedient and, therefore, are not classified in the fair value hierarchy.
 The following table presents the fair value at December 31, 2022, of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):
 
Balance at December 31, 2022Level 1Level 2Level 3OtherTotal
ASSETS
Risk management activities — derivative instruments:
Commodity contracts$— $127,129 $26,132 $(21,163)(a)$132,098 
Interest rate swaps— 131 — — 131 
Subtotal risk management activities - derivative instruments— 127,260 26,132 (21,163)132,229 
Nuclear decommissioning trust:
Equity securities14,658 — — 3,827 (b)18,485 
U.S. commingled equity funds— — — 472,582 (c)472,582 
U.S. Treasury debt211,923 — — — 211,923 
Corporate debt— 149,226 — — 149,226 
Mortgage-backed securities— 147,938 — — 147,938 
Municipal bonds— 64,881 — — 64,881 
Other fixed income— 8,375 — — 8,375 
Subtotal nuclear decommissioning trust226,581 370,420 — 476,409 1,073,410 
Other special use funds:
Equity securities66,974 — — 963 (b)67,937 
U.S. Treasury debt275,267 — — — 275,267 
Municipal bonds— 4,027 — — 4,027 
Subtotal other special use funds342,241 4,027 — 963 347,231 
Total assets$568,822 $501,707 $26,132 $456,209 $1,552,870 
LIABILITIES
Risk management activities — derivative instruments:
Commodity contracts$— $(25,874)$(31,020)$15,357 (a)$(41,537)
Interest rate swaps— (909)— — (909)
Subtotal risk management activities - derivative instruments— (26,783)(31,020)15,357 (42,446)
Total liabilities$— $(26,783)$(31,020)$15,357 $(42,446)
(a)Represents counterparty netting, margin, and collateral. See Note 15.
(b)Represents net pending securities sales and purchases.
(c)Valued using NAV as a practical expedient and, therefore, are not classified in the fair value hierarchy.
 
Fair Value Measurements Classified as Level 3
 
The significant unobservable inputs used in the fair value measurement of our energy derivative contracts include broker quotes that cannot be validated as an observable input primarily due to the long-term nature of the quote or other characteristics of the product.  Significant changes in these inputs in isolation would result in significantly higher or lower fair value measurements.  Changes in our derivative contract fair values, including changes relating to unobservable inputs, typically will not impact net income due to regulatory accounting treatment. See Note 3.
 
Because our forward commodity contracts classified as Level 3 are currently in a net purchase position, we would expect price increases of the underlying commodity to result in increases in the net fair value of the related contracts.  Conversely, if the price of the underlying commodity decreases, the net fair value of the related contracts would likely decrease.

Other unobservable valuation inputs include credit and liquidity reserves which do not have a material impact on our valuations; however, significant changes in these inputs could also result in higher or lower fair value measurements.

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

December 31, 2023
 Fair Value (thousands) 		ValuationSignificantWeighted-Average
Commodity ContractsAssetsLiabilitiesTechniqueUnobservable InputRange (b)
Electricity:
Forward Contracts (a)$6,587 $658 Discounted cash flowsElectricity forward price (per MWh)
$37.79
-
$259.04
$158.08 
Natural Gas:
Forward Contracts (a)29 1,037 Discounted cash flowsNatural gas forward price (per MMBtu)
$0.00
-
$0.08
$0.03 
Total$6,616 $1,695 
(a)Includes swaps and physical and financial contracts.
(b)Unobservable inputs were weighted by the relative fair value of the instrument.

December 31, 2022
 Fair Value (thousands) 		ValuationSignificantWeighted-Average
Commodity ContractsAssetsLiabilitiesTechniqueUnobservable InputRange(b)
Electricity:
Forward Contracts (a)$26,132 $1,759 Discounted cash flowsElectricity forward price (per MWh)$37.79 -$310.69 $163.92 
Natural Gas:
Forward Contracts (a)— 29,261 Discounted cash flowsNatural gas forward price (per MMBtu)$(11.81)-$0.00$(5.08)
Total$26,132 $31,020 
(a)Includes swaps and physical and financial contracts.
(b)Unobservable inputs were weighted by the relative fair value of the instrument.
The following table shows the changes in fair value for our risk management activities’ assets and liabilities that are measured at fair value on a recurring basis using Level 3 inputs (dollars in thousands):

 Year Ended December 31,
Commodity Contracts20232022
Net derivative balance at beginning of period$(4,888)$(2,738)
Total net gains (losses) realized/unrealized:
Deferred as a regulatory asset or liability(70,214)(374)
Settlements69,706 (1,123)
Transfers into Level 3 from Level 2(1,289)(846)
Transfers from Level 3 into Level 211,606 193 
Net derivative balance at end of period$4,921 $(4,888)
Net unrealized gains included in earnings related to instruments still held at end of period$— $— 

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

Financial Instruments Not Carried at Fair Value
 
The carrying value of our short-term borrowings approximate fair value and are classified within Level 2 of the fair value hierarchy.  See Note 6 for our long-term debt fair values.
v3.24.0.1
Earnings Per Share
 12 Months Ended
Dec. 31, 2023
Earnings Per Share [Abstract]  
Earnings Per Share Earnings Per Share
The following table presents the calculation of Pinnacle West’s basic and diluted earnings per share (in thousands, except per share amounts):
 202320222021
Net income attributable to common shareholders$501,557 $483,602 $618,720 
Weighted average common shares outstanding — basic113,442 113,196 112,910 
Net effect of dilutive securities:   
Contingently issuable performance shares and restricted stock units362 220 282 
Weighted average common shares outstanding — diluted113,804 113,416 113,192 
Earnings per weighted-average common share outstanding
Net income attributable to common shareholders — basic$4.42 $4.27 $5.48 
Net income attributable to common shareholders — diluted$4.41 $4.26 $5.47 
v3.24.0.1
Stock-Based Compensation
 12 Months Ended
Dec. 31, 2023
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 (“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, 2023, 3.5 million common shares were available for issuance under the 2021 Plan. During 2023, 2022 and 2021, 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 $17 million in 2023, $16 million in 2022, and $18 million in 2021.  The compensation cost capitalized is immaterial for all years. Income tax benefits related to stock-based compensation arrangements were $3 million in 2023, $2 million in 2022, and $3 million in 2021.

As of December 31, 2023, there were approximately $31 million of unrecognized compensation costs related to nonvested stock-based compensation arrangements. We expect to recognize these costs over a weighted-average period of two years. 

The total fair value of shares vested was $24 million in 2023, $25 million in 2022, and $22 million in 2021.
 
The following table is a summary of awards granted and the weighted-average grant date fair value for each of the last three years:
Restricted Stock Units, Stock Grants, and Stock Units (a)Performance Shares (b)
 202320222021202320222021
Units granted192,295 174,791 152,345 202,562 208,736 161,840 
Weighted-average grant date fair value$74.32 $69.66 $76.72 $79.61 $77.63 $82.42 
(a)Units granted includes awards that will be cash settled of 0 in 2023, 0 in 2022, and 51,074 in 2021. 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, 2022
317,587 $73.91 330,694 $78.91 
Granted192,295 74.32 202,562 79.61 
Vested(119,077)80.71 (169,290)83.12 
Forfeited (c)(16,438)73.95 (16,683)78.40 
Nonvested at December 31, 2023
374,367 (a)73.29 347,283 77.29 
Vested Awards Outstanding at December 31, 2023
70,766 155,708 
(a)Includes 34,367 of 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 $6 million, $3 million, and $4 million in 2023, 2022 and 2021, respectively. This includes cash used to settle restricted stock units of $3 million, $3 million, and $3 million in 2023, 2022 and 2021, 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, Clean and 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, Clean and Metric component at each balance sheet date. If the EPS, Clean and Metric component criteria are not ultimately achieved, no compensation cost is recognized relating to the EPS, Clean and 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.
v3.24.0.1
Derivative Accounting
 12 Months Ended
Dec. 31, 2023
Derivative Instruments and Hedging Activities Disclosure [Abstract]  
Derivative Accounting Derivative Accounting
 
Derivative financial instruments are used to manage exposure to commodity price and transportation costs of electricity, natural gas, emissions allowances, and interest rates.  Risks associated with market volatility are managed by utilizing various physical and financial derivative instruments, including futures, forwards, options, and swaps.  As part of our overall risk management program, we may use derivative instruments to hedge purchases and sales of electricity and natural gas.  Derivative instruments that meet certain hedge accounting criteria may be designated as cash flow hedges and are used to limit our exposure to cash flow variability on forecasted transactions.  The changes in market value of such instruments have a high correlation to price changes in the hedged transactions.  Derivative instruments are also entered into for economic hedging purposes.  While economic hedges may mitigate exposure to fluctuations in commodity prices, these instruments have not been designated as accounting hedges.  Contracts that have the same terms (quantities, delivery points and delivery periods) and for which power does not flow are netted, which reduces both revenues and fuel and purchased power costs in our Consolidated Statements of Income, but does not impact our financial condition, net income, or cash flows.
  
Our derivative instruments, excluding those qualifying for a scope exception, are recorded on the balance sheets as an asset or liability and are measured at fair value.  See Note 12 for a discussion of fair value measurements.  Derivative instruments may qualify for the normal purchases and normal sales scope exception if they require physical delivery, and the quantities represent those transacted in the normal course of business.  Derivative instruments qualifying for the normal purchases and sales scope exception are accounted for under the accrual method of accounting and excluded from our derivative instrument discussion and disclosures below.

Energy Derivatives

For its regulated operations, APS defers for future rate treatment 100% of the unrealized gains and losses on 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 3.  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, 2023December 31, 2022
PowerGWh1,212 1,197 
GasBillion cubic feet200 149 
 
Gains and Losses from Energy Derivative Instruments
 
For the years ended December 31, 2023, 2022 and 2021, 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 ContractsLocation202320222021
Net Gain (Loss) Recognized in IncomeFuel and purchased power (a)$(370,145)$307,287 $216,847 
(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.
As of December 31, 2023:
 (dollars in thousands) 		Gross 
Recognized 
Derivatives
 (a)		Amounts 
Offset
(b)		Net
 Recognized
 Derivatives		Other
 (c)		Amounts 
Reported on 
Balance Sheets
Current assets$8,497 $(1,694)$6,803 $5 $6,808 
Investments and other assets— — — — — 
Total assets8,497 (1,694)6,803 5 6,808 
Current liabilities(85,736)10,894 (74,842)(6,071)(80,913)
Deferred credits and other(42,975)— (42,975)— (42,975)
Total liabilities(128,711)10,894 (117,817)(6,071)(123,888)
Total$(120,214)$9,200 $(111,014)$(6,066)$(117,080)
(a)All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)Includes cash collateral provided to counterparties of $9,200 thousand that is subject to offsetting.
(c)Represents cash collateral and cash margin that is not subject to offsetting. Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument.  Includes cash collateral received from counterparties of $6,071 thousand and cash margin provided to counterparties of $5 thousand.
As of December 31, 2022:
 (dollars in thousands) 		Gross
 Recognized
 Derivatives
 (a)		Amounts
Offset 
(b)		Net
 Recognized
 Derivatives		Other
 (c)		Amounts
 Reported on
 Balance Sheets
Current assets$103,484 $(15,808)$87,676 $28 $87,704 
Investments and other assets49,777 (5,383)44,394 — 44,394 
Total assets153,261 (21,191)132,070 28 132,098 
Current liabilities(47,670)15,808 (31,862)(5,835)(37,697)
Deferred credits and other(9,223)5,383 (3,840)— (3,840)
Total liabilities(56,893)21,191 (35,702)(5,835)(41,537)
Total$96,368 $— $96,368 $(5,807)$90,561 
(a)All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)No cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting.
(c)Represents cash collateral and cash margin that is not subject to offsetting.  Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument.  Includes cash collateral received from counterparties of $5,835 thousand and cash margin provided to counterparties of $28 thousand.
Interest Rate Derivatives

On October 19, 2022, Bright Canyon Energy entered into an interest rate swap to hedge the variable interest rate exposure relating to the credit agreement for the Los Alamitos project. The transaction qualified and had been designated as a cash flow hedge. The interest rate swap was included in the BCE Sale, and was assumed by Ameresco as part of the first stage of the closing. See Note 20. Prior to being transferred in the BCE Sale, the interest rate swap was in an asset position valued at $0.2 million. As of December 31, 2023, the interest rate swap has no impact on our Consolidated Balance Sheets.

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, 2023, we have no counterparties with positive exposures of greater than 10% of Pinnacle West’s risk management assets. Our risk management process assesses and monitors the financial exposure of all counterparties.  Despite the fact that the great majority of our trading counterparties’ debt is rated as investment grade by the credit rating agencies, there is still a possibility that one or more of these counterparties could default, resulting in a material impact on consolidated earnings for a given period. Counterparties in the portfolio consist principally of financial institutions, major energy companies, municipalities, and local distribution companies.  We maintain credit policies that we believe minimize overall credit risk to within acceptable limits.  Determination of the credit quality of our counterparties is based upon a number of factors, including credit ratings and our evaluation of their financial condition.  To manage credit risk, we employ collateral requirements and standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty.  Valuation adjustments are established representing our estimated credit losses on our overall exposure to counterparties.
 
Certain of our energy derivative instrument contracts contain credit-risk-related contingent features including, among other things, investment grade credit rating provisions, credit-related cross-default provisions, and adequate assurance provisions.  Adequate assurance provisions allow a counterparty with reasonable grounds for uncertainty to demand additional collateral based on subjective events and/or conditions.  For those energy derivative instruments in a net liability position, with investment grade credit contingencies, the counterparties could demand additional collateral if our debt credit rating were to fall below investment grade (below BBB- for Standard & Poor’s or Fitch or Baa3 for Moody’s).
 
The following table provides information about our energy derivative instruments that have credit-risk-related contingent features (dollars in thousands):
 December 31, 2023
Aggregate fair value of derivative instruments in a net liability position$128,711 
Cash collateral posted9,200 
Additional cash collateral in the event credit-risk related contingent features were fully triggered (a)117,566 
(a)This amount is after counterparty netting and includes those contracts which qualify for scope exceptions, which are excluded from the derivative details above.
 
We also have energy related non-derivative instrument contracts with investment grade credit-related contingent features, which could also require us to post additional collateral of approximately $205 million if our debt credit ratings were to fall below investment grade.
v3.24.0.1
Other Income and Other Expense
 12 Months Ended
Dec. 31, 2023
Other Income and Expenses [Abstract]  
Other Income and Other Expense Other Income and Other Expense
 
The following table provides detail of Pinnacle West’s Consolidated other income and other expense for 2023, 2022 and 2021 (dollars in thousands):
 202320222021
Other income:   
Interest income$27,242 (a)$7,326 $6,726 
Gain on Sale of BCE (Note 20)
6,205 — — 
Debt return on Four Corners SCR deferral (Note 3)
— — 14,955 
Debt return on Ocotillo modernization project (Note 3)
— — 23,366 
Miscellaneous219 590 53 
Total other income$33,666 $7,916 $45,100 
Other expense:   
Non-operating costs$(15,260)$(18,619)$(13,008)
Investment gains (losses) — net(3,402)(20,537)(b)(1,367)
Miscellaneous(6,394)(13,229)(c)(11,021)
Total other expense$(25,056)$(52,385)$(25,396)
(a)The 2023 interest income is primarily related to PSA Interest. See Note 3.
(b)The 2022 investment loss is primarily related to an impairment of PNW Power’s Clear Creek wind farm investment. See Note 10.
(c)The 2022 miscellaneous amount includes donations of $7 million to the APS Foundation.
Other Income and Other Expense - APS
 
The following table provides detail of APS’s other income and other expense for 2023, 2022 and 2021 (dollars in thousands):
 202320222021
Other income:   
Interest income$26,853 (a)$5,332 $4,692 
Debt return on Four Corners SCR deferral (Note 3)
— — 14,955 
Debt return on Ocotillo modernization project (Note 3)
— — 23,366 
Miscellaneous219 556 40 
Total other income$27,072 $5,888 $43,053 
Other expense:   
Non-operating costs$(14,070)$(15,579)$(10,080)
Miscellaneous(4,194)(10,529)(b)(8,817)
Total other expense$(18,264)$(26,108)$(18,897)
(a)The 2023 interest income is primarily related to PSA Interest. See Note 3.
(b)The 2022 miscellaneous amount includes donations of $7 million to the APS Foundation.
v3.24.0.1
Palo Verde Sale Leaseback Variable Interest Entities
 12 Months Ended
Dec. 31, 2023
Variable Interest Entities [Abstract]  
Palo Verde Sale Leaseback Variable Interest Entities Palo Verde Sale Leaseback Variable Interest Entities
 
In 1986, APS entered into agreements with three separate VIE lessor trust entities in order to sell and lease back interests in Palo Verde Unit 2 and related common facilities. APS will retain the assets through 2033 under all three lease agreements. APS will be required to make payments relating to the three leases in total of approximately $21 million annually for the period 2024 through 2033. At the end of the lease period, APS will have the option to purchase the leased assets at their fair market value, extend the leases for up to two years, or return the assets to the lessors.
 
The leases’ terms give APS the ability to utilize the assets for a significant portion of the assets’ economic life, and therefore provide APS with the power to direct activities of the VIEs that most significantly impact the VIEs’ economic performance. Predominantly due to the lease terms, APS has been deemed the primary beneficiary of these VIEs and therefore consolidates the VIEs.

As a result of consolidation, we eliminate lease accounting and instead recognize depreciation expense, resulting in an increase in net income of $17 million for 2023, 2022 and 2021, respectively. 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 the VIEs (dollars in thousands):
 December 31, 2023December 31, 2022
Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation$86,426 $90,296 
Equity-Noncontrolling interests107,198 111,229 
 
Assets of the VIEs 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 these VIEs upon the occurrence of certain events that APS does not consider to be reasonably likely to occur.  Under certain circumstances (for example, the NRC issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), APS would be required to make specified payments to the VIEs’ noncontrolling equity participants and take title to the leased Unit 2 interests, which, if appropriate, may be required to be written-down in value.  If such an event were to occur during the lease periods, APS may be required to pay the noncontrolling equity participants approximately $334 million beginning in 2024, and up to $501 million over the lease extension terms.
 
For regulatory ratemaking purposes, the agreements continue to be treated as operating leases and, as a result, we have recorded a regulatory asset relating to the arrangements.
v3.24.0.1
Investments in Nuclear Decommissioning Trusts and Other Special Use Funds
 12 Months Ended
Dec. 31, 2023
Investments, Debt and Equity Securities [Abstract]  
Investments in Nuclear Decommissioning Trusts and Other Special Use Funds Investments in Nuclear Decommissioning Trusts and Other Special Use Funds
 
We have investments in debt and equity securities held in Nuclear Decommissioning Trusts, Coal Reclamation Escrow Account, and an Active Union Employee Medical Account. Investments in debt securities are classified as available-for-sale securities. We record both debt and equity security
investments at their fair value on our Consolidated Balance Sheets. See Note 12 for a discussion of how fair value is determined and the classification of the investments within the fair value hierarchy. The investments in each trust or account are restricted for use and are intended to fund specified costs and activities as further described for each fund below.

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

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

Active Union Employee Medical Account — APS has investments restricted for paying active union employee medical costs. These investments may be used to pay active union employee medical costs incurred in the current and future periods. In 2023 and 2022, APS was reimbursed $14 million and $15 million, respectively, for prior year active union employee medical claims from the active union employee medical account. The account is invested primarily in fixed income securities. In accordance with the ratemaking treatment, APS has deferred the unrealized gains and losses (including credit losses) in other regulatory liabilities. Activities relating to active union employee medical account investments are included within the other special use funds in the table below.
APS

The following tables present the unrealized gains and losses based on the original cost of the investment and summarizes the fair value of APS’s nuclear decommissioning trusts and other special use fund assets (dollars in thousands): 
December 31, 2023
 Fair ValueTotal
Unrealized
Gains		Total
Unrealized
Losses
Investment Type:Nuclear Decommissioning TrustsOther Special Use FundsTotal
Equity securities$420,680 $40,991 $461,671 $336,555 $— 
Available for sale-fixed income securities781,333 319,594 1,100,927 (a)21,518 (40,868)
Other(767)2,196 1,429 (b)39 — 
Total$1,201,246 $362,781 $1,564,027 $358,112 $(40,868)
(a)As of December 31, 2023, the amortized cost basis of these available-for-sale investments is $1,120 million.
(b)Represents net pending securities sales and purchases.

December 31, 2022
 Fair ValueTotal
Unrealized
Gains		Total
Unrealized
Losses
Investment Type:Nuclear Decommissioning TrustsOther Special Use FundsTotal
Equity securities$487,240 $66,974 $554,214 $334,817 $(267)
Available for sale-fixed income securities582,343 279,294 861,637 (a)3,177 (68,795)
Other3,827 963 4,790 (b)— (29)
Total$1,073,410 $347,231 $1,420,641 $337,994 $(69,091)
(a)As of December 31, 2022, the amortized cost basis of these available-for-sale investments is $927 million.
(b)Represents net pending securities sales and purchases.
The following table sets forth APS’s realized gains and losses relating to the sale and maturity of available-for-sale debt securities and equity securities, and the proceeds from the sale and maturity of these investment securities (dollars in thousands):
 Year Ended December 31,
 Nuclear Decommissioning TrustsOther Special Use FundsTotal
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 
2022
Realized gains$9,017 $420 $9,437 
Realized losses$(40,239)$— $(40,239)
Proceeds from the sale of securities (a)$979,639 $227,558 $1,207,197 
2021
Realized gains$134,610 $49 $134,659 
Realized losses$(8,431)$(7)$(8,438)
Proceeds from the sale of securities (a)$1,457,305 $263,661 $1,720,966 
(a)Proceeds are reinvested in the nuclear decommissioning trusts and other special use funds, excluding amounts reimbursed to the Company for active union employee medical claims from the active union employee medical account.
    
Fixed Income Securities Contractual Maturities

The fair value of APS’s fixed income securities, summarized by contractual maturities, at December 31, 2023, is as follows (dollars in thousands):
 
 Nuclear Decommissioning TrustsCoal Reclamation Escrow AccountActive Union Employee Medical AccountTotal
Less than one year$26,057 $58,692 $36,857 $121,606 
1 year – 5 years225,891 46,120 152,761 424,772 
5 years – 10 years176,288 — 25,164 201,452 
Greater than 10 years353,097 — — 353,097 
Total$781,333 $104,812 $214,782 $1,100,927 
v3.24.0.1
Changes in Accumulated Other Comprehensive Loss
 12 Months Ended
Dec. 31, 2023
Comprehensive Income (Loss), Net of Tax, Attributable to Parent [Abstract]  
Changes in Accumulated Other Comprehensive Loss Changes in Accumulated Other Comprehensive Loss
 
The following 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 Benefits Derivative InstrumentsTotal
Balance at December 31, 2021$(53,885)$(976)$(54,861)
OCI (loss) before reclassifications17,550 1,873 19,423 
Amounts reclassified from accumulated other comprehensive loss4,003 (a)— 4,003 
Balance at December 31, 2022(32,332)897 (31,435)
OCI (loss) before reclassifications(4,420)713 (3,707)
Amounts reclassified from accumulated other comprehensive loss1,998 (a)— 1,998 
Balance at December 31, 2023$(34,754)$1,610 $(33,144)
(a)These amounts primarily represent amortization of actuarial loss and are included in the computation of net periodic pension cost. See Note 7.
Changes in Accumulated Other Comprehensive Loss — APS
 
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 BenefitsTotal
Balance at December 31, 2021$(34,880)$(34,880)
OCI (loss) before reclassifications15,646 15,646 
Amounts reclassified from accumulated other comprehensive loss3,638 (a)3,638 
Balance at December 31, 2022(15,596)(15,596)
OCI (loss) before reclassifications(3,383)(3,383)
Amounts reclassified from accumulated other comprehensive loss1,760 (a)1,760 
Balance at December 31, 2023$(17,219)$(17,219)
(a)These amounts primarily represent amortization of actuarial loss and are included in the computation of net periodic pension cost. See Note 7.
v3.24.0.1
Sale of Bright Canyon Energy
 12 Months Ended
Dec. 31, 2023
Discontinued Operations and Disposal Groups [Abstract]  
Sale of Bright Canyon Energy Sale of Bright Canyon Energy
On August 4, 2023, Pinnacle West entered into a purchase and sale agreement pursuant to which we agreed to sell all of our equity interest in our wholly-owned subsidiary, BCE, to Ameresco. The transaction is accounted for as the sale of a business and was structured to close in multiple stages that were completed on January 12, 2024. Certain investments and assets that BCE previously held, including the TransCanyon joint venture and holdings in the two Tenaska wind farm investments, were not included in the BCE Sale and were instead transferred to PNW Power, a newly-formed, 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 first stage of the BCE Sale closed on August 4, 2023, with the carrying value of net assets transferred to Ameresco totaling $44 million, which included a $36 million construction term loan. See Note 6. The assets and liabilities transferred in this 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. Our Consolidated Income Statement for the year ended December 31, 2023, includes a pretax gain of $6 million relating to this stage of the BCE Sale reported within other income. Our Consolidated Balance Sheets as of December 31, 2023, includes a $28 million note receivable from Ameresco relating to this initial stage of the BCE Sale, which was received in full by Pinnacle West on January 29, 2024.

As of December 31, 2023, our Consolidated Balance Sheets also include $35 million of assets classified as held for sale, relating to the remaining assets of BCE that transferred to Ameresco on January 12, 2024, in the second stage of the sale. These assets held for sale include BCE’s investment in the Kūpono Solar project, and other projects in various stages of development. The completion of the second stage of the BCE Sale was subject to various conditions precedent, including third-party consents which have been obtained. Prior to being classified as held for sale, these assets were primarily included in the other assets line item within the investments and other assets section on our Consolidated Balance Sheets. We measure assets held for sale at the lower of carrying value or fair value less cost to sell. For the year ended December 31, 2023, no impairment loss was recognized related to the assets classified as held for sale.

The purchase and sale agreement, as amended, provided for Pinnacle West to purchase, from Ameresco, approximately $28 million of investment tax credits that were generated by the assets included in the BCE Sale. The tax credits were purchased and transferred to Pinnacle West on January 30, 2024.
As of January 12, 2024, all stages of the BCE Sale have been completed. The purchase and sale agreement, as amended, allows Ameresco to make certain deferred payments relating to the BCE Sale throughout 2024. Pinnacle West continues to maintain certain performance guarantees relating to the BCE Kūpono Solar project financing which were not transferred in the BCE Sale transaction. See Note 10.
v3.24.0.1
New Accounting Standards
 12 Months Ended
Dec. 31, 2023
Accounting Standards Update and Change in Accounting Principle [Abstract]  
New Accounting Standards New Accounting Standards
 
ASU 2023-07, Segment Reporting: Improvements to Reportable Segment Disclosures

In November 2023, a new accounting standard was issued that changes disclosures relating to reportable segments. The new guidance expands the disclosure requirements relating to reportable segments, including requiring entities to disclose information about a reportable segment’s significant expenses, among other changes. The amended guidance does not change how an entity identifies reportable segments or the accounting for segments. The new standard is effective for us, using a retrospective approach, on December 31, 2024, with early adoption permitted. The adoption of the new guidance may result in changes to our reportable segment disclosures, but will not impact our segment accounting or financial statement results.

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 changes require entities to include a tabular income tax rate reconciliation, disclose details on specific reconciliation categories and reconciling items, and disclose the amount of income taxes paid by jurisdiction, among other disclosure changes. The standard is effective for us on December 31, 2025, using a prospective approach, and may be early adopted. The adoption of the new guidance may result in changes to our income tax disclosures, but will not impact our accounting for income taxes or our financial statement results.
v3.24.0.1
Schedule I - Condensed Financial Information of Registrant
 12 Months Ended
Dec. 31, 2023
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,
 202320222021
Operating expenses$11,249 $8,850 $10,245 
Other   
Equity in earnings of subsidiaries539,962 500,042 628,916 
Other income (expense)2,823 (4,725)(4,919)
Total542,785 495,317 623,997 
Interest expense47,251 18,861 10,672 
Income before income taxes484,285 467,606 603,080 
Income tax benefit(17,272)(15,996)(15,640)
Net income attributable to common shareholders501,557 483,602 618,720 
Other comprehensive income (loss) — attributable to common shareholders(1,709)23,426 7,935 
Total comprehensive income — attributable to common shareholders$499,848 $507,028 $626,655 
 
See Combined Notes to Consolidated Financial Statements.
PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY
SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED BALANCE SHEETS
(dollars in thousands)
 
 December 31,
 20232022
ASSETS  
Current assets  
Cash and cash equivalents$9 $— 
Accounts receivable163,829 132,061 
Income tax receivable1,832 14,494 
Assets held for sale- investment in subsidiaries35,139 — 
Other current assets28,379 288 
Total current assets229,188 146,843 
Investments and other assets  
Investments in subsidiaries7,369,159 7,105,789 
Deferred income taxes15,746 1,521 
Other assets22,839 23,153 
Total investments and other assets7,407,744 7,130,463 
TOTAL ASSETS$7,636,932 $7,277,306 
  
LIABILITIES AND EQUITY
Current liabilities  
Accounts payable$8,176 $6,499 
Accrued taxes4,543 7,694 
Common dividends payable99,813 97,895 
Short-term borrowings76,650 15,720 
Current maturities of long-term debt625,000 — 
Operating lease liabilities 127 117 
Other current liabilities11,400 14,637 
Total current liabilities825,709 142,562 
Long-term debt less current maturities498,731 947,892 
Pension liabilities6,487 8,218 
Operating lease liabilities1,332 1,459 
Other19,811 17,299 
Total deferred credits and other27,630 26,976 
COMMITMENTS AND CONTINGENCIES
Common stock equity
Common stock2,744,491 2,719,735 
Accumulated other comprehensive loss(33,144)(31,435)
Retained earnings3,466,317 3,360,347 
Total Pinnacle West Shareholders’ equity6,177,664 6,048,647 
Noncontrolling interests107,198 111,229 
Total Equity6,284,862 6,159,876 
TOTAL LIABILITIES AND EQUITY$7,636,932 $7,277,306 
See Combined Notes to Consolidated Financial Statements.
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,
 202320222021
Cash flows from operating activities   
Net income$501,557 $483,602 $618,720 
Adjustments to reconcile net income to net cash provided by operating activities: 
Equity in earnings of subsidiaries — net(539,962)(500,042)(628,916)
Gain on sale relating to BCE(6,423)— — 
Depreciation and amortization76 76 93 
Deferred income taxes(13,955)17,256 (11,381)
Accounts receivable(28,273)(8,535)8,897 
Accounts payable1,839 3,431 (2,598)
Accrued taxes and income tax receivables — net9,505 (25,157)16,079 
Dividends received from subsidiaries393,600 385,800 376,500 
Other(14,201)47,719 4,214 
Net cash flow provided by operating activities303,763 404,150 381,608 
Cash flows from investing activities   
Proceeds from sale relating to BCE23,400 — — 
Investments in subsidiaries(119,682)(186,630)(145,266)
Repayments of loans from subsidiaries and other6,526 14,308 4,017 
Advances of loans to subsidiaries(59,349)(3,308)(12,256)
Net cash flow used for investing activities(149,105)(175,630)(153,505)
Cash flows from financing activities   
Issuance of long-term debt175,000 300,000 300,000 
Short-term debt repayments under revolving credit facility— — (19,000)
Short-term borrowings and (repayments) — net60,930 2,420 (136,700)
Dividends paid on common stock(386,486)(378,881)(369,478)
Repayment of long-term debt— (150,000)— 
Common stock equity issuance and purchases — net(4,093)(2,653)(2,350)
Net cash flow used for financing activities(154,649)(229,114)(227,528)
Net increase (decrease) in cash and cash equivalents9 (594)575 
Cash and cash equivalents at beginning of year— 594 19 
Cash and cash equivalents at end of year$9 $— $594 
     
See Combined Notes to Consolidated Financial Statements.
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.
v3.24.0.1
Insider Trading Arrangements
 3 Months Ended
Dec. 31, 2023
Trading Arrangements, by Individual  
Rule 10b5-1 Arrangement Adopted false
Non-Rule 10b5-1 Arrangement Adopted false
Rule 10b5-1 Arrangement Terminated false
Non-Rule 10b5-1 Arrangement Terminated false
v3.24.0.1
Summary of Significant Accounting Policies (Policies)
 12 Months Ended
Dec. 31, 2023
Accounting Policies [Abstract]  
Description of Business and Basis of Presentation
Description of Business and Basis of Presentation
 
Pinnacle West is a 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 is a wholly-owned subsidiary that was created in September 2023 to hold certain investments in wind and transmission joint projects. See Note 20 for more information on PNW Power.
 
BCE was a Pinnacle West subsidiary that was formed in 2014. On August 4, 2023, Pinnacle West entered into a purchase and sale agreement pursuant to which all of our equity interest in BCE was sold. The sale was completed on January 12, 2024. See Note 20 for more information relating to the sale of BCE.

Pinnacle West’s Consolidated Financial Statements include the accounts of Pinnacle West and our subsidiaries: APS, El Dorado, BCE and PNW Power. APS’s Consolidated Financial Statements include the accounts of APS and certain VIEs relating to the Palo Verde sale leaseback.  Intercompany accounts and transactions between the consolidated companies have been eliminated.
 
We consolidate Variable Interest Entities (each a “VIE”) 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 certain VIE lessor trusts relating to the Palo Verde sale leaseback, and therefore APS consolidates these entities. See Note 17 for additional information. We have determined that Pinnacle West is the primary beneficiary of a captive insurance protected cell VIE. As of December 31, 2023, the captive cell’s activities are insignificant to our consolidated financial statements.
 
Our consolidated financial statements reflect all adjustments (consisting only of normal recurring adjustments, except as otherwise disclosed in the notes) that we believe are necessary for the fair presentation of our financial position, results of operations and cash flows for the periods presented.
Accounting Records and Use of Estimates
Accounting Records and Use of Estimates
 
Our accounting records are maintained in accordance with accounting principles generally accepted in the United States of America (“GAAP”).  The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period.  Actual results could differ from
those estimates. To conform with the current year’s disaggregated presentation of significant changes in assets and liabilities and the aggregation of less significant changes in assets and liabilities, we made certain reclassifications for the year ended December 31, 2022, within the operating activities section of our Consolidated Statements of Cash Flows.
Regulatory Accounting
Regulatory Accounting
 
APS is regulated by the ACC and the 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. See Note 2.
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 11 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, 2023, were as follows:

•Steam generation — 11 years;
•Nuclear plant — 25 years;
•Other generation — 18 years;
•Transmission — 38 years;
•Distribution — 33 years; and
•General plant — 7 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 radiated 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 6.29% for 2023, 5.75% for 2022, and 6.75% for 2021.  APS compounds AFUDC semi-annually and ceases to accrue AFUDC when construction work is completed and the property is placed in service.

On June 30, 2020, FERC issued an order granting a waiver request related to the existing AFUDC rate calculation beginning March 1, 2020, through February 28, 2021.  On February 23, 2021, this waiver was extended until September 30, 2021. On September 21, 2021, it was further extended until March 31, 2022. The order provided a simplified approach that companies may elect to implement in order to minimize the significant distorted effect on the AFUDC formula resulting from increased short-term debt financing during the COVID-19 pandemic.  APS adopted this simplified approach to computing the AFUDC composite rate by using a simple average of the actual historical short-term debt balances for 2019, instead of current period short-term debt balances, and left all other aspects of the AFUDC formula composite rate calculation unchanged. This change impacted the AFUDC composite rate in 2021 and for the three-month period ended March 31, 2022.  Furthermore, the change in the composite rate calculation did not impact our accounting treatment for these costs. The change did not have a material impact on our financial statements.
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 short-term 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 6 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.
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.  See Note 7 for additional information on pension and other postretirement benefits.
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 2023.
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. See Note 4 for additional discussion.
Cash and Cash Equivalents
Cash and Cash Equivalents
 
We consider cash equivalents to be highly liquid investments with a remaining maturity of three months or less at acquisition.
Intangible Assets
Intangible Assets
 
We have no goodwill recorded and have separately disclosed other intangible assets, primarily APS’s software, on Pinnacle West’s Consolidated Balance Sheets. 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 20% ownership and no significant influence).

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 20% ownership and no significant influence).
 
Our investments in the nuclear decommissioning trusts, coal reclamation escrow accounts and active union employee medical account, are accounted for in accordance with guidance on accounting for investments in debt and equity securities. See Notes 12 and 18 for more information on these investments.
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 purchased power agreement 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 3. We also may enter into lease agreements related to vehicles, office space, land, and other equipment. See Note 8 for information on our lease agreements.
Business Segments
Business Segments
 
Pinnacle West’s reportable business segment is our regulated electricity segment, which consists of traditional regulated retail and wholesale electricity businesses (primarily electricity service to Native Load customers) and related activities and includes electricity generation, transmission, and distribution. All other segment activities are insignificant.
New Accounting Standards New Accounting Standards
 
ASU 2023-07, Segment Reporting: Improvements to Reportable Segment Disclosures

In November 2023, a new accounting standard was issued that changes disclosures relating to reportable segments. The new guidance expands the disclosure requirements relating to reportable segments, including requiring entities to disclose information about a reportable segment’s significant expenses, among other changes. The amended guidance does not change how an entity identifies reportable segments or the accounting for segments. The new standard is effective for us, using a retrospective approach, on December 31, 2024, with early adoption permitted. The adoption of the new guidance may result in changes to our reportable segment disclosures, but will not impact our segment accounting or financial statement results.

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 changes require entities to include a tabular income tax rate reconciliation, disclose details on specific reconciliation categories and reconciling items, and disclose the amount of income taxes paid by jurisdiction, among other disclosure changes. The standard is effective for us on December 31, 2025, using a prospective approach, and may be early adopted. The adoption of the new guidance may result in changes to our income tax disclosures, but will not impact our accounting for income taxes or our financial statement results.
v3.24.0.1
Summary of Significant Accounting Policies (Tables)
 12 Months Ended
Dec. 31, 2023
Accounting Policies [Abstract]  
Schedule of Property, Plant and Equipment
Pinnacle West’s property, plant and equipment included in the December 31, 2023, and 2022 Consolidated Balance Sheets is composed of the following (dollars in thousands):

Property, Plant and Equipment:20232022
Generation$10,446,291 $9,563,145 
Transmission3,773,253 3,589,456 
Distribution8,448,293 7,951,867 
General plant1,543,330 1,347,678 
Plant in service and held for future use
24,211,167 22,452,146 
Accumulated depreciation and amortization(8,408,040)(7,929,878)
Net
15,803,127 14,522,268 
Construction work in progress1,724,004 1,882,791 
Palo Verde sale leaseback, net of accumulated depreciation86,426 90,296 
Intangible assets, net of accumulated amortization267,110 258,880 
Nuclear fuel, net of accumulated amortization99,490 100,119 
Total property, plant and equipment$17,980,157 $16,854,354 
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,
 202320222021
Cash paid during the period for:   
Income taxes, net of refunds$8,788 $46,227 $229 
Interest, net of amounts capitalized310,996 245,271 227,584 
Significant non-cash investing and financing activities:   
Accrued capital expenditures$206,269 $114,999 $167,733 
Dividends declared but not paid99,813 97,895 95,988 
BCE Sale non-cash consideration (Note 20)
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,
 202320222021
Cash paid during the period for:   
Income taxes, net of refunds$21,734 $95,985 $19,783 
Interest, net of amounts capitalized267,261 227,159 217,749 
Significant non-cash investing and financing activities:   
Accrued capital expenditures$206,269 $116,533 $167,657 
Dividends declared but not paid99,800 97,900 96,000 
v3.24.0.1
Revenue (Tables)
 12 Months Ended
Dec. 31, 2023
Revenue from Contract with Customer [Abstract]  
Schedule of Disaggregation of revenue
The following table provides detail of Pinnacle West’s consolidated revenue disaggregated by revenue sources (dollars in thousands):
Year Ended December 31,
202320222021
Retail Electric Service
Residential$2,289,196 $2,046,111 $1,913,324 
Non-Residential2,048,416 1,767,616 1,586,940 
Wholesale Energy Sales208,985 383,126 187,640 
Transmission Services for Others138,631 116,628 99,285 
Other Sources10,763 10,904 16,646 
Total Operating Revenues$4,695,991 $4,324,385 $3,803,835 
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,
202320222021
Allowance for doubtful accounts, balance at beginning of period$23,778 $25,354 $19,782 
Bad debt expense23,399 17,006 22,251 
Actual write-offs(24,744)(18,582)(16,679)
Allowance for doubtful accounts, balance at end of period$22,433 $23,778 $25,354 
v3.24.0.1
Regulatory Matters (Tables)
 12 Months Ended
Dec. 31, 2023
Regulated Operations [Abstract]  
Schedule Of Capital Structure And Cost Of Capital, Regulatory Matter the following proposed capital structure and costs of capital:
Capital StructureCost of Capital
Long-term debt48.07 %3.85 %
Common stock equity51.93 %10.25 %
Weighted-average cost of capital7.17 %
Schedule of changes in the Deferred Fuel and Purchased Power Regulatory Asset
The following table shows the changes in the deferred fuel and purchased power regulatory asset for 2023 and 2022 (dollars in thousands):
 Twelve Months Ended
December 31,
 20232022
Beginning balance$460,561 $388,148 
Deferred fuel and purchased power costs — current period549,877 291,992 
Amounts charged to customers(547,243)(219,579)
Ending balance$463,195 $460,561 
Schedule of Regulatory Assets
The detail of regulatory assets is as follows (dollars in thousands):
SDecember 31,
 Amortization Through20232022
Pension(a)$696,476 $637,656 
Deferred fuel and purchased power (b) (c)2024463,195 460,561 
Income taxes — AFUDC equity2053189,058 179,631 
Ocotillo deferral2031128,636 138,143 
Deferred fuel and purchased power — mark-to-market (Note 16)2026120,214 — 
SCR deferral (e)203889,477 97,624 
Retired power plant costs203383,536 98,692 
Lease incentives (Note 8)(g)46,615 — 
Income taxes — investment tax credit basis adjustment205634,230 23,977 
Deferred compensation203633,972 33,660 
Deferred property taxes202732,488 41,057 
Palo Verde VIEs (Note 17)
204620,772 20,933 
Power supply adjustor-interest202419,416 1,541 
Active union medical trust(f)12,747 18,226 
Navajo coal reclamation202610,883 13,862 
Mead-Phoenix transmission line — contributions in aid of construction20508,716 9,048 
Loss on reacquired debt20387,965 9,468 
Four Corners cost deferral20247,922 15,999 
Tax expense adjustor mechanism (b)20315,190 5,845 
Lost fixed cost recovery (b)2023— 9,547 
OtherVarious4,528 6,630 
Total regulatory assets (d)$2,016,036 $1,822,100 
Less: current regulatory assets$625,757 $538,879 
Total non-current regulatory assets$1,390,279 $1,283,221 
(a)This asset represents the future recovery of pension benefit obligations and expense through retail rates.  If these costs are disallowed by the ACC, this regulatory asset would be charged to OCI and result in lower future revenues.  As a result of the 2019 Rate Case Decision, the amount authorized for inclusion in rate base was determined using an averaging methodology, which resulted in a reduced return in retail rates. The approved 2022 Rate Case ROO, as amended, allows for the full return on the pension asset in rate base. See Note 7 for further discussion.
(b)See “Cost Recovery Mechanisms” discussion above.
(c)Subject to a carrying charge.
(d)There are no regulatory assets for which the ACC has allowed recovery of costs, but not allowed a return by exclusion from rate base. FERC rates are set using a formula rate as described in “Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters.”
(e)See “Four Corners SCR Cost Recovery” discussion above.
(f)Collected in retail rates.
(g)Amortization periods vary based on specific terms of lease contract. See Note 8.
Schedule of Regulatory Liabilities
The detail of regulatory liabilities is as follows (dollars in thousands):
 December 31,
 Amortization Through20232022
Excess deferred income taxes - ACC — Tax Cuts and Jobs Act (a)2046$930,344 $971,545 
Excess deferred income taxes - FERC — Tax Cuts and Jobs Act (a)2058214,667 221,877 
Asset retirement obligations2057392,383 354,002 
Other postretirement benefits(d)226,726 270,604 
Removal costs (c) 94,368 106,889 
Income taxes — deferred investment tax credit205668,521 48,035 
Income taxes — change in rates205160,667 64,806 
Four Corners coal reclamation203855,917 52,592 
Renewable energy standard (b)202443,251 35,720 
Spent nuclear fuel202733,154 39,217 
Sundance maintenance203119,989 16,893 
Demand side management (b)202314,374 8,461 
Property tax deferral (e)202410,850 15,521 
Tax expense adjustor mechanism (b)20314,835 4,835 
FERC transmission true up (b)20251,869 22,895 
Deferred fuel and purchased power — mark-to-market (Note 15)
2026— 96,367 
OtherVarious3,873 3,092 
Total regulatory liabilities$2,175,788 $2,333,351 
Less: current regulatory liabilities$209,923 $271,575 
Total non-current regulatory liabilities$1,965,865 $2,061,776 
(a)For purposes of presentation on the Statement of Cash Flows, amortization of the regulatory liabilities for excess deferred income taxes are reflected as “Deferred income taxes” under Cash Flows From Operating Activities.
(b)See “Cost Recovery Mechanisms” discussion above.
(c)In accordance with regulatory accounting, APS accrues removal costs for its regulated assets, even if there is no legal obligation for removal.
(d)See Note 7.
v3.24.0.1
Income Taxes (Tables)
 12 Months Ended
Dec. 31, 2023
Income Tax Disclosure [Abstract]  
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
 202320222021202320222021
Total unrecognized tax benefits, January 1$43,097 $45,086 $45,655 $43,097 $45,086 $45,655 
Additions for tax positions of the current year1,473 1,399 3,305 1,473 1,399 3,305 
Additions for tax positions of prior years419 2,069 1,449 419 2,069 1,449 
Reductions for tax positions of prior years for:      
Changes in judgment661 (3,495)(2,659)661 (3,495)(2,659)
Settlements with taxing authorities— — — — — — 
Lapses of applicable statute of limitations(1,376)(1,962)(2,664)(1,376)(1,962)(2,664)
Total unrecognized tax benefits, December 31$44,274 $43,097 $45,086 $44,274 $43,097 $45,086 
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
 202320222021202320222021
Tax positions, that if recognized, would decrease our effective tax rate$28,762 $28,246 $26,300 $28,762 $28,246 $26,300 
The amount of interest expense or benefit recognized related to unrecognized tax benefits are as follows (dollars in thousands):
Pinnacle West ConsolidatedAPS Consolidated
 202320222021202320222021
Unrecognized tax benefit interest expense/(benefit) recognized$452 $(139)$(535)$452 $(139)$(535)

Following are the total amount 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
 202320222021202320222021
Unrecognized tax benefit interest accrued $1,633 $1,181 $1,320 $1,633 $1,181 $1,320 
Schedule 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,
 202320222021202320222021
Current:   
Federal$21,272 $35,617 $(5,041)$26,405 $103,349 $1,514 
State2,854 1,950 2,458 1,027 161 (11)
Total current24,126 37,567 (2,583)27,432 103,510 1,503 
Deferred:      
Federal37,273 23,693 95,327 44,922 (31,860)101,175 
State15,513 13,567 17,342 21,830 19,150 22,875 
Total deferred52,786 37,260 112,669 66,752 (12,710)124,050 
Income tax expense/(benefit)$76,912 $74,827 $110,086 $94,184 $90,800 $125,553 
Schedule Comparison of Pretax Income from Continuing Operations at the Federal Income Tax Rate to Income Tax Expense - Continuing Operations
The following chart compares pretax income at the 21% statutory federal income tax rate to income tax expense (dollars in thousands):
Pinnacle West ConsolidatedAPS Consolidated
 Year Ended December 31,Year Ended December 31,
 202320222021202320222021
Federal income tax expense at statutory rate$125,095 $120,887 $156,666 $138,337 $132,920 $162,762 
Increases (reductions) in tax expense resulting from:      
State income tax net of federal income tax benefit18,024 17,740 22,656 19,832 19,000 23,339 
State income tax credits net of federal income tax benefit(3,513)(5,482)(7,015)(1,775)(3,744)(5,277)
Net operating loss carryback tax benefit— — (5,915)— — — 
Excess deferred income taxes — Tax Cuts and Jobs Act(36,558)(36,241)(36,558)(36,558)(36,241)(36,558)
Allowance for equity funds used during construction (Note 1)
(5,964)(4,629)(4,180)(5,964)(4,629)(4,180)
Palo Verde VIE noncontrolling interest (Note 17)
(3,617)(3,617)(3,617)(3,617)(3,617)(3,617)
Investment tax credit amortization(9,495)(5,608)(7,620)(9,495)(5,608)(7,620)
   Federal production tax credit(8,441)(3,146)(3,064)(5,460)— — 
   Other federal income tax credits(3,453)(7,721)(3,912)(2,803)(7,721)(3,912)
Other4,834 2,644 2,645 1,687 440 616 
Income tax expense/(benefit)$76,912 $74,827 $110,086 $94,184 $90,800 $125,553 
Schedule 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,
 2023202220232022
DEFERRED TAX ASSETS  
Risk management activities$31,411 $8,826 $31,411 $8,826 
Regulatory liabilities:   
Excess deferred income taxes — Tax Cuts and Jobs Act283,161 295,014 283,161 295,014 
Asset retirement obligation and removal costs113,312 107,104 113,312 107,104 
Unamortized investment tax credits68,521 48,035 68,521 48,035 
Other postretirement benefits56,070 66,893 56,070 66,893 
Other39,857 62,915 39,857 62,915 
Operating lease liabilities316,067 184,030 315,670 182,663 
Pension liabilities33,294 33,674 29,918 30,436 
Coal reclamation liabilities45,505 44,312 45,505 44,312 
Renewable energy incentives17,261 19,948 17,261 19,948 
Credit and loss carryforwards43,940 37,647 3,031 13,654 
Other77,865 72,605 77,865 72,605 
Total deferred tax assets1,126,264 981,003 1,081,582 952,405 
DEFERRED TAX LIABILITIES   
Plant-related(2,572,495)(2,518,164)(2,572,495)(2,518,164)
Risk management activities(1,682)(32,648)(1,682)(32,648)
Pension and other postretirement assets(78,853)(96,845)(78,297)(96,196)
Other special use funds(56,550)(57,572)(56,550)(57,572)
Operating lease right-of-use assets(316,067)(184,030)(315,670)(182,663)
Regulatory assets:   
Allowance for equity funds used during construction(46,754)(44,405)(46,754)(44,405)
Deferred fuel and purchased power(149,078)(114,232)(149,078)(114,232)
Pension benefits(172,239)(157,629)(172,239)(157,629)
Retired power plant costs (20,659)(24,397)(20,659)(24,397)
Other(92,260)(103,023)(92,260)(103,023)
Other(36,107)(32,479)(7,595)(7,123)
Total deferred tax liabilities(3,542,744)(3,365,424)(3,513,279)(3,338,052)
Deferred income taxes — net$(2,416,480)$(2,384,421)$(2,431,697)$(2,385,647)
v3.24.0.1
Lines of Credit and Short-Term Borrowings (Tables)
 12 Months Ended
Dec. 31, 2023
Lines of Credit and Short-Term Borrowings  
Schedule of Consolidated Credit Facilities and Amounts Available and Outstanding
The table below presents the consolidated credit facilities and the amounts available and outstanding (dollars in thousands): 
December 31, 2023December 31, 2022
Pinnacle WestAPSTotalPinnacle WestAPSTotal
Commitments under Credit Facilities$200,000 $1,250,000 $1,450,000 $200,000 $1,000,000 $1,200,000 
Outstanding short-term borrowings(76,650)(532,850)(609,500)(15,720)(325,000)(340,720)
Amount of Credit Facilities Available$123,350 $717,150 $840,500 $184,280 $675,000 $859,280 
Weighted-Average Commitment Fees0.170%0.120%0.175%0.125%
v3.24.0.1
Long-Term Debt and Liquidity Matters (Tables)
 12 Months Ended
Dec. 31, 2023
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)Rates20232022
APS    
Pollution control bonds:    
Variable2029(b)$163,975 $163,975 
Total pollution control bonds  163,975 163,975 
Senior unsecured notes2024-2050
2.20%-6.88%
7,180,000 6,680,000 
Unamortized discount  (14,197)(14,548)
Unamortized premium  11,162 12,368 
Unamortized debt issuance cost(49,049)(48,266)
Total APS long-term debt  7,291,891 6,793,529 
Less current maturities 250,000 — 
Total APS long-term debt less current maturities  7,041,891 6,793,529 
BCE
Los Alamitos equity bridge loan(d)(d)— 27,575 
Los Alamitos construction facility(d)(d)— 23,110 
Unamortized debt issuance cost— (135)
Total BCE long-term debt— 50,550 
Less current maturities— 50,685 
Total BCE long-term debt less current maturities— (135)
Pinnacle West    
Senior unsecured notes20251.30%500,000 500,000 
Term loans2024(c)625,000 450,000 
Unamortized discount(15)(25)
Unamortized debt issuance cost(1,254)(2,083)
Total Pinnacle West long-term debt1,123,731 947,892 
Less current maturities625,000 — 
Total Pinnacle West long-term debt less current maturities498,731 947,892 
TOTAL LONG-TERM DEBT LESS CURRENT MATURITIES
$7,540,622 $7,741,286 
(a)    This schedule does not reflect the timing of redemptions that may occur prior to maturities.
(b)    The weighted-average interest rate for the variable rate pollution control bonds was 4.11% at December 31, 2023, and 3.96% at December 31, 2022.
(c)    The weighted-average interest rate was 6.20% at December 31, 2023, and 5.10% at December 31, 2022. See additional details below.
(d)    On August 4, 2023, concurrent with the BCE Sale, the construction facility was transferred to Ameresco and the equity bridge loan was paid in full by Pinnacle West. See Note 20 and discussion 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
2024$875,000 $250,000 
2025800,000 300,000 
2026250,000 250,000 
2027300,000 300,000 
2028— — 
Thereafter6,243,975 6,243,975 
Total$8,468,975 $7,343,975 
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, 2023		As of
December 31, 2022
 Carrying
Amount		Fair ValueCarrying
Amount		Fair Value
Pinnacle West$1,123,731 $1,095,935 $947,892 $905,525 
APS7,291,891 6,459,718 6,793,529 5,629,491 
BCE— — 50,550 50,685 
Total$8,415,622 $7,555,653 $7,791,971 $6,585,701 
v3.24.0.1
Retirement Plans and Other Postretirement Benefits (Tables)
 12 Months Ended
Dec. 31, 2023
Retirement Benefits [Abstract]  
Schedule of Net Periodic Benefit Costs and the Portion of these Costs Charged to Expense (Including Administrative Costs and Excluding Amounts Capitalized as Overhead Construction, Billed to Electric Plant Participants or Charged or Amortized to the Regulatory Asset)
The following table provides details of the plans’ net periodic benefit costs and the portion of these costs charged to expense (including administrative costs and excluding amounts capitalized as overhead construction or billed to electric plant participants) (dollars in thousands):
 Pension PlansOther Benefits Plans
 202320222021202320222021
Service cost-benefits earned during the period$39,461 $55,473 $61,236 $8,567 $16,470 $17,796 
Non-service costs (credits):
Interest cost on benefit obligation153,561 107,492 98,566 22,509 17,491 16,513 
Expected return on plan assets(182,938)(185,775)(202,628)(43,486)(46,042)(41,444)
Amortization of:      
Prior service credit (a)— — — (37,789)(37,789)(37,705)
Net actuarial (gain)/loss38,420 17,515 15,948 (9,614)(12,835)(10,093)
Net periodic benefit cost/(benefit)$48,504 $(5,295)$(26,878)$(59,813)$(62,705)$(54,933)
Portion of cost/(benefit) charged to expense$27,029 $(16,431)$(32,743)$(43,408)$(45,042)$(38,657)
(a)    Prior-service costs or credits reflect the impact of modifications to the pension or postretirement plan benefits. The impact of these modifications is amortized over a period which reflects the demographics of the impacted population. In 2014, Pinnacle West made changes to the postretirement benefits offered to Medicare eligible retirees which resulted in prior-service credits. We have been amortizing these prior-serviced credits since 2015 with the last full-year amortization occurring in 2024.
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
 2023202220232022
Change in Benefit Obligation    
Benefit obligation at January 1$2,809,529 $3,716,824 $409,461 $591,841 
Service cost39,461 55,473 8,567 16,470 
Interest cost153,561 107,492 22,509 17,491 
Benefit payments(210,737)(212,565)(30,784)(30,913)
Actuarial (gain) loss116,249 (857,695)20,681 (185,428)
Benefit obligation at December 312,908,063 2,809,529 430,434 409,461 
Change in Plan Assets    
Fair value of plan assets at January 12,829,485 3,812,041 652,287 872,435 
Actual return/(loss) on plan assets199,098 (787,874)67,317 (193,807)
Benefit payments(193,034)(194,682)(23,110)(26,341)
Fair value of plan assets at December 312,835,549 2,829,485 696,494 652,287 
Funded/(Underfunded) Status at December 31$(72,514)$19,956 $266,060 $242,826 
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,
 20232022
Accumulated benefit obligation$123,701 $126,759 
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,
 20232022
Projected benefit obligation$129,891 $133,818 
Fair value of plan assets— — 
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
 2023202220232022
Noncurrent asset$57,378 $153,773 $266,060 $242,826 
Current liability(17,190)(17,531)— — 
Noncurrent liability(112,702)(116,286)— — 
Net amount recognized (funded status)$(72,514)$19,956 $266,060 $242,826 
Schedule of Accumulated Other Comprehensive Loss
The following table shows the details related to accumulated other comprehensive loss (gain) as of December 31, 2023, and 2022 (dollars in thousands): 
 Pension PlansOther Benefits Plans
 2023202220232022
Net actuarial loss (gain)$743,003 $681,335 $(188,630)$(195,095)
Prior service credit— — (39,054)(76,843)
APS’s portion recorded as a regulatory (asset) liability(696,476)(637,656)226,726 270,604 
Income tax expense (benefit)(11,506)(10,797)691 784 
Accumulated other comprehensive loss (gain)$35,021 $32,882 $(267)$(550)
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,
 20232022202320222021
Discount rate – pension plans5.21 %5.56 %5.56 %2.92 %2.53 %
Discount rate – other benefits plans5.23 %5.58 %5.58 %2.98 %2.63 %
Rate of compensation increase4.52 %4.57 %4.57 %4.00 %4.00 %
Expected long-term return on plan assets - pension plansN/AN/A6.70 %5.00 %5.30 %
Expected long-term return on plan assets - other benefit plansN/AN/A6.80 %5.35 %4.90 %
Initial healthcare cost trend rate (pre-65 participants)6.25 %6.50 %6.50 %6.00 %6.50 %
Ultimate healthcare cost trend rate (pre-65 participants)4.75 %4.75 %4.75 %4.75 %4.75 %
Number of years to ultimate trend rate (pre-65 participants)56534
Initial and ultimate healthcare cost trend rate (post-65 participants)2.00 %2.00 %2.00 %2.00 %2.00 %
Interest crediting rate – cash balance pension plans4.54 %4.50 %4.50 %4.50 %4.50 %
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, 2023, 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 following table presents the actual allocations of the investment for the other postretirement benefit plan at December 31, 2023:
Actual Allocation
Long-term fixed income assets62 %
Return-seeking assets38 %
Total100 %
The fair value of Pinnacle West’s pension plan and other postretirement benefit plan assets at December 31, 2023, by asset category, are as follows (dollars in thousands):
 
 Level 1Level 2Other (a)Total
Pension Plan:   
Fixed income securities:   
Corporate$— $1,415,346 $— $1,415,346 
U.S. Treasury622,273 — — 622,273 
Other (b)— 135,184 — 135,184 
Common stock equities (c)150,657 — — 150,657 
Mutual funds (d)112,791 — — 112,791 
Common and collective trusts:
Equities— — 192,945 192,945 
Real estate— — 140,613 140,613 
Short-term investments and other (e)— — 65,740 65,740 
Total$885,721 $1,550,530 $399,298 $2,835,549 
Other Benefits:    
Fixed income securities:   
Corporate$— $189,902 $— $189,902 
U.S. Treasury207,665 — — 207,665 
Other (b)— 8,372 — 8,372 
Common stock equities (c)139,952 — — 139,952 
Mutual funds (d)22,256 — — 22,256 
Common and collective trusts:   
Equities— — 81,724 81,724 
Real estate— — 20,001 20,001 
Short-term investments and other (e)21,146 — 5,476 26,622 
Total$391,019 $198,274 $107,201 $696,494 
(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)This category includes plan receivables and payables.
The fair value of Pinnacle West’s pension plan and other postretirement benefit plan assets at December 31, 2022, by asset category, are as follows (dollars in thousands):
 Level 1Level 2Other (a)Total
Pension Plan:   
Cash and cash equivalents$1,252 $— $— $1,252 
Fixed income securities:   
Corporate— 1,374,810 — 1,374,810 
U.S. Treasury635,245 — — 635,245 
Other (b)— 131,999 — 131,999 
Common stock equities (c)155,231 — — 155,231 
Mutual funds (d)101,557 — — 101,557 
Common and collective trusts:
   Equities— — 181,912 181,912 
   Real estate— — 174,228 174,228 
Partnerships— — 13,359 13,359 
Short-term investments and other (e)— — 59,892 59,892 
Total $893,285 $1,506,809 $429,391 $2,829,485 
Other Benefits:    
Cash and cash equivalents$204 $— $— $204 
Fixed income securities:   
Corporate— 166,879 — 166,879 
U.S. Treasury221,936 — — 221,936 
Other (b)— 7,321 — 7,321 
Common stock equities (c)127,493 — — 127,493 
Mutual funds (d)18,824 — — 18,824 
Common and collective trusts:
   Equities— — 73,956 73,956 
   Real estate— — 23,541 23,541 
Short-term investments and other (e)3,274 — 8,859 12,133 
Total $371,731 $174,200 $106,356 $652,287 
(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.
(c)This category primarily consists of U.S. common stock equities.
(d)These funds invest in U.S. and international common stock equities.
(e)This category 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
2024$244,772 $31,024 
2025226,748 30,446 
2026229,322 30,396 
2027226,906 30,024 
2028229,397 29,741 
Years 2029-20331,136,944 149,312 
v3.24.0.1
Leases (Tables)
 12 Months Ended
Dec. 31, 2023
Leases [Abstract]  
Schedule of Lease Costs
The following table provides information related to our lease costs (dollars in thousands):
Year Ended December 31,
202320222021
Operating Lease Cost - Purchased Power & Energy Storage Lease Contracts$126,655 $104,001 $105,762 
Operating Lease Cost - Land, Property, and Other Equipment19,235 18,061 18,498 
Total Operating Lease Cost145,890 122,062 124,260 
Variable Lease Cost (a)135,007 122,040 118,969 
Short-term Lease Cost21,530 9,928 3,872 
Total Lease Cost$302,427 $254,030 $247,101 
(a)     Primarily relates to purchased power lease contracts.
The following tables provide other additional information related to operating lease liabilities (dollars in thousands):
Year Ended December 31,
202320222021
Cash paid for amounts included in the measurement of lease liabilities — operating cash flows:$123,472 $118,463 $116,661 
Right-of-use operating lease assets obtained in exchange for operating lease liabilities602,301 (a)16,990 500,582 


December 31, 2023December 31, 2022
Weighted average remaining lease term10 years7 years
Weighted average discount rate (b)4.53 %2.21 %

(a)Primarily relates to the two purchased power operating lease agreements that were modified in January 2023.
(b)Most of our lease agreements do not contain an implicit rate that is readily determinable. For these agreements we use our incremental borrowing rate to measure the present value of lease liabilities. We determine our incremental borrowing rate at lease commencement based on the rate of interest that we would have to pay to borrow, on a collateralized basis over a similar term, an amount equal to the lease payments in a similar economic environment. We use the implicit rate when it is readily determinable.
Schedule of Maturities of Operating Lease Labilities
The following table provides information related to the maturity of our operating lease liabilities (dollars in thousands):
December 31, 2023
YearPurchased Power & Energy Storage Lease ContractsLand, Property & Equipment LeasesTotal
2024$108,201 $14,750 $122,951 
2025124,968 12,148 137,116 
2026138,692 9,826 148,518 
2027164,613 7,731 172,344 
2028168,410 5,401 173,811 
Thereafter835,813 64,090 899,903 
Total lease commitments1,540,697 113,946 1,654,643 
Less imputed interest334,693 41,878 376,571 
Total lease liabilities$1,206,004 $72,068 $1,278,072 
v3.24.0.1
Jointly-Owned Facilities (Tables)
 12 Months Ended
Dec. 31, 2023
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, 2023 (dollars in thousands):
 Percent
Owned		 Plant in
Service		Accumulated
Depreciation		Construction
Work in
Progress
Generating facilities:     
Palo Verde Units 1 and 329.1 %$1,990,237 $1,087,614 $21,442 
Palo Verde Unit 2 (a)16.8 %681,483 387,485 12,700 
Palo Verde Common28.0 %(b)857,807 356,962 65,911 
Palo Verde Sale Leaseback (a)351,050 264,624 — 
Four Corners Generating Station 63.0 %1,748,436 659,780 29,586 
Cholla Common Facilities (c)50.5 %250,994 167,357 7,487 
Transmission facilities:     
ANPP 500kV System33.4 %(b)136,145 58,252 4,801 
Navajo Southern System25.2 %(b)87,185 36,743 550 
Palo Verde — Yuma 500kV System25.3 %(b)24,057 7,912 432 
Four Corners Switchyards57.5 %(b)84,279 21,918 161 
Phoenix — Mead System17.1 %(b)39,772 20,679 257 
Palo Verde — Rudd 500kV System50.0 %95,736 32,665 731 
Morgan — Pinnacle Peak System63.2 %(b)117,080 26,990 229 
Round Valley System50.0 %548 205 — 
Palo Verde — Morgan System87.5 %(b)268,629 40,962 8,053 
Hassayampa — North Gila System80.0 %151,684 24,618 — 
Cholla 500kV Switchyard85.7 %8,445 2,760 — 
Saguaro 500kV Switchyard60.0 %21,627 14,060 17 
Kyrene — Knox System50.0 %578 340 — 
Agua Fria Switchyard10.0 %— — 77 
(a)See Note 17.
(b)Weighted-average of interests.
(c)PacifiCorp owns Cholla Unit 4 (see Note 3 for additional information), and APS operated the unit for PacifiCorp.  Cholla Unit 4 was retired on December 24, 2020. The common facilities at Cholla are jointly-owned.
v3.24.0.1
Commitments and Contingencies (Tables)
 12 Months Ended
Dec. 31, 2023
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,
 20242025202620272028Thereafter
Coal take-or-pay commitments (a)$208,694 $229,111 $221,122 $200,256 $205,237 $647,377 
 
(a)Total take-or-pay commitments are approximately $1.7 billion.  The total net present value of these commitments is approximately $1.4 billion.
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,
 202320222021
Total purchases$255,219 $305,502 $219,958 
v3.24.0.1
Asset Retirement Obligations (Tables)
 12 Months Ended
Dec. 31, 2023
Asset Retirement Obligation Disclosure [Abstract]  
Schedule of Change in Asset Retirement Obligations
The following table shows the change in our AROs (dollars in thousands):

 20232022
Asset retirement obligations at the beginning of year$797,762 $767,382 
Changes attributable to:  
Accretion expense44,269 41,240 
Settlements(14,039)(10,860)
Estimated cash flow revisions135,323 — 
Newly incurred obligation2,686 — 
Asset retirement obligations at the end of year$966,001 $797,762 
v3.24.0.1
Fair Value Measurements (Tables)
 12 Months Ended
Dec. 31, 2023
Fair Value Disclosures [Abstract]  
Schedule of Fair Value of Assets and Liabilities Measured at Fair Value on a Recurring Basis
The following table presents the fair value at December 31, 2023, of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):

Balance at December 31, 2023Level 1Level 2Level 3OtherTotal
ASSETS
Cash equivalents$10 $— $— $— $10 
Risk management activities — derivative instruments:
Commodity contracts— 1,881 6,616 (1,689)(a)6,808 
Nuclear decommissioning trust:
Equity securities11,064 — — (767)(b)10,297 
U.S. commingled equity funds— — — 409,616 (c)409,616 
U.S. Treasury debt319,734 — — — 319,734 
Corporate debt— 188,317 — — 188,317 
Mortgage-backed securities— 208,306 — — 208,306 
Municipal bonds— 59,323 — — 59,323 
Other fixed income— 5,653 — — 5,653 
Subtotal nuclear decommissioning trust330,798 461,599 — 408,849 1,201,246 
Other special use funds:
Equity securities40,991 — — 2,196 (b)43,187 
U.S. Treasury debt319,594 — — — 319,594 
Municipal bonds— — — — — 
Subtotal other special use funds360,585 — — 2,196 362,781 
Total assets$691,393 $463,480 $6,616 $409,356 $1,570,845 
LIABILITIES
Risk management activities — derivative instruments:
Commodity contracts$— $(127,016)$(1,695)$4,823 (a)$(123,888)
(a)Represents counterparty netting, margin, and collateral. See Note 15.
(b)Represents net pending securities sales and purchases.
(c)Valued using NAV as a practical expedient and, therefore, are not classified in the fair value hierarchy.
 The following table presents the fair value at December 31, 2022, of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):
 
Balance at December 31, 2022Level 1Level 2Level 3OtherTotal
ASSETS
Risk management activities — derivative instruments:
Commodity contracts$— $127,129 $26,132 $(21,163)(a)$132,098 
Interest rate swaps— 131 — — 131 
Subtotal risk management activities - derivative instruments— 127,260 26,132 (21,163)132,229 
Nuclear decommissioning trust:
Equity securities14,658 — — 3,827 (b)18,485 
U.S. commingled equity funds— — — 472,582 (c)472,582 
U.S. Treasury debt211,923 — — — 211,923 
Corporate debt— 149,226 — — 149,226 
Mortgage-backed securities— 147,938 — — 147,938 
Municipal bonds— 64,881 — — 64,881 
Other fixed income— 8,375 — — 8,375 
Subtotal nuclear decommissioning trust226,581 370,420 — 476,409 1,073,410 
Other special use funds:
Equity securities66,974 — — 963 (b)67,937 
U.S. Treasury debt275,267 — — — 275,267 
Municipal bonds— 4,027 — — 4,027 
Subtotal other special use funds342,241 4,027 — 963 347,231 
Total assets$568,822 $501,707 $26,132 $456,209 $1,552,870 
LIABILITIES
Risk management activities — derivative instruments:
Commodity contracts$— $(25,874)$(31,020)$15,357 (a)$(41,537)
Interest rate swaps— (909)— — (909)
Subtotal risk management activities - derivative instruments— (26,783)(31,020)15,357 (42,446)
Total liabilities$— $(26,783)$(31,020)$15,357 $(42,446)
(a)Represents counterparty netting, margin, and collateral. See Note 15.
(b)Represents net pending securities sales and purchases.
(c)Valued using NAV as a practical expedient and, therefore, are not classified in the fair value hierarchy.
The following table shows the changes in fair value for our risk management activities’ assets and liabilities that are measured at fair value on a recurring basis using Level 3 inputs (dollars in thousands):

 Year Ended December 31,
Commodity Contracts20232022
Net derivative balance at beginning of period$(4,888)$(2,738)
Total net gains (losses) realized/unrealized:
Deferred as a regulatory asset or liability(70,214)(374)
Settlements69,706 (1,123)
Transfers into Level 3 from Level 2(1,289)(846)
Transfers from Level 3 into Level 211,606 193 
Net derivative balance at end of period$4,921 $(4,888)
Net unrealized gains included in earnings related to instruments still held at end of period$— $— 
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 at December 31, 2023, and December 31, 2022:

December 31, 2023
 Fair Value (thousands) 		ValuationSignificantWeighted-Average
Commodity ContractsAssetsLiabilitiesTechniqueUnobservable InputRange (b)
Electricity:
Forward Contracts (a)$6,587 $658 Discounted cash flowsElectricity forward price (per MWh)
$37.79
-
$259.04
$158.08 
Natural Gas:
Forward Contracts (a)29 1,037 Discounted cash flowsNatural gas forward price (per MMBtu)
$0.00
-
$0.08
$0.03 
Total$6,616 $1,695 
(a)Includes swaps and physical and financial contracts.
(b)Unobservable inputs were weighted by the relative fair value of the instrument.

December 31, 2022
 Fair Value (thousands) 		ValuationSignificantWeighted-Average
Commodity ContractsAssetsLiabilitiesTechniqueUnobservable InputRange(b)
Electricity:
Forward Contracts (a)$26,132 $1,759 Discounted cash flowsElectricity forward price (per MWh)$37.79 -$310.69 $163.92 
Natural Gas:
Forward Contracts (a)— 29,261 Discounted cash flowsNatural gas forward price (per MMBtu)$(11.81)-$0.00$(5.08)
Total$26,132 $31,020 
(a)Includes swaps and physical and financial contracts.
(b)Unobservable inputs were weighted by the relative fair value of the instrument.
v3.24.0.1
Earnings Per Share (Tables)
 12 Months Ended
Dec. 31, 2023
Earnings Per Share [Abstract]  
Schedule of Earnings Per Weighted Average Common Share Outstanding
The following table presents the calculation of Pinnacle West’s basic and diluted earnings per share (in thousands, except per share amounts):
 202320222021
Net income attributable to common shareholders$501,557 $483,602 $618,720 
Weighted average common shares outstanding — basic113,442 113,196 112,910 
Net effect of dilutive securities:   
Contingently issuable performance shares and restricted stock units362 220 282 
Weighted average common shares outstanding — diluted113,804 113,416 113,192 
Earnings per weighted-average common share outstanding
Net income attributable to common shareholders — basic$4.42 $4.27 $5.48 
Net income attributable to common shareholders — diluted$4.41 $4.26 $5.47 
v3.24.0.1
Stock-Based Compensation (Tables)
 12 Months Ended
Dec. 31, 2023
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 three years:
Restricted Stock Units, Stock Grants, and Stock Units (a)Performance Shares (b)
 202320222021202320222021
Units granted192,295 174,791 152,345 202,562 208,736 161,840 
Weighted-average grant date fair value$74.32 $69.66 $76.72 $79.61 $77.63 $82.42 
(a)Units granted includes awards that will be cash settled of 0 in 2023, 0 in 2022, and 51,074 in 2021. 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, 2022
317,587 $73.91 330,694 $78.91 
Granted192,295 74.32 202,562 79.61 
Vested(119,077)80.71 (169,290)83.12 
Forfeited (c)(16,438)73.95 (16,683)78.40 
Nonvested at December 31, 2023
374,367 (a)73.29 347,283 77.29 
Vested Awards Outstanding at December 31, 2023
70,766 155,708 
(a)Includes 34,367 of awards that will be cash settled.
(b)The performance shares are reflected at target payout level. 
(c)We account for forfeitures as they occur.
Schedule of Nonvested Performance Shares
The following table is a summary of awards granted and the weighted-average grant date fair value for each of the last three years:
Restricted Stock Units, Stock Grants, and Stock Units (a)Performance Shares (b)
 202320222021202320222021
Units granted192,295 174,791 152,345 202,562 208,736 161,840 
Weighted-average grant date fair value$74.32 $69.66 $76.72 $79.61 $77.63 $82.42 
(a)Units granted includes awards that will be cash settled of 0 in 2023, 0 in 2022, and 51,074 in 2021. 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, 2022
317,587 $73.91 330,694 $78.91 
Granted192,295 74.32 202,562 79.61 
Vested(119,077)80.71 (169,290)83.12 
Forfeited (c)(16,438)73.95 (16,683)78.40 
Nonvested at December 31, 2023
374,367 (a)73.29 347,283 77.29 
Vested Awards Outstanding at December 31, 2023
70,766 155,708 
(a)Includes 34,367 of awards that will be cash settled.
(b)The performance shares are reflected at target payout level. 
(c)We account for forfeitures as they occur.
v3.24.0.1
Derivative Accounting (Tables)
 12 Months Ended
Dec. 31, 2023
Derivative Instruments and Hedging Activities Disclosure [Abstract]  
Schedule of Outstanding Gross Notional Amount of Derivatives, which Represents Both Purchases and Sales (Does Not Reflect Net Position)
The following table shows the outstanding gross notional volume of energy derivatives, which represent both purchases and sales (does not reflect net position):
Quantity
CommodityUnit of MeasureDecember 31, 2023December 31, 2022
PowerGWh1,212 1,197 
GasBillion cubic feet200 149 
Schedule of Gains and Losses from Derivative Instruments Not Designated as Accounting Hedges Instruments
The following table provides information about gains and losses from energy derivative instruments not designated as accounting hedging instruments (dollars in thousands):
Financial Statement Year Ended
December 31,
Commodity ContractsLocation202320222021
Net Gain (Loss) Recognized in IncomeFuel and purchased power (a)$(370,145)$307,287 $216,847 
(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.
As of December 31, 2023:
 (dollars in thousands) 		Gross 
Recognized 
Derivatives
 (a)		Amounts 
Offset
(b)		Net
 Recognized
 Derivatives		Other
 (c)		Amounts 
Reported on 
Balance Sheets
Current assets$8,497 $(1,694)$6,803 $5 $6,808 
Investments and other assets— — — — — 
Total assets8,497 (1,694)6,803 5 6,808 
Current liabilities(85,736)10,894 (74,842)(6,071)(80,913)
Deferred credits and other(42,975)— (42,975)— (42,975)
Total liabilities(128,711)10,894 (117,817)(6,071)(123,888)
Total$(120,214)$9,200 $(111,014)$(6,066)$(117,080)
(a)All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)Includes cash collateral provided to counterparties of $9,200 thousand that is subject to offsetting.
(c)Represents cash collateral and cash margin that is not subject to offsetting. Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument.  Includes cash collateral received from counterparties of $6,071 thousand and cash margin provided to counterparties of $5 thousand.
As of December 31, 2022:
 (dollars in thousands) 		Gross
 Recognized
 Derivatives
 (a)		Amounts
Offset 
(b)		Net
 Recognized
 Derivatives		Other
 (c)		Amounts
 Reported on
 Balance Sheets
Current assets$103,484 $(15,808)$87,676 $28 $87,704 
Investments and other assets49,777 (5,383)44,394 — 44,394 
Total assets153,261 (21,191)132,070 28 132,098 
Current liabilities(47,670)15,808 (31,862)(5,835)(37,697)
Deferred credits and other(9,223)5,383 (3,840)— (3,840)
Total liabilities(56,893)21,191 (35,702)(5,835)(41,537)
Total$96,368 $— $96,368 $(5,807)$90,561 
(a)All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)No cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting.
(c)Represents cash collateral and cash margin that is not subject to offsetting.  Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument.  Includes cash collateral received from counterparties of $5,835 thousand and cash margin provided to counterparties of $28 thousand.
Schedule of 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.
As of December 31, 2023:
 (dollars in thousands) 		Gross 
Recognized 
Derivatives
 (a)		Amounts 
Offset
(b)		Net
 Recognized
 Derivatives		Other
 (c)		Amounts 
Reported on 
Balance Sheets
Current assets$8,497 $(1,694)$6,803 $5 $6,808 
Investments and other assets— — — — — 
Total assets8,497 (1,694)6,803 5 6,808 
Current liabilities(85,736)10,894 (74,842)(6,071)(80,913)
Deferred credits and other(42,975)— (42,975)— (42,975)
Total liabilities(128,711)10,894 (117,817)(6,071)(123,888)
Total$(120,214)$9,200 $(111,014)$(6,066)$(117,080)
(a)All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)Includes cash collateral provided to counterparties of $9,200 thousand that is subject to offsetting.
(c)Represents cash collateral and cash margin that is not subject to offsetting. Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument.  Includes cash collateral received from counterparties of $6,071 thousand and cash margin provided to counterparties of $5 thousand.
As of December 31, 2022:
 (dollars in thousands) 		Gross
 Recognized
 Derivatives
 (a)		Amounts
Offset 
(b)		Net
 Recognized
 Derivatives		Other
 (c)		Amounts
 Reported on
 Balance Sheets
Current assets$103,484 $(15,808)$87,676 $28 $87,704 
Investments and other assets49,777 (5,383)44,394 — 44,394 
Total assets153,261 (21,191)132,070 28 132,098 
Current liabilities(47,670)15,808 (31,862)(5,835)(37,697)
Deferred credits and other(9,223)5,383 (3,840)— (3,840)
Total liabilities(56,893)21,191 (35,702)(5,835)(41,537)
Total$96,368 $— $96,368 $(5,807)$90,561 
(a)All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)No cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting.
(c)Represents cash collateral and cash margin that is not subject to offsetting.  Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument.  Includes cash collateral received from counterparties of $5,835 thousand and cash margin provided to counterparties of $28 thousand.
Schedule of Information about Derivative Instruments that have Credit-Risk-Related Contingent Features
The following table provides information about our energy derivative instruments that have credit-risk-related contingent features (dollars in thousands):
 December 31, 2023
Aggregate fair value of derivative instruments in a net liability position$128,711 
Cash collateral posted9,200 
Additional cash collateral in the event credit-risk related contingent features were fully triggered (a)117,566 
(a)This amount is after counterparty netting and includes those contracts which qualify for scope exceptions, which are excluded from the derivative details above.
v3.24.0.1
Other Income and Other Expense (Tables)
 12 Months Ended
Dec. 31, 2023
Other Income and Expenses [Abstract]  
Schedule of other income and other expense
The following table provides detail of Pinnacle West’s Consolidated other income and other expense for 2023, 2022 and 2021 (dollars in thousands):
 202320222021
Other income:   
Interest income$27,242 (a)$7,326 $6,726 
Gain on Sale of BCE (Note 20)
6,205 — — 
Debt return on Four Corners SCR deferral (Note 3)
— — 14,955 
Debt return on Ocotillo modernization project (Note 3)
— — 23,366 
Miscellaneous219 590 53 
Total other income$33,666 $7,916 $45,100 
Other expense:   
Non-operating costs$(15,260)$(18,619)$(13,008)
Investment gains (losses) — net(3,402)(20,537)(b)(1,367)
Miscellaneous(6,394)(13,229)(c)(11,021)
Total other expense$(25,056)$(52,385)$(25,396)
(a)The 2023 interest income is primarily related to PSA Interest. See Note 3.
(b)The 2022 investment loss is primarily related to an impairment of PNW Power’s Clear Creek wind farm investment. See Note 10.
(c)The 2022 miscellaneous amount includes donations of $7 million to the APS Foundation.
The following table provides detail of APS’s other income and other expense for 2023, 2022 and 2021 (dollars in thousands):
 202320222021
Other income:   
Interest income$26,853 (a)$5,332 $4,692 
Debt return on Four Corners SCR deferral (Note 3)
— — 14,955 
Debt return on Ocotillo modernization project (Note 3)
— — 23,366 
Miscellaneous219 556 40 
Total other income$27,072 $5,888 $43,053 
Other expense:   
Non-operating costs$(14,070)$(15,579)$(10,080)
Miscellaneous(4,194)(10,529)(b)(8,817)
Total other expense$(18,264)$(26,108)$(18,897)
(a)The 2023 interest income is primarily related to PSA Interest. See Note 3.
(b)The 2022 miscellaneous amount includes donations of $7 million to the APS Foundation.
v3.24.0.1
Palo Verde Sale Leaseback Variable Interest Entities (Tables)
 12 Months Ended
Dec. 31, 2023
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 the VIEs (dollars in thousands):
 December 31, 2023December 31, 2022
Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation$86,426 $90,296 
Equity-Noncontrolling interests107,198 111,229 
v3.24.0.1
Investments in Nuclear Decommissioning Trusts and Other Special Use Funds (Tables)
 12 Months Ended
Dec. 31, 2023
Investments, Debt and Equity Securities [Abstract]  
Schedule of Fair Value of APS's Nuclear Decommissioning Trust Fund Assets
The following tables present the unrealized gains and losses based on the original cost of the investment and summarizes the fair value of APS’s nuclear decommissioning trusts and other special use fund assets (dollars in thousands): 
December 31, 2023
 Fair ValueTotal
Unrealized
Gains		Total
Unrealized
Losses
Investment Type:Nuclear Decommissioning TrustsOther Special Use FundsTotal
Equity securities$420,680 $40,991 $461,671 $336,555 $— 
Available for sale-fixed income securities781,333 319,594 1,100,927 (a)21,518 (40,868)
Other(767)2,196 1,429 (b)39 — 
Total$1,201,246 $362,781 $1,564,027 $358,112 $(40,868)
(a)As of December 31, 2023, the amortized cost basis of these available-for-sale investments is $1,120 million.
(b)Represents net pending securities sales and purchases.

December 31, 2022
 Fair ValueTotal
Unrealized
Gains		Total
Unrealized
Losses
Investment Type:Nuclear Decommissioning TrustsOther Special Use FundsTotal
Equity securities$487,240 $66,974 $554,214 $334,817 $(267)
Available for sale-fixed income securities582,343 279,294 861,637 (a)3,177 (68,795)
Other3,827 963 4,790 (b)— (29)
Total$1,073,410 $347,231 $1,420,641 $337,994 $(69,091)
(a)As of December 31, 2022, the amortized cost basis of these available-for-sale investments is $927 million.
(b)Represents net pending securities sales and purchases.
Schedule of Realized Gains and Losses and Proceeds from the Sale of Securities by the Nuclear Decommissioning Trust Funds
The following table sets forth APS’s realized gains and losses relating to the sale and maturity of available-for-sale debt securities and equity securities, and the proceeds from the sale and maturity of these investment securities (dollars in thousands):
 Year Ended December 31,
 Nuclear Decommissioning TrustsOther Special Use FundsTotal
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 
2022
Realized gains$9,017 $420 $9,437 
Realized losses$(40,239)$— $(40,239)
Proceeds from the sale of securities (a)$979,639 $227,558 $1,207,197 
2021
Realized gains$134,610 $49 $134,659 
Realized losses$(8,431)$(7)$(8,438)
Proceeds from the sale of securities (a)$1,457,305 $263,661 $1,720,966 
(a)Proceeds are reinvested in the nuclear decommissioning trusts and other special use funds, excluding amounts reimbursed to the Company for active union employee medical claims from the active union employee medical account.
Schedule of Fair Value of Fixed Income Securities, Summarized by Contractual Maturities
The fair value of APS’s fixed income securities, summarized by contractual maturities, at December 31, 2023, is as follows (dollars in thousands):
 
 Nuclear Decommissioning TrustsCoal Reclamation Escrow AccountActive Union Employee Medical AccountTotal
Less than one year$26,057 $58,692 $36,857 $121,606 
1 year – 5 years225,891 46,120 152,761 424,772 
5 years – 10 years176,288 — 25,164 201,452 
Greater than 10 years353,097 — — 353,097 
Total$781,333 $104,812 $214,782 $1,100,927 
v3.24.0.1
Changes in Accumulated Other Comprehensive Loss (Tables)
 12 Months Ended
Dec. 31, 2023
Comprehensive Income (Loss), Net of Tax, Attributable to Parent [Abstract]  
Schedule of Changes in Accumulated Other Comprehensive Loss Including Reclassification Adjustments, by Component
The following table shows the changes in Pinnacle West’s consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component (dollars in thousands): 
 Pension and Other Postretirement Benefits Derivative InstrumentsTotal
Balance at December 31, 2021$(53,885)$(976)$(54,861)
OCI (loss) before reclassifications17,550 1,873 19,423 
Amounts reclassified from accumulated other comprehensive loss4,003 (a)— 4,003 
Balance at December 31, 2022(32,332)897 (31,435)
OCI (loss) before reclassifications(4,420)713 (3,707)
Amounts reclassified from accumulated other comprehensive loss1,998 (a)— 1,998 
Balance at December 31, 2023$(34,754)$1,610 $(33,144)
(a)These amounts primarily represent amortization of actuarial loss and are included in the computation of net periodic pension cost. See Note 7.
The following table shows the changes in APS’s consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component (dollars in thousands): 
 Pension and Other Postretirement BenefitsTotal
Balance at December 31, 2021$(34,880)$(34,880)
OCI (loss) before reclassifications15,646 15,646 
Amounts reclassified from accumulated other comprehensive loss3,638 (a)3,638 
Balance at December 31, 2022(15,596)(15,596)
OCI (loss) before reclassifications(3,383)(3,383)
Amounts reclassified from accumulated other comprehensive loss1,760 (a)1,760 
Balance at December 31, 2023$(17,219)$(17,219)
(a)These amounts primarily represent amortization of actuarial loss and are included in the computation of net periodic pension cost. See Note 7.
v3.24.0.1
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, 2023
USD ($)
$ / shares
shares
Dec. 31, 2022
USD ($)
Dec. 31, 2021
USD ($)
Dec. 31, 2023
USD ($)
$ / shares
shares
Approximate remaining average useful lives of utility property          
Depreciation   $ 669 $ 632 $ 575  
Depreciation rates (as a percent)   2.98% 3.03% 2.87%  
Allowance for Funds Used During Construction          
Composite rate used to calculate AFUDC (as a percent)   6.29% 5.75% 6.75%  
Income Taxes          
Percent likelihood largest tax benefit amount is realized (greater than)   50.00%      
Intangible Assets          
Amortization expense   $ 90 $ 84 $ 80  
Estimated amortization expense on existing intangible assets over the next five years          
Estimated amortization expense, next year   90     $ 90
Estimated amortization expense, in two years   75     75
Estimated amortization expense, in three years   49     49
Estimated amortization expense, in four years   23     23
Estimated amortization expense, in five years   $ 11     $ 11
Remaining amortization period for intangible assets   5 years     5 years
Pinnacle West          
Preferred Stock          
Preferred stock, shares authorized (in shares) | shares   10,000,000     10,000,000
Preferred stock, shares outstanding (in shares) | shares   0     0
Arizona Public Service Company          
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
Minimum          
Approximate remaining average useful lives of utility property          
Depreciation rates (as a percent)         1.37%
Maximum          
Approximate remaining average useful lives of utility property          
Depreciation rates (as a percent)         12.15%
Investments          
Ownership percentage for classification as cost method investments by El Dorado   20.00%      
Steam Generation          
Approximate remaining average useful lives of utility property          
Average useful life   11 years     11 years
Nuclear Plant          
Approximate remaining average useful lives of utility property          
Average useful life   25 years     25 years
Other Generation          
Approximate remaining average useful lives of utility property          
Average useful life   18 years     18 years
Transmission          
Approximate remaining average useful lives of utility property          
Average useful life   38 years     38 years
Distribution          
Approximate remaining average useful lives of utility property          
Average useful life   33 years     33 years
General Plant          
Approximate remaining average useful lives of utility property          
Average useful life   7 years     7 years
v3.24.0.1
Summary of Significant Accounting Policies - Summary of Property, Plant and Equipment (Details) - USD ($)
$ in Thousands
Dec. 31, 2023
Dec. 31, 2022
Utility Plant and Depreciation [Line Items]    
Net $ 15,803,127 $ 14,522,268
Construction work in progress 1,724,004 1,882,791
Intangible assets, net of accumulated amortization 267,110 258,880
Nuclear fuel, net of accumulated amortization 99,490 100,119
Total property, plant and equipment 17,980,157 16,854,354
Electric Service    
Utility Plant and Depreciation [Line Items]    
Generation 10,446,291 9,563,145
Transmission 3,773,253 3,589,456
Distribution 8,448,293 7,951,867
General plant 1,543,330 1,347,678
Plant in service and held for future use 24,211,167 22,452,146
Accumulated depreciation and amortization (8,408,040) (7,929,878)
Net 15,803,127 14,522,268
Construction work in progress 1,724,004 1,882,791
Intangible assets, net of accumulated amortization 267,110 258,880
Nuclear fuel, net of accumulated amortization 99,490 100,119
Total property, plant and equipment 17,980,157 16,854,354
Electric Service | Variable Interest Entity    
Utility Plant and Depreciation [Line Items]    
Total property, plant and equipment $ 86,426 $ 90,296
v3.24.0.1
Summary of Significant Accounting Policies - Supplemental Cash Flow Information (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Cash and Cash Equivalents [Line Items]      
Income taxes, net of refunds $ 8,788 $ 46,227 $ 229
Interest, net of amounts capitalized 310,996 245,271 227,584
Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]      
Accrued capital expenditures 206,269 114,999 167,733
Dividends declared but not paid 99,813 97,895 95,988
BCE Sale non-cash consideration 28,262 0 0
Arizona Public Service Company      
Cash and Cash Equivalents [Line Items]      
Income taxes, net of refunds 21,734 95,985 19,783
Interest, net of amounts capitalized 267,261 227,159 217,749
Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]      
Accrued capital expenditures 206,269 116,533 167,657
Dividends declared but not paid $ 99,800 $ 97,900 $ 96,000
v3.24.0.1
Revenue - Schedule of Disaggregation (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Disaggregation of Revenue [Line Items]      
Total Operating Revenues $ 4,695,991 $ 4,324,385 $ 3,803,835
Retail Electric Service | Residential      
Disaggregation of Revenue [Line Items]      
Total Operating Revenues 2,289,196 2,046,111 1,913,324
Retail Electric Service | Non-Residential      
Disaggregation of Revenue [Line Items]      
Total Operating Revenues 2,048,416 1,767,616 1,586,940
Wholesale Energy Sales      
Disaggregation of Revenue [Line Items]      
Total Operating Revenues 208,985 383,126 187,640
Transmission Services for Others      
Disaggregation of Revenue [Line Items]      
Total Operating Revenues 138,631 116,628 99,285
Other Sources      
Disaggregation of Revenue [Line Items]      
Total Operating Revenues $ 10,763 $ 10,904 $ 16,646
v3.24.0.1
Revenue - Additional Information (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Disaggregation of Revenue [Line Items]      
Operating revenues $ 4,695,991 $ 4,324,385 $ 3,803,835
Regulatory cost recovery revenue 45,000 22,000 44,000
Electric and Transmission Service      
Disaggregation of Revenue [Line Items]      
Operating revenues $ 4,651,000 $ 4,302,000 $ 3,760,000
v3.24.0.1
Revenue - Allowance for Doubtful Accounts (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Accounts Receivable, Allowance for Credit Loss [Roll Forward]      
Allowance for doubtful accounts, balance at beginning of period $ 23,778 $ 25,354 $ 19,782
Bad debt expense 23,399 17,006 22,251
Actual write-offs (24,744) (18,582) (16,679)
Allowance for doubtful accounts, balance at end of period $ 22,433 $ 23,778 $ 25,354
v3.24.0.1
Regulatory Matters - Retail Rate Case Filing (Details)
$ in Thousands
Feb. 22, 2024
USD ($)
Jan. 25, 2024
USD ($)
$ / MWh
Jul. 26, 2023
USD ($)
$ / kWh
Jul. 12, 2023
USD ($)
$ / kWh
Jul. 11, 2023
$ / kWh
Jun. 14, 2023
USD ($)
Oct. 28, 2022
USD ($)
$ / kWh
Jun. 30, 2022
USD ($)
Dec. 17, 2021
USD ($)
Oct. 27, 2021
USD ($)
Aug. 02, 2021
USD ($)
Feb. 23, 2024
USD ($)
Nov. 06, 2023
USD ($)
Nov. 05, 2023
USD ($)
Aug. 04, 2023
USD ($)
Aug. 03, 2023
USD ($)
Jun. 15, 2023
USD ($)
Mar. 06, 2023
Dec. 31, 2022
USD ($)
Nov. 30, 2022
USD ($)
Subsequent Event                                        
Public Utilities, General Disclosures [Line Items]                                        
Revenue increase (decrease) $ 491,700 $ 523,100                                    
ACC                                        
Public Utilities, General Disclosures [Line Items]                                        
Base fuel rate (in dollars per kWh) | $ / kWh     0.006 0.006 0.004                              
Revenue increase (decrease)     $ 281,900 $ 383,100                 $ 282,700 $ 281,900     $ 251,000      
Alternative revenue increase (decrease)                                 $ 312,000      
Recommended return on equity, percentage     9.68% 10.25%                         9.60%      
Increment of fair value rate, percentage     0.50% 0.50%                         0.00%      
Alternative increment of fair value rate percentage                                 0.0075      
Hypothetical capital structure of equity layer percentage                                 0.46      
ACC | Subsequent Event                                        
Public Utilities, General Disclosures [Line Items]                                        
Recommended return on equity, percentage 9.55% 9.55%                                    
Increment of fair value rate, percentage 0.25% 0.25%                                    
ACC | Coal Community Transition Plan | Navajo Nation, Electrification Projects                                        
Public Utilities, General Disclosures [Line Items]                                        
Amount funded by shareholders                                     $ 7,000  
ACC | Coal Community Transition Plan | Navajo Nation, Electrification Projects | Subsequent Event                                        
Public Utilities, General Disclosures [Line Items]                                        
Amount funded by shareholders                       $ 1,000                
ACC | Coal Community Transition Plan | Navajo Nation, Hopi Tribe | Subsequent Event                                        
Public Utilities, General Disclosures [Line Items]                                        
Regulatory matters, amounts recoverable by rates                       1,000                
ACC | Coal Community Transition Plan | Navajo Nation | Subsequent Event                                        
Public Utilities, General Disclosures [Line Items]                                        
Regulatory matters, amounts recoverable by rates                       6,660                
ACC | Coal Community Transition Plan | Navajo Nation, Hopi Reservation | Subsequent Event                                        
Public Utilities, General Disclosures [Line Items]                                        
Regulatory matters, amounts recoverable by rates                       1,250                
ACC | Coal Community Transition Plan | Navajo County Communities | Subsequent Event                                        
Public Utilities, General Disclosures [Line Items]                                        
Regulatory matters, amounts recoverable by rates                       500                
ACC | Coal Community Transition Plan | Navajo County Communities, CCT and Economic Development | Subsequent Event                                        
Public Utilities, General Disclosures [Line Items]                                        
Amount funded by shareholders                       1,100                
ACC | Coal Community Transition Plan | Navajo Nation, Hopi Tribe for CCT and Economic Development | Subsequent Event                                        
Public Utilities, General Disclosures [Line Items]                                        
Amount funded by shareholders                       $ 1,250                
ACC | Coal Community Transition Plan | Navajo and Hopi Tribes                                        
Public Utilities, General Disclosures [Line Items]                                        
Disbursement                                       $ 1,250
ACC | Arizona Public Service Company                                        
Public Utilities, General Disclosures [Line Items]                                        
Total revenue deficiency             $ 772,000                          
Revenue increase (decrease)                         $ 376,200   $ 377,700 $ 383,100        
Regulatory matters, customer bill impact rate       11.30%                 11.10%   11.20%          
Regulatory matters, no of basis penalty point                 0.0020 20               0.0020    
Reversal of basis point penalty           0.0020                            
ACC | Arizona Public Service Company | Retail Rate Case Filing with Arizona Corporation Commission                                        
Public Utilities, General Disclosures [Line Items]                                        
Approximate percentage of increase in average residential customer bill             13.60%                          
Rate matter, cost base rate               $ 10,500,000                        
Base fuel rate (in dollars per kWh) | $ / kWh             0.038321                          
Revenue increase (decrease)                     $ (111,000)                  
Recommended return on equity, percentage                 8.90% 8.70% 9.16%                  
Increment of fair value rate, percentage                     0.30%                  
Reduction on equity percentage                     0.03%                  
Effective fair value percentage                     4.95%                  
ACC | Arizona Public Service Company | Retail Rate Case Filing with Arizona Corporation Commission | Subsequent Event                                        
Public Utilities, General Disclosures [Line Items]                                        
Base fuel rate (in dollars per kWh) | $ / MWh   0.006                                    
Effective fair value percentage 4.39% 4.36%                                    
Increases in annual revenue $ 253,400                                      
Increase to the typical residential customer’s bill 8.00%                                      
Prepaid pension asset rate   5.00%                                    
Pension and otherpost retirement and post employment benefit plans   5.35%                                    
Retention of REAC   $ 1,900                                    
Transfer to LFCR   $ 27,100                                    
ACC | Arizona Public Service Company | Retail Rate Case Filing with Arizona Corporation Commission | Coal Community Transition Plan | Navajo Nation, Economic Development Organization                                        
Public Utilities, General Disclosures [Line Items]                                        
Disallowance of annual amortization percentage                     15.00%                  
Amount funded by customers, term                     10 years                  
Amount funded by customers                     $ 50,000                  
ACC | Arizona Public Service Company | Retail Rate Case Filing with Arizona Corporation Commission | Coal Community Transition Plan | Navajo County Communities, Cholla Power Plant Closure                                        
Public Utilities, General Disclosures [Line Items]                                        
Amount funded by shareholders                   $ 500 $ 5,000                  
Amount funded by shareholders, term                   60 days 5 years                  
ACC | Arizona Public Service Company | Retail Rate Case Filing with Arizona Corporation Commission | Coal Community Transition Plan | Navajo Nation, Hopi Tribe                                        
Public Utilities, General Disclosures [Line Items]                                        
Amount funded by shareholders                   $ 1,000 $ 1,675                  
Amount funded by shareholders, term                   60 days                    
Amount not recoverable                   $ 215,500                    
ACC | Arizona Public Service Company | Retail Rate Case Filing with Arizona Corporation Commission | Coal Community Transition Plan | Navajo Nation                                        
Public Utilities, General Disclosures [Line Items]                                        
Amount funded by shareholders                   $ 10,000                    
Amount funded by shareholders, term                   3 years                    
ACC | Arizona Public Service Company | Retail Rate Case Filing with Arizona Corporation Commission | Coal Community Transition Plan | Navajo Nation, Hopi Reservation                                        
Public Utilities, General Disclosures [Line Items]                                        
Amount funded by shareholders                   $ 1,250                    
ACC | Arizona Public Service Company | Retail Rate Case Filing with Arizona Corporation Commission | Coal Community Transition Plan | Navajo Nation Reservation                                        
Public Utilities, General Disclosures [Line Items]                                        
Revenue increase (decrease)                   (4,800)                    
Recommended return on equity, percentage           8.70%                            
Amount funded by shareholders                   $ 1,250                    
Disallowance of plant investments                 $ 215,500                      
Requested reversal of rate adjustment           $ 215,500                            
Lost revenue recovery           $ 59,600                            
Residential Utilities Consumer Office | ACC                                        
Public Utilities, General Disclosures [Line Items]                                        
Revenue increase (decrease)                                 $ 84,900      
Recommended return on equity, percentage                                 8.20%      
Increment of fair value rate, percentage                                 0.00%      
Alternate recommended return on equity percentage                                 0.087      
Minimum | ACC | Arizona Public Service Company                                        
Public Utilities, General Disclosures [Line Items]                                        
Annual increase in retail base rates             $ 460,000                          
Maximum | ACC                                        
Public Utilities, General Disclosures [Line Items]                                        
Increment of fair value rate, percentage         1.00%                              
v3.24.0.1
Regulatory Matters - Capital Structure and Costs of Capital (Details) - Arizona Public Service Company
Oct. 28, 2022
Cost Of Capital [Abstract]  
Requested Long-term debt cost of capital, percentage 3.85%
Requested equity cost of capital, percentage 10.25%
Requested weighted average cost of capital, percentage 7.17%
Retail Rate Case Filing with Arizona Corporation Commission  
Capital Structure  
Requested equity capital structure, percentage 51.93%
Retail Rate Case Filing with Arizona Corporation Commission | ACC  
Capital Structure  
Requested debt capital structure, percentage 48.07%
v3.24.0.1
Regulatory Matters - Cost Recovery Mechanisms (Details)
 6 Months Ended 12 Months Ended
Feb. 01, 2024
USD ($)
Oct. 11, 2023
Jul. 31, 2023
USD ($)
Jul. 01, 2023
USD ($)
$ / KWH_Kilowatt_hour
Jun. 14, 2023
USD ($)
May 01, 2023
$ / kWh
Mar. 10, 2023
USD ($)
Feb. 23, 2023
USD ($)
$ / kWh
Feb. 01, 2023
USD ($)
$ / kWh
Jan. 06, 2023
USD ($)
Sep. 23, 2022
MW
Jul. 12, 2022
USD ($)
$ / kWh
Jun. 01, 2022
USD ($)
Feb. 15, 2022
USD ($)
Feb. 01, 2022
USD ($)
$ / kWh
$ / KWH_Kilowatt_hour
Oct. 01, 2021
$ / kWh
Jun. 01, 2021
USD ($)
Feb. 15, 2021
USD ($)
Feb. 01, 2020
$ / kWh
Oct. 31, 2019
$ / KWH_Kilowatt_hour
Sep. 01, 2017
Jun. 30, 2021
program
MW
Dec. 31, 2023
USD ($)
storage
Dec. 31, 2022
USD ($)
storage
Dec. 31, 2021
USD ($)
storage
Dec. 31, 2017
$ / kWh
Dec. 31, 2017
$ / KWH_Kilowatt_hour
Nov. 30, 2023
USD ($)
Oct. 27, 2023
USD ($)
Jun. 30, 2023
USD ($)
May 31, 2023
USD ($)
Nov. 30, 2022
USD ($)
Jul. 01, 2022
USD ($)
Apr. 18, 2022
USD ($)
Dec. 17, 2021
USD ($)
Dec. 09, 2021
USD ($)
Jul. 01, 2021
USD ($)
Change in regulatory asset                                                                          
Deferred fuel and purchased power costs — current period                                             $ 549,877,000 $ 291,992,000 $ 256,871,000                        
Amounts charged to customers                                             (547,243,000) (219,579,000) (44,557,000)                        
Arizona Public Service Company                                                                          
Change in regulatory asset                                                                          
Deferred fuel and purchased power costs — current period                                             549,877,000 291,992,000 256,871,000                        
Amounts charged to customers                                             $ (547,243,000) $ (219,579,000) $ (44,557,000)                        
Number of energy storage PPA | storage                                             9 1 4                        
Number of energy storage PPA, terminated | storage                                                 1                        
Annual amount of approved equity infusions                                             $ 150,000,000                            
Increased in equity contributions                                                         $ 500,000,000                
Arizona Public Service Company | Damage from Fire, Explosion or Other Hazard                                                                          
Change in regulatory asset                                                                          
Past due balance threshold qualifying for payment extension                                                                   $ 75      
ACC | Arizona Public Service Company                                                                          
Settlement Agreement                                                                          
Program term                                           18 years                              
Change in regulatory asset                                                                          
Number of public utility programs | program                                           2                              
Solar power capacity | MW                                           80                              
Arizona Renewable Energy Standard and Tariff | ACC | Arizona Public Service Company                                                                          
Settlement Agreement                                                                          
Plan term                                             5 years                            
Arizona Renewable Energy Standard and Tariff 2018 | ACC | Arizona Public Service Company                                                                          
Settlement Agreement                                                                          
Amount of proposed budget                                                           $ 95,100,000     $ 86,200,000     $ 100,500,000 $ 93,100,000
Arizona Renewable Energy Standard and Tariff 2018 | ACC | Arizona Public Service Company | Minimum                                                                          
Change in regulatory asset                                                                          
Authorized spending in capital costs                       $ 20,000,000                                                  
Arizona Renewable Energy Standard and Tariff 2018 | ACC | Arizona Public Service Company | Maximum                                                                          
Change in regulatory asset                                                                          
Authorized spending in capital costs                       $ 30,000,000                                                  
Arizona Renewable Energy Standard and Tariff 2018 | ACC | Arizona Public Service Company | Solar Communities                                                                          
Settlement Agreement                                                                          
Program term                       3 years                                                  
Power Supply Adjustor (PSA) | ACC | Arizona Public Service Company                                                                          
Change in regulatory asset                                                                          
Beginning balance                                             $ 460,561,000 $ 388,148,000                          
Deferred fuel and purchased power costs — current period                                             549,877,000 291,992,000                          
Amounts charged to customers                                             (547,243,000) (219,579,000)                          
Ending balance                                             $ 463,195,000 $ 460,561,000 $ 388,148,000                        
PSA rate (in dollars per kWh) | $ / kWh               0.019074 0.006           0.007544                                            
Forward component Of PSA rate1 (in dollars per kWh) | $ / kWh               (0.005527)             0.004842                                            
Historical component Of PSA rate1 (in dollars per kWh) | $ / kWh               0.013071             0.012386                                            
Period to reduce balancing account               24 months                                                          
Reporting threshold of balancing account               $ 500,000                                                          
Transition component of PSA rate | $ / kWh               0.011530                                                          
Power Supply Adjustor (PSA) | ACC | Arizona Public Service Company | Cost Recovery Mechanisms                                                                          
Change in regulatory asset                                                                          
Maximum increase decrease in PSA rate (in dollars per kWh) | $ / kWh                                     0.004                                    
PSA rate In prior years1 (in dollars per kWh) | $ / kWh                             (0.004)                                            
Retail Rate Case Filing with Arizona Corporation Commission | Arizona Public Service Company | Maximum                                                                          
Change in regulatory asset                                                                          
Fixed costs recoverable per power lost (in dollars per kWh) | $ / KWH_Kilowatt_hour                                       2.68                                  
Retail Rate Case Filing with Arizona Corporation Commission | ACC | Arizona Public Service Company                                                                          
Change in regulatory asset                                                                          
Commercial customers, market pricing, threshold | MW                     140                                                    
Retail Rate Case Filing with Arizona Corporation Commission | ACC | Arizona Public Service Company | Coal Community Transition Plan | Navajo Nation Reservation                                                                          
Change in regulatory asset                                                                          
Lost revenue recovery         $ 59,600,000                                                                
Demand Side Management Adjustor Charge 2022 | ACC | Arizona Public Service Company                                                                          
Settlement Agreement                                                                          
Amount of proposed budget                                                                     $ 78,400,000    
Change in regulatory asset                                                                          
Rate matter, increase (decrease) in proposed budget                                                                     $ 14,000,000    
Demand Side Management Adjustor Charge 2023 | ACC | Arizona Public Service Company                                                                          
Settlement Agreement                                                                          
Amount of proposed budget                                                             $ 88,000,000 $ 88,000,000          
Environmental Improvement Surcharge | FERC | Arizona Public Service Company                                                                          
Change in regulatory asset                                                                          
Rate matters, environmental surcharge cap rate1 (in dollars per kWh) | $ / KWH_Kilowatt_hour                             0.0005                                            
Rate matters, environmental surcharge cap rate1, amount             $ 4,000,000                                                            
Rate matters, increase (decrease) In cost recovery             (10,700,000)   $ 14,700,000                                                        
Rate matters, increase (decrease) In cost recovery, excess Of annual amount             $ (7,500,000)   $ 3,300,000                                                        
Environmental Improvement Surcharge | FERC | Arizona Public Service Company | Subsequent Event                                                                          
Change in regulatory asset                                                                          
Rate matters, increase (decrease) In cost recovery $ 15,300,000                                                                        
Rate matters, increase (decrease) In cost recovery, excess Of annual amount $ 11,300,000                                                                        
Environmental Improvement Surcharge | FERC | Arizona Public Service Company | Minimum                                                                          
Change in regulatory asset                                                                          
Rate matters, environmental surcharge cap rate1, amount                             $ 13,000,000                                            
Environmental Improvement Surcharge | FERC | Arizona Public Service Company | Maximum                                                                          
Change in regulatory asset                                                                          
Rate matters, environmental surcharge cap rate1, amount                             $ 15,000,000                                            
Transmission rates, transmission cost adjustor and other transmission matters | FERC | Arizona Public Service Company                                                                          
Change in regulatory asset                                                                          
Rate matters, increase (decrease) In cost recovery                   $ 34,700,000     $ (33,000,000)       $ 4,000,000                                        
Rate matters, increase (decrease) in cost recovery, wholesale customer rates                   20,700,000     6,400,000       3,200,000                                        
Rate matters, increase (decrease) in cost recovery, retail customer rates                   14,000,000     (26,600,000)       7,200,000                                        
Rate matters, increase (decrease) In retail revenue requirements                   $ 10,000,000     $ 2,400,000       $ 28,400,000                                        
Lost Fixed Cost Recovery Mechanism | Arizona Public Service Company                                                                          
Change in regulatory asset                                                                          
Fixed costs recoverable per power lost (in dollars per kWh)                                                   2.50 2.56                    
Rate matter cap percentage of retail revenue                                             1.00%                            
Amount of adjustment approved representing prorated sales losses pending approval     $ 68,700,000                     $ 59,100,000       $ 38,500,000                                      
Increase (decrease) In amount Of adjustment representing prorated sales losses                           $ 32,500,000       $ 11,800,000                                      
Amount of adjustment representing annual recovery     $ 9,600,000                                                                    
Net Metering | ACC | Arizona Public Service Company                                                                          
Change in regulatory asset                                                                          
Rate matters, cost of service, resource comparison proxy method, maximum annual percentage decrease   10.00%       10.00%           10.00%                 10.00%                                
Rate matters, cost of service for interconnected dg system customers, grandfathered period                                         20 years                                
Rate matters, cost of service for new customers, guaranteed export price period                                         10 years                                
Rate matter, request second-year energy price for exported energy1 (in dollars per kwh) | $ / kWh                       0.0846       0.094                                          
Third-year export energy price (in dollars per kWh) | $ / kWh           0.07619                                                              
Court Resolution Surcharge | ACC | Arizona Public Service Company                                                                          
Change in regulatory asset                                                                          
Court resolution surcharge (in dollars per kWh) | $ / KWH_Kilowatt_hour       0.00175                                                                  
Lost revenue recovery       $ 59,600,000                                                                  
2023 Transportation Electrification Plan | ACC | Arizona Public Service Company                                                                          
Settlement Agreement                                                                          
Amount of proposed budget                                                               $ 5,000,000          
Navajo Nation Reservation | Coal Community Transition Plan | Arizona Public Service Company | Coal Community Transition Plan                                                                          
Change in regulatory asset                                                                          
Lost revenue recovery collected                                             $ 9,400,000                            
Demand Side Management Adjustor Charge 2024 | ACC | Arizona Public Service Company                                                                          
Settlement Agreement                                                                          
Amount of proposed budget                                                       $ 91,500,000                  
v3.24.0.1
Regulatory Matters - Four Corners, Cholla and Navajo Plant (Details) - Arizona Public Service Company - USD ($)
$ in Millions
 1 Months Ended
Nov. 02, 2021
Sep. 30, 2018
Apr. 30, 2018
Dec. 31, 2023
Aug. 02, 2021
Coal Community Transition Plan | Navajo Nation, Economic Development Organization | Retail Rate Case Filing with Arizona Corporation Commission | ACC          
Acquisition          
Disallowance of annual amortization percentage         15.00%
Retired power plant costs          
Acquisition          
Net book value       $ 32.7  
Navajo Plant          
Acquisition          
Net book value       43.0  
Navajo Plant, Coal Reclamation Regulatory Asset          
Acquisition          
Net book value       $ 10.9  
SCE | Four Corners Units 4 and 5          
Acquisition          
Settlement agreement, ACC approved rate adjustment, annualized customer impact   $ 58.5 $ 67.5    
Disallowance of plant investments $ 194.0        
Cost deferrals $ 215.5        
v3.24.0.1
Regulatory Matters - Schedule of Regulatory Assets (Details) - USD ($)
$ in Thousands
Dec. 31, 2023
Dec. 31, 2022
Detail of regulatory assets    
Total non-current regulatory assets $ 2,016,036 $ 1,822,100
Less: current regulatory assets 625,757 538,879
Total non-current regulatory assets 1,390,279 1,283,221
Pension    
Detail of regulatory assets    
Total non-current regulatory assets 696,476 637,656
Deferred fuel and purchased power    
Detail of regulatory assets    
Total non-current regulatory assets 463,195 460,561
Income taxes — AFUDC equity    
Detail of regulatory assets    
Total non-current regulatory assets 189,058 179,631
Ocotillo deferral    
Detail of regulatory assets    
Total non-current regulatory assets 128,636 138,143
Deferred fuel and purchased power — mark-to-market (Note 16)    
Detail of regulatory assets    
Total non-current regulatory assets 120,214 0
SCR deferral    
Detail of regulatory assets    
Total non-current regulatory assets 89,477 97,624
Retired power plant costs    
Detail of regulatory assets    
Total non-current regulatory assets 83,536 98,692
Lease incentives (Note 8)    
Detail of regulatory assets    
Total non-current regulatory assets 46,615 0
Income taxes — investment tax credit basis adjustment    
Detail of regulatory assets    
Total non-current regulatory assets 34,230 23,977
Deferred compensation    
Detail of regulatory assets    
Total non-current regulatory assets 33,972 33,660
Deferred property taxes    
Detail of regulatory assets    
Total non-current regulatory assets 32,488 41,057
Palo Verde VIEs (Note 17)    
Detail of regulatory assets    
Total non-current regulatory assets 20,772 20,933
Power supply adjustor-interest    
Detail of regulatory assets    
Total non-current regulatory assets 19,416 1,541
Active union medical trust    
Detail of regulatory assets    
Total non-current regulatory assets 12,747 18,226
Navajo coal reclamation    
Detail of regulatory assets    
Total non-current regulatory assets 10,883 13,862
Mead-Phoenix transmission line — contributions in aid of construction    
Detail of regulatory assets    
Total non-current regulatory assets 8,716 9,048
Loss on reacquired debt    
Detail of regulatory assets    
Total non-current regulatory assets 7,965 9,468
Four Corners cost deferral    
Detail of regulatory assets    
Total non-current regulatory assets 7,922 15,999
Tax expense adjustor mechanism    
Detail of regulatory assets    
Total non-current regulatory assets 5,190 5,845
Lost fixed cost recovery    
Detail of regulatory assets    
Total non-current regulatory assets 0 9,547
Other    
Detail of regulatory assets    
Total non-current regulatory assets $ 4,528 $ 6,630
v3.24.0.1
Regulatory Matters - Schedule of Regulatory Liabilities (Details) - USD ($)
$ in Thousands
Dec. 31, 2023
Dec. 31, 2022
Detail of regulatory liabilities    
Total regulatory liabilities $ 2,175,788 $ 2,333,351
Regulatory liabilities (Note 3) 209,923 271,575
Total non-current regulatory liabilities 1,965,865 2,061,776
Asset retirement obligations    
Detail of regulatory liabilities    
Total regulatory liabilities 392,383 354,002
Other postretirement benefits    
Detail of regulatory liabilities    
Total regulatory liabilities 226,726 270,604
Removal costs    
Detail of regulatory liabilities    
Total regulatory liabilities 94,368 106,889
Deferred fuel and purchased power — mark-to-market (Note 16)    
Detail of regulatory liabilities    
Total regulatory liabilities 0 96,367
Income taxes — change in rates    
Detail of regulatory liabilities    
Total regulatory liabilities 60,667 64,806
Four Corners coal reclamation    
Detail of regulatory liabilities    
Total regulatory liabilities 55,917 52,592
Income taxes — deferred investment tax credit    
Detail of regulatory liabilities    
Total regulatory liabilities 68,521 48,035
Spent nuclear fuel    
Detail of regulatory liabilities    
Total regulatory liabilities 33,154 39,217
Renewable energy program    
Detail of regulatory liabilities    
Total regulatory liabilities 43,251 35,720
FERC transmission true up    
Detail of regulatory liabilities    
Total regulatory liabilities 1,869 22,895
Property tax deferral    
Detail of regulatory liabilities    
Total regulatory liabilities 10,850 15,521
Sundance maintenance    
Detail of regulatory liabilities    
Total regulatory liabilities 19,989 16,893
Demand side management    
Detail of regulatory liabilities    
Total regulatory liabilities 14,374 8,461
Tax expense adjustor mechanism    
Detail of regulatory liabilities    
Total regulatory liabilities 4,835 4,835
Other    
Detail of regulatory liabilities    
Total regulatory liabilities 3,873 3,092
ACC | Excess deferred income taxes - ACC - Tax Cuts and Jobs Act    
Detail of regulatory liabilities    
Total regulatory liabilities 930,344 971,545
FERC | Excess deferred income taxes - ACC - Tax Cuts and Jobs Act    
Detail of regulatory liabilities    
Total regulatory liabilities $ 214,667 $ 221,877
v3.24.0.1
Income Taxes - Additional Information (Details)
$ in Millions
 12 Months Ended
Dec. 31, 2023
USD ($)
Income Taxes  
Income tax expense attributable to non controlling interests $ 0
Interest expense to be received on the underpayment of income taxes 1
Increase (decrease) in deferred income taxes due to regulation adoption 12
Arizona Public Service Company  
Income Taxes  
Increase (decrease) in deferred income taxes due to regulation adoption 12
Federal  
Income Taxes  
State credit carryforwards net of federal benefit 56
Federal | Arizona Public Service Company  
Income Taxes  
State credit carryforwards net of federal benefit 15
State  
Income Taxes  
State credit carryforwards net of federal benefit 56
State | Arizona Public Service Company  
Income Taxes  
State credit carryforwards net of federal benefit $ 15
v3.24.0.1
Income Taxes - Reconciliation of Unrecognized Tax Benefits (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
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 $ 43,097 $ 45,086 $ 45,655
Additions for tax positions of the current year 1,473 1,399 3,305
Additions for tax positions of prior years 419 2,069 1,449
Reductions for tax positions of prior years for:      
Changes in judgment 661 (3,495) (2,659)
Settlements with taxing authorities 0 0 0
Lapses of applicable statute of limitations (1,376) (1,962) (2,664)
Total unrecognized tax benefits, end of the year 44,274 43,097 45,086
Arizona Public Service Company      
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 43,097 45,086 45,655
Additions for tax positions of the current year 1,473 1,399 3,305
Additions for tax positions of prior years 419 2,069 1,449
Reductions for tax positions of prior years for:      
Changes in judgment 661 (3,495) (2,659)
Settlements with taxing authorities 0 0 0
Lapses of applicable statute of limitations (1,376) (1,962) (2,664)
Total unrecognized tax benefits, end of the year $ 44,274 $ 43,097 $ 45,086
v3.24.0.1
Income Taxes - Summary of Unrecognized Tax Benefits (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Income Tax [Line Items]      
Tax positions, that if recognized, would decrease our effective tax rate $ 28,762 $ 28,246 $ 26,300
Unrecognized tax benefit interest expense/(benefit) recognized 452 (139) (535)
Unrecognized tax benefit interest accrued 1,633 1,181 1,320
Arizona Public Service Company      
Income Tax [Line Items]      
Tax positions, that if recognized, would decrease our effective tax rate 28,762 28,246 26,300
Unrecognized tax benefit interest expense/(benefit) recognized 452 (139) (535)
Unrecognized tax benefit interest accrued $ 1,633 $ 1,181 $ 1,320
v3.24.0.1
Income Taxes - Components of Income Tax Expense (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Current:      
Federal $ 21,272 $ 35,617 $ (5,041)
State 2,854 1,950 2,458
Total current 24,126 37,567 (2,583)
Deferred:      
Federal 37,273 23,693 95,327
State 15,513 13,567 17,342
Total deferred 52,786 37,260 112,669
Income tax expense/(benefit) 76,912 74,827 110,086
Arizona Public Service Company      
Current:      
Federal 26,405 103,349 1,514
State 1,027 161 (11)
Total current 27,432 103,510 1,503
Deferred:      
Federal 44,922 (31,860) 101,175
State 21,830 19,150 22,875
Total deferred 66,752 (12,710) 124,050
Income tax expense/(benefit) $ 94,184 $ 90,800 $ 125,553
v3.24.0.1
Income Taxes - Effective Tax Rate Reconciliation (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Income Tax Reconciliation Increases Reductions in Tax Expense [Abstract]      
Federal income tax expense at statutory rate $ 125,095 $ 120,887 $ 156,666
State income tax net of federal income tax benefit 18,024 17,740 22,656
State income tax credits net of federal income tax benefit (3,513) (5,482) (7,015)
Net operating loss carryback tax benefit 0 0 (5,915)
Excess deferred income taxes — Tax Cuts and Jobs Act (36,558) (36,241) (36,558)
Allowance for equity funds used during construction (Note 1) (5,964) (4,629) (4,180)
Palo Verde VIE noncontrolling interest (Note 17) (3,617) (3,617) (3,617)
Investment tax credit amortization (9,495) (5,608) (7,620)
Federal production tax credit (8,441) (3,146) (3,064)
Other federal income tax credits (3,453) (7,721) (3,912)
Other 4,834 2,644 2,645
Income tax expense/(benefit) 76,912 74,827 110,086
Arizona Public Service Company      
Income Tax Reconciliation Increases Reductions in Tax Expense [Abstract]      
Federal income tax expense at statutory rate 138,337 132,920 162,762
State income tax net of federal income tax benefit 19,832 19,000 23,339
State income tax credits net of federal income tax benefit (1,775) (3,744) (5,277)
Net operating loss carryback tax benefit 0 0 0
Excess deferred income taxes — Tax Cuts and Jobs Act (36,558) (36,241) (36,558)
Allowance for equity funds used during construction (Note 1) (5,964) (4,629) (4,180)
Palo Verde VIE noncontrolling interest (Note 17) (3,617) (3,617) (3,617)
Investment tax credit amortization (9,495) (5,608) (7,620)
Federal production tax credit (5,460) 0 0
Other federal income tax credits (2,803) (7,721) (3,912)
Other 1,687 440 616
Income tax expense/(benefit) $ 94,184 $ 90,800 $ 125,553
v3.24.0.1
Income Taxes - Components of Deferred Income Tax Liability (Details) - USD ($)
$ in Thousands
Dec. 31, 2023
Dec. 31, 2022
DEFERRED TAX ASSETS    
Risk management activities $ 31,411 $ 8,826
Regulatory liabilities:    
Excess deferred income taxes — Tax Cuts and Jobs Act 283,161 295,014
Asset retirement obligation and removal costs 113,312 107,104
Unamortized investment tax credits 68,521 48,035
Other postretirement benefits 56,070 66,893
Other 39,857 62,915
Operating lease liabilities 316,067 184,030
Pension liabilities 33,294 33,674
Coal reclamation liabilities 45,505 44,312
Renewable energy incentives 17,261 19,948
Credit and loss carryforwards 43,940 37,647
Other 77,865 72,605
Total deferred tax assets 1,126,264 981,003
DEFERRED TAX LIABILITIES    
Plant-related (2,572,495) (2,518,164)
Risk management activities (1,682) (32,648)
Pension and other postretirement assets (78,853) (96,845)
Other special use funds (56,550) (57,572)
Operating lease right-of-use assets (316,067) (184,030)
Regulatory assets:    
Allowance for equity funds used during construction (46,754) (44,405)
Deferred fuel and purchased power (149,078) (114,232)
Pension benefits (172,239) (157,629)
Retired power plant costs (20,659) (24,397)
Other (92,260) (103,023)
Other (36,107) (32,479)
Total deferred tax liabilities (3,542,744) (3,365,424)
Deferred income taxes — net (2,416,480) (2,384,421)
Arizona Public Service Company    
DEFERRED TAX ASSETS    
Risk management activities 31,411 8,826
Regulatory liabilities:    
Excess deferred income taxes — Tax Cuts and Jobs Act 283,161 295,014
Asset retirement obligation and removal costs 113,312 107,104
Unamortized investment tax credits 68,521 48,035
Other postretirement benefits 56,070 66,893
Other 39,857 62,915
Operating lease liabilities 315,670 182,663
Pension liabilities 29,918 30,436
Coal reclamation liabilities 45,505 44,312
Renewable energy incentives 17,261 19,948
Credit and loss carryforwards 3,031 13,654
Other 77,865 72,605
Total deferred tax assets 1,081,582 952,405
DEFERRED TAX LIABILITIES    
Plant-related (2,572,495) (2,518,164)
Risk management activities (1,682) (32,648)
Pension and other postretirement assets (78,297) (96,196)
Other special use funds (56,550) (57,572)
Operating lease right-of-use assets (315,670) (182,663)
Regulatory assets:    
Allowance for equity funds used during construction (46,754) (44,405)
Deferred fuel and purchased power (149,078) (114,232)
Pension benefits (172,239) (157,629)
Retired power plant costs (20,659) (24,397)
Other (92,260) (103,023)
Other (7,595) (7,123)
Total deferred tax liabilities (3,513,279) (3,338,052)
Deferred income taxes — net $ (2,431,697) $ (2,385,647)
v3.24.0.1
Lines of Credit and Short-Term Borrowings - Schedule of Credit Facilities (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Pinnacle West    
Lines of Credit and Short-Term Borrowings    
Commitment fees (as a percent) 0.17% 0.175%
Arizona Public Service Company    
Lines of Credit and Short-Term Borrowings    
Commitment fees (as a percent) 0.12% 0.125%
Commercial paper    
Lines of Credit and Short-Term Borrowings    
Commitments under Credit Facilities $ 1,450,000 $ 1,200,000
Outstanding short-term borrowings (609,500) (340,720)
Amount of Credit Facilities Available 840,500 859,280
Commercial paper | Pinnacle West    
Lines of Credit and Short-Term Borrowings    
Commitments under Credit Facilities 200,000 200,000
Outstanding short-term borrowings (76,650) (15,720)
Amount of Credit Facilities Available 123,350 184,280
Commercial paper | Arizona Public Service Company    
Lines of Credit and Short-Term Borrowings    
Commitments under Credit Facilities 1,250,000 1,000,000
Outstanding short-term borrowings (532,850) (325,000)
Amount of Credit Facilities Available $ 717,150 $ 675,000
v3.24.0.1
Lines of Credit and Short-Term Borrowings - Additional Information (Details)
Feb. 09, 2024
USD ($)
Dec. 12, 2023
USD ($)
Dec. 31, 2023
USD ($)
Dec. 30, 2023
Apr. 10, 2023
USD ($)
creditFacility
Apr. 09, 2023
USD ($)
Dec. 31, 2022
USD ($)
Dec. 17, 2020
USD ($)
Arizona Public Service Company | ACC                
Debt Provisions                
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               $ 500,000,000
Term Loan | Arizona Public Service Company                
Lines of Credit and Short-Term Borrowings                
Notes issued   $ 350,000,000            
Debt instrument term   364 days            
Term Loan | Arizona Public Service Company | Subsequent Event                
Lines of Credit and Short-Term Borrowings                
Loan amount drawn $ 350,000,000              
Term Loan | Arizona Public Service Company | SOFR                
Lines of Credit and Short-Term Borrowings                
Debt instrument, basis spread on variable rate   1.00%            
Revolving credit facility | Revolving credit facility maturing May 2026 | Arizona Public Service Company                
Lines of Credit and Short-Term Borrowings                
Commitments under Credit Facilities         $ 500,000,000      
Number of credit facilities | creditFacility         2      
Revolving credit facility | Revolving credit facility maturing May 2026, facility two | Arizona Public Service Company                
Lines of Credit and Short-Term Borrowings                
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders         $ 400,000,000      
Revolving credit facility | Revolving credit facility maturing May 2026, facility one | Arizona Public Service Company                
Lines of Credit and Short-Term Borrowings                
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders         400,000,000      
Revolving credit facility | Revolving credit facility maturing in 2022 and 2023 | Arizona Public Service Company                
Lines of Credit and Short-Term Borrowings                
Long-term line of credit     $ 0          
Debt, weighted average interest rate       5.46%        
Revolving credit facility | Revolving Credit Facility Maturing April 2028 | Arizona Public Service Company                
Lines of Credit and Short-Term Borrowings                
Commitments under Credit Facilities         1,250,000,000      
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders         1,650,000,000      
Letter of Credit | Arizona Public Service Company                
Lines of Credit and Short-Term Borrowings                
Outstanding letters of credit     27,000,000          
Letter of Credit | Revolving Credit Facility Maturing April 2028 | Arizona Public Service Company                
Lines of Credit and Short-Term Borrowings                
Outstanding letters of credit     0          
Commercial paper                
Lines of Credit and Short-Term Borrowings                
Commitments under Credit Facilities     1,450,000,000       $ 1,200,000,000  
Long-term line of credit     609,500,000       340,720,000  
Commercial paper | Arizona Public Service Company                
Lines of Credit and Short-Term Borrowings                
Commitments under Credit Facilities     1,250,000,000       1,000,000,000  
Long-term line of credit     532,850,000       325,000,000  
Maximum commercial paper support available under credit facility         1,000,000,000 $ 750,000,000    
Commercial paper | Revolving Credit Facility Maturing April 2028 | Arizona Public Service Company                
Lines of Credit and Short-Term Borrowings                
Commercial paper     533,000,000          
Pinnacle West | Revolving credit facility | Revolving credit facility maturing May 2026                
Lines of Credit and Short-Term Borrowings                
Commitments under Credit Facilities         200,000,000      
Pinnacle West | Revolving credit facility | Revolving Credit Facility Maturing April 2028                
Lines of Credit and Short-Term Borrowings                
Commitments under Credit Facilities         200,000,000      
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders         $ 300,000,000      
Long-term line of credit     0          
Pinnacle West | Letter of Credit | Revolving Credit Facility Maturing April 2028                
Lines of Credit and Short-Term Borrowings                
Outstanding letters of credit     0          
Pinnacle West | Commercial paper                
Lines of Credit and Short-Term Borrowings                
Commitments under Credit Facilities     200,000,000       200,000,000  
Long-term line of credit     76,650,000       $ 15,720,000  
Pinnacle West | Commercial paper | Revolving Credit Facility Maturing April 2028                
Lines of Credit and Short-Term Borrowings                
Commercial paper     $ 77,000,000          
Debt, weighted average interest rate     5.47%          
v3.24.0.1
Long-Term Debt and Liquidity Matters - Components of Long-Term Debt (Details) - USD ($)
$ in Thousands
Dec. 31, 2023
Dec. 31, 2022
Long-Term Debt and Liquidity Matters [Line Items]    
Total long-term debt $ 8,415,622 $ 7,791,971
Long-term debt less current maturities (Note 6) 7,540,622 7,741,286
Pinnacle West    
Long-Term Debt and Liquidity Matters [Line Items]    
Gross long-term debt 8,468,975  
Unamortized discount (15) (25)
Unamortized debt issuance cost (1,254) (2,083)
Total long-term debt 1,123,731 947,892
Less current maturities 625,000 0
Total long-term debt less current maturities 498,731 947,892
Long-term debt less current maturities (Note 6) 498,731 947,892
Arizona Public Service Company    
Long-Term Debt and Liquidity Matters [Line Items]    
Gross long-term debt 7,343,975  
Unamortized discount (14,197) (14,548)
Unamortized premium 11,162 12,368
Unamortized debt issuance cost (49,049) (48,266)
Total long-term debt 7,291,891 6,793,529
Less current maturities 250,000 0
Total long-term debt less current maturities 7,041,891 6,793,529
Long-term debt less current maturities (Note 6) 7,041,891 6,793,529
Bright Canyon Energy Corporation    
Long-Term Debt and Liquidity Matters [Line Items]    
Los Alamitos equity bridge loan 0 27,575
Los Alamitos construction facility 0 23,110
Unamortized debt issuance cost 0 (135)
Total long-term debt 0 50,550
Less current maturities 0 50,685
Total long-term debt less current maturities 0 (135)
Pollution Control Bonds - Variable | Arizona Public Service Company    
Long-Term Debt and Liquidity Matters [Line Items]    
Gross long-term debt $ 163,975 $ 163,975
Weighted-average interest rate (as a percent) 4.11% 3.96%
Total Pollution Control Bonds | Arizona Public Service Company    
Long-Term Debt and Liquidity Matters [Line Items]    
Gross long-term debt $ 163,975 $ 163,975
Senior Unsecured Notes | Pinnacle West    
Long-Term Debt and Liquidity Matters [Line Items]    
Gross long-term debt $ 500,000 500,000
Interest rate (as a percent) 1.30%  
Senior Unsecured Notes | Arizona Public Service Company    
Long-Term Debt and Liquidity Matters [Line Items]    
Gross long-term debt $ 7,180,000 6,680,000
Senior Unsecured Notes | Arizona Public Service Company | Minimum    
Long-Term Debt and Liquidity Matters [Line Items]    
Interest rate (as a percent) 2.20%  
Senior Unsecured Notes | Arizona Public Service Company | Maximum    
Long-Term Debt and Liquidity Matters [Line Items]    
Interest rate (as a percent) 6.88%  
Term Loan | Pinnacle West    
Long-Term Debt and Liquidity Matters [Line Items]    
Term loans $ 625,000 $ 450,000
Term Loan | Arizona Public Service Company    
Long-Term Debt and Liquidity Matters [Line Items]    
Weighted-average interest rate (as a percent) 6.20% 5.10%
v3.24.0.1
Long-Term Debt and Liquidity Matters - Future Principal Payments (Details)
$ in Thousands
Dec. 31, 2023
USD ($)
Arizona Public Service Company  
Principal payments due on long-term debt  
2024 $ 250,000
2025 300,000
2026 250,000
2027 300,000
2028 0
Thereafter 6,243,975
Total 7,343,975
Pinnacle West  
Principal payments due on long-term debt  
2024 875,000
2025 800,000
2026 250,000
2027 300,000
2028 0
Thereafter 6,243,975
Total $ 8,468,975
v3.24.0.1
Long-Term Debt and Liquidity Matters - Fair Value of Long-Term Debt (Details) - USD ($)
$ in Thousands
Dec. 31, 2023
Dec. 31, 2022
Estimated fair value of long-term debt, including current maturities    
Carrying Amount $ 8,415,622 $ 7,791,971
Fair Value 7,555,653 6,585,701
Arizona Public Service Company    
Estimated fair value of long-term debt, including current maturities    
Carrying Amount 7,291,891 6,793,529
Fair Value 6,459,718 5,629,491
Bright Canyon Energy Corporation    
Estimated fair value of long-term debt, including current maturities    
Carrying Amount 0 50,550
Fair Value 0 50,685
Pinnacle West    
Estimated fair value of long-term debt, including current maturities    
Carrying Amount 1,123,731 947,892
Fair Value $ 1,095,935 $ 905,525
v3.24.0.1
Long-Term Debt and Liquidity Matters - Additional Information (Details)
$ in Millions
 12 Months Ended
Jun. 30, 2023
USD ($)
Jan. 06, 2023
USD ($)
Feb. 11, 2022
USD ($)
MW
Dec. 31, 2023
USD ($)
Oct. 27, 2023
USD ($)
Dec. 16, 2022
USD ($)
Dec. 17, 2020
USD ($)
Dec. 16, 2020
USD ($)
Maximum                
Debt Provisions                
Ratio of consolidated debt to consolidated capitalization (as a percent)       65.00%        
Arizona Public Service Company                
Long-Term Debt and Liquidity Matters [Line Items]                
Annual amount of approved equity infusions       $ 150        
Increased in equity contributions         $ 500      
Equity infusion from Pinnacle West   $ 150            
Debt Provisions                
Actual ratio of consolidated debt to total consolidated capitalization required to be maintained as per the debt covenant (as a percent)       52.00%        
Arizona Public Service Company | ACC                
Debt Provisions                
Long term debt authorization             $ 8,000 $ 7,500
Bright Canyon Energy Corporation                
Debt Provisions                
Solar plant capacity (in mw) | MW     31          
Battery storage capacity (in mwh) | MW     20          
5.55% Unsecured Senior Notes Due Aug 2033 | Arizona Public Service Company                
Long-Term Debt and Liquidity Matters [Line Items]                
Interest rate (as a percent) 5.55%              
Debt Provisions                
Notes Issued $ 500              
Term Loan | Non-Recourse Construction Term Loan Facility | Bright Canyon Energy Corporation                
Long-Term Debt and Liquidity Matters [Line Items]                
Notes issued     $ 36          
Pinnacle West                
Debt Provisions                
Actual ratio of consolidated debt to total consolidated capitalization required to be maintained as per the debt covenant (as a percent)       60.00%        
Pinnacle West | Term Loan                
Long-Term Debt and Liquidity Matters [Line Items]                
Notes issued           $ 175    
v3.24.0.1
Retirement Plans and Other Postretirement Benefits - Additional Information (Details) - USD ($)
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Defined Benefit Plan Disclosure [Line Items]      
Ultimate healthcare cost trend rate (pre-65 participants) 4.75% 4.75%  
Initial and ultimate healthcare cost trend rate (post-65 participants) 2.00% 2.00%  
Funded percentage (more than) 100.00% 100.00%  
Partnership funding commitments, contribution amount (up to) $ 50,000,000    
Partnership funding commitments, funded amount $ 38,000,000    
Other Benefits      
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 $ 23,000,000 $ 26,000,000 $ 24,000,000
Pension Benefits      
Defined Benefit Plan Disclosure [Line Items]      
Expected long-term return on plan assets for next fiscal year (as a percent) 6.90%    
Employer contributions     100,000,000
Minimum contributions under MAP-21 $ 0    
Pinnacle West      
Defined Benefit Plan Disclosure [Line Items]      
Expenses recorded for the defined contribution savings plan $ 12,000,000 $ 12,000,000 $ 12,000,000
Arizona Public Service Company      
Defined Benefit Plan Disclosure [Line Items]      
APS's employees share of total cost of the plans (as a percent) 99.00%    
v3.24.0.1
Retirement Plans and Other Postretirement Benefits - Net Periodic Benefit Costs and Portion including Portion Charged to Expense (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Net periodic benefit costs and the portion of these costs charged to expense      
Portion of cost/(benefit) charged to expense $ (40,648) $ (98,487) $ (112,541)
Pension Benefits      
Net periodic benefit costs and the portion of these costs charged to expense      
Service cost-benefits earned during the period 39,461 55,473 61,236
Interest cost on benefit obligation 153,561 107,492 98,566
Expected return on plan assets (182,938) (185,775) (202,628)
Prior service credit (a) 0 0 0
Net actuarial (gain)/loss 38,420 17,515 15,948
Net periodic benefit cost/(benefit) 48,504 (5,295) (26,878)
Portion of cost/(benefit) charged to expense 27,029 (16,431) (32,743)
Other Benefits      
Net periodic benefit costs and the portion of these costs charged to expense      
Service cost-benefits earned during the period 8,567 16,470 17,796
Interest cost on benefit obligation 22,509 17,491 16,513
Expected return on plan assets (43,486) (46,042) (41,444)
Prior service credit (a) (37,789) (37,789) (37,705)
Net actuarial (gain)/loss (9,614) (12,835) (10,093)
Net periodic benefit cost/(benefit) (59,813) (62,705) (54,933)
Portion of cost/(benefit) charged to expense $ (43,408) $ (45,042) $ (38,657)
v3.24.0.1
Retirement Plans and Other Postretirement Benefits - Changes Benefit Obligations and Funded Status (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Pension Benefits      
Change in Benefit Obligation      
Benefit obligation at the beginning of the period $ 2,809,529 $ 3,716,824  
Service cost 39,461 55,473 $ 61,236
Interest cost 153,561 107,492 98,566
Benefit payments (210,737) (212,565)  
Actuarial (gain) loss 116,249 (857,695)  
Benefit obligation at the end of the period 2,908,063 2,809,529 3,716,824
Change in Plan Assets      
Balance at the beginning of the period 2,829,485 3,812,041  
Actual return/(loss) on plan assets 199,098 (787,874)  
Benefit payments (193,034) (194,682)  
Balance at the end of the period 2,835,549 2,829,485 3,812,041
Funded/(Underfunded) Status at the end of the period (72,514) 19,956  
Other Benefits      
Change in Benefit Obligation      
Benefit obligation at the beginning of the period 409,461 591,841  
Service cost 8,567 16,470 17,796
Interest cost 22,509 17,491 16,513
Benefit payments (30,784) (30,913)  
Actuarial (gain) loss 20,681 (185,428)  
Benefit obligation at the end of the period 430,434 409,461 591,841
Change in Plan Assets      
Balance at the beginning of the period 652,287 872,435  
Actual return/(loss) on plan assets 67,317 (193,807)  
Benefit payments (23,110) (26,341)  
Balance at the end of the period 696,494 652,287 $ 872,435
Funded/(Underfunded) Status at the end of the period $ 266,060 $ 242,826  
v3.24.0.1
Retirement Plans and Other Postretirement Benefits - Projected Benefit Obligation for Pension Plans (Details) - Pension Benefits - USD ($)
$ in Thousands
Dec. 31, 2023
Dec. 31, 2022
Projected benefit obligation and the accumulated benefit obligation for pension plans with an accumulated obligation in excess of plan assets    
Accumulated benefit obligation $ 123,701 $ 126,759
Fair value of plan assets 0 0
Projected benefit obligation 129,891 133,818
Fair value of plan assets $ 0 $ 0
v3.24.0.1
Retirement Plans and Other Postretirement Benefits - Amounts Recognized on the Consolidated Balance Sheets (Details) - USD ($)
$ in Thousands
Dec. 31, 2023
Dec. 31, 2022
Amounts recognized on the Consolidated Balance Sheets    
Noncurrent asset $ 323,438 $ 396,599
Pension Benefits    
Amounts recognized on the Consolidated Balance Sheets    
Noncurrent asset 57,378 153,773
Current liability (17,190) (17,531)
Noncurrent liability (112,702) (116,286)
Net amount recognized (funded status) (72,514) 19,956
Other Benefits    
Amounts recognized on the Consolidated Balance Sheets    
Noncurrent asset 266,060 242,826
Current liability 0 0
Noncurrent liability 0 0
Net amount recognized (funded status) $ 266,060 $ 242,826
v3.24.0.1
Retirement Plans and Other Postretirement Benefits - Impact to Accumulated Other Comprehensive Loss (Details) - USD ($)
$ in Thousands
Dec. 31, 2023
Dec. 31, 2022
Pension Benefits    
Details related to accumulated other comprehensive loss    
Net actuarial loss (gain) $ 743,003 $ 681,335
Prior service credit 0 0
APS’s portion recorded as a regulatory (asset) liability (696,476) (637,656)
Income tax expense (benefit) (11,506) (10,797)
Accumulated other comprehensive loss (gain) 35,021 32,882
Other Benefits    
Details related to accumulated other comprehensive loss    
Net actuarial loss (gain) (188,630) (195,095)
Prior service credit (39,054) (76,843)
APS’s portion recorded as a regulatory (asset) liability 226,726 270,604
Income tax expense (benefit) 691 784
Accumulated other comprehensive loss (gain) $ (267) $ (550)
v3.24.0.1
Retirement Plans and Other Postretirement Benefits - Weighted-Average Assumptions for Pensions and Other Benefits (Details)
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Weighted-average assumptions used to determine benefit obligations      
Rate of compensation increase 4.52% 4.57%  
Initial healthcare cost trend rate (pre-65 participants) 6.25% 6.50%  
Ultimate healthcare cost trend rate (pre-65 participants) 4.75% 4.75%  
Number of years to ultimate trend rate (pre-65 participants) 5 years 6 years  
Initial and ultimate healthcare cost trend rate (post-65 participants) 2.00% 2.00%  
Interest crediting rate – cash balance pension plans 4.54% 4.50%  
Weighted-average assumptions used to determine net periodic benefit costs      
Initial healthcare cost trend rate (pre-65 participants) 6.50% 6.00% 6.50%
Ultimate healthcare cost trend rate (pre-65 participants) 4.75% 4.75% 4.75%
Number of years to ultimate trend rate (pre-65 participants) 5 years 3 years 4 years
Initial and ultimate healthcare cost trend rate (post-65 participants) 2.00% 2.00% 2.00%
Interest crediting rate – cash balance pension plans 4.50% 4.50% 4.50%
Pension Benefits      
Weighted-average assumptions used to determine benefit obligations      
Discount rate (as a percent) 5.21% 5.56%  
Weighted-average assumptions used to determine net periodic benefit costs      
Discount rate (as a percent) 5.56% 2.92% 2.53%
Rate of compensation increase 4.57% 4.00% 4.00%
Expected long-term return on plan assets (as a percent) 6.70% 5.00% 5.30%
Other Benefits      
Weighted-average assumptions used to determine benefit obligations      
Discount rate (as a percent) 5.23% 5.58%  
Weighted-average assumptions used to determine net periodic benefit costs      
Discount rate (as a percent) 5.58% 2.98% 2.63%
Expected long-term return on plan assets (as a percent) 6.80% 5.35% 4.90%
v3.24.0.1
Retirement Plans and Other Postretirement Benefits - Asset Allocation (Details)
Dec. 31, 2023
Pension Benefits  
Defined Benefit Plan Disclosure [Line Items]  
Target Allocation 100.00%
Actual Allocation 100.00%
Pension Benefits | Long-term fixed income assets  
Defined Benefit Plan Disclosure [Line Items]  
Target Allocation 80.00%
Actual Allocation 78.00%
Pension Benefits | Return-seeking assets  
Defined Benefit Plan Disclosure [Line Items]  
Target Allocation 20.00%
Actual Allocation 22.00%
Target Allocation 20.00%
Pension Benefits | Equities in US and other developed markets  
Defined Benefit Plan Disclosure [Line Items]  
Target Allocation 12.00%
Pension Benefits | Equities in emerging markets  
Defined Benefit Plan Disclosure [Line Items]  
Target Allocation 4.00%
Pension Benefits | Alternative investments  
Defined Benefit Plan Disclosure [Line Items]  
Target Allocation 4.00%
Other Benefits  
Defined Benefit Plan Disclosure [Line Items]  
Actual Allocation 100.00%
Other Benefits | Long-term fixed income assets  
Defined Benefit Plan Disclosure [Line Items]  
Actual Allocation 62.00%
Other Benefits | Return-seeking assets  
Defined Benefit Plan Disclosure [Line Items]  
Actual Allocation 38.00%
v3.24.0.1
Retirement Plans and Other Postretirement Benefits - Fair Value of Pinnacle West's Pension Plan (Details) - USD ($)
$ in Thousands
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Pension Benefits      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Other $ 399,298 $ 429,391  
Fair value of plan assets 2,835,549 2,829,485 $ 3,812,041
Pension Benefits | 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 885,721 893,285  
Pension Benefits | 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 1,550,530 1,506,809  
Other Benefits      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Other 107,201 106,356  
Fair value of plan assets 696,494 652,287 $ 872,435
Other Benefits | 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 391,019 371,731  
Other Benefits | 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 198,274 174,200  
Cash and cash equivalents | Pension Benefits      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Other   0  
Fair value of plan assets   1,252  
Cash and cash equivalents | Pension Benefits | 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   1,252  
Cash and cash equivalents | Pension Benefits | 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  
Cash and cash equivalents | Other Benefits      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Other   0  
Fair value of plan assets   204  
Cash and cash equivalents | Other Benefits | 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   204  
Cash and cash equivalents | Other Benefits | 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  
Corporate | Pension Benefits      
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 1,415,346 1,374,810  
Corporate | Pension Benefits | 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 Benefits | 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 1,415,346 1,374,810  
Corporate | Other Benefits      
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 189,902 166,879  
Corporate | Other Benefits | 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 | 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 189,902 166,879  
U.S. Treasury | Pension Benefits      
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 622,273 635,245  
U.S. Treasury | Pension Benefits | 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 622,273 635,245  
U.S. Treasury | Pension Benefits | 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      
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 207,665 221,936  
U.S. Treasury | Other Benefits | 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 207,665 221,936  
U.S. Treasury | Other Benefits | 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 fixed income | Pension Benefits      
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 135,184 131,999  
Other fixed income | Pension Benefits | 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 fixed income | Pension Benefits | 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 135,184 131,999  
Other fixed income | Other Benefits      
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 8,372 7,321  
Other fixed income | Other Benefits | 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 fixed income | Other Benefits | 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 8,372 7,321  
Common stock equities | Pension Benefits      
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 150,657 155,231  
Common stock equities | Pension Benefits | 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 150,657 155,231  
Common stock equities | Pension Benefits | 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      
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 139,952 127,493  
Common stock equities | Other Benefits | 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 139,952 127,493  
Common stock equities | Other Benefits | 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 Benefits      
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 112,791 101,557  
Mutual funds | Pension Benefits | 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 112,791 101,557  
Mutual funds | Pension Benefits | 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      
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 22,256 18,824  
Mutual funds | Other Benefits | 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 22,256 18,824  
Mutual funds | Other Benefits | 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 Benefits      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Other 192,945 181,912  
Fair value of plan assets 192,945 181,912  
Equities | Pension Benefits | 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 Benefits | 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      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Other 81,724 73,956  
Fair value of plan assets 81,724 73,956  
Equities | Other Benefits | 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 | 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 Benefits      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Other 140,613 174,228  
Fair value of plan assets 140,613 174,228  
Real estate | Pension Benefits | 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 Benefits | 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      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Other 20,001 23,541  
Fair value of plan assets 20,001 23,541  
Real estate | Other Benefits | 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 | 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  
Partnerships | Pension Benefits      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Other   13,359  
Fair value of plan assets   13,359  
Partnerships | Pension Benefits | 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  
Partnerships | Pension Benefits | 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  
Short-term investments and other | Pension Benefits      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Other 65,740 59,892  
Fair value of plan assets 65,740 59,892  
Short-term investments and other | Pension Benefits | 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  
Short-term investments and other | Pension Benefits | 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  
Short-term investments and other | Other Benefits      
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category      
Other 5,476 8,859  
Fair value of plan assets 26,622 12,133  
Short-term investments and other | Other Benefits | 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 21,146 3,274  
Short-term investments and other | Other Benefits | 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  
v3.24.0.1
Retirement Plans and Other Postretirement Benefits - Estimated Future Benefit Payments (Details)
$ in Thousands
Dec. 31, 2023
USD ($)
Pension Benefits  
Estimated Future Benefit Payments  
2024 $ 244,772
2025 226,748
2026 229,322
2027 226,906
2028 229,397
Years 2029-2033 1,136,944
Other Benefits  
Estimated Future Benefit Payments  
2024 31,024
2025 30,446
2026 30,396
2027 30,024
2028 29,741
Years 2029-2033 $ 149,312
v3.24.0.1
Leases - Additional information (Details)
$ in Billions
Dec. 31, 2023
USD ($)
lease
Jan. 31, 2023
agreement
Leases [Abstract]    
Number of lease agreements, sell and lease back | lease 3  
Number of purchase power operating lease agreements | agreement   2
Lease not yet commenced | $ $ 7.1  
v3.24.0.1
Leases - Lease costs (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Operating Leased Assets [Line Items]      
Operating Lease Cost $ 145,890 $ 122,062 $ 124,260
Variable lease cost 135,007 122,040 118,969
Short-term Lease Cost 21,530 9,928 3,872
Purchased Power & Energy Storage Lease Contracts      
Operating Leased Assets [Line Items]      
Operating Lease Cost 126,655 104,001 105,762
Land, Property & Equipment Leases      
Operating Leased Assets [Line Items]      
Operating Lease Cost 19,235 18,061 18,498
Total Lease Cost $ 302,427 $ 254,030 $ 247,101
v3.24.0.1
Leases - Maturity of our operating lease liabilities (Details)
$ in Thousands
Dec. 31, 2023
USD ($)
Lessee, Lease, Description [Line Items]  
2024 $ 122,951
2025 137,116
2026 148,518
2027 172,344
2028 173,811
Thereafter 899,903
Total lease commitments 1,654,643
Less imputed interest 376,571
Total lease liabilities 1,278,072
Purchased Power & Energy Storage Lease Contracts  
Lessee, Lease, Description [Line Items]  
2024 108,201
2025 124,968
2026 138,692
2027 164,613
2028 168,410
Thereafter 835,813
Total lease commitments 1,540,697
Less imputed interest 334,693
Total lease liabilities 1,206,004
Land, Property & Equipment Leases  
Lessee, Lease, Description [Line Items]  
2024 14,750
2025 12,148
2026 9,826
2027 7,731
2028 5,401
Thereafter 64,090
Total lease commitments 113,946
Less imputed interest 41,878
Total lease liabilities $ 72,068
v3.24.0.1
Leases - Other additional information related to operating lease liabilities (Details)
$ in Thousands
 12 Months Ended
Dec. 31, 2023
USD ($)
Dec. 31, 2022
USD ($)
Dec. 31, 2021
USD ($)
Jan. 31, 2023
agreement
Leases [Abstract]        
Cash paid for amounts included in the measurement of lease liabilities — operating cash flows: $ 123,472 $ 118,463 $ 116,661  
Right-of-use operating lease assets obtained in exchange for operating lease liabilities $ 602,301 $ 16,990 $ 500,582  
Weighted average remaining lease term 10 years 7 years    
Weighted average discount rate 4.53% 2.21%    
Number of purchase power operating lease agreements | agreement       2
v3.24.0.1
Jointly-Owned Facilities (Details) - Arizona Public Service Company
$ in Thousands
Dec. 31, 2023
USD ($)
Palo Verde Units 1 and 3  
Interests in jointly-owned facilities  
Percent Owned 29.10%
Plant in Service $ 1,990,237
Accumulated Depreciation 1,087,614
Construction Work in Progress $ 21,442
Palo Verde Unit 2  
Interests in jointly-owned facilities  
Percent Owned 16.80%
Plant in Service $ 681,483
Accumulated Depreciation 387,485
Construction Work in Progress $ 12,700
Palo Verde Common  
Interests in jointly-owned facilities  
Percent Owned 28.00%
Plant in Service $ 857,807
Accumulated Depreciation 356,962
Construction Work in Progress 65,911
Palo Verde Sale Leaseback  
Interests in jointly-owned facilities  
Plant in Service 351,050
Accumulated Depreciation 264,624
Construction Work in Progress $ 0
Four Corners Generating Station  
Interests in jointly-owned facilities  
Percent Owned 63.00%
Plant in Service $ 1,748,436
Accumulated Depreciation 659,780
Construction Work in Progress $ 29,586
Cholla Common Facilities  
Interests in jointly-owned facilities  
Percent Owned 50.50%
Plant in Service $ 250,994
Accumulated Depreciation 167,357
Construction Work in Progress $ 7,487
ANPP 500kV System  
Interests in jointly-owned facilities  
Percent Owned 33.40%
Plant in Service $ 136,145
Accumulated Depreciation 58,252
Construction Work in Progress $ 4,801
Navajo Southern System  
Interests in jointly-owned facilities  
Percent Owned 25.20%
Plant in Service $ 87,185
Accumulated Depreciation 36,743
Construction Work in Progress $ 550
Palo Verde — Yuma 500kV System  
Interests in jointly-owned facilities  
Percent Owned 25.30%
Plant in Service $ 24,057
Accumulated Depreciation 7,912
Construction Work in Progress $ 432
Four Corners Switchyards  
Interests in jointly-owned facilities  
Percent Owned 57.50%
Plant in Service $ 84,279
Accumulated Depreciation 21,918
Construction Work in Progress $ 161
Phoenix — Mead System  
Interests in jointly-owned facilities  
Percent Owned 17.10%
Plant in Service $ 39,772
Accumulated Depreciation 20,679
Construction Work in Progress $ 257
Palo Verde — Rudd 500kV System  
Interests in jointly-owned facilities  
Percent Owned 50.00%
Plant in Service $ 95,736
Accumulated Depreciation 32,665
Construction Work in Progress $ 731
Morgan — Pinnacle Peak System  
Interests in jointly-owned facilities  
Percent Owned 63.20%
Plant in Service $ 117,080
Accumulated Depreciation 26,990
Construction Work in Progress $ 229
Round Valley System  
Interests in jointly-owned facilities  
Percent Owned 50.00%
Plant in Service $ 548
Accumulated Depreciation 205
Construction Work in Progress $ 0
Palo Verde — Morgan System  
Interests in jointly-owned facilities  
Percent Owned 87.50%
Plant in Service $ 268,629
Accumulated Depreciation 40,962
Construction Work in Progress $ 8,053
Hassayampa — North Gila System  
Interests in jointly-owned facilities  
Percent Owned 80.00%
Plant in Service $ 151,684
Accumulated Depreciation 24,618
Construction Work in Progress $ 0
Cholla 500kV Switchyard  
Interests in jointly-owned facilities  
Percent Owned 85.70%
Plant in Service $ 8,445
Accumulated Depreciation 2,760
Construction Work in Progress $ 0
Saguaro 500kV Switchyard  
Interests in jointly-owned facilities  
Percent Owned 60.00%
Plant in Service $ 21,627
Accumulated Depreciation 14,060
Construction Work in Progress $ 17
Kyrene — Knox System  
Interests in jointly-owned facilities  
Percent Owned 50.00%
Plant in Service $ 578
Accumulated Depreciation 340
Construction Work in Progress $ 0
Agua Fria Switchyard  
Interests in jointly-owned facilities  
Percent Owned 10.00%
Plant in Service $ 0
Accumulated Depreciation 0
Construction Work in Progress $ 77
v3.24.0.1
Commitments and Contingencies - Additional Information (Details)
$ in Thousands
 1 Months Ended 12 Months Ended 132 Months Ended
Jan. 01, 2024
USD ($)
trust
Oct. 31, 2023
claim
Jan. 17, 2023
USD ($)
Sep. 30, 2022
USD ($)
Nov. 02, 2021
USD ($)
Jul. 03, 2018
USD ($)
Jul. 06, 2016
Aug. 14, 2014
USD ($)
Feb. 29, 2024
USD ($)
Dec. 31, 2023
USD ($)
trust
MW
Dec. 31, 2022
USD ($)
Jun. 30, 2022
timePeriod
claim
Apr. 18, 2023
USD ($)
Schedule of Commitments and Contingencies [Line Items]                          
Coal mine reclamation                   $ 184,007 $ 179,255    
Non-recourse construction financing agreement                         $ 140,000
Financing agreement of sponsor equity                         $ 40,000
Production tax credit guarantees                   $ 31,000      
Kūpono Solar                          
Schedule of Commitments and Contingencies [Line Items]                          
Project plant capacity (in MW's) | MW                   42      
Asset purchase power agreement                   20 years      
Arizona Public Service Company                          
Schedule of Commitments and Contingencies [Line Items]                          
Number of VIE lessor trusts | trust                   3      
Amount of "all risk" (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde                   $ 2,800,000      
Request second-year energy price for exported energy                   22,400      
Collateral assurance based on rating triggers                   $ 62,600      
Period to provide collateral assurance based on rating triggers                   20 days      
2024                   $ 1,034,000      
2025                   1,190,000      
2026                   1,310,000      
2027                   1,284,000      
2028                   1,292,000      
Thereafter                   14,700,000      
Coal mine reclamation                   184,007 179,255    
Arizona Public Service Company | Subsequent Event                          
Schedule of Commitments and Contingencies [Line Items]                          
Maximum insurance against public liability per occurrence for a nuclear incident $ 16,300,000                        
Maximum available nuclear liability insurance 500,000                        
Remaining nuclear liability insurance through mandatory industry wide retrospective assessment program 15,800,000                        
Maximum assessment per reactor for each nuclear incident 165,900                        
Annual limit per incident with respect to maximum assessment $ 24,700                        
Number of VIE lessor trusts | trust 3                        
Maximum potential retrospective assessment per incident of APS $ 144,900                        
Annual payment limitation with respect to maximum potential retrospective assessment $ 21,600                        
Arizona Public Service Company | Surety Bonds Expiring in 2025                          
Schedule of Commitments and Contingencies [Line Items]                          
Surety bonds expiring, amount                   20,000      
Arizona Public Service Company | Letter of Credit                          
Schedule of Commitments and Contingencies [Line Items]                          
Outstanding letters of credit                   27,000      
Arizona Public Service Company | SCE | Four Corners Units 4 and 5                          
Schedule of Commitments and Contingencies [Line Items]                          
Disallowance of plant investments         $ 194,000                
Cost deferrals         $ 215,500                
Arizona Public Service Company | Contaminated Groundwater Wells                          
Schedule of Commitments and Contingencies [Line Items]                          
Costs related to investigation and study under Superfund site                   3,000      
Remedial investigation work     $ 1,700                    
Arizona Public Service Company | Contaminated Groundwater Wells | Pending Litigation                          
Schedule of Commitments and Contingencies [Line Items]                          
Settlement amount       $ 20,700                  
Arizona Public Service Company | Renewable Energy Credits                          
Schedule of Commitments and Contingencies [Line Items]                          
2024                   29,000      
2025                   27,000      
2026                   24,000      
2027                   20,000      
2028                   17,000      
Thereafter                   52,000      
Arizona Public Service Company | Coal Mine Reclamation Balance Sheet Obligations                          
Schedule of Commitments and Contingencies [Line Items]                          
Coal mine reclamation                   184,000 179,000    
Arizona Public Service Company | Coal Mine Reclamation Obligations                          
Schedule of Commitments and Contingencies [Line Items]                          
2024                   19,000      
2025                   20,000      
2026                   21,000      
2027                   22,000      
2028                   23,000      
Thereafter                   2,000      
4CA | Four Corners                          
Schedule of Commitments and Contingencies [Line Items]                          
Percentage share cost of control             7.00%            
NTEC | Four Corners                          
Schedule of Commitments and Contingencies [Line Items]                          
Option to purchase, ownership interest (as a percent)           7.00%              
Proceeds from operating and maintenance cost reimbursement           $ 70,000              
Asset purchase agreement, option to purchase, ownership interest, percentage           7.00%              
Bright Canyon Energy Corporation | Clear Creek Wind Farm                          
Schedule of Commitments and Contingencies [Line Items]                          
Equity method investments       $ 17,100             0    
Impairment of equity method investments                     $ 12,800    
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               $ 18,460   138,200      
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]                          
Settlement amount, awarded to company                 $ 18,390        
Arizona Public Service Company and Palo Verde Owners vs. United States Department of Energy - Spent Nuclear Fuel and Waste Disposal | Arizona Public Service Company                          
Schedule of Commitments and Contingencies [Line Items]                          
Gain contingency, new claims filed, number | claim   10                   9  
Gain contingency, number of settlement agreement time periods | timePeriod                       9  
Settlement amount, awarded to company               $ 5,400   $ 40,200      
v3.24.0.1
Commitments and Contingencies - Estimated Coal Take-or-pay Commitments and Actual Amount Purchased (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Fuel and Purchased Power Commitments and Purchase Obligations [Abstract]      
Total take-or-pay commitments $ 184,007 $ 179,255  
Arizona Public Service Company      
Fuel and Purchased Power Commitments and Purchase Obligations [Abstract]      
2024 1,034,000    
2025 1,190,000    
2026 1,310,000    
2027 1,284,000    
2028 1,292,000    
Thereafter 14,700,000    
Total take-or-pay commitments 184,007 179,255  
Arizona Public Service Company | Coal Take-or-Pay Commitments      
Fuel and Purchased Power Commitments and Purchase Obligations [Abstract]      
2024 208,694    
2025 229,111    
2026 221,122    
2027 200,256    
2028 205,237    
Thereafter 647,377    
Total take-or-pay commitments 1,700,000    
Present value of commitments 1,400,000    
Total purchases 255,219 305,502 $ 219,958
Arizona Public Service Company | Renewable Energy Credits      
Fuel and Purchased Power Commitments and Purchase Obligations [Abstract]      
2024 29,000    
2025 27,000    
2026 24,000    
2027 20,000    
2028 17,000    
Thereafter 52,000    
Arizona Public Service Company | Coal Mine Reclamation Obligations      
Fuel and Purchased Power Commitments and Purchase Obligations [Abstract]      
2024 19,000    
2025 20,000    
2026 21,000    
2027 22,000    
2028 23,000    
Thereafter 2,000    
Arizona Public Service Company | Coal Mine Reclamation Balance Sheet Obligations      
Fuel and Purchased Power Commitments and Purchase Obligations [Abstract]      
Total take-or-pay commitments $ 184,000 $ 179,000  
v3.24.0.1
Asset Retirement Obligations - Narrative (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Schedule of Asset Retirement Obligations [Line Items]    
Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation $ 17,980,157 $ 16,854,354
Arizona Public Service Company    
Schedule of Asset Retirement Obligations [Line Items]    
Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation 17,979,860 $ 16,800,254
Cholla | Arizona Public Service Company    
Schedule of Asset Retirement Obligations [Line Items]    
Increase (decrease) in asset retirement obligation 71,000  
Four Corners Coal-Fired Power Plant | Arizona Public Service Company    
Schedule of Asset Retirement Obligations [Line Items]    
Increase (decrease) in asset retirement obligation (7,000)  
Navajo Coal-Fired Power Plant | Arizona Public Service Company    
Schedule of Asset Retirement Obligations [Line Items]    
Increase (decrease) in asset retirement obligation 8,000  
Palo Verde | Arizona Public Service Company    
Schedule of Asset Retirement Obligations [Line Items]    
Increase (decrease) in asset retirement obligation 63,000  
Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation 59,000  
Decrease in regulatory liability $ 4,000  
v3.24.0.1
Asset Retirement Obligations - Roll-Forward (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Change in asset retirement obligations    
Asset retirement obligations at the beginning of year $ 797,762 $ 767,382
Changes attributable to:    
Accretion expense 44,269 41,240
Settlements (14,039) (10,860)
Estimated cash flow revisions 135,323 0
Newly incurred obligation 2,686 0
Asset retirement obligations at the end of year $ 966,001 $ 797,762
v3.24.0.1
Fair Value Measurements - Assets and Liabilities Measured on a Recurring Basis (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2022
Dec. 31, 2023
Fair Value Disclosures [Abstract]    
Derivative liability statement of financial position not disclosed flag interest rate derivative instruments  
ASSETS    
Cash equivalents   $ 10
Commodity contracts, assets $ 132,229  
Commodity contracts assets, other (21,163)  
Nuclear decommissioning trust 1,073,410 1,201,246
Nuclear decommissioning trust, other 476,409 408,849
Other special use fund 347,231 362,781
Other special use funds, other 963 2,196
Total assets 1,552,870 1,570,845
Total assets, other 456,209 409,356
LIABILITIES    
Derivative instruments, other 15,357  
Derivative instruments, total (42,446)  
Total liabilities (42,446)  
Total liabilities, other 15,357  
Commodity contracts    
ASSETS    
Commodity contracts, assets 132,098 6,808
Commodity contracts assets, other (21,163) (1,689)
LIABILITIES    
Derivative instruments, other 15,357 4,823
Derivative instruments, total (41,537) (123,888)
Interest rate swaps    
ASSETS    
Commodity contracts, assets 131  
Commodity contracts assets, other 0  
LIABILITIES    
Derivative instruments, other 0  
Derivative instruments, total (909)  
Equity securities    
ASSETS    
Nuclear decommissioning trust 18,485 10,297
Nuclear decommissioning trust, other 3,827 (767)
Other special use fund 67,937 43,187
Other special use funds, other 963 2,196
U.S. commingled equity funds    
ASSETS    
Nuclear decommissioning trust 472,582 409,616
U.S. Treasury debt    
ASSETS    
Nuclear decommissioning trust 211,923 319,734
Other special use fund 275,267 319,594
Corporate debt    
ASSETS    
Nuclear decommissioning trust 149,226 188,317
Mortgage-backed securities    
ASSETS    
Nuclear decommissioning trust 147,938 208,306
Municipal bonds    
ASSETS    
Nuclear decommissioning trust 64,881 59,323
Other special use fund 4,027 0
Other fixed income    
ASSETS    
Nuclear decommissioning trust 8,375 5,653
Level 1    
ASSETS    
Cash equivalents   10
Commodity contracts, assets 0  
Nuclear decommissioning trust 226,581 330,798
Other special use fund 342,241 360,585
Total assets 568,822 691,393
LIABILITIES    
Derivative instruments 0  
Total liabilities 0  
Level 1 | Commodity contracts    
ASSETS    
Commodity contracts, assets 0 0
LIABILITIES    
Derivative instruments 0 0
Level 1 | Interest rate swaps    
ASSETS    
Commodity contracts, assets 0  
LIABILITIES    
Derivative instruments 0  
Level 1 | Equity securities    
ASSETS    
Nuclear decommissioning trust 14,658 11,064
Other special use fund 66,974 40,991
Level 1 | U.S. commingled equity funds    
ASSETS    
Nuclear decommissioning trust 0 0
Level 1 | U.S. Treasury debt    
ASSETS    
Nuclear decommissioning trust 211,923 319,734
Other special use fund 275,267 319,594
Level 1 | Corporate debt    
ASSETS    
Nuclear decommissioning trust 0 0
Level 1 | Mortgage-backed securities    
ASSETS    
Nuclear decommissioning trust 0 0
Level 1 | Municipal bonds    
ASSETS    
Nuclear decommissioning trust 0 0
Other special use fund 0 0
Level 1 | Other fixed income    
ASSETS    
Nuclear decommissioning trust 0 0
Level 2    
ASSETS    
Cash equivalents   0
Commodity contracts, assets 127,260  
Nuclear decommissioning trust 370,420 461,599
Other special use fund 4,027 0
Total assets 501,707 463,480
LIABILITIES    
Derivative instruments (26,783)  
Total liabilities (26,783)  
Level 2 | Commodity contracts    
ASSETS    
Commodity contracts, assets 127,129 1,881
LIABILITIES    
Derivative instruments (25,874) (127,016)
Level 2 | Interest rate swaps    
ASSETS    
Commodity contracts, assets 131  
LIABILITIES    
Derivative instruments (909)  
Level 2 | Equity securities    
ASSETS    
Nuclear decommissioning trust 0 0
Other special use fund 0 0
Level 2 | U.S. commingled equity funds    
ASSETS    
Nuclear decommissioning trust 0 0
Level 2 | U.S. Treasury debt    
ASSETS    
Nuclear decommissioning trust 0 0
Other special use fund 0 0
Level 2 | Corporate debt    
ASSETS    
Nuclear decommissioning trust 149,226 188,317
Level 2 | Mortgage-backed securities    
ASSETS    
Nuclear decommissioning trust 147,938 208,306
Level 2 | Municipal bonds    
ASSETS    
Nuclear decommissioning trust 64,881 59,323
Other special use fund 4,027 0
Level 2 | Other fixed income    
ASSETS    
Nuclear decommissioning trust 8,375 5,653
Level 3    
ASSETS    
Cash equivalents   0
Commodity contracts, assets 26,132  
Nuclear decommissioning trust 0 0
Other special use fund 0 0
Total assets 26,132 6,616
LIABILITIES    
Derivative instruments (31,020)  
Total liabilities (31,020)  
Level 3 | Commodity contracts    
ASSETS    
Commodity contracts, assets 26,132 6,616
LIABILITIES    
Derivative instruments (31,020) (1,695)
Level 3 | Interest rate swaps    
ASSETS    
Commodity contracts, assets 0  
LIABILITIES    
Derivative instruments 0  
Level 3 | Equity securities    
ASSETS    
Nuclear decommissioning trust 0 0
Other special use fund 0 0
Level 3 | U.S. commingled equity funds    
ASSETS    
Nuclear decommissioning trust 0 0
Level 3 | U.S. Treasury debt    
ASSETS    
Nuclear decommissioning trust 0 0
Other special use fund 0 0
Level 3 | Corporate debt    
ASSETS    
Nuclear decommissioning trust 0 0
Level 3 | Mortgage-backed securities    
ASSETS    
Nuclear decommissioning trust 0 0
Level 3 | Municipal bonds    
ASSETS    
Nuclear decommissioning trust 0 0
Other special use fund 0 0
Level 3 | Other fixed income    
ASSETS    
Nuclear decommissioning trust 0 0
Fair Value Measured at Net Asset Value Per Share | U.S. commingled equity funds    
ASSETS    
Nuclear decommissioning trust $ 472,582 $ 409,616
v3.24.0.1
Fair Value Measurements - Significant Unobservable Inputs Used to Value Level 3 Instruments (Details 2)
$ in Thousands
 12 Months Ended
Dec. 31, 2023
USD ($)
$ / MWh
$ / MMBTU
Dec. 31, 2022
USD ($)
$ / MMBTU
$ / MWh
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments    
Assets $ 1,570,845 $ 1,552,870
Liabilities   42,446
Level 3    
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments    
Assets 6,616 26,132
Liabilities   31,020
Level 3 | Forward Contracts | Commodity Contracts    
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments    
Assets 6,616 26,132
Liabilities $ 1,695 $ 31,020
Level 3 | Forward Contracts | Valuation Technique, Discounted Cash Flow | Commodity Contracts | Weighted Average    
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments    
Electricity forward price (in usd per MWh) | $ / MWh 158.08 163.92
Natural gas forward price (in usd per MMBTu) | $ / MMBTU 0.03 (5.08)
Level 3 | Forward Contracts | Valuation Technique, Discounted Cash Flow | Commodity Contracts | Minimum    
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments    
Electricity forward price (in usd per MWh) | $ / MWh 37.79 37.79
Natural gas forward price (in usd per MMBTu) | $ / MMBTU 0.00 (11.81)
Level 3 | Forward Contracts | Valuation Technique, Discounted Cash Flow | Commodity Contracts | Maximum    
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments    
Electricity forward price (in usd per MWh) | $ / MWh 259.04 310.69
Natural gas forward price (in usd per MMBTu) | $ / MMBTU 0.08 0
Level 3 | Forward Contracts | Valuation Technique, Discounted Cash Flow | Electricity: | Commodity Contracts    
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments    
Assets $ 6,587 $ 26,132
Liabilities 658 1,759
Level 3 | Forward Contracts | Valuation Technique, Discounted Cash Flow | Natural Gas: | Commodity Contracts    
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments    
Assets 29 0
Liabilities $ 1,037 $ 29,261
v3.24.0.1
Fair Value Measurements - Fair value for our risk management activities (Details) - Commodity Contracts - Level 3 - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]    
Net derivative balance at beginning of period $ (4,888) $ (2,738)
Deferred as a regulatory asset or liability (70,214) (374)
Settlements 69,706 (1,123)
Transfers into Level 3 from Level 2 (1,289) (846)
Transfers from Level 3 into Level 2 11,606 193
Net derivative balance at end of period 4,921 (4,888)
Net unrealized gains included in earnings related to instruments still held at end of period $ 0 $ 0
v3.24.0.1
Earnings Per Share (Details) - USD ($)
$ / shares in Units, shares in Thousands, $ in Thousands
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Earnings Per Share [Abstract]      
Net income attributable to common shareholders $ 501,557 $ 483,602 $ 618,720
Weighted average common shares outstanding — basic (in shares) 113,442 113,196 112,910
Net effect of dilutive securities:      
Contingently issuable performance shares and restricted stock units (in shares) 362 220 282
Weighted average common shares outstanding — diluted (in shares) 113,804 113,416 113,192
Earnings per weighted-average common share outstanding      
Net income attributable to common shareholders - basic (in dollars per share) $ 4.42 $ 4.27 $ 5.48
Net Income attributable to common shareholders - diluted (in dollars per share) $ 4.41 $ 4.26 $ 5.47
v3.24.0.1
Stock-Based Compensation - Additional Information (Details)
shares in Millions, $ in Millions
 12 Months Ended
Dec. 31, 2023
USD ($)
program
shares
Dec. 31, 2022
USD ($)
Dec. 31, 2021
USD ($)
performance_criteria
Stock-Based Compensation      
Compensation cost that has been charged against income $ 17 $ 16 $ 18
Total income tax benefit recognized 3 2 3
Total unrecognized compensation cost related to nonvested share-based compensation arrangements granted $ 31    
Expected weighted-average period of recognition of unrecognized compensation cost 2 years    
Total fair value of shares vested $ 24 25 $ 22
Performance Share Awards      
Performance period 3 years    
Number of unrelated performance element criteria | program 3    
Number of performance element criteria | performance_criteria     2
Restricted Stock Units      
Stock-Based Compensation      
Share-based liabilities paid $ 6 3 $ 4
Cash flow effect, cash used to settle awards $ 3 $ 3 $ 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%
Performance Shares | Minimum      
Performance Share Awards      
Exact number of shares issued as a percentage of the target award 0.00%   0.00%
Performance Shares | Maximum      
Performance Share Awards      
Exact number of shares issued as a percentage of the target award 200.00%   200.00%
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%
2012 Plan      
Stock-Based Compensation      
Common shares available for grant (in shares) | shares 4.3    
Common shares available for issuance (in shares) | shares 3.5    
v3.24.0.1
Stock-Based Compensation - Summary of Restricted Stock, Stock Grants, Stock Units and Performance Shares (Details) - $ / shares
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Restricted Stock Units, Stock Grants, and Stock Units      
Stocks granted and the weighted average fair value      
Units granted (in shares) 192,295 174,791 152,345
Weighted-average grant date fair value (in dollars per share) $ 74.32 $ 69.66 $ 76.72
Number of granted awards to be settled in cash (in shares) 0 0 51,074
Performance Shares      
Stocks granted and the weighted average fair value      
Units granted (in shares) 202,562 208,736 161,840
Weighted-average grant date fair value (in dollars per share) $ 79.61 $ 77.63 $ 82.42
v3.24.0.1
Stock-Based Compensation - Status of Nonvested Restricted Stock, Stock Grants, Stock Units and Performance Shares (Details) - $ / shares
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Restricted Stock Units, Stock Grants, and Stock Units      
Nonvested shares      
Balance at the beginning of the period (in shares) 317,587    
Granted (in shares) 192,295 174,791 152,345
Vested (in shares) (119,077)    
Forfeited (in shares) (16,438)    
Balance at the end of the period (in shares) 374,367 317,587  
Weighted-Average Grant-Date Fair Value      
Balance at the beginning of the period (in dollars per share) $ 73.91    
Granted (in dollars per share) 74.32 $ 69.66 $ 76.72
Vested (in dollars per share) 80.71    
Forfeited (in dollars per share) 73.95    
Balance at the end of the period (in dollars per share) $ 73.29 $ 73.91  
Vested awards outstanding at end of year (in shares) 70,766    
Vested awards outstanding at end of year (in dollars per share)    
Number of nonvested awards to be settled in cash (in shares) 34,367    
Performance Shares      
Nonvested shares      
Balance at the beginning of the period (in shares) 330,694    
Granted (in shares) 202,562 208,736 161,840
Vested (in shares) (169,290)    
Forfeited (in shares) (16,683)    
Balance at the end of the period (in shares) 347,283 330,694  
Weighted-Average Grant-Date Fair Value      
Balance at the beginning of the period (in dollars per share) $ 78.91    
Granted (in dollars per share) 79.61 $ 77.63 $ 82.42
Vested (in dollars per share) 83.12    
Forfeited (in dollars per share) 78.40    
Balance at the end of the period (in dollars per share) $ 77.29 $ 78.91  
Vested awards outstanding at end of year (in shares) 155,708    
Vested awards outstanding at end of year (in dollars per share)    
v3.24.0.1
Derivative Accounting - Additional Information (Details) - USD ($)
$ in Thousands
Dec. 31, 2023
Dec. 31, 2022
Oct. 18, 2022
Commodity Contracts      
Derivative [Line Items]      
Derivative asset $ 6,808 $ 132,098  
Additional collateral to counterparties for energy related non-derivative instrument contracts $ 205,000    
Interest rate swaps      
Derivative [Line Items]      
Derivative asset     $ 200
Arizona Public Service Company      
Derivative [Line Items]      
Percentage of unrealized gains and losses on certain derivatives deferred for future rate treatment before accounting treatment change 100.00%    
v3.24.0.1
Derivative Accounting - Outstanding Gross Notional Amounts Outstanding (Details) - Commodity Contracts
MWh in Thousands
 12 Months Ended
Dec. 31, 2023
MWh
Bcf
Dec. 31, 2022
MWh
Bcf
Outstanding gross notional amount of derivatives    
Power | MWh 1,212 1,197
Gas | Bcf 200 149
v3.24.0.1
Derivative Accounting - Gains and Losses from Derivative Instruments (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Commodity Contracts | Fuel and purchased power | Not Designated as Hedging Instruments      
Derivative Instruments Not Designated as Cash Flows Hedges      
Net Gain (Loss) Recognized in Income $ (370,145) $ 307,287 $ 216,847
v3.24.0.1
Derivative Accounting - Derivative Instruments in the Balance Sheet (Details) - USD ($)
$ in Thousands
Dec. 31, 2023
Dec. 31, 2022
Assets    
Gross Recognized Derivatives   $ 132,229
Liabilities    
Amounts  Reported on  Balance Sheets   (42,446)
Commodity Contracts    
Assets    
Gross Recognized Derivatives $ 8,497 153,261
Amounts Offset (1,694) (21,191)
Net Recognized Derivatives 6,803 132,070
Other 5 28
Amounts  Reported on  Balance Sheets 6,808 132,098
Liabilities    
Gross Recognized Derivatives (128,711) (56,893)
Amounts Offset 10,894 21,191
Net Recognized Derivatives (117,817) (35,702)
Other (6,071) (5,835)
Amounts  Reported on  Balance Sheets (123,888) (41,537)
Assets and Liabilities    
Gross Recognized Derivatives (120,214) 96,368
Amounts Offset 9,200 0
Net Recognized Derivatives (111,014) 96,368
Other (6,066) (5,807)
Amounts  Reported on  Balance Sheets (117,080) 90,561
Cash collateral provided or received subject to offsetting 9,200 0
Cash collateral received from counterparties 6,071 5,835
Cash margin provided to counterparties 5 28
Commodity Contracts | Current assets    
Assets    
Gross Recognized Derivatives 8,497 103,484
Amounts Offset (1,694) (15,808)
Net Recognized Derivatives 6,803 87,676
Other 5 28
Amounts  Reported on  Balance Sheets 6,808 87,704
Assets and Liabilities    
Cash margin provided to counterparties 5 28
Commodity Contracts | Other Investments    
Assets    
Gross Recognized Derivatives 0 49,777
Amounts Offset 0 (5,383)
Net Recognized Derivatives 0 44,394
Other 0 0
Amounts  Reported on  Balance Sheets 0 44,394
Assets and Liabilities    
Cash margin provided to counterparties 0 0
Commodity Contracts | Current liabilities    
Liabilities    
Gross Recognized Derivatives (85,736) (47,670)
Amounts Offset 10,894 15,808
Net Recognized Derivatives (74,842) (31,862)
Other (6,071) (5,835)
Amounts  Reported on  Balance Sheets (80,913) (37,697)
Assets and Liabilities    
Cash collateral received from counterparties 6,071 5,835
Commodity Contracts | Deferred credits and other    
Liabilities    
Gross Recognized Derivatives (42,975) (9,223)
Amounts Offset 0 5,383
Net Recognized Derivatives (42,975) (3,840)
Other 0 0
Amounts  Reported on  Balance Sheets (42,975) (3,840)
Assets and Liabilities    
Cash collateral received from counterparties $ 0 $ 0
v3.24.0.1
Derivative Accounting - Credit Risk and Related Contingent Features (Details) - Commodity Contracts
$ in Thousands
Dec. 31, 2023
USD ($)
Credit Risk and Credit-Related Contingent Features  
Aggregate fair value of derivative instruments in a net liability position $ 128,711
Cash collateral posted 9,200
Additional cash collateral in the event credit-risk related contingent features were fully triggered $ 117,566
v3.24.0.1
Other Income and Other Expense (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Other income:      
Interest income $ 27,242 $ 7,326 $ 6,726
Gain on Sale of BCE (Note 20) 6,205 0 0
Miscellaneous 219 590 53
Total other income 33,666 7,916 45,100
Other expense:      
Non-operating costs (15,260) (18,619) (13,008)
Investment gains (losses) — net (3,402) (20,537) (1,367)
Miscellaneous (6,394) (13,229) (11,021)
Total other expense (25,056) (52,385) (25,396)
Arizona Public Service Company      
Other income:      
Interest income 26,853 5,332 4,692
Miscellaneous 219 556 40
Total other income 27,072 5,888 43,053
Other expense:      
Non-operating costs (14,070) (15,579) (10,080)
Miscellaneous (4,194) (10,529) (8,817)
Total other expense (18,264) (26,108) (18,897)
ACC | Navajo Nation, Electrification Projects | Coal Community Transition Plan      
Other expense:      
Amount funded by shareholders   7,000  
SCR deferral      
Other income:      
Debt return     14,955
SCR deferral | Arizona Public Service Company      
Other income:      
Debt return 0 0 14,955
Octotillo modernization project      
Other income:      
Debt return     23,366
Octotillo modernization project | Arizona Public Service Company      
Other income:      
Debt return $ 0 $ 0 $ 23,366
v3.24.0.1
Palo Verde Sale Leaseback Variable Interest Entities - Additional Information (Details)
$ in Thousands
 12 Months Ended
Dec. 31, 2023
USD ($)
lease
trust
Dec. 31, 2022
USD ($)
Dec. 31, 2021
USD ($)
Dec. 31, 1986
Trust
Palo Verde Sale Leaseback Variable Interest Entities        
Net income attributable to noncontrolling interest $ 17,224 $ 17,224 $ 17,224  
Arizona Public Service Company        
Palo Verde Sale Leaseback Variable Interest Entities        
Number of VIE lessor trusts | trust 3      
Net income attributable to noncontrolling interest $ 17,224 17,224 17,224  
Arizona Public Service Company | Variable Interest Entity        
Palo Verde Sale Leaseback Variable Interest Entities        
Number of VIE lessor trusts | Trust       3
Net income attributable to noncontrolling interest 17,000 $ 17,000 $ 17,000  
Initial loss exposure to the VIEs noncontrolling equity participants during lease extension period 334,000      
Arizona Public Service Company | Variable Interest Entity | Maximum        
Palo Verde Sale Leaseback Variable Interest Entities        
Maximum loss exposure to the VIE's noncontrolling equity participants during lease extension period (up to) $ 501,000      
Arizona Public Service Company | Period 2022 through 2023 | Variable Interest Entity        
Palo Verde Sale Leaseback Variable Interest Entities        
Number of leases under which assets are retained | lease 3      
Annual lease payments $ 21,000      
Arizona Public Service Company | Period 2022 through 2023 | Variable Interest Entity | Maximum        
Palo Verde Sale Leaseback Variable Interest Entities        
Lease period (up to) 2 years      
v3.24.0.1
Palo Verde Sale Leaseback Variable Interest Entities - Schedule of VIEs (Details) - USD ($)
$ in Thousands
Dec. 31, 2023
Dec. 31, 2022
Palo Verde Sale Leaseback Variable Interest Entities    
Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation $ 17,980,157 $ 16,854,354
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets    
Equity-Noncontrolling interests 107,198 111,229
Arizona Public Service Company    
Palo Verde Sale Leaseback Variable Interest Entities    
Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation 17,979,860 16,800,254
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets    
Equity-Noncontrolling interests 107,198 111,229
Palo Verde VIE | Arizona Public Service Company    
Palo Verde Sale Leaseback Variable Interest Entities    
Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation 86,426 90,296
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets    
Equity-Noncontrolling interests $ 107,198 $ 111,229
v3.24.0.1
Investments in Nuclear Decommissioning Trusts and Other Special Use Funds - Additional Information (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Arizona Public Service Company    
Schedule of Equity Method Investments [Line Items]    
Employee medical claims amount $ 14 $ 15
v3.24.0.1
Investments in Nuclear Decommissioning Trusts and Other Special Use Funds (Details) - Arizona Public Service Company - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Nuclear decommissioning trust fund assets      
Fair Value $ 1,564,027 $ 1,420,641  
Total Unrealized Gains 358,112 337,994  
Total Unrealized Losses (40,868) (69,091)  
Amortized cost 1,120,000 927,000  
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds      
Realized gains 112,094 9,437 $ 134,659
Realized losses (41,780) (40,239) (8,438)
Proceeds from the sale of securities 1,679,722 1,207,197 1,720,966
Nuclear Decommissioning Trusts      
Nuclear decommissioning trust fund assets      
Fair Value 1,201,246 1,073,410  
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds      
Realized gains 111,922 9,017 134,610
Realized losses (41,212) (40,239) (8,431)
Proceeds from the sale of securities 1,324,978 979,639 1,457,305
Other Special Use Funds      
Nuclear decommissioning trust fund assets      
Fair Value 362,781 347,231  
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds      
Realized gains 172 420 49
Realized losses (568) 0 (7)
Proceeds from the sale of securities 354,744 227,558 $ 263,661
Equity securities      
Nuclear decommissioning trust fund assets      
Equity securities 461,671 554,214  
Total Unrealized Gains 336,555 334,817  
Total Unrealized Losses 0 (267)  
Equity securities | Nuclear Decommissioning Trusts      
Nuclear decommissioning trust fund assets      
Equity securities 420,680 487,240  
Equity securities | Other Special Use Funds      
Nuclear decommissioning trust fund assets      
Equity securities 40,991 66,974  
Available for sale-fixed income securities      
Nuclear decommissioning trust fund assets      
Fair Value 1,100,927 861,637  
Total Unrealized Gains 21,518 3,177  
Total Unrealized Losses (40,868) (68,795)  
Fair value of fixed income securities, summarized by contractual maturities      
Less than one year 121,606    
1 year – 5 years 424,772    
5 years – 10 years 201,452    
Greater than 10 years 353,097    
Total 1,100,927    
Available for sale-fixed income securities | Nuclear Decommissioning Trusts      
Nuclear decommissioning trust fund assets      
Fair Value 781,333 582,343  
Fair value of fixed income securities, summarized by contractual maturities      
Less than one year 26,057    
1 year – 5 years 225,891    
5 years – 10 years 176,288    
Greater than 10 years 353,097    
Total 781,333    
Available for sale-fixed income securities | Other Special Use Funds      
Nuclear decommissioning trust fund assets      
Fair Value 319,594 279,294  
Available for sale-fixed income securities | Coal Reclamation Escrow Account      
Fair value of fixed income securities, summarized by contractual maturities      
Less than one year 58,692    
1 year – 5 years 46,120    
5 years – 10 years 0    
Greater than 10 years 0    
Total 104,812    
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 36,857    
1 year – 5 years 152,761    
5 years – 10 years 25,164    
Greater than 10 years 0    
Total 214,782    
Other      
Nuclear decommissioning trust fund assets      
Fair Value 1,429 4,790  
Total Unrealized Gains 39 0  
Total Unrealized Losses 0 (29)  
Other | Nuclear Decommissioning Trusts      
Nuclear decommissioning trust fund assets      
Fair Value (767) 3,827  
Other | Other Special Use Funds      
Nuclear decommissioning trust fund assets      
Fair Value $ 2,196 $ 963  
v3.24.0.1
Changes in Accumulated Other Comprehensive Loss (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Changes in accumulated other comprehensive income (loss) by component    
Beginning balance $ 6,159,876 $ 6,021,460
Ending balance 6,284,862 6,159,876
Accumulated Other Comprehensive Loss    
Changes in accumulated other comprehensive income (loss) by component    
Beginning balance (31,435) (54,861)
OCI (loss) before reclassifications (3,707) 19,423
Amounts reclassified from accumulated other comprehensive loss 1,998 4,003
Ending balance (33,144) (31,435)
Pension and Other Postretirement Benefits    
Changes in accumulated other comprehensive income (loss) by component    
Beginning balance (32,332) (53,885)
OCI (loss) before reclassifications (4,420) 17,550
Amounts reclassified from accumulated other comprehensive loss 1,998 4,003
Ending balance (34,754) (32,332)
Derivative Instruments    
Changes in accumulated other comprehensive income (loss) by component    
Beginning balance 897 (976)
OCI (loss) before reclassifications 713 1,873
Amounts reclassified from accumulated other comprehensive loss 0 0
Ending balance 1,610 897
Arizona Public Service Company    
Changes in accumulated other comprehensive income (loss) by component    
Beginning balance 7,052,955 6,750,473
Ending balance 7,349,136 7,052,955
Arizona Public Service Company | Accumulated Other Comprehensive Loss    
Changes in accumulated other comprehensive income (loss) by component    
Beginning balance (15,596) (34,880)
OCI (loss) before reclassifications (3,383) 15,646
Amounts reclassified from accumulated other comprehensive loss 1,760 3,638
Ending balance (17,219) (15,596)
Arizona Public Service Company | Pension and Other Postretirement Benefits    
Changes in accumulated other comprehensive income (loss) by component    
Beginning balance (15,596) (34,880)
OCI (loss) before reclassifications (3,383) 15,646
Amounts reclassified from accumulated other comprehensive loss 1,760 3,638
Ending balance $ (17,219) $ (15,596)
v3.24.0.1
Sale of Bright Canyon Energy (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Jan. 31, 2024
Aug. 04, 2023
Feb. 11, 2022
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]            
Gain on sale relating to BCE $ 6,423 $ 0 $ 0      
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 $ 31,000
Term Loan | Non-Recourse Construction Term Loan Facility | Bright Canyon Energy Corporation            
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]            
Debt instrument, face amount           $ 36,000
Discontinued Operations, Disposed of by Sale | Bright Canyon Energy Corporation            
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]            
Consideration received         $ 44,000  
Gain on sale relating to BCE 6,000          
Assets held-for-sale 35,000          
Discontinued Operations, Disposed of by Sale | Bright Canyou Energy Corportion | Ameresco, Inc.            
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]            
Note receivable, net book value $ 28,000          
Discontinued Operations, Disposed of by Sale | Bright Canyou Energy Corportion | Subsequent Event            
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]            
Investment tax credits       $ 28,000    
v3.24.0.1
Schedule I - Condensed Financial Information of Registrant - Comprehensive Income (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
CONDENSED FINANCIAL STATEMENTS      
Operating expenses $ 3,871,351 $ 3,592,474 $ 2,998,525
Other      
Total 102,376 99,281 173,982
Interest expense 374,887 283,569 254,314
Income tax benefit 76,912 74,827 110,086
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS 501,557 483,602 618,720
Other comprehensive income (loss) — attributable to common shareholders (1,709) 23,426 7,935
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS 499,848 507,028 626,655
Pinnacle West      
CONDENSED FINANCIAL STATEMENTS      
Operating expenses 11,249 8,850 10,245
Other      
Equity in earnings of subsidiaries 539,962 500,042 628,916
Other income (expense) 2,823 (4,725) (4,919)
Total 542,785 495,317 623,997
Interest expense 47,251 18,861 10,672
Income before income taxes 484,285 467,606 603,080
Income tax benefit (17,272) (15,996) (15,640)
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS 501,557 483,602 618,720
Other comprehensive income (loss) — attributable to common shareholders (1,709) 23,426 7,935
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS $ 499,848 $ 507,028 $ 626,655
v3.24.0.1
Schedule I - Condensed Financial Information of Registrant - Balance Sheets (Details) - USD ($)
$ in Thousands
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Dec. 31, 2020
Current assets        
Cash and cash equivalents $ 4,955 $ 4,832    
Accounts receivable 513,892 453,209    
Income tax receivable 332 14,086    
Assets held for sale (Note 20) 35,139 0    
Other current assets 101,417 60,091    
Total current assets 1,926,967 1,750,554    
Investments and other assets        
Other assets 102,845 125,672    
Total investments and other assets 1,666,872 1,590,707    
TOTAL ASSETS 24,661,153 22,723,405    
Current liabilities        
Accounts payable 442,455 430,425    
Accrued taxes 166,833 164,440    
Common dividends payable 99,813 97,895    
Outstanding short-term borrowings 609,500 340,720    
Current maturities of long-term debt 875,000 50,685    
Operating lease liabilities 67,883 105,210    
Other current liabilities 193,524 148,276    
Total current liabilities 2,889,347 1,762,141    
Deferred credits and other        
Long-term debt less current maturities 7,540,622 7,741,286    
Operating lease liabilities 1,210,189 639,247    
Other 251,469 247,400    
Total deferred credits and other 7,946,322 7,060,102    
COMMITMENTS AND CONTINGENCIES (Note 10)    
Common stock equity        
Common stock 2,752,676 2,724,740    
Accumulated other comprehensive loss (Note 19) (33,144) (31,435)    
Retained earnings 3,466,317 3,360,347    
Total shareholders’ equity 6,177,664 6,048,647    
Noncontrolling interests 107,198 111,229    
Total equity 6,284,862 6,159,876 $ 6,021,460 $ 5,752,793
TOTAL LIABILITIES AND EQUITY 24,661,153 22,723,405    
Pinnacle West        
Current assets        
Cash and cash equivalents 9 0    
Accounts receivable 163,829 132,061    
Income tax receivable 1,832 14,494    
Assets held for sale (Note 20) 35,139 0    
Other current assets 28,379 288    
Total current assets 229,188 146,843    
Investments and other assets        
Investments in subsidiaries 7,369,159 7,105,789    
Deferred income taxes 15,746 1,521    
Other assets 22,839 23,153    
Total investments and other assets 7,407,744 7,130,463    
TOTAL ASSETS 7,636,932 7,277,306    
Current liabilities        
Accounts payable 8,176 6,499    
Accrued taxes 4,543 7,694    
Common dividends payable 99,813 97,895    
Outstanding short-term borrowings 76,650 15,720    
Current maturities of long-term debt 625,000 0    
Operating lease liabilities 127 117    
Other current liabilities 11,400 14,637    
Total current liabilities 825,709 142,562    
Deferred credits and other        
Long-term debt less current maturities 498,731 947,892    
Pension liabilities 6,487 8,218    
Operating lease liabilities 1,332 1,459    
Other 19,811 17,299    
Total deferred credits and other 27,630 26,976    
COMMITMENTS AND CONTINGENCIES (Note 10)    
Common stock equity        
Common stock 2,744,491 2,719,735    
Accumulated other comprehensive loss (Note 19) (33,144) (31,435)    
Retained earnings 3,466,317 3,360,347    
Total shareholders’ equity 6,177,664 6,048,647    
Noncontrolling interests 107,198 111,229    
Total equity 6,284,862 6,159,876    
TOTAL LIABILITIES AND EQUITY $ 7,636,932 $ 7,277,306    
v3.24.0.1
Schedule I - Condensed Financial Information of Registrant - Cash Flows (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Cash flows from operating activities      
Net income $ 518,781 $ 500,826 $ 635,944
Adjustments to reconcile net income to net cash provided by operating activities:      
Depreciation and amortization 854,136 817,814 719,141
Deferred income taxes (24,310) 43,202 117,471
Accounts receivable (61,983) (63,869) (72,559)
Accounts payable (75,623) 90,076 20,267
Net cash provided by operating activities 1,207,697 1,241,441 860,014
Cash flows from investing activities      
Proceeds from sale relating to BCE 23,400 0 0
Net cash used for investing activities (1,694,249) (1,618,046) (1,386,929)
Cash flows from financing activities      
Issuance of long-term debt 689,349 875,537 746,999
Short-term debt repayments under revolving credit facility 0 0 (19,000)
Short-term borrowings and (repayments) — net 241,900 48,720 142,000
Dividends paid on common stock (386,486) (378,881) (369,478)
Repayment of long-term debt (32,740) (150,000) 0
Common stock equity issuance and purchases — net (4,093) (2,653) (2,350)
Net cash provided by financing activities 486,675 371,468 476,916
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 123 (5,137) (49,999)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 4,832 9,969 59,968
CASH AND CASH EQUIVALENTS AT END OF YEAR 4,955 4,832 9,969
Pinnacle West      
Cash flows from operating activities      
Net income 501,557 483,602 618,720
Adjustments to reconcile net income to net cash provided by operating activities:      
Equity in earnings of subsidiaries — net (539,962) (500,042) (628,916)
Gain on sale relating to BCE (6,423) 0 0
Depreciation and amortization 76 76 93
Deferred income taxes (13,955) 17,256 (11,381)
Accounts receivable (28,273) (8,535) 8,897
Accounts payable 1,839 3,431 (2,598)
Accrued taxes and income tax receivables — net 9,505 (25,157) 16,079
Dividends received from subsidiaries 393,600 385,800 376,500
Other (14,201) 47,719 4,214
Net cash provided by operating activities 303,763 404,150 381,608
Cash flows from investing activities      
Proceeds from sale relating to BCE 23,400 0 0
Investments in subsidiaries (119,682) (186,630) (145,266)
Repayments of loans from subsidiaries and other 6,526 14,308 4,017
Advances of loans to subsidiaries (59,349) (3,308) (12,256)
Net cash used for investing activities (149,105) (175,630) (153,505)
Cash flows from financing activities      
Issuance of long-term debt 175,000 300,000 300,000
Short-term debt repayments under revolving credit facility 0 0 (19,000)
Short-term borrowings and (repayments) — net 60,930 2,420 (136,700)
Dividends paid on common stock (386,486) (378,881) (369,478)
Repayment of long-term debt 0 (150,000) 0
Common stock equity issuance and purchases — net (4,093) (2,653) (2,350)
Net cash provided by financing activities (154,649) (229,114) (227,528)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 9 (594) 575
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 0 594 19
CASH AND CASH EQUIVALENTS AT END OF YEAR $ 9 $ 0 $ 594