PINNACLE WEST CAPITAL CORP, 10-Q filed on 8/3/2022
Quarterly Report
v3.22.2
Cover Page - shares
 6 Months Ended
Jun. 30, 2022
Jul. 27, 2022
Entity Information [Line Items]    
Document Type 10-Q  
Document Quarterly Report true  
Document Period End Date Jun. 30, 2022  
Document Transition Report false  
Entity File Number 1-8962  
Entity Registrant Name PINNACLE WEST CAPITAL CORPORATION  
Entity Tax Identification Number 86-0512431  
Entity Incorporation, State or Country Code AZ  
Entity Address, Address Line One 400 North Fifth Street, P.O. Box 53999  
Entity Address, City or Town Phoenix  
Entity Address, State or Province AZ  
Entity Address, Postal Zip Code 85072-3999  
City Area Code (602)  
Local Phone Number 250-1000  
Title of 12(b) Security Common Stock  
Trading Symbol PNW  
Security Exchange Name NYSE  
Entity Current Reporting Status Yes  
Entity Interactive Data Current Yes  
Entity Filer Category Large Accelerated Filer  
Entity Small Business false  
Entity Emerging Growth Company false  
Entity Shell Company false  
Entity Common Stock, Shares Outstanding   113,043,622
Entity Central Index Key 0000764622  
Amendment Flag false  
Current Fiscal Year End Date --12-31  
Document Fiscal Year Focus 2022  
Document Fiscal Period Focus Q2  
APS    
Entity Information [Line Items]    
Document Type 10-Q  
Document Period End Date Jun. 30, 2022  
Entity File Number 1-4473  
Entity Registrant Name ARIZONA PUBLIC SERVICE COMPANY  
Entity Tax Identification Number 86-0011170  
Entity Incorporation, State or Country Code AZ  
Entity Address, Address Line One 400 North Fifth Street, P.O. Box 53999  
Entity Address, City or Town Phoenix  
Entity Address, State or Province AZ  
Entity Address, Postal Zip Code 85072-3999  
City Area Code (602)  
Local Phone Number 250-1000  
Entity Current Reporting Status Yes  
Entity Interactive Data Current Yes  
Entity Filer Category Non-accelerated Filer  
Entity Small Business false  
Entity Emerging Growth Company false  
Entity Shell Company false  
Entity Common Stock, Shares Outstanding   71,264,947
Entity Central Index Key 0000007286  
Amendment Flag false  
Current Fiscal Year End Date --12-31  
Document Fiscal Year Focus 2022  
Document Fiscal Period Focus Q2  
v3.22.2
CONDENSED CONSOLIDATED STATEMENTS OF INCOME - USD ($)
shares in Thousands, $ in Thousands
 3 Months Ended 6 Months Ended
Jun. 30, 2022
Jun. 30, 2021
Jun. 30, 2022
Jun. 30, 2021
Income Statement [Abstract]        
OPERATING REVENUES (Note 2) $ 1,061,669 $ 1,000,249 $ 1,845,200 $ 1,696,724
OPERATING EXPENSES        
Fuel and purchased power 352,187 269,835 617,456 468,062
Operations and maintenance 245,387 229,690 463,729 459,745
Depreciation and amortization 186,497 158,750 373,102 316,570
Taxes other than income taxes 54,118 59,495 112,116 118,978
Other expenses 385 4,093 1,210 7,449
Total 838,574 721,863 1,567,613 1,370,804
OPERATING INCOME 223,095 278,386 277,587 325,920
OTHER INCOME (DEDUCTIONS)        
Allowance for equity funds used during construction 12,086 9,990 21,833 19,197
Pension and other postretirement non-service credits - net (Note 5) 25,257 28,175 49,066 55,966
Other income (Note 9) 1,682 12,207 3,386 24,636
Other expense (Note 9) (4,584) (5,184) (8,006) (9,037)
Total 34,441 45,188 66,279 90,762
INTEREST EXPENSE        
Interest charges 68,103 62,777 133,492 124,715
Allowance for borrowed funds used during construction (5,873) (5,199) (10,355) (10,193)
Total 62,230 57,578 123,137 114,522
INCOME BEFORE INCOME TAXES 195,306 265,996 220,729 302,160
INCOME TAXES 26,688 46,560 30,849 42,210
NET INCOME 168,618 219,436 189,880 259,950
Less: Comprehensive income attributable to noncontrolling interests 4,306 3,739 8,612 8,612
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS $ 164,312 $ 215,697 $ 181,268 $ 251,338
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — BASIC (in shares) 113,172 112,882 113,137 112,855
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — DILUTED (in shares) 113,369 113,223 113,332 113,158
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING        
Net income attributable to common shareholders - basic (in dollars per share) $ 1.45 $ 1.91 $ 1.60 $ 2.23
Net income attributable to common shareholders — diluted (in dollars per share) $ 1.45 $ 1.91 $ 1.60 $ 2.22
v3.22.2
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($)
$ in Thousands
 3 Months Ended 6 Months Ended
Jun. 30, 2022
Jun. 30, 2021
Jun. 30, 2022
Jun. 30, 2021
Statement of Comprehensive Income [Abstract]        
Net Income $ 168,618 $ 219,436 $ 189,880 $ 259,950
OTHER COMPREHENSIVE INCOME, NET OF TAX        
Derivative instruments net unrealized gain, net of tax expense of $(331), $(286), $(413), and $(372) 1,007 870 1,259 1,132
Pension and other postretirement benefit activity, net of tax benefit (expense) of $693, $(21), $398 and $(357) (2,113) 64 (1,212) 1,086
Total other comprehensive income (loss) (1,106) 934 47 2,218
COMPREHENSIVE INCOME 167,512 220,370 189,927 262,168
Less: Comprehensive income attributable to noncontrolling interests 4,306 3,739 8,612 8,612
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS $ 163,206 $ 216,631 $ 181,315 $ 253,556
v3.22.2
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($)
$ in Thousands
 3 Months Ended 6 Months Ended
Jun. 30, 2022
Jun. 30, 2021
Jun. 30, 2022
Jun. 30, 2021
Statement of Comprehensive Income [Abstract]        
Derivative instruments net unrealized gain, tax expense $ (331) $ (286) $ (413) $ (372)
Pension and other postretirement benefits activity, tax benefit (expense) $ 693 $ (21) $ 398 $ (357)
v3.22.2
CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($)
$ in Thousands
Jun. 30, 2022
Dec. 31, 2021
CURRENT ASSETS    
Cash and cash equivalents $ 29,189 $ 9,969
Customer and other receivables 420,288 391,923
Accrued unbilled revenues 234,523 133,980
Allowance for doubtful accounts (Note 2) (23,147) (25,354)
Materials and supplies (at average cost) 371,655 349,135
Income tax receivable 0 7,514
Fossil fuel (at average cost) 29,827 18,032
Assets from risk management activities (Note 7) 137,028 63,481
Deferred fuel and purchased power regulatory asset (Note 4) 390,013 388,148
Other regulatory assets (Note 4) 119,163 130,376
Other current assets 89,609 83,896
Total current assets 1,798,148 1,551,100
INVESTMENTS AND OTHER ASSETS    
Nuclear decommissioning trusts (Notes 11 and 12) 1,076,088 1,294,757
Other special use funds (Notes 11 and 12) 346,406 358,410
Assets from risk management activities (Note 7) 111,847 46,908
Other assets 117,573 97,884
Total investments and other assets 1,651,914 1,797,959
PROPERTY, PLANT AND EQUIPMENT    
Plant in service and held for future use 22,167,179 21,688,661
Accumulated depreciation and amortization (7,667,678) (7,504,603)
Net 14,499,501 14,184,058
Construction work in progress 1,386,113 1,329,478
Palo Verde sale leaseback, net of accumulated depreciation (Note 6) 92,231 94,166
Intangible assets, net of accumulated amortization 265,662 273,693
Nuclear fuel, net of accumulated amortization 132,696 106,039
Total property, plant and equipment 16,376,203 15,987,434
DEFERRED DEBITS    
Regulatory assets (Note 4) 1,180,656 1,192,987
Operating lease right-of-use assets 871,480 890,057
Assets for pension and other postretirement benefits (Note 5) 577,399 545,723
Other 45,680 37,962
Total deferred debits 2,675,215 2,666,729
TOTAL ASSETS 22,501,480 22,003,222
CURRENT LIABILITIES    
Accounts payable 436,308 393,083
Accrued taxes 181,927 168,645
Accrued interest 57,349 57,332
Common dividends payable 96,081 95,988
Short-term borrowings (Note 3) 541,000 292,000
Current maturities of long-term debt (Note 3) 0 150,000
Customer deposits 41,459 42,293
Liabilities from risk management activities (Note 7) 5,596 4,373
Liabilities for asset retirements 5,111 4,473
Operating lease liabilities 125,320 100,443
Regulatory liabilities (Note 4) 404,107 296,271
Other current liabilities 128,190 151,968
Total current liabilities 2,022,448 1,756,869
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 3) 7,241,295 6,913,735
DEFERRED CREDITS AND OTHER    
Deferred income taxes 2,357,469 2,311,862
Regulatory liabilities (Note 4) 2,268,148 2,499,213
Liabilities for asset retirements 779,360 762,909
Liabilities for pension benefits (Note 5) 150,837 152,865
Customer advances 336,198 257,151
Coal mine reclamation 176,936 174,616
Deferred investment tax credit 184,032 186,570
Unrecognized tax benefits 4,896 4,657
Operating lease liabilities 710,511 728,401
Other 247,827 232,914
Total deferred credits and other 7,216,214 7,311,158
COMMITMENTS AND CONTINGENCIES (Note 8)
EQUITY    
Common stock, no par value; authorized 150,000,000 shares, 113,078,049 and 113,014,528 issued at respective dates 2,712,297 2,702,743
Treasury stock at cost; 41,531 and 87,608 shares at respective dates (2,976) (6,401)
Total common stock 2,709,321 2,696,342
Retained earnings 3,253,772 3,264,719
Accumulated other comprehensive loss (Note 13) (54,814) (54,861)
Total shareholders’ equity 5,908,279 5,906,200
Noncontrolling interests (Note 6) 113,244 115,260
Total equity 6,021,523 6,021,460
TOTAL LIABILITIES AND EQUITY $ 22,501,480 $ 22,003,222
v3.22.2
CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - shares
Jun. 30, 2022
Dec. 31, 2021
EQUITY    
Common stock, authorized shares (in shares) 150,000,000 150,000,000
Common stock, issued shares (in shares) 113,078,049 113,014,528
Treasury stock at cost, shares (in shares) 41,531 87,608
v3.22.2
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)
$ in Thousands
 6 Months Ended
Jun. 30, 2022
Jun. 30, 2021
CASH FLOWS FROM OPERATING ACTIVITIES    
Net income $ 189,880 $ 259,950
Adjustments to reconcile net income to net cash provided by operating activities:    
Depreciation and amortization including nuclear fuel 405,127 350,536
Deferred fuel and purchased power (98,707) (135,905)
Deferred fuel and purchased power amortization 96,842 10,828
Allowance for equity funds used during construction (21,833) (19,197)
Deferred income taxes 22,169 30,231
Deferred investment tax credit (2,538) (3,651)
Stock compensation 7,872 13,484
Changes in current assets and liabilities:    
Customer and other receivables (31,146) (41,138)
Accrued unbilled revenues (100,543) (91,721)
Materials, supplies and fossil fuel (34,315) (31,449)
Income tax receivable 7,514 6,792
Other current assets 5,195 (14,021)
Accounts payable 104,849 66,558
Accrued taxes 13,282 23,486
Other current liabilities (7,316) (39,638)
Change in margin and collateral accounts — assets 40,430 0
Change in other long-term assets 174,013 (152,846)
Change in operating lease assets 29,759 34,810
Change in other long-term liabilities (184,626) 76,290
Change in operating lease liabilities (27,622) (31,049)
Net cash provided by operating activities 588,286 312,350
CASH FLOWS FROM INVESTING ACTIVITIES    
Capital expenditures (843,219) (681,148)
Contributions in aid of construction 68,879 32,104
Allowance for borrowed funds used during construction (10,111) (10,193)
Proceeds from nuclear decommissioning trusts sales and other special use funds 692,186 587,842
Investment in nuclear decommissioning trusts and other special use funds (692,811) (588,982)
Other (9,174) 10,809
Net cash used for investing activities (794,250) (649,568)
CASH FLOWS FROM FINANCING ACTIVITIES    
Issuance of long-term debt 325,802 150,000
Short-term borrowing and (repayments) — net 249,000 354,700
Short-term debt repayments under revolving credit facility 0 (19,000)
Dividends paid on common stock (188,542) (183,500)
Repayment of long-term debt (150,000) 0
Common stock equity issuances and (purchases) — net (448) (176)
Distributions to noncontrolling interests (10,628) (10,628)
Net cash provided by financing activities 225,184 291,396
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 19,220 (45,822)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 9,969 59,968
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 29,189 $ 14,146
v3.22.2
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY - USD ($)
$ in Thousands
Total
Common Stock
Treasury Stock
Retained Earnings
Accumulated Other Comprehensive Income (Loss)
Noncontrolling Interests
Beginning balance (in shares) at Dec. 31, 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 259,950     251,338   8,612
Other comprehensive income (loss) 2,218       2,218  
Dividends on common stock (187,176)     (187,176)    
Issuance of common stock (in shares)   59,652        
Issuance of common stock 14,533 $ 14,533        
Purchase of treasury stock (in shares) [1]     (17,437)      
Purchase of treasury stock [1] (1,333)   $ (1,333)      
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 (10,628)         (10,628)
Other (1)     (2)   1
Ending balance (in shares) at Jun. 30, 2021   112,819,703        
Ending balance at Jun. 30, 2021 5,834,899 $ 2,692,015 $ (3,079) 3,089,266 (60,578) 117,275
Ending balance (in shares) at Jun. 30, 2021     (36,153)      
Beginning balance (in shares) at Mar. 31, 2021   112,791,565        
Beginning balance at Mar. 31, 2021 5,806,680 $ 2,687,052 $ (3,776) 3,060,752 (61,512) 124,164
Beginning balance (in shares) at Mar. 31, 2021     (44,338)      
Increase (Decrease) in Shareholders' Equity            
Net income 219,436     215,697   3,739
Other comprehensive income (loss) 934       934  
Dividends on common stock (187,181)     (187,181)    
Issuance of common stock (in shares)   28,138        
Issuance of common stock 4,963 $ 4,963        
Reissuance of treasury stock for stock-based compensation and other (in shares)     8,185      
Reissuance of treasury stock for stock-based compensation and other 697   $ 697      
Capital activities by noncontrolling interests (10,628)         (10,628)
Other (2)     (2)    
Ending balance (in shares) at Jun. 30, 2021   112,819,703        
Ending balance at Jun. 30, 2021 $ 5,834,899 $ 2,692,015 $ (3,079) 3,089,266 (60,578) 117,275
Ending balance (in shares) at Jun. 30, 2021     (36,153)      
Beginning balance (in shares) at Dec. 31, 2021 113,014,528 113,014,528        
Beginning balance at Dec. 31, 2021 $ 6,021,460 $ 2,702,743 $ (6,401) 3,264,719 (54,861) 115,260
Beginning balance (in shares) at Dec. 31, 2021 (87,608)   (87,608)      
Increase (Decrease) in Shareholders' Equity            
Net income $ 189,880     181,268   8,612
Other comprehensive income (loss) 47       47  
Dividends on common stock (192,213)     (192,213)    
Issuance of common stock (in shares)   63,521        
Issuance of common stock 9,554 $ 9,554        
Purchase of treasury stock (in shares) [1]     (24,885)      
Purchase of treasury stock [1] (1,715)   $ (1,715)      
Reissuance of treasury stock for stock-based compensation and other (in shares)     70,962      
Reissuance of treasury stock for stock-based compensation and other 5,140   $ 5,140      
Capital activities by noncontrolling interests (10,628)         (10,628)
Other $ (2)     (2)    
Ending balance (in shares) at Jun. 30, 2022 113,078,049 113,078,049        
Ending balance at Jun. 30, 2022 $ 6,021,523 $ 2,712,297 $ (2,976) 3,253,772 (54,814) 113,244
Ending balance (in shares) at Jun. 30, 2022 (41,531)   (41,531)      
Beginning balance (in shares) at Mar. 31, 2022   113,047,699        
Beginning balance at Mar. 31, 2022 $ 6,050,136 $ 2,706,325 $ (3,648) 3,281,601 (53,708) 119,566
Beginning balance (in shares) at Mar. 31, 2022     (50,921)      
Increase (Decrease) in Shareholders' Equity            
Net income 168,618     164,312   4,306
Other comprehensive income (loss) (1,106)       (1,106)  
Dividends on common stock (192,139)     (192,139)    
Issuance of common stock (in shares)   30,350        
Issuance of common stock 5,972 $ 5,972        
Reissuance of treasury stock for stock-based compensation and other (in shares)     9,390      
Reissuance of treasury stock for stock-based compensation and other 673   $ 673      
Capital activities by noncontrolling interests (10,628)         (10,628)
Other $ (3)   (1) (2)    
Ending balance (in shares) at Jun. 30, 2022 113,078,049 113,078,049        
Ending balance at Jun. 30, 2022 $ 6,021,523 $ 2,712,297 $ (2,976) $ 3,253,772 $ (54,814) $ 113,244
Ending balance (in shares) at Jun. 30, 2022 (41,531)   (41,531)      
[1] Primarily represents shares of common stock withheld from certain stock awards for tax purposes.
v3.22.2
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Parenthetical) - $ / shares
 3 Months Ended 6 Months Ended
Jun. 30, 2022
Jun. 30, 2021
Jun. 30, 2022
Jun. 30, 2021
Statement of Stockholders' Equity [Abstract]        
Dividends declared per common share (in dollars per share) $ 1.70 $ 1.66 $ 1.70 $ 1.66
v3.22.2
CONDENSED CONSOLIDATED STATEMENTS OF INCOME - USD ($)
$ in Thousands
 3 Months Ended 6 Months Ended
Jun. 30, 2022
Jun. 30, 2021
Jun. 30, 2022
Jun. 30, 2021
OPERATING REVENUES (Note 2) $ 1,061,669 $ 1,000,249 $ 1,845,200 $ 1,696,724
OPERATING EXPENSES        
Fuel and purchased power 352,187 269,835 617,456 468,062
Operations and maintenance 245,387 229,690 463,729 459,745
Depreciation and amortization 186,497 158,750 373,102 316,570
Taxes other than income taxes 54,118 59,495 112,116 118,978
Other expenses 385 4,093 1,210 7,449
Total 838,574 721,863 1,567,613 1,370,804
OPERATING INCOME 223,095 278,386 277,587 325,920
OTHER INCOME (DEDUCTIONS)        
Allowance for equity funds used during construction 12,086 9,990 21,833 19,197
Pension and other postretirement non-service credits - net (Note 5) 25,257 28,175 49,066 55,966
Other income (Note 9) 1,682 12,207 3,386 24,636
Other expense (Note 9) (4,584) (5,184) (8,006) (9,037)
Total 34,441 45,188 66,279 90,762
INTEREST EXPENSE        
Interest charges 68,103 62,777 133,492 124,715
Allowance for borrowed funds used during construction (5,873) (5,199) (10,355) (10,193)
Total 62,230 57,578 123,137 114,522
INCOME BEFORE INCOME TAXES 195,306 265,996 220,729 302,160
INCOME TAXES 26,688 46,560 30,849 42,210
NET INCOME 168,618 219,436 189,880 259,950
Less: Comprehensive income attributable to noncontrolling interests 4,306 3,739 8,612 8,612
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS 164,312 215,697 181,268 251,338
APS        
OPERATING REVENUES (Note 2) 1,061,669 1,000,249 1,845,200 1,696,724
OPERATING EXPENSES        
Fuel and purchased power 352,187 269,835 617,456 468,062
Operations and maintenance 242,273 226,698 456,874 453,099
Depreciation and amortization 186,477 158,728 373,060 316,528
Taxes other than income taxes 54,094 59,478 112,053 118,950
Other expenses 385 4,093 1,210 7,449
Total 835,416 718,832 1,560,653 1,364,088
OPERATING INCOME 226,253 281,417 284,547 332,636
OTHER INCOME (DEDUCTIONS)        
Allowance for equity funds used during construction 12,086 9,990 21,833 19,197
Pension and other postretirement non-service credits - net (Note 5) 25,382 28,234 49,289 56,071
Other income (Note 9) 1,396 11,563 2,548 23,523
Other expense (Note 9) (2,786) (4,261) (4,634) (7,611)
Total 36,078 45,526 69,036 91,180
INTEREST EXPENSE        
Interest charges 64,223 59,930 126,532 119,318
Allowance for borrowed funds used during construction (5,689) (5,199) (10,111) (10,193)
Total 58,534 54,731 116,421 109,125
INCOME BEFORE INCOME TAXES 203,797 272,212 237,162 314,691
INCOME TAXES 29,522 48,725 34,381 51,044
NET INCOME 174,275 223,487 202,781 263,647
Less: Comprehensive income attributable to noncontrolling interests 4,306 3,739 8,612 8,612
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS $ 169,969 $ 219,748 $ 194,169 $ 255,035
v3.22.2
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($)
$ in Thousands
 3 Months Ended 6 Months Ended
Jun. 30, 2022
Jun. 30, 2021
Jun. 30, 2022
Jun. 30, 2021
NET INCOME $ 168,618 $ 219,436 $ 189,880 $ 259,950
OTHER COMPREHENSIVE INCOME, NET OF TAX        
Pension and other postretirement benefits activity, net of tax benefit (expense) of $709, $(53), $440, and $(357) (2,113) 64 (1,212) 1,086
Total other comprehensive income (loss) (1,106) 934 47 2,218
COMPREHENSIVE INCOME 167,512 220,370 189,927 262,168
Less: Comprehensive income attributable to noncontrolling interests 4,306 3,739 8,612 8,612
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS 163,206 216,631 181,315 253,556
APS        
NET INCOME 174,275 223,487 202,781 263,647
OTHER COMPREHENSIVE INCOME, NET OF TAX        
Pension and other postretirement benefits activity, net of tax benefit (expense) of $709, $(53), $440, and $(357) (2,161) 159 (1,341) 1,086
Total other comprehensive income (loss) (2,161) 159 (1,341) 1,086
COMPREHENSIVE INCOME 172,114 223,646 201,440 264,733
Less: Comprehensive income attributable to noncontrolling interests 4,306 3,739 8,612 8,612
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS $ 167,808 $ 219,907 $ 192,828 $ 256,121
v3.22.2
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($)
$ in Thousands
 3 Months Ended 6 Months Ended
Jun. 30, 2022
Jun. 30, 2021
Jun. 30, 2022
Jun. 30, 2021
Pension and other postretirement benefits activity, tax benefit (expense) $ 693 $ (21) $ 398 $ (357)
APS        
Pension and other postretirement benefits activity, tax benefit (expense) $ 709 $ (53) $ 440 $ (357)
v3.22.2
CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($)
$ in Thousands
Jun. 30, 2022
Dec. 31, 2021
PROPERTY, PLANT AND EQUIPMENT    
Plant in service and held for future use $ 22,167,179 $ 21,688,661
Accumulated depreciation and amortization (7,667,678) (7,504,603)
Net 14,499,501 14,184,058
Construction work in progress 1,386,113 1,329,478
Palo Verde sale leaseback, net of accumulated depreciation (Note 6) 92,231 94,166
Intangible assets, net of accumulated amortization 265,662 273,693
Nuclear fuel, net of accumulated amortization 132,696 106,039
Total property, plant and equipment 16,376,203 15,987,434
INVESTMENTS AND OTHER ASSETS    
Nuclear decommissioning trusts (Notes 11 and 12) 1,076,088 1,294,757
Other special use funds (Notes 11 and 12) 346,406 358,410
Assets from risk management activities (Note 7) 111,847 46,908
Other assets 117,573 97,884
Total investments and other assets 1,651,914 1,797,959
CURRENT ASSETS    
Cash and cash equivalents 29,189 9,969
Customer and other receivables 420,288 391,923
Accrued unbilled revenues 234,523 133,980
Allowance for doubtful accounts (Note 2) (23,147) (25,354)
Materials and supplies (at average cost) 371,655 349,135
Fossil fuel (at average cost) 29,827 18,032
Income tax receivable 0 7,514
Assets from risk management activities (Note 7) 137,028 63,481
Deferred fuel and purchased power regulatory asset (Note 4) 390,013 388,148
Other regulatory assets (Note 4) 119,163 130,376
Other current assets 89,609 83,896
Total current assets 1,798,148 1,551,100
DEFERRED DEBITS    
Regulatory assets (Note 4) 1,180,656 1,192,987
Operating lease right-of-use assets 871,480 890,057
Assets for pension and other postretirement benefits (Note 5) 577,399 545,723
Other 45,680 37,962
Total deferred debits 2,675,215 2,666,729
TOTAL ASSETS 22,501,480 22,003,222
EQUITY    
Retained earnings 3,253,772 3,264,719
Accumulated other comprehensive loss (Note 13) (54,814) (54,861)
Total shareholders’ equity 5,908,279 5,906,200
Noncontrolling interests (Note 6) 113,244 115,260
Total equity 6,021,523 6,021,460
Long-term debt less current maturities (Note 3) 7,241,295 6,913,735
CURRENT LIABILITIES    
Short-term borrowings (Note 3) 541,000 292,000
Accounts payable 436,308 393,083
Accrued taxes 181,927 168,645
Accrued interest 57,349 57,332
Common dividends payable 96,081 95,988
Customer deposits 41,459 42,293
Liabilities from risk management activities (Note 7) 5,596 4,373
Liabilities for asset retirements 5,111 4,473
Operating lease liabilities 125,320 100,443
Regulatory liabilities (Note 4) 404,107 296,271
Other current liabilities 128,190 151,968
Total current liabilities 2,022,448 1,756,869
DEFERRED CREDITS AND OTHER    
Deferred income taxes 2,357,469 2,311,862
Regulatory liabilities (Note 4) 2,268,148 2,499,213
Liabilities for asset retirements 779,360 762,909
Liabilities for pension benefits (Note 5) 150,837 152,865
Customer advances 336,198 257,151
Coal mine reclamation 176,936 174,616
Deferred investment tax credit 184,032 186,570
Unrecognized tax benefits 4,896 4,657
Operating lease liabilities 710,511 728,401
Other 247,827 232,914
Total deferred credits and other 7,216,214 7,311,158
COMMITMENTS AND CONTINGENCIES (Note 8)
TOTAL LIABILITIES AND EQUITY 22,501,480 22,003,222
APS    
PROPERTY, PLANT AND EQUIPMENT    
Plant in service and held for future use 22,163,718 21,685,200
Accumulated depreciation and amortization (7,664,384) (7,501,317)
Net 14,499,334 14,183,883
Construction work in progress 1,365,400 1,327,721
Palo Verde sale leaseback, net of accumulated depreciation (Note 6) 92,231 94,166
Intangible assets, net of accumulated amortization 265,507 273,537
Nuclear fuel, net of accumulated amortization 132,696 106,039
Total property, plant and equipment 16,355,168 15,985,346
INVESTMENTS AND OTHER ASSETS    
Nuclear decommissioning trusts (Notes 11 and 12) 1,076,088 1,294,757
Other special use funds (Notes 11 and 12) 346,406 358,410
Assets from risk management activities (Note 7) 111,847 46,908
Other assets 42,748 42,440
Total investments and other assets 1,577,089 1,742,515
CURRENT ASSETS    
Cash and cash equivalents 27,782 9,374
Customer and other receivables 419,364 390,533
Accrued unbilled revenues 234,523 133,980
Allowance for doubtful accounts (Note 2) (23,147) (25,354)
Materials and supplies (at average cost) 371,655 349,135
Fossil fuel (at average cost) 29,827 18,032
Income tax receivable 0 10,756
Assets from risk management activities (Note 7) 137,028 63,481
Deferred fuel and purchased power regulatory asset (Note 4) 390,013 388,148
Other regulatory assets (Note 4) 119,163 130,376
Other current assets 76,519 57,729
Total current assets 1,782,727 1,526,190
DEFERRED DEBITS    
Regulatory assets (Note 4) 1,180,656 1,192,987
Operating lease right-of-use assets 866,182 888,207
Assets for pension and other postretirement benefits (Note 5) 568,515 537,092
Other 43,648 37,319
Total deferred debits 2,659,001 2,655,605
TOTAL ASSETS 22,373,985 21,909,656
EQUITY    
Common stock 178,162 178,162
Additional paid-in capital 3,171,696 3,021,696
Retained earnings 3,472,403 3,470,235
Accumulated other comprehensive loss (Note 13) (36,221) (34,880)
Total shareholders’ equity 6,786,040 6,635,213
Noncontrolling interests (Note 6) 113,244 115,260
Total equity 6,899,284 6,750,473
Long-term debt less current maturities (Note 3) 6,268,271 6,266,693
Total capitalization 13,167,555 13,017,166
CURRENT LIABILITIES    
Short-term borrowings (Note 3) 515,000 278,700
Accounts payable 429,672 389,365
Accrued taxes 191,420 152,012
Accrued interest 56,625 56,622
Common dividends payable 96,000 96,000
Customer deposits 41,459 42,293
Liabilities from risk management activities (Note 7) 5,596 4,373
Liabilities for asset retirements 5,111 4,473
Operating lease liabilities 124,947 100,199
Regulatory liabilities (Note 4) 404,107 296,271
Other current liabilities 131,285 145,286
Total current liabilities 2,001,222 1,565,594
DEFERRED CREDITS AND OTHER    
Deferred income taxes 2,351,848 2,331,701
Regulatory liabilities (Note 4) 2,268,148 2,499,213
Liabilities for asset retirements 779,360 762,909
Liabilities for pension benefits (Note 5) 137,355 138,328
Customer advances 336,198 257,151
Coal mine reclamation 176,936 174,616
Deferred investment tax credit 184,032 186,570
Unrecognized tax benefits 37,662 37,423
Operating lease liabilities 705,305 726,572
Other 228,364 212,413
Total deferred credits and other 7,205,208 7,326,896
COMMITMENTS AND CONTINGENCIES (Note 8)
TOTAL LIABILITIES AND EQUITY $ 22,373,985 $ 21,909,656
v3.22.2
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)
$ in Thousands
 6 Months Ended
Jun. 30, 2022
Jun. 30, 2021
CASH FLOWS FROM OPERATING ACTIVITIES    
Net income $ 189,880 $ 259,950
Adjustments to reconcile net income to net cash provided by operating activities:    
Depreciation and amortization including nuclear fuel 405,127 350,536
Deferred fuel and purchased power (98,707) (135,905)
Deferred fuel and purchased power amortization 96,842 10,828
Allowance for equity funds used during construction (21,833) (19,197)
Deferred income taxes 22,169 30,231
Deferred investment tax credit (2,538) (3,651)
Changes in current assets and liabilities:    
Customer and other receivables (31,146) (41,138)
Accrued unbilled revenues (100,543) (91,721)
Materials, supplies and fossil fuel (34,315) (31,449)
Income tax receivable 7,514 6,792
Other current assets 5,195 (14,021)
Accounts payable 104,849 66,558
Accrued taxes 13,282 23,486
Other current liabilities (7,316) (39,638)
Change in margin and collateral accounts — assets 40,430 0
Change in other long-term assets 174,013 (152,846)
Change in operating lease assets 29,759 34,810
Change in other long-term liabilities (184,626) 76,290
Change in operating lease liabilities (27,622) (31,049)
Net cash provided by operating activities 588,286 312,350
CASH FLOWS FROM INVESTING ACTIVITIES    
Capital expenditures (843,219) (681,148)
Contributions in aid of construction 68,879 32,104
Allowance for borrowed funds used during construction (10,111) (10,193)
Proceeds from nuclear decommissioning trusts sales and other special use funds 692,186 587,842
Investment in nuclear decommissioning trusts and other special use funds (692,811) (588,982)
Other (9,174) 10,809
Net cash used for investing activities (794,250) (649,568)
CASH FLOWS FROM FINANCING ACTIVITIES    
Short-term borrowing and (repayments) — net 249,000 354,700
Dividends paid on common stock (188,542) (183,500)
Distributions to noncontrolling interests (10,628) (10,628)
Net cash provided by financing activities 225,184 291,396
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 19,220 (45,822)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 9,969 59,968
CASH AND CASH EQUIVALENTS AT END OF PERIOD 29,189 14,146
APS    
CASH FLOWS FROM OPERATING ACTIVITIES    
Net income 202,781 263,647
Adjustments to reconcile net income to net cash provided by operating activities:    
Depreciation and amortization including nuclear fuel 405,085 350,494
Deferred fuel and purchased power (98,707) (135,905)
Deferred fuel and purchased power amortization 96,842 10,828
Allowance for equity funds used during construction (21,833) (19,197)
Deferred income taxes (2,838) 23,161
Deferred investment tax credit (2,538) (3,651)
Changes in current assets and liabilities:    
Customer and other receivables (31,612) (41,963)
Accrued unbilled revenues (100,543) (91,721)
Materials, supplies and fossil fuel (34,315) (31,449)
Income tax receivable 10,756 0
Other current assets (7,883) (12,636)
Accounts payable 101,931 66,192
Accrued taxes 39,408 44,439
Other current liabilities 2,384 (39,749)
Change in margin and collateral accounts — assets 40,430 0
Change in other long-term assets 183,701 (148,912)
Change in operating lease assets 29,613 34,758
Change in other long-term liabilities (184,896) 77,323
Change in operating lease liabilities (27,470) (30,996)
Net cash provided by operating activities 600,296 314,663
CASH FLOWS FROM INVESTING ACTIVITIES    
Capital expenditures (824,269) (681,148)
Contributions in aid of construction 68,879 32,104
Allowance for borrowed funds used during construction (10,111) (10,193)
Proceeds from nuclear decommissioning trusts sales and other special use funds 692,186 587,842
Investment in nuclear decommissioning trusts and other special use funds (692,811) (588,982)
Other 566 2,986
Net cash used for investing activities (765,560) (657,391)
CASH FLOWS FROM FINANCING ACTIVITIES    
Short-term borrowing and (repayments) — net 236,300 495,000
Equity infusion 150,000 0
Dividends paid on common stock (192,000) (187,000)
Distributions to noncontrolling interests (10,628) (10,628)
Net cash provided by financing activities 183,672 297,372
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 18,408 (45,356)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 9,374 57,310
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 27,782 $ 11,954
v3.22.2
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY - USD ($)
$ in Thousands
Total
Common Stock
Retained Earnings
Accumulated Other Comprehensive Income (Loss)
Noncontrolling Interests
APS
APS
Common Stock
APS
Additional Paid-In Capital
APS
Retained Earnings
APS
Accumulated Other Comprehensive Income (Loss)
APS
Noncontrolling Interests
Beginning balance (in shares) at Dec. 31, 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                      
Net Income 259,950   251,338   8,612 263,647     255,035   8,612
Other comprehensive income (loss) 2,218     2,218   1,086       1,086  
Dividends on common stock (187,176)   (187,176)     (187,000)     (187,000)    
Capital activities by noncontrolling interests (10,628)       (10,628) (10,628)         (10,628)
Other (1)   (2)   1 0     (1)   1
Ending balance (in shares) at Jun. 30, 2021   112,819,703         71,264,947        
Ending balance at Jun. 30, 2021 5,834,899 $ 2,692,015 3,089,266 (60,578) 117,275 6,412,290 $ 178,162 2,871,696 3,284,989 (39,832) 117,275
Beginning balance (in shares) at Mar. 31, 2021   112,791,565         71,264,947        
Beginning balance at Mar. 31, 2021 5,806,680 $ 2,687,052 3,060,752 (61,512) 124,164 6,386,275 $ 178,162 2,871,696 3,252,244 (39,991) 124,164
Increase (Decrease) in Shareholders' Equity                      
Net Income 219,436   215,697   3,739 223,487     219,748   3,739
Other comprehensive income (loss) 934     934   159       159  
Dividends on common stock (187,181)   (187,181)     (187,000)     (187,000)    
Capital activities by noncontrolling interests (10,628)       (10,628) (10,628)         (10,628)
Other (2)   (2)     (3)     (3)    
Ending balance (in shares) at Jun. 30, 2021   112,819,703         71,264,947        
Ending balance at Jun. 30, 2021 $ 5,834,899 $ 2,692,015 3,089,266 (60,578) 117,275 6,412,290 $ 178,162 2,871,696 3,284,989 (39,832) 117,275
Beginning balance (in shares) at Dec. 31, 2021 113,014,528 113,014,528         71,264,947        
Increase (Decrease) in Shareholders' Equity                      
Equity infusion from Pinnacle West           150,000   150,000      
Beginning 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                      
Net Income 189,880   181,268   8,612 202,781     194,169   8,612
Other comprehensive income (loss) 47     47   (1,341)       (1,341)  
Dividends on common stock (192,213)   (192,213)     (192,000)     (192,000)    
Capital activities by noncontrolling interests (10,628)       (10,628) (10,628)         (10,628)
Other $ (2)   (2)     (1)     (1)    
Ending balance (in shares) at Jun. 30, 2022 113,078,049 113,078,049         71,264,947        
Ending balance at Jun. 30, 2022 $ 6,021,523 $ 2,712,297 3,253,772 (54,814) 113,244 6,899,284 $ 178,162 3,171,696 3,472,403 (36,221) 113,244
Beginning balance (in shares) at Mar. 31, 2022   113,047,699         71,264,947        
Beginning balance at Mar. 31, 2022 6,050,136 $ 2,706,325 3,281,601 (53,708) 119,566 6,929,796 $ 178,162 3,171,696 3,494,432 (34,060) 119,566
Increase (Decrease) in Shareholders' Equity                      
Net Income 168,618   164,312   4,306 174,275     169,969   4,306
Other comprehensive income (loss) (1,106)     (1,106)   (2,161)       (2,161)  
Dividends on common stock (192,139)   (192,139)     (192,000)     (192,000)    
Capital activities by noncontrolling interests (10,628)       (10,628) (10,628)         (10,628)
Other $ (3)   (2)     2     2    
Ending balance (in shares) at Jun. 30, 2022 113,078,049 113,078,049         71,264,947        
Ending balance at Jun. 30, 2022 $ 6,021,523 $ 2,712,297 $ 3,253,772 $ (54,814) $ 113,244 $ 6,899,284 $ 178,162 $ 3,171,696 $ 3,472,403 $ (36,221) $ 113,244
v3.22.2
Consolidation and Nature of Operations
 6 Months Ended
Jun. 30, 2022
Organization, Consolidation and Presentation of Financial Statements [Abstract]  
Consolidation and Nature of Operations Consolidation and Nature of Operations
 
The unaudited condensed consolidated financial statements include the accounts of Pinnacle West and our subsidiaries:  APS, 4C Acquisition, LLC (“4CA”), Bright Canyon Energy Corporation (“BCE”) and El Dorado Investment Company (“El Dorado”).  See Note 8 for more information on 4CA matters. Intercompany accounts and transactions between the consolidated companies have been eliminated.  The unaudited condensed consolidated financial statements for APS include the accounts of APS and the Palo Verde Generating Station (“Palo Verde”) sale leaseback variable interest entities (“VIEs”). See Note 6 for further discussion.  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.

Amounts reported in our interim Condensed Consolidated Statements of Income are not necessarily indicative of amounts expected for the respective annual periods, due to the effects of seasonal temperature variations on energy consumption, timing of maintenance on electric generating units (“EGU”), and other factors.
 
Our condensed consolidated financial statements reflect all adjustments (consisting only of normal recurring adjustments except as otherwise disclosed in the notes) that we believe are necessary for the fair presentation of our financial position, results of operations, and cash flows for the periods presented. Certain information and footnote disclosures normally included in financial statements prepared in conformity with GAAP have been condensed or omitted pursuant to such regulations, although we believe that the disclosures provided are adequate to make the interim information presented not misleading. The accompanying condensed consolidated financial statements and these notes should be read in conjunction with the audited consolidated financial statements and notes included in our 2021 Form 10-K.

On June 30, 2020, the United States Federal Energy Regulatory Commission (“FERC”) issued an order granting a waiver request related to the existing Allowance for Funds Used During Construction (“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. See Note 1 in our 2021 Form 10-K for information on the accounting treatment for AFUDC.
Supplemental Cash Flow Information

The following table summarizes supplemental Pinnacle West cash flow information (dollars in thousands):
 Six Months Ended
June 30,
 20222021
Cash paid (received) during the period for:
Income taxes, net of refunds$(1,746)$(788)
Interest, net of amounts capitalized120,359 112,010 
Significant non-cash investing and financing activities:
Accrued capital expenditures$106,033 $105,515 
Right-of-use operating lease assets obtained in exchange for operating lease liabilities11,101 248,694 
Dividends accrued but not yet paid96,081 93,610 


The following table summarizes supplemental APS cash flow information (dollars in thousands):
Six Months Ended
June 30,
 20222021
Cash paid (received) during the period for:
Income taxes, net of refunds$(25)$3,317 
Interest, net of amounts capitalized114,069 107,044 
Significant non-cash investing and financing activities:
Accrued capital expenditures$106,033 $105,515 
Right-of-use operating lease assets obtained in exchange for operating lease liabilities7,512 248,694 
Dividends accrued but not yet paid96,000 93,500 
v3.22.2
Revenue
 6 Months Ended
Jun. 30, 2022
Revenue from Contract with Customer [Abstract]  
Revenue Revenue
Sources of Revenue

The following table provides detail of Pinnacle West’s consolidated revenue disaggregated by revenue sources (dollars in thousands):
Three Months Ended June 30,Six Months Ended June 30,
2022202120222021
Retail Electric Service
Residential$537,589 $531,717 $904,935 $872,555 
Non-Residential462,669 420,995 822,185 735,778 
Wholesale Energy Sales29,902 18,007 58,805 35,604 
Transmission Services for Others29,352 22,579 54,844 41,572 
Other Sources2,157 6,951 4,431 11,215 
Total operating revenues$1,061,669 $1,000,249 $1,845,200 $1,696,724 

Retail Electric Revenue. Pinnacle West’s retail electric revenue is generated by wholly owned, regulated subsidiary APS’s 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.

In the electricity business, some contracts to purchase energy are settled by netting against other contracts to sell electricity. This is referred to as a book-out, and usually occurs in contracts that have the same terms (product type, quantities, and delivery points) and for which power does not flow. We net these book-outs, which reduces both wholesale revenues and fuel and purchased power costs.

Revenue Activities

Our revenues primarily consist of activities that are classified as revenues from contracts with customers. We derive our revenues from contracts with customers primarily from sales of electricity to our regulated retail customers. Revenues from contracts with customers also include wholesale and transmission activities. Our revenues from contracts with customers for the three and six months ended June 30, 2022 were $1,064 million and $1,835 million, respectively, and for the three and six months ended June 30, 2021 were $980 million and $1,663 million, respectively.
We have certain revenues that do not meet the specific accounting criteria to be classified as revenues from contracts with customers. For the three and six months ended June 30, 2022, and 2021, our revenues that do not qualify as revenue from contracts with customers were $(2) million and $10 million, respectively, and for the three and six months ended June 30, 2021 were $20 million and $34 million, respectively. This amount includes revenues related to certain regulatory cost recovery mechanisms that are considered alternative revenue programs. We recognize revenue associated with alternative revenue programs when specific events permitting recognition are completed. Certain amounts associated with alternative revenue programs will subsequently be billed to customers; however, we do not reclassify billed amounts into revenue from contracts with customers. See Note 4 for a discussion of our regulatory cost recovery mechanisms.

Contract Assets and Liabilities from Contracts with Customers

There were no material contract assets, contract liabilities, or deferred contract costs recorded on the Condensed Consolidated Balance Sheets as of June 30, 2022, or December 31, 2021.

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 COVID-19, 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):
June 30, 2022December 31, 2021
Allowance for doubtful accounts, balance at beginning of period$25,354 $19,782 
Bad debt expense8,119 22,251 
Actual write-offs(10,326)(16,679)
Allowance for doubtful accounts, balance at end of period$23,147 $25,354 
v3.22.2
Long-Term Debt and Liquidity Matters
 6 Months Ended
Jun. 30, 2022
Debt Disclosure [Abstract]  
Long-Term Debt and Liquidity Matters Long-Term Debt and Liquidity Matters
Pinnacle West and APS maintain committed revolving credit facilities in order to enhance liquidity and provide credit support for their commercial paper programs, to refinance indebtedness, and for other general corporate purposes.
 
Pinnacle West

On December 21, 2021, Pinnacle West entered into a $450 million term loan facility that matures December 20, 2024. On December 21, 2021, $150 million of the proceeds were received and recognized as long-term debt on the Condensed Consolidated Balance Sheets. On January 6, 2022, the remaining $300 million of proceeds were received and recognized on that date as long-term debt on the Condensed Consolidated Balance Sheets. The proceeds were used for general corporate purposes.
On December 23, 2020, Pinnacle West entered into a $150 million term loan facility that would have matured June 30, 2022. The proceeds were received on January 4, 2021 and used for general corporate purposes. We recognized the term loan facility as long-term debt upon settlement on January 4, 2021. On January 6, 2022, Pinnacle West repaid this loan facility early.

At June 30, 2022, Pinnacle West had a $200 million revolving credit facility that matures on May 28, 2026. Pinnacle West has the option to increase the amount of the facility up to a maximum 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 credits. At June 30, 2022, Pinnacle West had no outstanding borrowings under its revolving credit facility, no letters of credit outstanding under the credit facility and $26 million of outstanding commercial paper borrowings.

APS

At June 30, 2022, APS had two $500 million revolving credit facilities that total $1 billion and that mature on May 28, 2026.  APS may increase the amount of each facility up to a maximum of $700 million, for a total of $1.4 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 agreements include 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. These facilities are available to support APS’s general corporate purposes, including support for APS’s $750 million commercial paper program, for bank borrowings or for issuances of letters of credit.  At June 30, 2022, APS had no outstanding borrowings under its revolving credit facilities, no letters of credit outstanding under the credit facilities and $515 million of outstanding commercial paper borrowings.

On December 17, 2020, the ACC issued a financing order in which, subject to specified parameters and procedures, it approved APS’s short-term debt authorization equal to the sum of (i) 7% of APS’s capitalization, and (ii) $500 million (which is required to be used for costs relating to purchases of natural gas and power) and a long-term debt authorization of $7.5 billion. On April 6, 2022, APS filed an application with the ACC to increase the long-term debt limit under the terms required by APS from $7.5 billion to $8.0 billion (subject to appropriate regulatory treatment of PPA lease agreements) and to continue its authorization of short-term debt granted in the 2020 financing order. This application is pending the ACC’s review. APS cannot predict the outcome of this matter.

On January 6, 2022, Pinnacle West contributed $150 million into APS in the form of an equity infusion. APS used this contribution to repay short-term indebtedness.

See “Financial Assurances” in Note 8 for a discussion of other outstanding letters of credit.

BCE

On February 11, 2022, a special purpose subsidiary of BCE entered into a credit agreement to finance capital expenditures and related costs for a 31 MW solar and battery storage project in Los Alamitos, California (“Los Alamitos”) that is under development by the subsidiary. The credit facilities consist of an approximately $33 million equity bridge loan facility, an approximately $42 million non-recourse construction to term loan facility, and an approximately $5 million letter of credit facility. In connection with the credit
agreement, Pinnacle West has guaranteed the full amount of the equity bridge loan. As of June 30, 2022, $25.8 million has been drawn from the equity bridge loan and there is no outstanding balance for the non-recourse construction to term loan.
 
Debt Fair Value
 
Our long-term debt fair value estimates are classified within Level 2 of the fair value hierarchy. The following table presents the estimated fair value of our long-term debt, including current maturities (dollars in thousands):
 As of June 30, 2022As of December 31, 2021
 Carrying
Amount		Fair ValueCarrying
Amount		Fair Value
Pinnacle West$947,547 $909,520 $797,042 $792,735 
APS6,268,271 5,488,229 6,266,693 6,933,619 
BCE25,477 25,802 — — 
Total$7,241,295 $6,423,551 $7,063,735 $7,726,354 
v3.22.2
Regulatory Matters
 6 Months Ended
Jun. 30, 2022
Regulated Operations [Abstract]  
Regulatory Matters Regulatory Matters
 
2019 Retail Rate Case

APS filed an application with the ACC on October 31, 2019 (the “2019 Rate Case”) seeking an increase in annual retail base rates of $69 million. This amount includes recovery of the deferral and rate base effects of the Four Corners Power Plant (“Four Corners”) selective catalytic reduction (“SCR”) project that was the subject of a separate proceeding. See “Four Corners SCR Cost Recovery” below. It also reflects a net credit to base rates of approximately $115 million primarily due to the prospective inclusion of rate refunds currently provided through the Tax Expense Adjustment Mechanism (“TEAM”). The proposed total annual revenue increase in APS’s application is $184 million. The average annual customer bill impact of APS’s request is an increase of 5.6% (the average annual bill impact for a typical APS residential customer is 5.4%).

The principal provisions of APS’s application were:

•a test year comprised of 12 months ended June 30, 2019, adjusted as described below;
•an original cost rate base of $8.87 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 Structure Cost of Capital 
Long-term debt 45.3 %4.10 %
Common stock equity 54.7 %10.15 %
Weighted-average cost of capital   7.41 %
 
•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 $0.030168 per kWh for the portion of APS’s retail base rates attributable to fuel and purchased power costs (“Base Fuel Rate”);
•authorization to defer until APS’s next general rate case the increase or decrease in its Arizona property taxes attributable to tax rate changes after the date the rate application is adjudicated;
•a number of proposed rate and program changes for residential customers, including:
▪a super off-peak period during the winter months for APS’s time-of-use with demand rates;
▪additional $1.25 million in funding for APS’s limited-income crisis bill program; and
▪a flat bill/subscription rate pilot program;
•proposed rate design changes for commercial customers, including an experimental program designed to provide access to market pricing for up to 200 MW of medium and large commercial customers;
•recovery of the deferral and rate base effects of the construction and operating costs of the Ocotillo modernization project (see discussion below of the 2017 Settlement Agreement); and
•continued recovery of the remaining investment and other costs related to the retirement and closure of the Navajo Generating Station (the “Navajo Plant”) (see “Navajo Plant” below).

On October 2, 2020, the ACC Staff, the Residential Utility Consumer Office (“RUCO”) and other intervenors filed their initial written testimony with the ACC. The ACC Staff recommended, among other things, (i) an $89.7 million revenue increase, (ii) an average annual customer bill increase of 2.7%, (iii) a return on equity of 9.4%, (iv) a 0.3% or, as an alternative, a 0% return on the increment of fair value rate base greater than original cost, (v) the recovery of the deferral and rate base effects of the construction and operating costs of the Four Corners SCR project and (vi) the recovery of the rate base effects of the construction and ongoing consideration of the deferral of the Ocotillo modernization project. RUCO recommended, among other things, (i) a $20.8 million revenue decrease, (ii) an average annual customer bill decrease of 0.63%, (iii) a return on equity of 8.74%, (iv) a 0% return on the increment of fair value rate base, (v) the nonrecovery of the deferral and rate base effects of the construction and operating costs of the Four Corners SCR project pending further consideration, and (vi) the recovery of the deferral and rate base effects of the construction and operating costs of the Ocotillo modernization project.

The filed ACC Staff and intervenor testimony include additional recommendations, some of which materially differ from APS’s filed application. On November 6, 2020, APS filed its rebuttal testimony and the principal provisions which differ from its initial application include, among other things, (i) a $169 million revenue increase, (ii) average annual customer bill increase of 5.14%, (iii) return on equity of 10%, (iv) return on the increment of fair value rate base of 0.8%, (v) new cost recovery adjustor mechanism, the Advanced Energy Mechanism (“AEM”), to enable more timely recovery of clean investments as APS pursues its clean energy commitment, (vi) recognition that securitization is a potentially useful financing tool to recover the remaining book value of retiring assets and effectuate a transition to a cleaner energy future that APS intends to pursue, provided legislative hurdles are addressed, and (vii) a Coal Community Transition (“CCT”) plan related to the closure or future closure of coal-fired generation facilities, of which $25 million would be funds that are not recoverable through rates with a proposal that the remainder be funded by customers over 10 years.

The CCT plan includes the following proposed components: (i) $100 million that will be paid over 10 years to the Navajo Nation for a sustainable transition to a post-coal economy, which would be funded by customers, (ii) $1.25 million that will be paid over five years to the Navajo Nation to fund an economic development organization, which would be funds not recoverable through rates, (iii) $10 million to facilitate electrification projects within the Navajo Nation, which would be funded equally by funds not recoverable through rates and by customers, (iv) $2.5 million per year in transmission revenue sharing to be paid to the Navajo Nation beginning after the closure of the Four Corners through 2038, which would be funds not recoverable through rates, (v) $12 million that will be paid over five years to the Navajo County Communities surrounding Cholla Power Plant, which would primarily be funded by customers, and (vi) $3.7 million that will be paid over five years to the Hopi Tribe related to APS’s ownership interests in the Navajo Plant, which would primarily be funded by customers. The commitment of funds that would not be recoverable through rates of $25 million were recognized in our December 31, 2020 financials. In 2021, APS committed an additional $900,000 to be paid to the Hopi Tribe related to APS’s ownership interests in the Navajo Plant, and this amount was recognized in its December 31, 2021 financials.
On December 4, 2020, the ACC Staff and intervenors filed surrebuttal testimony. The ACC Staff reduced its recommended rate increase to $59.8 million, or an average annual customer bill increase of 1.82%. In RUCO’s surrebuttal, the recommended revenue decrease changed to $50.1 million, or an average annual customer bill decrease of 1.52%. The hearing concluded on March 3, 2021, and the post-hearing briefing concluded on April 30, 2021.

On August 2, 2021, the 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 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 Navajo Plant regulatory asset recovery, (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 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, 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%, (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, results in a total annual revenue decrease for APS of $4.8 million, excluding temporary CCT payments and expenditures. On November 2, 2021, the ACC approved the 2019 Rate Case ROO, as amended. 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 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. On February 8, 2022, the Arizona Supreme Court declined to accept jurisdiction on APS’s Petition for
Special Action. The appeal at the Arizona Court of Appeals is proceeding in the normal course. APS cannot predict the outcome of this proceeding.

Consistent with the 2019 Rate Case decision, APS implemented the new rates effective as of December 1, 2021. On December 3, 2021, ACC Staff notified the ACC of a discrepancy between the written decision, which approved the change in time-of-use on-peak hours to 4 p.m. to 7 p.m. but did not explicitly approve the 10 months contemplated in APS’s verbal testimony to implement the new time-of-use hours. On December 16, 2021, the ACC ordered APS to complete the implementation of the time-of-use peak period by April 1, 2022. On January 12, 2022, the ACC voted to extend the deadline until September 1, 2022, to complete the implementation of the new on-peak hours for residential customers. In addition, the ACC ordered extensive compliance and reporting obligations and will be continuing to explore whether penalties or rebates would be owed to certain customers. APS cannot predict the outcome of this matter.

Additionally, consistent with the 2019 Rate Case decision, as of April 2022, APS has completed the following payments that will be recoverable through rates related to the CCT: (i) $3.33 million to the Navajo Nation; (ii) $500,000 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) $500,000 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.

APS expects to file an application with the ACC for its next general retail rate case by the end of October 2022, allowing for a test year ending June 30, 2022.

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.

2016 Retail Rate Case Filing
 
On June 1, 2016, APS filed an application with the ACC for an annual increase in retail base rates. On March 27, 2017, a majority of the stakeholders in the general retail rate case, including the ACC Staff, RUCO, limited income advocates and private rooftop solar organizations signed a settlement agreement (the “2017 Settlement Agreement”) and filed it with the ACC. The 2017 Settlement Agreement provides for a net retail base rate increase of $94.6 million, excluding the transfer of adjustor balances, consisting of: (1) a non-fuel, non-depreciation, base rate increase of $87.2 million per year; (2) a base rate decrease of $53.6 million attributable to reduced fuel and purchased power costs; and (3) a base rate increase of $61.0 million due to changes in depreciation schedules.

Other key provisions of the 2017 Settlement Agreement include the following:

•an authorized return on common equity of 10.0%;
•a capital structure comprised of 44.2% debt and 55.8% common equity;
•a cost deferral order for potential future recovery in APS’s next general retail rate case for the construction and operating costs APS incurs for its Ocotillo modernization project;
•a cost deferral and procedure to allow APS to request rate adjustments prior to its next general retail rate case related to its share of the construction costs associated with installing SCR equipment at the Four Corners;
•a deferral for future recovery (or credit to customers) of the Arizona property tax expense above or below a specified test year level caused by changes to the applicable Arizona property tax rate;
•an expansion of the Power Supply Adjustor (“PSA”) to include certain environmental chemical costs and third-party energy storage costs;
•a new AZ Sun II program (now known as “APS Solar Communities”) for utility-owned solar distributed generation (“DG”) with the purpose of expanding access to rooftop solar for low-and moderate-income Arizonans, recoverable through the RES, to be no less than $10 million per year in capital costs, and not more than $15 million per year in capital costs;
•an increase to the per kWh cap for the environmental improvement surcharge from $0.00016 to $0.00050 and the addition of a balancing account;
•rate design changes, including:
▪a change in the on-peak time-of-use period from noon to 7 p.m. to 3 p.m. to 8 p.m. Monday through Friday, excluding holidays;
▪non-grandfathered DG customers would be required to select a rate option that has time of use rates and either a new grid access charge or demand component;
▪a Resource Comparison Proxy (“RCP”) for exported energy of 12.9 cents per kWh in year one; and
•an agreement by APS not to pursue any new self-build generation (with certain exceptions) having an in-service date prior to January 1, 2022 (extended to December 31, 2027, for combined-cycle generating units), unless expressly authorized by the ACC.

On August 15, 2017, the ACC approved the 2017 Settlement Agreement without material modifications and on August 18, 2017, the ACC issued a final written Opinion and Order reflecting its decision in APS’s general retail rate case (the “2017 Rate Case Decision”). The new rates went into effect on August 19, 2017.

See “Rate Plan Comparison Tool and Investigation” below for information regarding a review and investigation pertaining to the rate plan comparison tool offered to APS customers and other related issues.

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.
 
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.

On November 20, 2017, APS filed an updated 2018 RES budget to include budget adjustments for APS Solar Communities (formerly known as AZ Sun II), which was approved as part of the 2017 Rate Case
Decision. APS Solar Communities is a 3-year program authorizing APS to spend $10 million to $15 million in capital costs each year to install utility-owned DG systems for low to moderate income residential homes, non-profit entities, Title I schools and rural government facilities. The 2017 Rate Case Decision provided that all operations and maintenance expenses, property taxes, marketing and advertising expenses, and the capital carrying costs for this program will be recovered through the RES.

On July 1, 2019, APS filed its 2020 RES Implementation Plan and proposed a budget of approximately $86.3 million. APS’s budget request supports existing approved projects and commitments and requests a permanent waiver of the RES residential distributed energy requirement for 2020. On September 23, 2020, the ACC approved the 2020 RES Implementation Plan, including APS’s requested waiver of the residential distributed energy requirements for 2020. In addition, the ACC approved the implementation of a new pilot program that incentivizes Arizona households to install at-home battery systems. Recovery of the costs associated with the pilot will be addressed in the 2021 Demand Side Management Implementation Plan (“DSM Plan”).

On July 1, 2020, APS filed its 2021 RES Implementation Plan and proposed a budget of approximately $84.7 million.  APS’s budget request supports existing approved projects and commitments and requests a permanent waiver of the RES residential distributed energy requirement for 2021. In the 2021 RES Implementation Plan, APS requested $4.5 million to meet revenue requirements associated with the APS Solar Communities program to complete installations delayed as a result of the COVID-19 pandemic in 2020. On June 7, 2021, the ACC approved the 2021 RES Implementation Plan, including APS’s requested waiver of the residential distributed energy requirements for 2021. As part of the approval, the ACC approved the requested budget and authorized APS to collect $68.3 million through the Renewable Energy Adjustment Charge to support APS’s RES programs.

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 requests for proposals (“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 includes 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 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 supports existing approved projects and commitments and requests 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 Commission’s consideration at a future date.

In response to an ACC inquiry, the ACC Staff filed a report providing the history of APS’s long-term purchased power contract of the 280 MW Concentrating Solar Power Plant. This report outlines alternative options that the ACC could pursue to address the costs of this contract, which was executed in February 2008. On July 13, 2022, the ACC approved an option to take no action at this time.

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 Lost Fixed Cost Recovery (“LFCR”) mechanism. See below for discussion of the LFCR.

On September 1, 2017, APS filed its 2018 DSM Plan, which proposed modifications to the DSM portfolio to better meet system and customer needs by focusing on peak demand reductions, storage, load shifting and demand response programs in addition to traditional energy savings measures. The 2018 DSM Plan sought a requested budget of $52.6 million and requested a waiver of the Electric Energy Efficiency Standard for 2018.  On November 14, 2017, APS filed an amended 2018 DSM Plan, which revised the allocations between budget items to address customer participation levels but kept the overall budget at $52.6 million.

On December 31, 2018, APS filed its 2019 DSM Plan, which requested a budget of $34.1 million and focused on DSM strategies to better meet system and customer needs, such as peak demand reduction, load shifting, storage and electrification strategies.

On December 31, 2019, APS filed its 2020 DSM Plan, which requested a budget of $51.9 million and continued APS’s focus on DSM strategies such as peak demand reduction, load shifting, storage and electrification strategies. The 2020 DSM Plan addressed all components of the pending 2018 and 2019 DSM plans, which enabled the ACC to review the 2020 DSM Plan only. On May 15, 2020, APS filed an amended 2020 DSM Plan to provide assistance to customers experiencing economic impacts of the COVID-19 pandemic. The amended 2020 DSM Plan requested the same budget amount of $51.9 million. On September 23, 2020, the ACC approved the amended 2020 DSM Plan.

On April 17, 2020, APS filed an application with the ACC requesting a COVID-19 emergency relief package to provide additional assistance to its customers. On May 5, 2020, the ACC approved APS returning $36 million that had been collected through the DSM Adjustor Charge, but not allocated for current DSM programs, directly to customers through a bill credit in June 2020. APS has refunded approximately $43 million to customers. The additional $7 million over the ACC-approved amount was the result of the kWh credit being based on historic consumption which was different than actual consumption during the refund period. The difference was recorded to the DSM balancing account and was included in the 2021 DSM Implementation Plan, as described below.

On December 31, 2020, APS filed its 2021 DSM Plan, which requested a budget of $63.7 million and continued APS’s focus on DSM strategies, such as peak demand reduction, load shifting, storage and electrification strategies, as well as enhanced assistance to customers impacted economically by COVID-19. On April 6, 2021, APS filed an amended 2021 DSM Plan that proposed an additional performance incentive for customers participating in the residential energy storage pilot program approved in the 2020 RES Implementation Plan. On July 13, 2021, the ACC approved the amended 2021 DSM Plan.

On April 20, 2021, APS filed a request to extend the June 1, 2021 deadline to file its 2022 DSM Plan until 120 days after the ACC has taken action on APS’s amended 2021 DSM Plan. The ACC approved the request, granting an extension until 120 days after the ACC action on the 2021 DSM Plan, or December 31, 2021, whichever is later. On December 17, 2021, APS filed its 2022 DSM Plan, which requested a budget of $78.4 million and represents an increase of approximately $14 million in DSM spending above 2021. In March 2022, APS indicated that it intends to file its 2023 DSM Plan within 120 days after the ACC has taken action on APS's 2022 DSM Plan. The ACC has not yet ruled on the 2022 DSM Plan.
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 following table shows the changes in the deferred fuel and purchased power regulatory asset for 2022 and 2021 (dollars in thousands):
 
 Six Months Ended
June 30,
 20222021
Beginning balance$388,148 $175,835 
Deferred fuel and purchased power costs — current period98,707 135,905 
Amounts charged to customers(96,842)(10,828)
Ending balance$390,013 $300,912 

On November 27, 2019, APS filed its PSA rate for the PSA year beginning February 1, 2020. That rate was $(0.000456) per kWh, which consisted of a forward component of $(0.002086) per kWh and a historical component of $0.001630 per kWh. The 2020 PSA rate is a $0.002115 per kWh decrease compared to the 2019 PSA year. These rates went into effect as filed on February 1, 2020.

On November 30, 2020, APS filed its PSA rate for the PSA year beginning February 1, 2021. That rate was $0.003544 per kWh, which consisted of a forward component of $0.003434 per kWh and a historical component of $0.000110 per kWh. The 2021 PSA rate is a $0.004 per kWh increase compared to the 2020 PSA year, which is the maximum permitted under the Plan of Administration for the PSA. This left $215.9 million of fuel and purchased power costs above this annual cap which will be reflected in future year resets of the PSA. These rates were to be effective on February 1, 2021, but APS delayed the effectiveness of these rates until the first billing cycle of April 2021 due to concerns of the impact on customers during COVID-19. In March 2021, the ACC voted to implement the 2021 PSA rate on a staggered basis, with 50% of the rate increase taking effect in April 2021, and the remaining 50% taking effect in November 2021. The PSA rate implemented on April 1, 2021 was $0.001544 per kWh, which consisted of a forward component of $(0.004444) per kWh and a historical component of $0.005988 per kWh. On November 1, 2021, the remaining increase was implemented to a rate of $0.003544 per kWh and consisted of a forward component of $(0.004444) per kWh and a historical component of $0.007988 per kWh. As part of this approval, the ACC ordered ACC Staff to conduct a fuel and purchased power procurement audit to better understand the factors that contributed to the increase in fuel costs.

On April 1, 2022, the ACC filed a final report of its 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 the 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. APS cannot predict the future impacts, if any, of this audit.

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 is 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. At the time of the compliance filing, the amount remaining
over the annual cap was approximately $365 million of fuel and purchased power costs which will be reflected in future year resets of the PSA.

On March 15, 2019, APS filed an application with the ACC requesting approval to recover the costs related to two energy storage power purchase tolling agreements through the PSA, and on January 12, 2021, the ACC approved this application. On October 28, 2021, APS filed an application requesting approval to recover costs related to three additional energy storage projects through the PSA once the systems are in service, and on December 16, 2021, the ACC approved this application. On February 22, 2022, APS filed an application requesting similar recovery through the PSA for a solar plus energy storage project, and on April 13, 2022, the ACC approved this application. For each of these applications that have been approved by the ACC, the ACC has not ruled on prudency.

Environmental Improvement Surcharge. 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.  There is an overall cap of $0.0005 per kWh (approximately $13 million to $14 million per year).  APS’s February 1, 2022 application requested an increase in the charge to $11.4 million, or $1.1 million over the prior-period charge, and it became effective with the first billing cycle in April 2022.
 
Transmission Rates, Transmission Cost Adjustor (“TCA”) 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 made 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, 2020, APS’s annual wholesale transmission revenue requirement for all users of its transmission system decreased by approximately $6.1 million for the 12-month period beginning June 1, 2020, in accordance with the FERC-approved formula. Of this net amount, wholesale customer rates increased by $4.8 million and retail customer rates would have decreased by approximately $10.9 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 a total of $7.4 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, 2020.

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.

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 2.5 cents for both lost residential and non-residential kWh as set forth in the 2017 Settlement Agreement. The fixed costs recoverable by the LFCR mechanism are currently 2.56 cents for lost residential and 2.68 cents for lost non-residential kWh as set forth in the 2019 Rate Case decision. The LFCR adjustment 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 14, 2020, APS filed its 2020 annual LFCR adjustment, requesting that effective May 1, 2020, the annual LFCR recovery amount be reduced to $26.6 million (a $9.6 million decrease from previous levels). On April 14, 2020, the ACC approved the 2020 LFCR adjustment as filed, effective with the first billing cycle in May 2020. 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.

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. On December 22, 2017, the Tax Act was enacted.  This legislation made significant changes to the federal income tax laws including a reduction in the corporate tax rate from 35% to 21% effective January 1, 2018.

On August 13, 2018, APS filed a request with the ACC that addressed the return of $86.5 million in tax savings to customers related to the amortization of non-depreciation related excess deferred taxes previously collected from customers (“TEAM Phase II”).  The ACC approved this request on March 13, 2019, effective the first billing cycle in April 2019 through the last billing cycle in March 2020.

On March 19, 2020, due to the COVID-19 pandemic, APS delayed the discontinuation of TEAM Phase II until the first billing cycle in May 2020.  Amounts credited to customers after the last billing cycle in March 2020 were recorded as a part of the balancing account and were addressed for recovery as part of the 2019 Rate Case. Both the timing of the reduction in revenues refunded through TEAM Phase II and the offsetting income tax benefit were recognized based upon our seasonal kWh sales pattern.

On April 10, 2019, APS filed a third request with the ACC that addressed the amortization of depreciation related excess deferred taxes over a 28.5-year period consistent with IRS normalization rules (“TEAM Phase III”).  On October 29, 2019, the ACC approved TEAM Phase III providing both (i) a one-time bill credit of $64 million which was credited to customers on their December 2019 bills, and (ii) a monthly bill credit effective the first billing cycle in December 2019 which provided an additional benefit of $39.5 million to customers through December 31, 2020. On November 20, 2020, APS filed an application to continue the TEAM Phase III monthly bill credit through the earlier of December 31, 2021, or at the conclusion of the 2019 Rate Case. On December 9, 2020, the ACC approved this request. Both the timing of the reduction in revenues refunded through the TEAM Phase III monthly bill credit and the offsetting income tax benefit were recognized based upon APS’s seasonal kWh sales pattern.

As part of the 2019 Rate Case decision, the TEAM rates were reset to zero beginning December 31, 2021, and all impacts of the Tax Act were removed from the TEAM and incorporated into APS’s base rates. The TEAM was retained to address potential changes in tax law that may be enacted prior to a decision in APS’s next rate case.
Net Metering

APS’s 2017 Rate Case Decision provides that payments by utilities for energy exported to the grid from residential DG solar facilities will be determined using a 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 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.

In accordance with the 2017 Rate Case Decision, APS filed its request for a RCP export energy price of 10.5 cents per kWh on May 1, 2019.  This price also reflects the 10% annual reduction discussed above. The new rate rider became effective on October 1, 2019. APS filed its request for a fourth-year export energy price of 9.4 cents per kWh on May 1, 2020, with a requested effective date of September 1, 2020.  This price reflects the 10% annual reduction discussed above. On September 23, 2020, the ACC approved the annual reduction of the export energy price but voted to delay the effectiveness of the reduction in export prices until October 1, 2021. In accordance with this decision, the RCP export energy price of 9.4 cents per kWh became effective on October 1, 2021. On April 29, 2022, APS filed an application to decrease the RCP price 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.

See “2016 Retail Rate Case Filing” above for information regarding an ACC order in connection with the rate review of the 2017 Rate Case Decision requiring APS to provide grandfathered net metering customers on legacy demand rates with an opportunity to switch to another legacy rate to enable such customers to benefit from legacy net metering rates.
Subpoena from Former Arizona Corporation Commissioner Robert Burns

On August 25, 2016, then-Commissioner Robert Burns, individually and not by action of the ACC as a whole, served subpoenas in APS’s then current retail rate proceeding on APS and Pinnacle West for the production of records and information relating to a range of expenditures from 2011 through 2016. The subpoenas requested information concerning marketing and advertising expenditures, charitable donations, lobbying expenses, contributions to 501(c)(3) and (c)(4) nonprofits and political contributions. The return date for the production of information was set as September 15, 2016. The subpoenas also sought testimony from Company personnel having knowledge of the material, including the Chief Executive Officer.

After various proceedings between September 2016 and March 2020, at which time Burns’ appeal of a prior dismissal by the trial court was pending before the Arizona Court of Appeals, Burns’ position as an ACC commissioner ended on January 4, 2021. Nevertheless, Burns filed a motion with the Court of Appeals arguing that the appeal was not mooted by this fact and the court should decide the matter. On March 4, 2021, the Court of Appeals found Burns’ motion to be moot because the Court of Appeals had issued an opinion deciding the matter that same day.

In its March 4, 2021, opinion, the Court of Appeals affirmed the trial court’s dismissal of Burns’ complaint, concluding that Burns could not overturn the ACC’s 4-1 vote refusing to enforce his subpoenas. On May 15, 2021, Burns filed a petition for review with the Arizona Supreme Court asking for reversal of the Court of Appeals opinion and the trial court’s judgment. APS and the ACC filed responses to Burns’ petition on July 14, 2021, requesting that the petition be denied. The Arizona Supreme Court granted Burns’ petition and heard oral argument on March 8, 2022. Pinnacle West and APS cannot predict the outcome of this matter.

Energy Modernization Plan

On January 30, 2018, the initial Energy Modernization Plan was proposed, which consisted of a series of energy policies tied to clean energy sources such as energy storage, biomass, energy efficiency, electric vehicles, and expanded energy planning through the integrated resource plan (“IRP”) process. On April 25, 2019, the ACC Staff issued an initial set of draft energy rules and subsequent drafts were filed by ACC Staff in July 2019, February 2020, and July 2020. On July 30, 2020, the ACC Staff issued final draft energy rules which proposed 100% of retail kWh sales from clean energy resources by the end of 2050. Nuclear power was defined as a clean energy resource. The proposed rules also required 50% of retail energy served be renewable by the end of 2035. A new Energy Efficiency Standard (“EES”) was not included in the proposed rules. These rules would have required utilities to file a Clean Energy Implementation Plan and Energy Efficiency Report as part of their IRP every three years beginning in 2023. In addition, these rules would have changed the IRP planning horizon from 15 years to 10 years.

The ACC discussed the final draft energy rules at several different meetings in 2020 and 2021. On November 13, 2020, the ACC approved a final draft energy rules package. On April 19, 2021, the Administrative Law Judge issued a Recommended Order and Opinion on the final energy rules. In June 2021, the ACC adopted clean energy rules based on a series of ACC amendments. The adopted rules included a final standard of 100% clean energy by 2070 and the following interim standards for carbon reduction from baseline carbon emissions level: 50% reduction by December 31, 2032; 65% reduction by December 31, 2040; 80% reduction by December 31, 2050, and 95% reduction by December 31, 2060. 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. During March and
April 2022, the ACC reviewed several proposed amendments for a proposed all-source RFP and IRP rulemaking package but delayed a vote on the amendments to a future date. APS cannot predict the outcome of this matter.

Integrated Resource Planning

ACC rules require utilities to develop 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. Based on an ACC decision, APS was originally required to file its next IRP by April 1, 2020. On February 20, 2020, the ACC extended the deadline for all utilities to file their IRPs from April 1, 2020, to June 26, 2020. On June 26, 2020, APS filed its final IRP. On July 15, 2020, the ACC extended the schedule for final ACC review of utility IRPs to February 2021. In February 2022, the ACC acknowledged APS’s IRP. 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 2030 and authorizing future rate base treatment of qualifying demand-side resources as proposed in future rate cases. See “Energy Modernization Plan” above for information regarding proposed changes to the IRP filings.

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 16, 2020, FERC issued a final rule revising FERC’s regulations implementing PURPA. The final rule went into effect on December 31, 2020.

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 and customers will have four months to pay back their deposit and any remaining delinquent amounts. 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, and APS has employed the calendar method for its disconnection moratorium.

In accordance with the ACC service disconnection rules, APS now suspends 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 beginning 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. APS is continuing to apply Late Fee Waivers for residential customers; however, effective May 1, 2022, late payment fees for commercial and industrial customers were reinstated. 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 a bill that would nullify a 24-year-old electric deregulation law that has been in place since 1998. The bill was signed by the Arizona Governor and will take effect September 23, 2022. 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 and intends to intervene to contest it. 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 his insights on the applicable law.

On October 28, 2021, an ACC Commissioner docketed a letter directing ACC Staff and interested stakeholders to design a 200-300 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.
Rate Plan Comparison Tool and Investigation

On November 14, 2019, APS learned that its rate plan comparison tool was not functioning as intended due to an integration error between the tool and APS’s meter data management system. APS immediately removed the tool from its website and notified the ACC. The purpose of the tool was to provide customers with a rate plan recommendation based upon historical usage data. Upon investigation, APS determined that the error may have affected rate plan recommendations to customers between February 4, 2019, and November 14, 2019. By the middle of May 2020, APS provided refunds to approximately 13,000 potentially impacted customers equal to the difference between what they paid for electricity and the amount they would have paid had they selected their most economical rate, as applicable, and a $25 payment for any inconvenience that the customer may have experienced. The refunds and payment for inconvenience being provided did not have a material impact on APS’s financial statements. In February 2020, APS launched a new online rate comparison tool. The ACC hired an outside consultant to evaluate the extent of the error and the overall effectiveness of the tool. On August 20, 2020, ACC Staff filed the outside consultant’s report on APS’s rate comparison tool. The report concluded APS’s new rate comparison tool is working as intended. The report also identified a small population of additional customers that may have been affected by the error and APS has provided refunds and the $25 inconvenience payment to approximately 3,800 additional customers. These additional refunds and payment for inconvenience did not have a material impact on APS’s financial statements. On September 28, 2020, the ACC discussed this report but did not take any action. APS cannot predict whether additional inquiries or actions may be taken by the ACC.

APS received civil investigative demands from the Office of the Arizona Attorney General, Civil Litigation Division, Consumer Protection & Advocacy Section (“Attorney General”) seeking information pertaining to the rate plan comparison tool offered to APS customers and other related issues including implementation of rates from the 2017 Settlement Agreement and its Customer Education and Outreach Plan associated with the 2017 Settlement Agreement. APS fully cooperated with the Attorney General’s Office in this matter. On February 22, 2021, APS entered into a consent agreement with the Attorney General as a way to settle the matter. The settlement resulted in APS paying $24.75 million, approximately $24 million of which has been returned to customers as restitution. While this matter has been resolved with the Attorney General, APS cannot predict whether additional inquiries or actions may be taken by the ACC.

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 and the appeal is proceeding in the normal course. Based on the partial recovery of these investments and cost deferrals in current rates and the uncertainty of the outcome of the legal appeals process, APS has not recorded an impairment or write-off relating to the SCR plant investments or deferrals as of June 30, 2022. If the 2019 Rate Case decision to disallow $215.5 million of the SCRs is ultimately upheld, APS will be required to record a charge to its results of operations, net of tax, of approximately $154.4 million. We cannot predict the outcome of the legal challenges nor the timing of when this matter will be resolved. 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 has committed to end the use of coal at its remaining Cholla units by 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, $39.5 million as of June 30, 2022, 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, $57.4 million as of June 30, 2022, 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, $15.4 million as of June 30, 2022. The disallowed recovery of 15% of the annual amortization does not have a material impact on APS financial statements.
Regulatory Assets and Liabilities 

The detail of regulatory assets is as follows (dollars in thousands): 
 Amortization ThroughJune 30, 2022December 31, 2021
 CurrentNon-CurrentCurrentNon-Current
Pension(a)$— $514,330 $— $509,751 
Deferred fuel and purchased power (b) (c)2023390,013 — 388,148 — 
Income taxes — allowance for funds used during construction (“AFUDC”) equity20527,625 167,644 7,625 164,768 
Ocotillo deferral (e)20319,507 133,390 9,507 138,143 
Retired power plant costs203315,157 91,113 15,160 99,681 
SCR deferral (e)(f)20318,147 93,551 8,147 97,624 
Deferred property taxes20278,569 36,772 8,569 41,057 
Lost fixed cost recovery (b)202343,788 — 63,889 — 
Deferred compensation2036— 34,251 — 33,997 
Income taxes — investment tax credit basis adjustment2056826 23,606 1,129 23,639 
Palo Verde VIEs (Note 6)2046— 21,013 — 21,094 
Four Corners cost deferral20248,077 11,960 8,077 15,998 
Coal reclamation20262,978 12,372 2,978 13,862 
Active Union Medical Trust(g)— 13,704 — 1,175 
Loss on reacquired debt20381,648 8,579 1,648 9,372 
Mead-Phoenix transmission line contributions in aid of construction (“CIAC”)2050332 8,882 332 9,048 
TCA balancing account (b)20238,805 — 170 3,663 
Tax expense adjustor mechanism (b)2031656 5,518 656 5,845 
Tax expense of Medicare subsidy20241,235 1,968 1,235 2,469 
OtherVarious1,813 2,003 1,254 1,801 
Total regulatory assets (d) $509,176 $1,180,656 $518,524 $1,192,987 

(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. See Note 5 for further discussion.
(b)See “Cost Recovery Mechanisms” discussion above.
(c)Subject to a carrying charge.
(d)There are no regulatory assets for which the ACC has allowed recovery of costs, but not allowed a return by exclusion from rate base.  FERC rates are set using a formula rate as described in “Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters.”
(e)Balance includes amounts for future regulatory consideration and amortization period determination.
(f)See “Four Corners SCR Cost Recovery” discussion above.
(g)Collected in retail rates.
The detail of regulatory liabilities is as follows (dollars in thousands):
 
 Amortization ThroughJune 30, 2022December 31, 2021
 CurrentNon-CurrentCurrentNon-Current
Excess deferred income taxes — ACC - Tax Act (a)2046$40,903 $954,939 $40,903 $971,545 
Excess deferred income taxes — FERC - Tax Act (a)20587,239 218,939 7,239 221,877 
Asset retirement obligations2057— 376,575 — 614,683 
Other postretirement benefits(d)50,624 305,045 37,789 337,027 
Deferred fuel and purchased power — mark-to-market (Note 7)2024173,712 111,847 60,693 46,908 
Removal costs(c)57,454 55,570 69,476 50,104 
Income taxes — change in rates20512,876 63,636 2,876 64,802 
Four Corners coal reclamation20382,316 50,860 2,316 53,076 
Income taxes — deferred investment tax credit20562,264 46,663 2,264 47,337 
Spent nuclear fuel20276,730 35,227 6,701 38,581 
FERC transmission true up (b)202429,238 3,620 21,379 12,924 
Renewable energy standard (b)202425,401 492 38,453 187 
Property tax deferral (e)20244,671 13,186 4,671 15,521 
Sundance maintenance2031— 15,345 — 13,797 
Demand side management (b)2023— 9,214 — 5,417 
Tax expense adjustor mechanism (b) (e)N/A— 4,835 — 4,835 
OtherVarious679 2,155 1,511 592 
Total regulatory liabilities $404,107 $2,268,148 $296,271 $2,499,213 

(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 guidance, APS accrues removal costs for its regulated assets, even if there is no legal obligation for removal.
(d)See Note 5.
(e)Balance includes amounts for future regulatory consideration and amortization period determination.
v3.22.2
Retirement Plans and Other Postretirement Benefits
 6 Months Ended
Jun. 30, 2022
Retirement Benefits [Abstract]  
Retirement Plans and Other Postretirement Benefits Retirement Plans and Other Postretirement Benefits
 
Pinnacle West sponsors a qualified defined benefit and account balance pension plan, a non-qualified supplemental excess benefit retirement plan, and other postretirement benefit plans for the employees of Pinnacle West and our subsidiaries.  The other postretirement benefit plans include a group life and medical plan and a post-65 retiree health reimbursement arrangement (“HRA”). Pinnacle West uses a December 31 measurement date each year for its pension and other postretirement benefit plans.  The market-related value of our plan assets is their fair value at the measurement date.
The following table provides details of the plans’ net periodic benefit costs and the portion of these costs charged to expense (including administrative costs and excluding amounts capitalized as overhead construction or billed to electric plant participants) (dollars in thousands):
 Pension BenefitsOther Benefits
 Three Months Ended
June 30,		Six Months Ended
June 30,		Three Months Ended
June 30,		Six Months Ended
June 30,
 20222021202220212022202120222021
Service cost — benefits earned during the period$13,406 $14,939 $27,737 $30,618 $4,017 $4,341 $8,235 $8,898 
Non-service costs (credits):
Interest cost on benefit obligation26,723 24,614 53,746 49,283 4,283 4,095 8,746 8,257 
Expected return on plan assets(46,494)(50,706)(92,888)(101,314)(11,511)(10,361)(23,021)(20,722)
  Amortization of:       
  Prior service credit— — — — (9,447)(9,427)(18,894)(18,854)
  Net actuarial loss (gain)3,989 3,989 8,757 7,974 (3,436)(2,641)(6,418)(5,046)
Net periodic benefit$(2,376)$(7,164)$(2,648)$(13,439)$(16,094)$(13,993)$(31,352)$(27,467)
Portion of benefit charged to expense$(4,722)$(8,614)$(8,012)$(16,625)$(11,523)$(9,608)$(22,418)$(19,136)
 
Contributions
 
We have not made any voluntary contributions to our pension plan year-to-date in 2022. The minimum required contributions for the pension plan are zero and we do not expect to make any contributions in 2022, 2023 or 2024. With regard to contributions to our other postretirement benefit plan, we have not made a contribution year-to-date in 2022 and do not expect to make any contributions in 2022, 2023 or 2024.
v3.22.2
Palo Verde Sale Leaseback Variable Interest Entities
 6 Months Ended
Jun. 30, 2022
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 2022 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 for the three and six months ended June 30, 2022, of $4 million and $9 million respectively, and for the three and six months ended June 30, 2021 of $4 million and $9 million, 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 Condensed Consolidated Balance Sheets at June 30, 2022, and December 31, 2021, include the following amounts relating to the VIEs (dollars in thousands):

June 30, 2022December 31, 2021
Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation$92,231 $94,166 
Equity — Noncontrolling interests113,244 115,260 
 
Assets of the VIEs are restricted and may only be used for payment to the noncontrolling interest holders. These assets are reported on our condensed consolidated financial statements.
 
APS is exposed to losses relating to these VIEs upon the occurrence of certain events that APS does not consider to be reasonably likely to occur.  Under certain circumstances (for example, the Nuclear Regulatory Commission (“NRC”) issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), APS would be required to make specified payments to the VIEs’ noncontrolling equity participants and take title to the leased Unit 2 interests, which, if appropriate, may be required to be written down in value.  If such an event were to occur during the lease periods, APS may be required to pay the noncontrolling equity participants approximately $315 million beginning in 2022, and up to $501 million over the lease 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.
v3.22.2
Derivative Accounting
 6 Months Ended
Jun. 30, 2022
Derivative Instruments and Hedging Activities Disclosure [Abstract]  
Derivative Accounting Derivative Accounting
 
Derivative financial instruments are used to manage exposure to commodity price and transportation costs of electricity, natural gas, emissions allowances, and interest rates.  Risks associated with market volatility are managed by utilizing various physical and financial derivative instruments, including futures, forwards, options and swaps.  As part of our overall risk management program, we may use derivative instruments to hedge purchases and sales of electricity and natural gas.  Derivative instruments that meet certain hedge accounting criteria may be designated as cash flow hedges and are used to limit our exposure to cash flow variability on forecasted transactions.  The changes in market value of such instruments have a high correlation to price changes in the hedged transactions.  Derivative instruments are also entered into for economic hedging purposes.  While economic hedges may mitigate exposure to fluctuations in commodity prices, these instruments have not been designated as accounting hedges.  Contracts that have the same terms (quantities, delivery points and delivery periods) and for which power does not flow are netted, which reduces both revenues and fuel and purchased power costs in our Condensed Consolidated Statements of Income, but does not impact our financial condition, net income or cash flows.
 
Our derivative instruments, excluding those qualifying for a scope exception, are recorded on the balance sheets as an asset or liability and are measured at fair value.  See Note 11 for a discussion of fair value measurements.  Derivative instruments may qualify for the normal purchases and normal sales scope exception if they require physical delivery, and the quantities represent those transacted in the normal course of business.  Derivative instruments qualifying for the normal purchases and sales scope exception are accounted for under the accrual method of accounting and excluded from our derivative instrument discussion and disclosures below.
 
For its regulated operations, APS defers for future rate treatment 100% of the unrealized gains and losses on derivatives pursuant to the PSA mechanism that would otherwise be recognized in income.  Realized gains and losses on derivatives are deferred in accordance with the PSA to the extent the amounts are above or below the Base Fuel Rate. See Note 4.  Gains and losses from 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 derivatives, which represent both purchases and sales (does not reflect net position): 
Quantity
CommodityUnit of MeasureJune 30, 2022December 31, 2021
PowerGWh1,208 — 
GasBillion cubic feet168 155 
 
Gains and Losses from Derivative Instruments
 
For the three and six months ended June 30, 2022 and 2021, APS had no derivative instruments in designated accounting hedging relationships.
 
The following table provides information about gains and losses from derivative instruments not designated as accounting hedging instruments (dollars in thousands):

 Financial Statement LocationThree Months Ended
June 30,		Six Months Ended
June 30,
Commodity Contracts2022202120222021
Net Gain Recognized in IncomeFuel and purchased power (a)$62,525 $95,116 $286,267 $121,975 
 
(a)Amounts are before the effect of PSA deferrals.
 
Derivative Instruments in the Condensed Consolidated Balance Sheets
 
Our derivative transactions are typically executed under standardized or customized agreements, which include collateral requirements and, in the event of a default, would allow for the netting of positive and negative exposures associated with a single counterparty.  Agreements that allow for the offsetting of positive and negative exposures associated with a single counterparty are considered master netting arrangements.  Transactions with counterparties that have master netting arrangements are offset and reported net on the Condensed Consolidated Balance Sheets.  Transactions that do not allow for offsetting of positive and negative positions are reported gross on the Condensed Consolidated Balance Sheets.
 
We do not offset a counterparty’s current derivative contracts with the counterparty’s non-current 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 our 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 our Condensed Consolidated Balance Sheets.
As of June 30, 2022:
(dollars in thousands)
Gross
 Recognized
 Derivatives
 (a)
Amounts
Offset
 (b)
Net
 Recognized
 Derivatives
Other
 (c)
Amount Reported on Balance Sheets
Current assets$177,765 $(40,787)$136,978 $50 $137,028 
Investments and other assets111,847 — 111,847 — 111,847 
Total assets289,612 (40,787)248,825 50 248,875 
Current liabilities(4,053)357 (3,696)(1,900)(5,596)
Total$285,559 $(40,430)$245,129 $(1,850)$243,279 

(a)All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)Includes cash collateral received from counterparties of $40,430 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 or received in excess of the recognized derivative instrument. Includes cash collateral received from counterparties of $1,900 and cash margin provided to counterparties of $50.

As of December 31, 2021:
(dollars in thousands)
Gross
Recognized
Derivatives
 (a)
Amounts
Offset
(b)
Net
 Recognized
 Derivatives
Other
 (c)
Amount
Reported on
Balance Sheets
Current assets$66,777 $(3,346)$63,431 $50 $63,481 
Investments and other assets48,302 (1,394)46,908 — 46,908 
Total assets115,079 (4,740)110,339 50 110,389 
Current liabilities(6,084)3,346 (2,738)(1,635)(4,373)
Deferred credits and other(1,394)1,394 — — — 
Total liabilities(7,478)4,740 (2,738)(1,635)(4,373)
Total$107,601 $— $107,601 $(1,585)$106,016 

(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 $1,635 and cash margin provided to counterparties of $50.
Credit Risk and Credit Related Contingent Features
 
We are exposed to losses in the event of nonperformance or nonpayment by counterparties and have risk management contracts with many counterparties. As of June 30, 2022, we have one counterparty for which our exposure represents approximately 19% of Pinnacle West’s $249 million of risk management assets. This exposure relates to a master agreement with the counterparty, and the counterparty is rated as investment grade. 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 companies 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 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 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 derivative instruments that have credit-risk-related contingent features (dollars in thousands):
 June 30, 2022
Aggregate fair value of derivative instruments in a net liability position$1,882 
Additional cash collateral in the event credit-risk-related contingent features were fully triggered (a)883 
(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 have energy-related non-derivative instrument contracts with investment grade credit-related contingent features, which could require us to post additional collateral of approximately $77 million if our debt credit ratings were to fall below investment grade.
v3.22.2
Commitments and Contingencies
 6 Months Ended
Jun. 30, 2022
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 United States Department of Energy (“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, as it was required to do 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, stipulating to a dismissal of the lawsuit and payment by DOE to 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, as amended, provides APS with a method for submitting claims and getting recovery for costs incurred through December 31, 2022.

APS has submitted seven claims pursuant to the terms of the August 18, 2014 settlement agreement, for seven separate time periods during July 1, 2011 through June 30, 2020. The DOE has approved and paid $111.8 million for these claims (APS’s share is $32.5 million). The amounts recovered were primarily recorded as adjustments to a regulatory liability and had no impact on reported net income. In accordance with the 2017 Rate Case Decision, this regulatory liability is being refunded to customers. See Note 4. On November 1, 2021, APS filed its eighth claim pursuant to the terms of the August 18, 2014 settlement agreement in the amount of $12.2 million (APS’s share is $3.6 million). On March 22, 2022, the DOE approved a payment of $12.1 million (APS’s share is $3.5 million) and on April 19, 2022, APS received this payment.

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.  In accordance with the Price-Anderson Act, the Palo Verde participants are insured against public liability for a nuclear incident of up to approximately $13.5 billion per occurrence. Palo Verde maintains the maximum available nuclear liability insurance in the amount of $450 million, which is provided by American Nuclear Insurers (“ANI”).  The remaining balance of approximately $13.1 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 $137.6 million, subject to a maximum annual premium of approximately $20.5 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 $120.1 million, with a maximum annual retrospective premium of approximately $17.9 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 $22.3 million for each retrospective premium assessment declared by NEIL’s Board of Directors due to losses.  In addition, NEIL policies contain rating triggers that would result in APS providing approximately $62.8 million of collateral assurance within 20 business days of a rating downgrade to non-investment grade.  The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions, sublimits and exclusions.

Contractual Obligations

As of June 30, 2022, our fuel and purchased power and purchase obligation commitments have increased from the information provided in our 2021 Form 10-K. The increase is primarily due to new purchased power and energy storage commitments of approximately $1.2 billion. The majority of the changes relate to 2024 and thereafter. This amount includes approximately $500 million of commitments relating to a new purchased power lease contract that is included in our non-commenced lease discussion below.

At June 30, 2022, we have various lease arrangements that have been executed but have not yet commenced. These arrangements primarily relate to energy storage assets, with expected lease commencement dates ranging from September 2022 through June 2024, with terms expiring through May 2044. We expect the total fixed consideration paid for these arrangements, which includes both lease and nonlease payments, will approximate $1.8 billion over the term of the arrangements. For additional information regarding our lease commitments see our 2021 Form 10-K. Certain of these non-commenced lease agreements were previously expected to commence in June 2022; however, during the second quarter of 2022 due to delays impacting the leased asset’s in-service date, the lease commencement date has been delayed from June 2022 to September 2022. APS is currently working with the lessor to determine if this revised lease commencement date will be achieved.

Other than the items described above, there have been no material changes, as of June 30, 2022, outside the normal course of business in contractual obligations from the information provided in our 2021 Form 10-K. See Note 3 for discussion regarding changes in our short-term and long-term debt obligations.

Superfund and Other Related Matters
 
The Comprehensive Environmental Response Compensation and Liability Act (“Superfund” or “CERCLA”) establishes liability for the cleanup of hazardous substances found contaminating the soil, water or air.  Those who released, generated, transported to or disposed of hazardous substances at a contaminated site are among the parties who are potentially responsible (each a “PRP”).  PRPs may be strictly, jointly, and severally liable for clean-up.  On September 3, 2003, EPA advised APS that EPA considers APS to be a PRP in the Motorola 52nd Street Superfund Site, Operable Unit 3 (“OU3”) in Phoenix, Arizona.  APS has facilities that are within this Superfund site.  APS and Pinnacle West have agreed with EPA to perform certain investigative activities of the APS facilities within OU3.  In addition, on September 23, 2009, APS agreed with EPA and one other PRP to voluntarily assist with the funding and management of the site-wide groundwater remedial investigation and feasibility study (“RI/FS”).  Based upon discussions between the OU3 working group parties and EPA, along with the results of recent technical analyses prepared by the OU3 working group to supplement the RI/FS for OU3, APS anticipates finalizing the RI/FS later in 2022. APS’s estimated costs related to this investigation and study are approximately $3 million.  APS anticipates incurring additional expenditures in the future, but because the overall investigation is not complete and ultimate remediation requirements are not yet finalized, at the present time expenditures related to this matter cannot be reasonably estimated.
 
On August 6, 2013, the Roosevelt Irrigation District (“RID”) filed a lawsuit in Arizona District Court against APS and 24 other defendants, alleging that RID’s groundwater wells were contaminated by the release of hazardous substances from facilities owned or operated by the defendants.  The lawsuit also alleges that, under Superfund laws, the defendants are jointly and severally liable to RID.  The allegations against APS arise out of APS’s current and former ownership of facilities in and around OU3.  As part of a state governmental investigation into groundwater contamination in this area, on January 25, 2015, the Arizona Department of Environmental Quality (“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. On December 16, 2016, two RID environmental and engineering contractors filed an ancillary lawsuit for recovery of costs against APS and the other defendants in the RID litigation. That same day, another RID service provider filed an additional ancillary CERCLA lawsuit against certain of the defendants in the main RID litigation but excluded APS and certain other parties as named defendants. Because the ancillary lawsuits concern past costs allegedly incurred by these RID vendors, which were ruled unrecoverable directly by RID in November of 2016, the additional lawsuits do not increase APS’s exposure or risk related to these matters.

On April 5, 2018, RID and the defendants in that particular litigation executed a settlement agreement, fully resolving RID’s CERCLA claims concerning both past and future cost recovery. APS’s share of this settlement was immaterial. In addition, the two environmental and engineering vendors voluntarily dismissed their lawsuit against APS and the other named defendants without prejudice. An order to this effect was entered on April 17, 2018. With this disposition of the case, the vendors may file their lawsuit again in the future. On August 16, 2019, Maricopa County, one of the three direct defendants in the service provider lawsuit, filed a third-party complaint seeking contribution for its liability, if any, from APS and 28 other third-party defendants. We are unable to predict the outcome of these matters; however, we do not expect the outcome to have a material impact on our financial position, results of operations or cash flows.

On February 28, 2022, EPA provided APS with a request for information under CERCLA related to APS’s Ocotillo power plant site located in Tempe, Arizona. In particular, EPA seeks information from APS regarding APS’s use, storage, and disposal of substances containing per-and polyfluoroalkyl (“PFAS”) compounds at the Ocotillo power plant site in order to aid EPA’s investigation into actual or threatened releases of PFAS into groundwater within the South Indian Bend Wash (“SIBW”) Superfund site. The SIBW Superfund site includes the APS Ocotillo power plant site. On April 29, 2022, APS filed its response to this information request. At the present time, we are unable to predict the outcome of this matter and expenditures related to this matter cannot be reasonably estimated.

Arizona Attorney General Matter

APS received civil investigative demands from the Attorney General seeking information pertaining to the rate plan comparison tool offered to APS customers and other related issues including implementation of rates from the 2017 Settlement Agreement and its Customer Education and Outreach Plan associated with the 2017 Settlement Agreement. APS fully cooperated with the Attorney General’s Office in this matter. On February 22, 2021, APS entered into a consent agreement with the Attorney General as a way to settle the matter. The settlement resulted in APS paying $24.75 million, approximately $24 million of which was returned to customers as restitution.

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 and the appeal is proceeding in the normal course. Based on the partial recovery of these investments and cost deferrals in current rates and the uncertainty of the outcome of the legal appeals process, APS has not recorded an impairment or write-off relating to the SCR plant investments or deferrals as of June 30, 2022. If the 2019 Rate Case decision to disallow $215.5 million of the SCRs is ultimately upheld, APS will be required to record a charge to its results of operations, net of tax, of approximately $154.4 million. We cannot predict the outcome of the legal challenges nor the timing of when this matter will be resolved. See Note 4 for additional information regarding the Four Corners SCR cost recovery.

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 involve material compliance costs to APS.
 
Regional Haze Rules.  APS has received the final rulemaking imposing pollution control requirements on Four Corners. EPA required the plant to install pollution control equipment that constitutes best available retrofit technology (“BART”) to lessen the impacts of emissions on visibility surrounding the plant. Based on EPA’s final standards, APS’s 63% share of the cost of required controls for Four Corners Units 4 and 5 was approximately $400 million, which has been incurred. 

In addition, EPA issued a final rule for Regional Haze compliance at Cholla that does not involve the installation of new pollution controls and that will replace an earlier BART determination for this facility. See “Cholla” in Note 4 for information regarding future plans for Cholla and details related to the resulting regulatory asset and see “Four Corners SCR Cost Recovery” above regarding recovery of the Four Corners SCR project.
 
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 recent 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, including supporting the passage of new state legislation 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. 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.

•On November 4, 2019, EPA also proposed to change the manner by which facilities that have committed to cease burning coal in the near-term may qualify for alternative closure. Such qualification would allow CCR disposal units at these plants to continue operating, even though they would otherwise be subject to forced closure under the federal CCR regulations. EPA’s July 29, 2020, final regulation adopted this proposal and now requires explicit EPA approval for facilities to utilize an alternative closure deadline. With respect to the Cholla facility, APS’s application for alternative closure was submitted to EPA on November 30, 2020, and is currently 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. EPA began taking action on these applications in January 2022, deeming APS’s application for the Cholla facility “complete.” We expect to have a proposed decision from EPA regarding Cholla in 2023.

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

APS currently disposes of CCR in ash ponds and dry storage areas at Cholla and Four Corners. APS estimates that its share of incremental costs to comply with the CCR rule for Four Corners is approximately $30 million and its share of incremental costs to comply with the CCR rule for Cholla is approximately $16 million. The Navajo Plant disposed of CCR only in a dry landfill storage area. To comply with the CCR rule for the Navajo Plant, APS’s share of incremental costs was approximately $1 million, which has been incurred. 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. Based on the work performed to date, APS currently estimates that its share of corrective action and monitoring costs at Four Corners will likely range from $10 million to $15 million, which would be incurred over 30 years. The analysis needed to perform a similar cost estimate for Cholla remains ongoing at this time. 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 process, we cannot predict any ultimate impacts to the Company; however, at this time we do not believe the cost estimates for Cholla and any potential change to the cost estimate for Four Corners would have a material impact on our financial position, results of operations or cash flows.

EPA Climate Regulations. On June 19, 2019, EPA took final action on its proposals to repeal EPA’s 2015 Clean Power Plan (“CPP”) and replace those regulations with a new rule, the Affordable Clean Energy (“ACE”) regulations. EPA originally finalized the CPP on August 3, 2015, and such rules would have had far broader impact on the electric power sector than the ACE regulations. On January 19, 2021, the U.S. Court of Appeals for the D.C. Circuit vacated the ACE regulations and remanded them back to EPA to develop new existing power plant carbon regulations consistent with the court’s ruling. That ruling endorsed an expansive view of the federal Clean Air Act consistent with EPA’s 2015 CPP. Thereafter, on June 30, 2022, the U.S. Supreme Court reversed the D.C. Circuit’s ruling, holding that existing power plant carbon regulations on the scale of the CPP are not authorized by the federal Clean Air Act. While the Biden administration has nonetheless expressed an intent to continue its effort to regulate carbon emissions in this sector more aggressively under the Clean Air Act (consistent with the U.S. Supreme Court’s June 30 ruling), we cannot at this time predict the outcome of pending EPA rulemaking proceedings related to the regulation of carbon emissions from existing power plants.

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 our coal 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 the environmental groups had filed a petition for review of the EAB’s decision with the U.S. Court of Appeals for the Ninth Circuit, on May 2, 2022, the parties to the litigation executed a settlement agreement. We do not anticipate that this agreement will have a material impact on our financial position, results of operations, or cash flows.

Four Corners — 4CA Matter

On July 6, 2016, 4CA purchased El Paso’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.

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 June 30, 2022, standby letters of credit totaled $9 million and expire in 2023. As of June 30, 2022, surety bonds expiring through 2023 totaled $6 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 June 30, 2022. 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 BCE’s acquisition of minority ownership positions in the Clear Creek and Nobles 2 wind farms, Pinnacle West has issued parental guarantees to guarantee the obligations of BCE subsidiaries to make required equity contributions to fund project construction (the “Equity Contribution Guarantees”) and 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. The Equity Contribution Guarantees remaining as of June 30, 2022, are immaterial in amount and the PTC Guarantees (approximately $35 million as of June 30, 2022) are currently expected to be terminated ten years following the commercial operation date of the applicable project.
In connection with the credit agreement entered into by Los Alamitos on February 11, 2022, Pinnacle West has guaranteed the full amount of the equity bridge loan under the credit facility. See Note 3 for additional details.
v3.22.2
Other Income and Other Expense
 6 Months Ended
Jun. 30, 2022
Other Income and Expenses [Abstract]  
Other Income and Other Expense Other Income and Other Expense The following table provides detail of Pinnacle West’s Consolidated other income and other expense (dollars in thousands):
Three Months Ended
June 30,		Six Months Ended
June 30,
2022202120222021
Other income:
Interest income$1,691 $1,687 $3,333 $3,635 
Debt return on Four Corners SCR deferrals (Note 4)— 4,089 — 8,175 
Debt return on Ocotillo modernization project (Note 4)— 6,391 — 12,783 
Miscellaneous(9)40 53 43 
Total other income$1,682 $12,207 $3,386 $24,636 
Other expense:
Non-operating costs(3,701)(4,102)(6,154)(6,039)
Investment losses — net(575)(431)(1,256)(774)
Miscellaneous(308)(651)(596)(2,224)
Total other expense$(4,584)$(5,184)$(8,006)$(9,037)
The following table provides detail of APS’s other income and other expense (dollars in thousands):

 Three Months Ended
June 30,		Six Months Ended
June 30,
 2022202120222021
Other income:    
Interest income$1,396 $1,047 $2,495 $2,528 
Debt return on Four Corners SCR deferrals (Note 4)— 4,089 — 8,175 
Debt return on Ocotillo modernization project (Note 4)— 6,391 — 12,783 
Miscellaneous— 36 53 37 
Total other income$1,396 $11,563 $2,548 $23,523 
Other expense:  
Non-operating costs(2,477)(3,615)(4,038)(5,392)
Miscellaneous(309)(646)(596)(2,219)
Total other expense$(2,786)$(4,261)$(4,634)$(7,611)
v3.22.2
Earnings Per Share
 6 Months Ended
Jun. 30, 2022
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):
 Three Months Ended June 30,Six Months Ended June 30,
 2022202120222021
Net income attributable to common shareholders$164,312 $215,697 $181,268 $251,338 
Weighted average common shares outstanding — basic
113,172 112,882 113,137 112,855 
Net effect of dilutive securities:
Contingently issuable performance shares and restricted stock units
197 341 195 303 
Weighted average common shares outstanding — diluted
113,369 113,223 113,332 113,158 
Earnings per weighted-average common share outstanding
Net income attributable to common shareholders — basic
$1.45 $1.91 $1.60 $2.23 
Net income attributable to common shareholders — diluted
$1.45 $1.91 $1.60 $2.22 
v3.22.2
Fair Value Measurements
 6 Months Ended
Jun. 30, 2022
Fair Value Disclosures [Abstract]  
Fair Value Measurements Fair Value Measurements
 
We classify our assets and liabilities that are carried at fair value within the fair value hierarchy.  This hierarchy ranks the quality and reliability of the inputs used to determine fair values, which are then classified and disclosed in one of three categories.  The three levels of the fair value hierarchy are:
 
Level 1 — Inputs are unadjusted quoted prices in active markets for identical assets or liabilities at the measurement date.

Level 2 — Other significant observable inputs, including quoted prices in active markets for similar assets or liabilities; quoted prices in markets that are not active, and model-derived valuations whose inputs are observable (such as yield curves).

Level 3 — Valuation models with significant unobservable inputs that are supported by little or no market activity.  Instruments in this category may include long-dated derivative transactions where valuations are unobservable due to the length of the transaction, options, and transactions in locations where observable market data does not exist.  The valuation models we employ utilize spot prices, forward prices, historical market data and other factors to forecast future prices.

Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  Thus, a valuation may be classified in Level 3 even though the valuation may include significant inputs that are readily observable.  We maximize the use of observable inputs and minimize the use of unobservable inputs.  We rely primarily on the market approach of using prices and other market information for identical and/or comparable assets and liabilities.  If market data is not readily available, inputs may reflect our own assumptions about the inputs market participants would use.  Our assessment of the inputs and the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities as well as their placement within the fair value hierarchy levels.  We assess whether a market is active by obtaining observable broker quotes, reviewing actual market activity, and assessing the volume of transactions.  We consider broker quotes observable inputs when the quote is
binding on the broker, we can validate the quote with market activity, or we can determine that the inputs the broker used to arrive at the quoted price are observable.

Certain instruments have been valued using the concept of Net Asset Value (“NAV”) as a practical expedient. These instruments are typically structured as investment companies offering shares or units to multiple investors for the purpose of providing a return. These instruments are similar to mutual funds; however, their NAV is generally not published and publicly available, nor are these instruments traded on an exchange. Instruments valued using NAV as a practical expedient are included in our fair value disclosures; however, in accordance with GAAP are not classified within the fair value hierarchy levels.

Recurring Fair Value Measurements
 
We apply recurring fair value measurements to cash equivalents, derivative instruments, and investments held in the nuclear decommissioning trusts and other special use funds. On an annual basis, we apply fair value measurements to plan assets held in our retirement and other benefit plans.  See Note 8 in the 2021 Form 10-K for fair value discussion of plan assets held in our retirement and other benefit plans.
 
Cash Equivalents
 
Cash equivalents represent certain investments in money market funds that are valued using quoted prices in active markets.

Risk Management Activities — 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.  Our long-dated energy transactions consist of observable valuations for the near-term portion and unobservable valuations for the long-term portions of the transaction.  We rely primarily on broker quotes to value these instruments.  When our valuations utilize broker quotes, we perform various control procedures to ensure the quote has been developed consistent with fair value accounting guidance.  These controls include assessing the quote for reasonableness by comparison against other broker quotes, reviewing historical price relationships, and assessing market activity.  When broker quotes are not available, the primary valuation technique used to calculate the fair value is the extrapolation of forward pricing curves using observable market data for more liquid delivery points in the same region and actual transactions at more illiquid delivery points.
 
When the unobservable portion is significant to the overall valuation of the transaction, the entire transaction is classified as Level 3. 
 
Investments Held in Nuclear Decommissioning Trusts and Other Special Use Funds

The nuclear decommissioning trusts and other special use funds invest in fixed income and equity securities. Other special use funds include the coal reclamation escrow account and the active union employee medical account. See Note 12 for additional discussion about our investment accounts.

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

Fixed Income Securities

Fixed income securities issued by the U.S. Treasury are valued using quoted active market prices and are typically classified as Level 1.  Fixed income securities issued by corporations, municipalities, and other agencies, including mortgage-backed instruments, are valued using quoted inactive market prices, quoted active market prices for similar securities, or by utilizing calculations which incorporate observable inputs such as yield curves and spreads relative to such yield curves.  These fixed income instruments are classified as Level 2.  Whenever possible, multiple market quotes are obtained which enables a cross-check validation.  A primary price source is identified based on asset type, class, or issue of securities.

Fixed income securities may also include short-term investments in certificates of deposit, variable rate notes, time deposit accounts, U.S. Treasury and Agency obligations, U.S. Treasury repurchase agreements, commercial paper, and other short-term instruments. These instruments are valued using active market prices or utilizing observable inputs described above.

Equity Securities

The nuclear decommissioning trusts’ equity security investments are held indirectly through commingled funds.  The commingled funds are valued using the funds’ NAV as a practical expedient. The funds’ NAV is primarily derived from the quoted active market prices of the underlying equity securities held by the funds. We may transact in these commingled funds on a semi-monthly basis at the NAV.  The commingled funds are maintained by a bank and hold investments in accordance with the stated objective of tracking the performance of the S&P 500 Index.  Because the commingled funds’ shares are offered to a limited group of investors, they are not considered to be traded in an active market. As these instruments are valued using NAV, as a practical expedient, they have not been classified within the fair value hierarchy.

The nuclear decommissioning trusts and other special use funds may also hold equity securities that include exchange traded mutual funds and money market accounts for short-term liquidity purposes. These short-term, highly-liquid investments are valued using active market prices.
Fair Value Tables
 
The following table presents the fair value at June 30, 2022, of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):
 
 Level 1Level 2Level 3Other Total
Assets      
Risk management activities — derivative instruments:
Commodity contracts$— $281,107 $8,505 $(40,737)(a)$248,875 
Nuclear decommissioning trust:
Equity securities12,773 — — 1,401 (b)14,174 
U.S. commingled equity funds— — — 460,619 (c)460,619 
U.S. Treasury debt211,284 — — —  211,284 
Corporate debt— 177,297 — —  177,297 
Mortgage-backed securities— 135,858 — —  135,858 
Municipal bonds— 67,943 — —  67,943 
Other fixed income— 8,913 — —  8,913 
Subtotal nuclear decommissioning trust224,057 390,011 — 462,020 1,076,088 
Other special use funds:
Equity securities29,093 — — 938 (b)30,031 
U.S. Treasury debt310,667 — — — 310,667 
Municipal bonds— 5,708 — — 5,708 
Subtotal other special use funds339,760 5,708 — 938 346,406 
Total assets$563,817 $676,826 $8,505 $422,221 $1,671,369 
Liabilities      
Risk management activities — derivative instruments:      
Commodity contracts$— $(94)$(3,959)$(1,543)(a)$(5,596)

(a)Represents counterparty netting, margin, and collateral. See Note 7.
(b)Represents net pending securities sales and purchases.
(c)Valued using NAV as a practical expedient and, therefore, are not classified in the fair value hierarchy.
The following table presents the fair value at December 31, 2021, of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):
 
 Level 1Level 2Level 3Other Total
Assets      
Risk management activities — derivative instruments:
Commodity contracts$— $115,079 $— $(4,690)(a)$110,389 
Nuclear decommissioning trust:      
Equity securities45,264 — — (27,782)(b)17,482 
U.S. commingled equity funds— — — 595,048 (c)595,048 
U.S. Treasury debt240,745 — — — 240,745 
Corporate debt— 203,454 — —  203,454 
Mortgage-backed securities— 155,574 — —  155,574 
Municipal bonds— 72,189 — —  72,189 
Other fixed income— 10,265 — —  10,265 
Subtotal nuclear decommissioning trust286,009 441,482 — 567,266 1,294,757 
Other special use funds:
Equity securities47,570 — — 936 (b)48,506 
U.S. Treasury debt298,170 — — — 298,170 
Municipal bonds— 11,734 — — 11,734 
Subtotal other special use funds345,740 11,734 — 936 358,410 
Total assets$631,749 $568,295 $— $563,512 $1,763,556 
Liabilities      
Risk management activities — derivative instruments:      
Commodity contracts$— $(4,740)$(2,738)$3,105 (a)$(4,373)

(a)Represents counterparty netting, margin, and collateral. See Note 7.
(b)Represents net pending securities sales and purchases.
(c)Valued using NAV as a practical expedient and, therefore, are not classified in the fair value hierarchy.

Fair Value Measurements Classified as Level 3
 
The significant unobservable inputs used in the fair value measurement of our energy derivative contracts include broker quotes that cannot be validated as an observable input primarily due to the long-term nature of the quote or other characteristics of the product.  Significant changes in these inputs in isolation would result in significantly higher or lower fair value measurements.  Changes in our derivative contract fair values, including changes relating to unobservable inputs, typically will not impact net income due to regulatory accounting treatment. See Note 4.
 
Because our forward commodity contracts classified as Level 3 are currently in a net purchase position, we would expect price increases of the underlying commodity to result in increases in the net fair value of the related contracts.  Conversely, if the price of the underlying commodity decreases, the net fair value of the related contracts would likely decrease.
 
Other unobservable valuation inputs include credit and liquidity reserves which do not have a material impact on our valuations; however, significant changes in these inputs could also result in higher or lower fair value measurements.
 
Financial Instruments Not Carried at Fair Value
 
The carrying value of our short-term borrowings approximate fair value and are classified within Level 2 of the fair value hierarchy.  See Note 3 for our long-term debt fair values.
v3.22.2
Investments in Nuclear Decommissioning Trusts and Other Special Use Funds
 6 Months Ended
Jun. 30, 2022
Investments, Debt and Equity Securities [Abstract]  
Investments in Nuclear Decommissioning Trusts and Other Special Use Funds Investments in Nuclear Decommissioning Trusts and Other Special Use Funds
We have investments in debt and equity securities held in Nuclear Decommissioning Trusts, Coal Reclamation Escrow Account, and an Active Union Employee Medical Account. Investments in debt securities are classified as available-for-sale securities. We record both debt and equity security investments at their fair value on our Condensed Consolidated Balance Sheets. See Note 11 for a discussion of how fair value is determined and the classification of the investments within the fair value hierarchy. The investments in each trust or account are restricted for use and are intended to fund specified costs and activities as further described for each fund below.

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

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

Active Union Employee Medical Account — APS has investments restricted for paying active union employee medical costs. These investments may be used to pay active union employee medical costs incurred in the current and future periods. In 2021, APS was reimbursed $15 million for prior year active union employee medical claims from the active union employee medical account. The account is invested primarily in fixed income securities. In accordance with the ratemaking treatment, APS has deferred the unrealized gains and losses (including credit losses) in other regulatory 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):  
June 30, 2022
 Fair ValueTotal
Unrealized
Gains		Total
Unrealized
Losses
Investment Type:Nuclear Decommissioning TrustsOther Special Use FundsTotal
Equity securities$473,392 $29,093 $502,485 $327,032 $(183)
Available for sale-fixed income securities601,295 316,375 917,670 (a)2,997 (56,826)
Other1,401 938 2,339 (b)— — 
Total$1,076,088 $346,406 $1,422,494 $330,029 $(57,009)

(a)As of June 30, 2022, the amortized cost basis of these available-for-sale investments is $971 million.
(b)Represents net pending securities sales and purchases.

December 31, 2021
 Fair ValueTotal
Unrealized
Gains		Total
Unrealized
Losses
Investment Type:Nuclear Decommissioning TrustsOther Special Use FundsTotal
Equity securities$640,312 $47,570 $687,882 $451,387 $— 
Available for sale-fixed income securities682,227 309,904 992,131 (a)24,283 (4,063)
Other(27,782)936 (26,846)(b)— — 
Total$1,294,757 $358,410 $1,653,167 $475,670 $(4,063)

(a)As of December 31, 2021, the amortized cost basis of these available-for-sale investments is $972 million.
(b)Represents net pending securities sales and purchases.
The following tables set forth APS’s realized gains and losses relating to the sale and maturity of available-for-sale debt securities and equity securities, and the proceeds from the sale and maturity of these investment securities (dollars in thousands):
 Three Months Ended June 30,
 Nuclear Decommissioning TrustsOther Special Use FundsTotal
2022
Realized gains$6,282 $— $6,282 
Realized losses(12,439)— (12,439)
Proceeds from the sale of securities (a)309,966 20,466 330,432 
2021
Realized gains$1,406 $— $1,406 
Realized losses(1,146)— (1,146)
Proceeds from the sale of securities (a)190,340 17,524 207,864 

(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.

 Six Months Ended June 30,
 Nuclear Decommissioning TrustsOther Special Use FundsTotal
2022
Realized gains$7,305 $— $7,305 
Realized losses(19,674)— (19,674)
Proceeds from the sale of securities (a)629,659 62,011 691,670 
2021
Realized gains$4,374 $— $4,374 
Realized losses(5,294)— (5,294)
Proceeds from the sale of securities (a)425,068 162,774 587,842 

(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 June 30, 2022, is as follows (dollars in thousands):
 Nuclear Decommissioning TrustsCoal Reclamation Escrow AccountActive Union Employee Medical AccountTotal
Less than one year$13,114 $47,528 $40,224 $100,866 
1 year – 5 years192,566 31,422 150,008 373,996 
5 years – 10 years127,287 — 43,023 170,310 
Greater than 10 years268,328 4,170 — 272,498 
Total$601,295 $83,120 $233,255 $917,670 
v3.22.2
Changes in Accumulated Other Comprehensive Loss
 6 Months Ended
Jun. 30, 2022
Comprehensive Income (Loss), Net of Tax, Attributable to Parent [Abstract]  
Changes in Accumulated Other Comprehensive Loss Changes in Accumulated Other Comprehensive Loss
The following tables show the changes in Pinnacle West’s consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component (dollars in thousands):
 Pension and Other Postretirement Benefits Derivative Instruments Total
Three Months Ended June 30
Balance March 31, 2022$(52,984)$(724)$(53,708)
OCI before reclassifications(3,213)1,007 (2,206)
Amounts reclassified from accumulated other comprehensive loss1,100  (a)— 1,100 
Balance June 30, 2022$(55,097)$283 $(54,814)
Balance March 31, 2021$(59,703)$(1,809)$(61,512)
OCI before reclassifications(1,125)870 (255)
Amounts reclassified from accumulated other comprehensive loss1,189  (a)— 1,189 
Balance June 30, 2021$(59,639)$(939)$(60,578)

Pension and Other Postretirement BenefitsDerivative InstrumentsTotal
Six Months Ended June 30
Balance December 31, 2021$(53,885)$(976)$(54,861)
OCI (loss) before reclassifications(3,213)1,259 (1,954)
Amounts reclassified from accumulated other comprehensive loss2,001 (a)— 2,001 
Balance June 30, 2022$(55,097)$283 $(54,814)
Balance December 31, 2020$(60,725)$(2,071)$(62,796)
OCI (loss) before reclassifications(1,125)1,132 7 
Amounts reclassified from accumulated other comprehensive loss2,211 (a)— 2,211 
Balance June 30, 2021$(59,639)$(939)$(60,578)

(a)    These amounts primarily represent amortization of actuarial loss and are included in the computation of net periodic pension cost.  See Note 5.
The following tables show the changes in APS’s consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component (dollars in thousands): 
 Pension and Other Postretirement Benefits
Three Months Ended June 30
Balance March 31, 2022$(34,060)
OCI (loss) before reclassifications(3,160)
Amounts reclassified from accumulated other comprehensive loss999 (a)
Balance June 30, 2022$(36,221)
Balance March 31, 2021$(39,991)
OCI (loss) before reclassifications(914)
Amounts reclassified from accumulated other comprehensive loss1,073 (a)
Balance June 30, 2021$(39,832)

 Pension and Other Postretirement Benefits
Six Months Ended June 30
Balance December 31, 2021$(34,880)
OCI (loss) before reclassifications(3,160)
Amounts reclassified from accumulated other comprehensive loss1,819 (a)
Balance June 30, 2022$(36,221)
Balance December 31, 2020$(40,918)
OCI (loss) before reclassifications(914)
Amounts reclassified from accumulated other comprehensive loss2,000 (a)
Balance June 30, 2021$(39,832)

(a) These amounts primarily represent amortization of actuarial loss and are included in the computation of net periodic pension cost.  See Note 5.
v3.22.2
Consolidation and Nature of Operations (Tables)
 6 Months Ended
Jun. 30, 2022
Organization, Consolidation and Presentation of Financial Statements [Abstract]  
Summary of supplemental cash flow information
The following table summarizes supplemental Pinnacle West cash flow information (dollars in thousands):
 Six Months Ended
June 30,
 20222021
Cash paid (received) during the period for:
Income taxes, net of refunds$(1,746)$(788)
Interest, net of amounts capitalized120,359 112,010 
Significant non-cash investing and financing activities:
Accrued capital expenditures$106,033 $105,515 
Right-of-use operating lease assets obtained in exchange for operating lease liabilities11,101 248,694 
Dividends accrued but not yet paid96,081 93,610 


The following table summarizes supplemental APS cash flow information (dollars in thousands):
Six Months Ended
June 30,
 20222021
Cash paid (received) during the period for:
Income taxes, net of refunds$(25)$3,317 
Interest, net of amounts capitalized114,069 107,044 
Significant non-cash investing and financing activities:
Accrued capital expenditures$106,033 $105,515 
Right-of-use operating lease assets obtained in exchange for operating lease liabilities7,512 248,694 
Dividends accrued but not yet paid96,000 93,500 
v3.22.2
Revenue (Tables)
 6 Months Ended
Jun. 30, 2022
Revenue from Contract with Customer [Abstract]  
Disaggregation of revenue
The following table provides detail of Pinnacle West’s consolidated revenue disaggregated by revenue sources (dollars in thousands):
Three Months Ended June 30,Six Months Ended June 30,
2022202120222021
Retail Electric Service
Residential$537,589 $531,717 $904,935 $872,555 
Non-Residential462,669 420,995 822,185 735,778 
Wholesale Energy Sales29,902 18,007 58,805 35,604 
Transmission Services for Others29,352 22,579 54,844 41,572 
Other Sources2,157 6,951 4,431 11,215 
Total operating revenues$1,061,669 $1,000,249 $1,845,200 $1,696,724 
Schedule of accounts receivable
The following table provides a rollforward of Pinnacle West’s allowance for doubtful accounts (dollars in thousands):
June 30, 2022December 31, 2021
Allowance for doubtful accounts, balance at beginning of period$25,354 $19,782 
Bad debt expense8,119 22,251 
Actual write-offs(10,326)(16,679)
Allowance for doubtful accounts, balance at end of period$23,147 $25,354 
v3.22.2
Long-Term Debt and Liquidity Matters (Tables)
 6 Months Ended
Jun. 30, 2022
Debt Disclosure [Abstract]  
Schedule of estimated fair value of long-term debt, including current maturities The following table presents the estimated fair value of our long-term debt, including current maturities (dollars in thousands):
 As of June 30, 2022As of December 31, 2021
 Carrying
Amount		Fair ValueCarrying
Amount		Fair Value
Pinnacle West$947,547 $909,520 $797,042 $792,735 
APS6,268,271 5,488,229 6,266,693 6,933,619 
BCE25,477 25,802 — — 
Total$7,241,295 $6,423,551 $7,063,735 $7,726,354 
v3.22.2
Regulatory Matters (Tables)
 6 Months Ended
Jun. 30, 2022
Regulated Operations [Abstract]  
Schedule of capital structure and cost of capital the following proposed capital structure and costs of capital:
  Capital Structure Cost of Capital 
Long-term debt 45.3 %4.10 %
Common stock equity 54.7 %10.15 %
Weighted-average cost of capital   7.41 %
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 2022 and 2021 (dollars in thousands):
 
 Six Months Ended
June 30,
 20222021
Beginning balance$388,148 $175,835 
Deferred fuel and purchased power costs — current period98,707 135,905 
Amounts charged to customers(96,842)(10,828)
Ending balance$390,013 $300,912 
Schedule of regulatory assets
The detail of regulatory assets is as follows (dollars in thousands): 
 Amortization ThroughJune 30, 2022December 31, 2021
 CurrentNon-CurrentCurrentNon-Current
Pension(a)$— $514,330 $— $509,751 
Deferred fuel and purchased power (b) (c)2023390,013 — 388,148 — 
Income taxes — allowance for funds used during construction (“AFUDC”) equity20527,625 167,644 7,625 164,768 
Ocotillo deferral (e)20319,507 133,390 9,507 138,143 
Retired power plant costs203315,157 91,113 15,160 99,681 
SCR deferral (e)(f)20318,147 93,551 8,147 97,624 
Deferred property taxes20278,569 36,772 8,569 41,057 
Lost fixed cost recovery (b)202343,788 — 63,889 — 
Deferred compensation2036— 34,251 — 33,997 
Income taxes — investment tax credit basis adjustment2056826 23,606 1,129 23,639 
Palo Verde VIEs (Note 6)2046— 21,013 — 21,094 
Four Corners cost deferral20248,077 11,960 8,077 15,998 
Coal reclamation20262,978 12,372 2,978 13,862 
Active Union Medical Trust(g)— 13,704 — 1,175 
Loss on reacquired debt20381,648 8,579 1,648 9,372 
Mead-Phoenix transmission line contributions in aid of construction (“CIAC”)2050332 8,882 332 9,048 
TCA balancing account (b)20238,805 — 170 3,663 
Tax expense adjustor mechanism (b)2031656 5,518 656 5,845 
Tax expense of Medicare subsidy20241,235 1,968 1,235 2,469 
OtherVarious1,813 2,003 1,254 1,801 
Total regulatory assets (d) $509,176 $1,180,656 $518,524 $1,192,987 

(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. See Note 5 for further discussion.
(b)See “Cost Recovery Mechanisms” discussion above.
(c)Subject to a carrying charge.
(d)There are no regulatory assets for which the ACC has allowed recovery of costs, but not allowed a return by exclusion from rate base.  FERC rates are set using a formula rate as described in “Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters.”
(e)Balance includes amounts for future regulatory consideration and amortization period determination.
(f)See “Four Corners SCR Cost Recovery” discussion above.
(g)Collected in retail rates.
Schedule of regulatory liabilities
The detail of regulatory liabilities is as follows (dollars in thousands):
 
 Amortization ThroughJune 30, 2022December 31, 2021
 CurrentNon-CurrentCurrentNon-Current
Excess deferred income taxes — ACC - Tax Act (a)2046$40,903 $954,939 $40,903 $971,545 
Excess deferred income taxes — FERC - Tax Act (a)20587,239 218,939 7,239 221,877 
Asset retirement obligations2057— 376,575 — 614,683 
Other postretirement benefits(d)50,624 305,045 37,789 337,027 
Deferred fuel and purchased power — mark-to-market (Note 7)2024173,712 111,847 60,693 46,908 
Removal costs(c)57,454 55,570 69,476 50,104 
Income taxes — change in rates20512,876 63,636 2,876 64,802 
Four Corners coal reclamation20382,316 50,860 2,316 53,076 
Income taxes — deferred investment tax credit20562,264 46,663 2,264 47,337 
Spent nuclear fuel20276,730 35,227 6,701 38,581 
FERC transmission true up (b)202429,238 3,620 21,379 12,924 
Renewable energy standard (b)202425,401 492 38,453 187 
Property tax deferral (e)20244,671 13,186 4,671 15,521 
Sundance maintenance2031— 15,345 — 13,797 
Demand side management (b)2023— 9,214 — 5,417 
Tax expense adjustor mechanism (b) (e)N/A— 4,835 — 4,835 
OtherVarious679 2,155 1,511 592 
Total regulatory liabilities $404,107 $2,268,148 $296,271 $2,499,213 

(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 guidance, APS accrues removal costs for its regulated assets, even if there is no legal obligation for removal.
(d)See Note 5.
(e)Balance includes amounts for future regulatory consideration and amortization period determination.
v3.22.2
Retirement Plans and Other Postretirement Benefits (Tables)
 6 Months Ended
Jun. 30, 2022
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 BenefitsOther Benefits
 Three Months Ended
June 30,		Six Months Ended
June 30,		Three Months Ended
June 30,		Six Months Ended
June 30,
 20222021202220212022202120222021
Service cost — benefits earned during the period$13,406 $14,939 $27,737 $30,618 $4,017 $4,341 $8,235 $8,898 
Non-service costs (credits):
Interest cost on benefit obligation26,723 24,614 53,746 49,283 4,283 4,095 8,746 8,257 
Expected return on plan assets(46,494)(50,706)(92,888)(101,314)(11,511)(10,361)(23,021)(20,722)
  Amortization of:       
  Prior service credit— — — — (9,447)(9,427)(18,894)(18,854)
  Net actuarial loss (gain)3,989 3,989 8,757 7,974 (3,436)(2,641)(6,418)(5,046)
Net periodic benefit$(2,376)$(7,164)$(2,648)$(13,439)$(16,094)$(13,993)$(31,352)$(27,467)
Portion of benefit charged to expense$(4,722)$(8,614)$(8,012)$(16,625)$(11,523)$(9,608)$(22,418)$(19,136)
v3.22.2
Palo Verde Sale Leaseback Variable Interest Entities (Tables)
 6 Months Ended
Jun. 30, 2022
Variable Interest Entities [Abstract]  
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets
Our Condensed Consolidated Balance Sheets at June 30, 2022, and December 31, 2021, include the following amounts relating to the VIEs (dollars in thousands):

June 30, 2022December 31, 2021
Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation$92,231 $94,166 
Equity — Noncontrolling interests113,244 115,260 
v3.22.2
Derivative Accounting (Tables)
 6 Months Ended
Jun. 30, 2022
Derivative Instruments and Hedging Activities Disclosure [Abstract]  
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 derivatives, which represent both purchases and sales (does not reflect net position): 
Quantity
CommodityUnit of MeasureJune 30, 2022December 31, 2021
PowerGWh1,208 — 
GasBillion cubic feet168 155 
Gains and losses from derivative instruments not designated as accounting hedges instruments
The following table provides information about gains and losses from derivative instruments not designated as accounting hedging instruments (dollars in thousands):

 Financial Statement LocationThree Months Ended
June 30,		Six Months Ended
June 30,
Commodity Contracts2022202120222021
Net Gain Recognized in IncomeFuel and purchased power (a)$62,525 $95,116 $286,267 $121,975 
 
(a)Amounts are before the effect of PSA deferrals.
Schedule of offsetting assets
The following tables provide information about the fair value of our 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 our Condensed Consolidated Balance Sheets.
As of June 30, 2022:
(dollars in thousands)
Gross
 Recognized
 Derivatives
 (a)
Amounts
Offset
 (b)
Net
 Recognized
 Derivatives
Other
 (c)
Amount Reported on Balance Sheets
Current assets$177,765 $(40,787)$136,978 $50 $137,028 
Investments and other assets111,847 — 111,847 — 111,847 
Total assets289,612 (40,787)248,825 50 248,875 
Current liabilities(4,053)357 (3,696)(1,900)(5,596)
Total$285,559 $(40,430)$245,129 $(1,850)$243,279 

(a)All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)Includes cash collateral received from counterparties of $40,430 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 or received in excess of the recognized derivative instrument. Includes cash collateral received from counterparties of $1,900 and cash margin provided to counterparties of $50.

As of December 31, 2021:
(dollars in thousands)
Gross
Recognized
Derivatives
 (a)
Amounts
Offset
(b)
Net
 Recognized
 Derivatives
Other
 (c)
Amount
Reported on
Balance Sheets
Current assets$66,777 $(3,346)$63,431 $50 $63,481 
Investments and other assets48,302 (1,394)46,908 — 46,908 
Total assets115,079 (4,740)110,339 50 110,389 
Current liabilities(6,084)3,346 (2,738)(1,635)(4,373)
Deferred credits and other(1,394)1,394 — — — 
Total liabilities(7,478)4,740 (2,738)(1,635)(4,373)
Total$107,601 $— $107,601 $(1,585)$106,016 

(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 $1,635 and cash margin provided to counterparties of $50.
Schedule of offsetting liabilities
The following tables provide information about the fair value of our 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 our Condensed Consolidated Balance Sheets.
As of June 30, 2022:
(dollars in thousands)
Gross
 Recognized
 Derivatives
 (a)
Amounts
Offset
 (b)
Net
 Recognized
 Derivatives
Other
 (c)
Amount Reported on Balance Sheets
Current assets$177,765 $(40,787)$136,978 $50 $137,028 
Investments and other assets111,847 — 111,847 — 111,847 
Total assets289,612 (40,787)248,825 50 248,875 
Current liabilities(4,053)357 (3,696)(1,900)(5,596)
Total$285,559 $(40,430)$245,129 $(1,850)$243,279 

(a)All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)Includes cash collateral received from counterparties of $40,430 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 or received in excess of the recognized derivative instrument. Includes cash collateral received from counterparties of $1,900 and cash margin provided to counterparties of $50.

As of December 31, 2021:
(dollars in thousands)
Gross
Recognized
Derivatives
 (a)
Amounts
Offset
(b)
Net
 Recognized
 Derivatives
Other
 (c)
Amount
Reported on
Balance Sheets
Current assets$66,777 $(3,346)$63,431 $50 $63,481 
Investments and other assets48,302 (1,394)46,908 — 46,908 
Total assets115,079 (4,740)110,339 50 110,389 
Current liabilities(6,084)3,346 (2,738)(1,635)(4,373)
Deferred credits and other(1,394)1,394 — — — 
Total liabilities(7,478)4,740 (2,738)(1,635)(4,373)
Total$107,601 $— $107,601 $(1,585)$106,016 

(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 $1,635 and cash margin provided to counterparties of $50.
Information about derivative instruments that have credit-risk-related contingent features
The following table provides information about our derivative instruments that have credit-risk-related contingent features (dollars in thousands):
 June 30, 2022
Aggregate fair value of derivative instruments in a net liability position$1,882 
Additional cash collateral in the event credit-risk-related contingent features were fully triggered (a)883 
(a)This amount is after counterparty netting and includes those contracts which qualify for scope exceptions, which are excluded from the derivative details above.
v3.22.2
Other Income and Other Expense (Tables)
 6 Months Ended
Jun. 30, 2022
Other Income and Expenses [Abstract]  
Schedule of other income and other expense The following table provides detail of Pinnacle West’s Consolidated other income and other expense (dollars in thousands):
Three Months Ended
June 30,		Six Months Ended
June 30,
2022202120222021
Other income:
Interest income$1,691 $1,687 $3,333 $3,635 
Debt return on Four Corners SCR deferrals (Note 4)— 4,089 — 8,175 
Debt return on Ocotillo modernization project (Note 4)— 6,391 — 12,783 
Miscellaneous(9)40 53 43 
Total other income$1,682 $12,207 $3,386 $24,636 
Other expense:
Non-operating costs(3,701)(4,102)(6,154)(6,039)
Investment losses — net(575)(431)(1,256)(774)
Miscellaneous(308)(651)(596)(2,224)
Total other expense$(4,584)$(5,184)$(8,006)$(9,037)
The following table provides detail of APS’s other income and other expense (dollars in thousands):

 Three Months Ended
June 30,		Six Months Ended
June 30,
 2022202120222021
Other income:    
Interest income$1,396 $1,047 $2,495 $2,528 
Debt return on Four Corners SCR deferrals (Note 4)— 4,089 — 8,175 
Debt return on Ocotillo modernization project (Note 4)— 6,391 — 12,783 
Miscellaneous— 36 53 37 
Total other income$1,396 $11,563 $2,548 $23,523 
Other expense:  
Non-operating costs(2,477)(3,615)(4,038)(5,392)
Miscellaneous(309)(646)(596)(2,219)
Total other expense$(2,786)$(4,261)$(4,634)$(7,611)
v3.22.2
Earnings Per Share (Tables)
 6 Months Ended
Jun. 30, 2022
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):
 Three Months Ended June 30,Six Months Ended June 30,
 2022202120222021
Net income attributable to common shareholders$164,312 $215,697 $181,268 $251,338 
Weighted average common shares outstanding — basic
113,172 112,882 113,137 112,855 
Net effect of dilutive securities:
Contingently issuable performance shares and restricted stock units
197 341 195 303 
Weighted average common shares outstanding — diluted
113,369 113,223 113,332 113,158 
Earnings per weighted-average common share outstanding
Net income attributable to common shareholders — basic
$1.45 $1.91 $1.60 $2.23 
Net income attributable to common shareholders — diluted
$1.45 $1.91 $1.60 $2.22 
v3.22.2
Fair Value Measurements (Tables)
 6 Months Ended
Jun. 30, 2022
Fair Value Disclosures [Abstract]  
Fair value of assets and liabilities that are measured at fair value on a recurring basis
The following table presents the fair value at June 30, 2022, of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):
 
 Level 1Level 2Level 3Other Total
Assets      
Risk management activities — derivative instruments:
Commodity contracts$— $281,107 $8,505 $(40,737)(a)$248,875 
Nuclear decommissioning trust:
Equity securities12,773 — — 1,401 (b)14,174 
U.S. commingled equity funds— — — 460,619 (c)460,619 
U.S. Treasury debt211,284 — — —  211,284 
Corporate debt— 177,297 — —  177,297 
Mortgage-backed securities— 135,858 — —  135,858 
Municipal bonds— 67,943 — —  67,943 
Other fixed income— 8,913 — —  8,913 
Subtotal nuclear decommissioning trust224,057 390,011 — 462,020 1,076,088 
Other special use funds:
Equity securities29,093 — — 938 (b)30,031 
U.S. Treasury debt310,667 — — — 310,667 
Municipal bonds— 5,708 — — 5,708 
Subtotal other special use funds339,760 5,708 — 938 346,406 
Total assets$563,817 $676,826 $8,505 $422,221 $1,671,369 
Liabilities      
Risk management activities — derivative instruments:      
Commodity contracts$— $(94)$(3,959)$(1,543)(a)$(5,596)

(a)Represents counterparty netting, margin, and collateral. See Note 7.
(b)Represents net pending securities sales and purchases.
(c)Valued using NAV as a practical expedient and, therefore, are not classified in the fair value hierarchy.
The following table presents the fair value at December 31, 2021, of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):
 
 Level 1Level 2Level 3Other Total
Assets      
Risk management activities — derivative instruments:
Commodity contracts$— $115,079 $— $(4,690)(a)$110,389 
Nuclear decommissioning trust:      
Equity securities45,264 — — (27,782)(b)17,482 
U.S. commingled equity funds— — — 595,048 (c)595,048 
U.S. Treasury debt240,745 — — — 240,745 
Corporate debt— 203,454 — —  203,454 
Mortgage-backed securities— 155,574 — —  155,574 
Municipal bonds— 72,189 — —  72,189 
Other fixed income— 10,265 — —  10,265 
Subtotal nuclear decommissioning trust286,009 441,482 — 567,266 1,294,757 
Other special use funds:
Equity securities47,570 — — 936 (b)48,506 
U.S. Treasury debt298,170 — — — 298,170 
Municipal bonds— 11,734 — — 11,734 
Subtotal other special use funds345,740 11,734 — 936 358,410 
Total assets$631,749 $568,295 $— $563,512 $1,763,556 
Liabilities      
Risk management activities — derivative instruments:      
Commodity contracts$— $(4,740)$(2,738)$3,105 (a)$(4,373)

(a)Represents counterparty netting, margin, and collateral. See Note 7.
(b)Represents net pending securities sales and purchases.
(c)Valued using NAV as a practical expedient and, therefore, are not classified in the fair value hierarchy.
v3.22.2
Investments in Nuclear Decommissioning Trusts and Other Special Use Funds (Tables)
 6 Months Ended
Jun. 30, 2022
Investments, Debt and Equity Securities [Abstract]  
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):  
June 30, 2022
 Fair ValueTotal
Unrealized
Gains		Total
Unrealized
Losses
Investment Type:Nuclear Decommissioning TrustsOther Special Use FundsTotal
Equity securities$473,392 $29,093 $502,485 $327,032 $(183)
Available for sale-fixed income securities601,295 316,375 917,670 (a)2,997 (56,826)
Other1,401 938 2,339 (b)— — 
Total$1,076,088 $346,406 $1,422,494 $330,029 $(57,009)

(a)As of June 30, 2022, the amortized cost basis of these available-for-sale investments is $971 million.
(b)Represents net pending securities sales and purchases.

December 31, 2021
 Fair ValueTotal
Unrealized
Gains		Total
Unrealized
Losses
Investment Type:Nuclear Decommissioning TrustsOther Special Use FundsTotal
Equity securities$640,312 $47,570 $687,882 $451,387 $— 
Available for sale-fixed income securities682,227 309,904 992,131 (a)24,283 (4,063)
Other(27,782)936 (26,846)(b)— — 
Total$1,294,757 $358,410 $1,653,167 $475,670 $(4,063)

(a)As of December 31, 2021, the amortized cost basis of these available-for-sale investments is $972 million.
(b)Represents net pending securities sales and purchases.
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds
The following tables set forth APS’s realized gains and losses relating to the sale and maturity of available-for-sale debt securities and equity securities, and the proceeds from the sale and maturity of these investment securities (dollars in thousands):
 Three Months Ended June 30,
 Nuclear Decommissioning TrustsOther Special Use FundsTotal
2022
Realized gains$6,282 $— $6,282 
Realized losses(12,439)— (12,439)
Proceeds from the sale of securities (a)309,966 20,466 330,432 
2021
Realized gains$1,406 $— $1,406 
Realized losses(1,146)— (1,146)
Proceeds from the sale of securities (a)190,340 17,524 207,864 

(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.

 Six Months Ended June 30,
 Nuclear Decommissioning TrustsOther Special Use FundsTotal
2022
Realized gains$7,305 $— $7,305 
Realized losses(19,674)— (19,674)
Proceeds from the sale of securities (a)629,659 62,011 691,670 
2021
Realized gains$4,374 $— $4,374 
Realized losses(5,294)— (5,294)
Proceeds from the sale of securities (a)425,068 162,774 587,842 

(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.
Fair value of fixed income securities, summarized by contractual maturities
The fair value of APS’s fixed income securities, summarized by contractual maturities, at June 30, 2022, is as follows (dollars in thousands):
 Nuclear Decommissioning TrustsCoal Reclamation Escrow AccountActive Union Employee Medical AccountTotal
Less than one year$13,114 $47,528 $40,224 $100,866 
1 year – 5 years192,566 31,422 150,008 373,996 
5 years – 10 years127,287 — 43,023 170,310 
Greater than 10 years268,328 4,170 — 272,498 
Total$601,295 $83,120 $233,255 $917,670 
v3.22.2
Changes in Accumulated Other Comprehensive Loss (Tables)
 6 Months Ended
Jun. 30, 2022
Comprehensive Income (Loss), Net of Tax, Attributable to Parent [Abstract]  
Schedule of changes in accumulated other comprehensive loss including reclassification adjustments, net of tax, by component
The following tables show the changes in Pinnacle West’s consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component (dollars in thousands):
 Pension and Other Postretirement Benefits Derivative Instruments Total
Three Months Ended June 30
Balance March 31, 2022$(52,984)$(724)$(53,708)
OCI before reclassifications(3,213)1,007 (2,206)
Amounts reclassified from accumulated other comprehensive loss1,100  (a)— 1,100 
Balance June 30, 2022$(55,097)$283 $(54,814)
Balance March 31, 2021$(59,703)$(1,809)$(61,512)
OCI before reclassifications(1,125)870 (255)
Amounts reclassified from accumulated other comprehensive loss1,189  (a)— 1,189 
Balance June 30, 2021$(59,639)$(939)$(60,578)

Pension and Other Postretirement BenefitsDerivative InstrumentsTotal
Six Months Ended June 30
Balance December 31, 2021$(53,885)$(976)$(54,861)
OCI (loss) before reclassifications(3,213)1,259 (1,954)
Amounts reclassified from accumulated other comprehensive loss2,001 (a)— 2,001 
Balance June 30, 2022$(55,097)$283 $(54,814)
Balance December 31, 2020$(60,725)$(2,071)$(62,796)
OCI (loss) before reclassifications(1,125)1,132 7 
Amounts reclassified from accumulated other comprehensive loss2,211 (a)— 2,211 
Balance June 30, 2021$(59,639)$(939)$(60,578)

(a)    These amounts primarily represent amortization of actuarial loss and are included in the computation of net periodic pension cost.  See Note 5.
The following tables show the changes in APS’s consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component (dollars in thousands): 
 Pension and Other Postretirement Benefits
Three Months Ended June 30
Balance March 31, 2022$(34,060)
OCI (loss) before reclassifications(3,160)
Amounts reclassified from accumulated other comprehensive loss999 (a)
Balance June 30, 2022$(36,221)
Balance March 31, 2021$(39,991)
OCI (loss) before reclassifications(914)
Amounts reclassified from accumulated other comprehensive loss1,073 (a)
Balance June 30, 2021$(39,832)

 Pension and Other Postretirement Benefits
Six Months Ended June 30
Balance December 31, 2021$(34,880)
OCI (loss) before reclassifications(3,160)
Amounts reclassified from accumulated other comprehensive loss1,819 (a)
Balance June 30, 2022$(36,221)
Balance December 31, 2020$(40,918)
OCI (loss) before reclassifications(914)
Amounts reclassified from accumulated other comprehensive loss2,000 (a)
Balance June 30, 2021$(39,832)

(a) These amounts primarily represent amortization of actuarial loss and are included in the computation of net periodic pension cost.  See Note 5.
v3.22.2
Consolidation and Nature of Operations (Details) - USD ($)
$ in Thousands
 6 Months Ended
Jun. 30, 2022
Jun. 30, 2021
Cash paid (received) during the period for:    
Income taxes, net of refunds $ (1,746) $ (788)
Interest, net of amounts capitalized 120,359 112,010
Significant non-cash investing and financing activities:    
Accrued capital expenditures 106,033 105,515
Right-of-use operating lease assets obtained in exchange for operating lease liabilities 11,101 248,694
Dividends accrued but not yet paid 96,081 93,610
APS    
Cash paid (received) during the period for:    
Income taxes, net of refunds (25) 3,317
Interest, net of amounts capitalized 114,069 107,044
Significant non-cash investing and financing activities:    
Accrued capital expenditures 106,033 105,515
Right-of-use operating lease assets obtained in exchange for operating lease liabilities 7,512 248,694
Dividends accrued but not yet paid $ 96,000 $ 93,500
v3.22.2
Revenue - Schedule of Disaggregation (Details) - USD ($)
$ in Thousands
 3 Months Ended 6 Months Ended
Jun. 30, 2022
Jun. 30, 2021
Jun. 30, 2022
Jun. 30, 2021
Disaggregation of Revenue [Line Items]        
Total operating revenues $ 1,061,669 $ 1,000,249 $ 1,845,200 $ 1,696,724
Regulatory cost recovery revenue (2,000) 20,000 10,000 34,000
Retail Electric Service | Residential        
Disaggregation of Revenue [Line Items]        
Total operating revenues 537,589 531,717 904,935 872,555
Retail Electric Service | Non-Residential        
Disaggregation of Revenue [Line Items]        
Total operating revenues 462,669 420,995 822,185 735,778
Wholesale Energy Sales        
Disaggregation of Revenue [Line Items]        
Total operating revenues 29,902 18,007 58,805 35,604
Transmission Services for Others        
Disaggregation of Revenue [Line Items]        
Total operating revenues 29,352 22,579 54,844 41,572
Other Sources        
Disaggregation of Revenue [Line Items]        
Total operating revenues 2,157 6,951 4,431 11,215
Electric and Transmission Service        
Disaggregation of Revenue [Line Items]        
Total operating revenues $ 1,064,000 $ 980,000 $ 1,835,000 $ 1,663,000
v3.22.2
Revenue - Allowance for Doubtful Accounts (Details) - USD ($)
$ in Thousands
 6 Months Ended 12 Months Ended
Jun. 30, 2022
Dec. 31, 2021
Accounts Receivable, Allowance for Credit Loss [Roll Forward]    
Allowance for doubtful accounts, balance at beginning of period $ 25,354 $ 19,782
Bad debt expense 8,119 22,251
Actual write-offs (10,326) (16,679)
Allowance for doubtful accounts, balance at end of period $ 23,147 $ 25,354
v3.22.2
Long-Term Debt and Liquidity Matters - Narrative (Details)
 6 Months Ended
Feb. 11, 2022
USD ($)
MW
Jan. 06, 2022
USD ($)
Dec. 21, 2021
USD ($)
Jun. 30, 2022
USD ($)
creditFacility
Jun. 30, 2021
USD ($)
Apr. 06, 2022
USD ($)
Dec. 23, 2020
USD ($)
Dec. 17, 2020
USD ($)
Long-Term Debt and Liquidity Matters                
Issuance of long-term debt       $ 325,802,000 $ 150,000,000      
Pinnacle West | Term Loan                
Long-Term Debt and Liquidity Matters                
Debt instrument, face amount             $ 150,000,000  
Pinnacle West | Term Loan | Term Loan Maturing 2021                
Long-Term Debt and Liquidity Matters                
Debt instrument, face amount     $ 450,000,000          
Issuance of long-term debt   $ 300,000,000 $ 150,000,000          
Pinnacle West | Revolving Credit Facility | Revolving Credit Facility Maturing May 2026                
Long-Term Debt and Liquidity Matters                
Current borrowing capacity on credit facility       200,000,000        
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders (up to)       300,000,000        
Long-term line of credit       0        
Pinnacle West | Letter of Credit | Revolving Credit Facility Maturing May 2026                
Long-Term Debt and Liquidity Matters                
Outstanding letters of credit       0        
Pinnacle West | Commercial paper | Revolving Credit Facility Maturing May 2026                
Long-Term Debt and Liquidity Matters                
Commercial paper       26,000,000        
APS                
Long-Term Debt and Liquidity Matters                
Percentage of capitalization               7.00%
Capacity available for trade purchases               $ 500,000,000
Long-term debt limit           $ 8,000,000,000   $ 7,500,000,000
Equity infusion from Pinnacle West   $ 150,000,000            
Contributions from parent       150,000,000        
APS | Revolving Credit Facility | Revolving Credit Facility Maturing May 2026                
Long-Term Debt and Liquidity Matters                
Current borrowing capacity on credit facility       1,000,000,000        
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders (up to)       1,400,000,000        
APS | Revolving Credit Facility | Revolving Credit Facility Maturing May 2026, Facility One                
Long-Term Debt and Liquidity Matters                
Current borrowing capacity on credit facility       500,000,000        
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders (up to)       700,000,000        
APS | Revolving Credit Facility | Revolving Credit Facility Maturing May 2026, Facility Two                
Long-Term Debt and Liquidity Matters                
Current borrowing capacity on credit facility       500,000,000        
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders (up to)       700,000,000        
APS | Revolving Credit Facility | Revolving Credit Facility Maturing in 2022 and 2023                
Long-Term Debt and Liquidity Matters                
Long-term line of credit       $ 0        
Number of line of credit facilities | creditFacility       2        
APS | Letter of Credit | Revolving Credit Facility Maturing May 2026                
Long-Term Debt and Liquidity Matters                
Outstanding letters of credit       $ 0        
APS | Commercial paper                
Long-Term Debt and Liquidity Matters                
Maximum commercial paper support available under credit facility       750,000,000        
APS | Commercial paper | Revolving Credit Facility Maturing May 2026                
Long-Term Debt and Liquidity Matters                
Commercial paper       515,000,000        
BCE                
Long-Term Debt and Liquidity Matters                
Solar and battery storage capacity (in MW) | MW 31              
BCE | Term Loan | Non-Recourse Construction Term Loan Facility                
Long-Term Debt and Liquidity Matters                
Debt instrument, face amount $ 42,000,000              
Long-term line of credit       0        
BCE | Letter of Credit                
Long-Term Debt and Liquidity Matters                
Debt instrument, face amount 5,000,000              
BCE | Bridge Loan | Equity Bridge Loan Facility                
Long-Term Debt and Liquidity Matters                
Debt instrument, face amount $ 33,000,000              
Issuance of long-term debt       $ 25,800,000        
v3.22.2
Long-Term Debt and Liquidity Matters - Estimated Fair Value of Long-Term Debt (Details) - USD ($)
$ in Thousands
Jun. 30, 2022
Dec. 31, 2021
Estimated fair value of long-term debt, including current maturities    
Carrying Amount $ 7,241,295 $ 7,063,735
Fair Value 6,423,551 7,726,354
APS    
Estimated fair value of long-term debt, including current maturities    
Carrying Amount 6,268,271 6,266,693
Fair Value 5,488,229 6,933,619
BCE    
Estimated fair value of long-term debt, including current maturities    
Carrying Amount 25,477 0
Fair Value 25,802 0
Pinnacle West    
Estimated fair value of long-term debt, including current maturities    
Carrying Amount 947,547 797,042
Fair Value $ 909,520 $ 792,735
v3.22.2
Regulatory Matters - COVID-19 Pandemic (Details) - APS - USD ($)
 1 Months Ended
Mar. 31, 2021
Dec. 31, 2021
Jan. 21, 2021
May 05, 2020
Public Utilities, General Disclosures [Line Items]        
Demand side management funds       $ 36,000,000
Customer credits   $ 43,000,000    
Customer credits, additional funds   $ 7,000,000    
Percentage increase under PSA effective for first billing cycle beginning April 2021 50.00%      
Remaining percentage increase under PSA effective for first billing cycle beginning November 2021 50.00%      
Damage from Fire, Explosion or Other Hazard        
Public Utilities, General Disclosures [Line Items]        
Past due balance threshold qualifying for payment extension     $ 75  
v3.22.2
Regulatory Matters - Retail Rate Case Filing (Details)
Mar. 31, 2022
MW
Dec. 17, 2021
USD ($)
Oct. 27, 2021
USD ($)
Aug. 02, 2021
USD ($)
Nov. 06, 2020
USD ($)
Oct. 31, 2019
USD ($)
$ / kWh
MW
Jun. 30, 2019
USD ($)
Aug. 13, 2018
USD ($)
Mar. 27, 2017
USD ($)
$ / kWh
Apr. 30, 2022
USD ($)
Dec. 31, 2021
USD ($)
Dec. 31, 2020
USD ($)
Dec. 04, 2020
USD ($)
Oct. 02, 2020
USD ($)
ACC                            
Public Utilities, General Disclosures [Line Items]                            
Revenue increase (decrease)         $ 169,000,000               $ 59,800,000 $ 89,700,000
Average annual customer bill increase (decrease), percent         5.14%               1.82% 2.70%
Recommended return on equity, percentage         10.00%                 9.40%
Alternative, percentage                           0.30%
Increment of fair value rate, percentage         0.80%                 0.00%
Residential Utility Consumer Office                            
Public Utilities, General Disclosures [Line Items]                            
Revenue increase (decrease)                         $ (50,100,000) $ (20,800,000)
Average annual customer bill increase (decrease), percent                         (1.52%) (0.63%)
Recommended return on equity, percentage                           8.74%
Increment of fair value rate, percentage                           0.00%
ACC | APS                            
Public Utilities, General Disclosures [Line Items]                            
Proposed annual revenue increase           $ 184,000,000   $ (86,500,000)            
Retail Rate Case Filing with Arizona Corporation Commission | ACC | APS                            
Public Utilities, General Disclosures [Line Items]                            
Base rate decrease, elimination of tax expense adjustment mechanism           $ 115,000,000                
Approximate percentage of increase in average customer bill           5.60%                
Approximate percentage of increase in average residential customer bill           5.40%                
Rate matter, cost base rate             $ 8,870,000,000              
Base fuel rate (in dollars per kWh) | $ / kWh           0.030168                
Funding limited income crisis bill program           $ 1,250,000                
Commercial customers, market pricing, threshold | MW 280         0.02                
Revenue increase (decrease)       $ (111,000,000)                    
Recommended return on equity, percentage     8.70% 9.16%                    
Increment of fair value rate, percentage       0.30%                    
Reduction on equity percentage       0.03%                    
Effective fair value percentage       4.95%                    
Net retail base rate, increase                 $ 94,600,000          
Non-fuel and non-depreciation base rate, increase                 87,200,000          
Fuel-related base rate decrease                 53,600,000          
Base rate increase, changes in depreciation schedules                 $ 61,000,000          
Authorized return on common equity (as a percent)                 10.00%          
Percentage of debt in capital structure                 44.20%          
Percentage of common equity in capital structure                 55.80%          
Rate matter, resource comparison proxy for exported energy (in dollars per kWh) | $ / kWh                 0.129          
AZ Sun Program Phase 2 | Retail Rate Case Filing with Arizona Corporation Commission | ACC | APS                            
Public Utilities, General Disclosures [Line Items]                            
Public utilities, minimum annual renewable energy standard and tariff                 $ 10,000,000          
Public utilities, maximum annual renewable energy standard and tariff                 $ 15,000,000          
Coal Community Transition Plan | ACC                            
Public Utilities, General Disclosures [Line Items]                            
Amount funded by customers         $ 100,000,000                  
Amount funded by customers, term         10 years                  
Amount funded by shareholders         $ 25,000,000             $ 25,000,000    
Coal Community Transition Plan | ACC | Navajo Nation, Economic Development Organization                            
Public Utilities, General Disclosures [Line Items]                            
Amount funded by shareholders         $ 1,250,000                  
Amount funded by shareholders, term         5 years                  
Coal Community Transition Plan | ACC | Navajo Nation, Electrification Projects                            
Public Utilities, General Disclosures [Line Items]                            
Amount funded by customers         $ 10,000,000                  
Amount funded by shareholders         10,000,000         $ 500,000        
Coal Community Transition Plan | ACC | Navajo Nation, Transmission Revenue Sharing                            
Public Utilities, General Disclosures [Line Items]                            
Amount funded by shareholders         2,500,000                  
Coal Community Transition Plan | ACC | Navajo County Communities                            
Public Utilities, General Disclosures [Line Items]                            
Amount funded by customers         $ 12,000,000                  
Amount funded by customers, term         5 years                  
Coal Community Transition Plan | ACC | Navajo Nation, Generation Station                            
Public Utilities, General Disclosures [Line Items]                            
Amount funded by customers         $ 3,700,000                  
Coal Community Transition Plan | ACC | Navajo Nation, Hopi Tribe                            
Public Utilities, General Disclosures [Line Items]                            
Amount recoverable through rates related to the CCT                   1,000,000        
Coal Community Transition Plan | ACC | Navajo Nation                            
Public Utilities, General Disclosures [Line Items]                            
Amount recoverable through rates related to the CCT                   3,330,000        
Coal Community Transition Plan | ACC | Navajo Nation, Hopi Reservation                            
Public Utilities, General Disclosures [Line Items]                            
Amount recoverable through rates related to the CCT                   1,250,000        
Coal Community Transition Plan | ACC | Navajo Nation, Navajo Plant                            
Public Utilities, General Disclosures [Line Items]                            
Amount funded by customers                     $ 900,000      
Coal Community Transition Plan | ACC | Navajo County Communities                            
Public Utilities, General Disclosures [Line Items]                            
Amount recoverable through rates related to the CCT                   500,000        
Coal Community Transition Plan | ACC | Navajo County Communities, CCT and Economic Development                            
Public Utilities, General Disclosures [Line Items]                            
Amount funded by shareholders                   1,100,000        
Coal Community Transition Plan | ACC | Navajo Nation, Hopi Tribe for CCT and Economic Development                            
Public Utilities, General Disclosures [Line Items]                            
Amount funded by shareholders                   $ 1,250,000        
Coal Community Transition Plan | Retail Rate Case Filing with Arizona Corporation Commission | ACC | APS | Navajo Nation, Economic Development Organization                            
Public Utilities, General Disclosures [Line Items]                            
Disallowance of annual amortization percentage       15.00%                    
Amount funded by customers       $ 50,000,000                    
Amount funded by customers, term       10 years                    
Coal Community Transition Plan | Retail Rate Case Filing with Arizona Corporation Commission | ACC | APS | Navajo County Communities                            
Public Utilities, General Disclosures [Line Items]                            
Amount funded by shareholders     $ 500,000 $ 5,000,000                    
Amount funded by shareholders, term     60 days 5 years                    
Coal Community Transition Plan | Retail Rate Case Filing with Arizona Corporation Commission | ACC | APS | Navajo Nation, Hopi Tribe                            
Public Utilities, General Disclosures [Line Items]                            
Amount not recoverable     $ 215,500,000                      
Amount funded by shareholders     $ 1,000,000 $ 1,675,000                    
Amount funded by shareholders, term     60 days                      
Coal Community Transition Plan | Retail Rate Case Filing with Arizona Corporation Commission | ACC | APS | Navajo Nation                            
Public Utilities, General Disclosures [Line Items]                            
Amount funded by shareholders     $ 10,000,000                      
Amount funded by shareholders, term     3 years                      
Coal Community Transition Plan | Retail Rate Case Filing with Arizona Corporation Commission | ACC | APS | Navajo Nation, Hopi Reservation                            
Public Utilities, General Disclosures [Line Items]                            
Amount funded by shareholders     $ 1,250,000                      
Coal Community Transition Plan | Retail Rate Case Filing with Arizona Corporation Commission | ACC | APS | Navajo Nation Reservation                            
Public Utilities, General Disclosures [Line Items]                            
Revenue increase (decrease)     4,800,000                      
Amount funded by shareholders     $ 1,250,000                      
Disallowance of plant investments   $ 215,000,000                        
Minimum | ACC | APS                            
Public Utilities, General Disclosures [Line Items]                            
Annual increase in retail base rates           $ 69,000,000                
Minimum | Retail Rate Case Filing with Arizona Corporation Commission | ACC | APS                            
Public Utilities, General Disclosures [Line Items]                            
Rate matter, environmental surcharge cap rate (in dollars per kWh) | $ / kWh                 0.00016          
Maximum | Retail Rate Case Filing with Arizona Corporation Commission | ACC | APS                            
Public Utilities, General Disclosures [Line Items]                            
Rate matter, environmental surcharge cap rate (in dollars per kWh) | $ / kWh                 0.00050          
v3.22.2
Regulatory Matters - Capital Structure and Costs of Capital (Details) - APS - $ / kWh
Oct. 01, 2021
May 01, 2020
Oct. 31, 2019
May 01, 2019
Cost of Capital        
Long-term debt     4.10%  
Common stock equity     10.15%  
Weighted-average cost of capital     7.41%  
Retail Rate Case Filing with Arizona Corporation Commission        
Capital Structure        
Common stock equity     54.70%  
Retail Rate Case Filing with Arizona Corporation Commission | ACC        
Capital Structure        
Long-term debt     45.30%  
Net Metering | ACC        
Cost of Capital        
Second-year export energy price (in dollars per kWh) 0.094 0.094   0.105
v3.22.2
Regulatory Matters - Cost Recovery Mechanisms (Details)
 1 Months Ended 6 Months Ended 12 Months Ended
Jul. 12, 2022
$ / kWh
Jun. 01, 2022
USD ($)
Feb. 15, 2022
USD ($)
Feb. 01, 2022
USD ($)
$ / kWh
Nov. 01, 2021
$ / kWh
Oct. 01, 2021
$ / kWh
Jul. 01, 2021
USD ($)
Jun. 07, 2021
USD ($)
Jun. 01, 2021
USD ($)
Apr. 01, 2021
$ / kWh
Feb. 22, 2021
USD ($)
Feb. 15, 2021
USD ($)
Feb. 01, 2021
USD ($)
$ / kWh
Aug. 20, 2020
USD ($)
customer
Jun. 01, 2020
USD ($)
May 01, 2020
$ / kWh
Feb. 14, 2020
USD ($)
Feb. 01, 2020
$ / kWh
Nov. 14, 2019
USD ($)
customer
Oct. 31, 2019
USD ($)
$ / kWh
Oct. 29, 2019
USD ($)
May 01, 2019
$ / kWh
Apr. 10, 2019
Aug. 13, 2018
USD ($)
Nov. 20, 2017
USD ($)
Sep. 01, 2017
USD ($)
Mar. 31, 2021
Jun. 30, 2022
USD ($)
Jun. 30, 2021
USD ($)
Dec. 31, 2020
USD ($)
program
MW
Dec. 31, 2017
$ / kWh
Dec. 31, 2021
USD ($)
Dec. 17, 2021
USD ($)
Dec. 09, 2021
USD ($)
Jul. 01, 2020
USD ($)
May 15, 2020
USD ($)
May 05, 2020
USD ($)
Dec. 31, 2019
USD ($)
Jul. 01, 2019
USD ($)
Mar. 15, 2019
agreement
Dec. 31, 2018
USD ($)
Nov. 14, 2017
USD ($)
Change in regulatory asset                                                                                    
Deferred fuel and purchased power costs — current period                                                       $ 98,707,000 $ 135,905,000                          
Amounts charged to customers                                                       (96,842,000) (10,828,000)                          
Rate plan comparison tool, number of customers | customer                           3,800         13,000                                              
Rate plan comparison tool, inconvenience payment                           $ 25         $ 25                                              
APS                                                                                    
Change in regulatory asset                                                                                    
Deferred fuel and purchased power costs — current period                                                       98,707,000 135,905,000                          
Amounts charged to customers                                                       $ (96,842,000) (10,828,000)                          
Percentage increase under PSA effective for first billing cycle beginning April 2021                                                     50.00%                              
Remaining percentage increase under PSA effective for first billing cycle beginning November 2021                                                     50.00%                              
Demand side management funds                                                                         $ 36,000,000          
Customer credits                                                               $ 43,000,000                    
Customer credits, additional funds                                                               $ 7,000,000                    
APS | 2017 Settlement Agreement and its Customer Education and Outreach Plan                                                                                    
Change in regulatory asset                                                                                    
Settlement amount                     $ 24,750,000                                                              
Settlement amount returned to customers                     $ 24,000,000                                                              
Lost Fixed Cost Recovery Mechanisms | APS                                                                                    
Change in regulatory asset                                                                                    
Fixed cost recoverable per power lost (in dollars per kWh) | $ / kWh                                                             0.025                      
Percentage of retail revenues                                                       1.00%                            
Amount of adjustment representing prorated sales losses pending approval     $ 59,100,000                 $ 38,500,000         $ 26,600,000                                                  
Increase (decrease) in amount of adjustment representing prorated sales losses     $ 32,500,000                 $ 11,800,000         $ (9,600,000)                                                  
ACC | APS                                                                                    
Settlement Agreement                                                                                    
Program term                                                           18 years                        
Change in regulatory asset                                                                                    
Amount requested to be returned in form of tax savings to customers                                       $ (184,000,000)       $ 86,500,000                                    
Deferred taxes amortization, period                                             28 years 6 months                                      
Public Utilities, one-time bill credit                                         $ 64,000,000                                          
Public Utilities, one-time bill credit, additional benefit                                         $ 39,500,000                                          
Number of programs | program                                                           2                        
Solar capacity (in MW) | MW                                                           80                        
ACC | RES | APS                                                                                    
Settlement Agreement                                                                                    
Plan term                                                       5 years                            
ACC | RES 2018 | APS                                                                                    
Settlement Agreement                                                                                    
Amount of proposed budget             $ 93,100,000                                                     $ 100,500,000 $ 84,700,000       $ 86,300,000      
Revenue requirements                                                                     $ 4,500,000              
Authorized amount to be collected               $ 68,300,000                                                                    
ACC | RES 2018 | APS | Solar Communities                                                                                    
Settlement Agreement                                                                                    
Program term                                                 3 years                                  
ACC | Demand Side Management Adjustor Charge 2018 | APS                                                                                    
Settlement Agreement                                                                                    
Amount of proposed budget                                                   $ 52,600,000                               $ 52,600,000
ACC | Demand Side Management Adjustor Charge 2019 | APS                                                                                    
Settlement Agreement                                                                                    
Amount of proposed budget                                                                                 $ 34,100,000  
ACC | Demand Side Management Adjustor Charge 2020 | APS                                                                                    
Settlement Agreement                                                                                    
Amount of proposed budget                                                                       $ 51,900,000   $ 51,900,000        
ACC | Power Supply Adjustor (PSA) | APS                                                                                    
Change in regulatory asset                                                                                    
Beginning balance             300,912,000                                         $ 388,148,000 175,835,000                          
Deferred fuel and purchased power costs — current period                                                       98,707,000 135,905,000                          
Amounts charged to customers                                                       (96,842,000) (10,828,000)                          
Ending balance                                                       $ 390,013,000 $ 300,912,000 $ 175,835,000                        
PSA rate (in dollars per kWh) | $ / kWh       0.007544 0.003544         0.001544     0.003544         (0.000456)                                                
PSA rate for prior year (in dollars per kWh) | $ / kWh       (0.004842) (0.004444)         (0.004444)     0.003434         (0.002086)                                                
Forward component of increase in PSA (in dollars per kWh) | $ / kWh       0.012386 0.007988         0.005988     0.000110         0.001630                                                
Fuel and purchased power costs above annual cap       $ 365,000,000                 $ 215,900,000                                                          
ACC | Net Metering | APS                                                                                    
Change in regulatory asset                                                                                    
Cost of service, resource comparison proxy method, maximum annual percentage decrease                                                   10.00%                                
Cost of service for interconnected DG system customers, grandfathered period                                                   20 years                                
Cost of service for new customers, guaranteed export price period                                                   10 years                                
Second-year export energy price (in dollars per kWh) | $ / kWh           0.094                   0.094           0.105                                        
ACC | Net Metering | APS | Subsequent Event                                                                                    
Change in regulatory asset                                                                                    
Cost of service, resource comparison proxy method, maximum annual percentage decrease 10.00%                                                                                  
Second-year export energy price (in dollars per kWh) | $ / kWh 0.0846                                                                                  
ACC | Demand Side Management Adjustor Charge 2021 | APS                                                                                    
Settlement Agreement                                                                                    
Amount of proposed budget                                                           $ 63,700,000                        
ACC | Demand Side Management Adjustor Charge 2022 | APS                                                                                    
Settlement Agreement                                                                                    
Amount of proposed budget                                                                 $ 78,400,000                  
Change in regulatory asset                                                                                    
Increase in proposed budget                                                                 $ 14,000,000                  
FERC | Environmental Improvement Surcharge | APS                                                                                    
Change in regulatory asset                                                                                    
Increase (decrease) in annual wholesale transmission rates                         11,400,000                                                          
Rate matters, increase (decrease) in cost recovery, excess of annual amount                         $ 1,100,000                                                          
FERC | Open Access Transmission Tariff | APS                                                                                    
Change in regulatory asset                                                                                    
Increase (decrease) in annual wholesale transmission rates   $ 33,000,000             $ 4,000,000           $ (6,100,000)                                                      
Increase (decrease) in wholesale customer rates   (6,400,000)             (3,200,000)           4,800,000                                                      
Increase (decrease) in retail customer rates   26,600,000             7,200,000           (10,900,000)                                                      
Increase (decrease) in retail revenue requirements   $ (2,400,000)             $ (28,400,000)           $ (7,400,000)                                                      
Cost Recovery Mechanisms | ACC | Power Supply Adjustor (PSA) | APS                                                                                    
Change in regulatory asset                                                                                    
Historical component of increase in PSA (in dollars per kWh) | $ / kWh       0.004                 0.004         (0.002115)                                                
Cost recovery, number of agreements | agreement                                                                               2    
Minimum | Retail Rate Case Filing with Arizona Corporation Commission | APS                                                                                    
Change in regulatory asset                                                                                    
Fixed cost recoverable per power lost (in dollars per kWh) | $ / kWh                                       0.0256                                            
Minimum | ACC | APS                                                                                    
Change in regulatory asset                                                                                    
Operating results                                       $ (69,000,000)                                            
Minimum | ACC | RES 2018 | APS                                                                                    
Change in regulatory asset                                                                                    
Authorized spending             20,000,000                                                                      
Minimum | ACC | RES 2018 | APS | Solar Communities                                                                                    
Settlement Agreement                                                                                    
Required annual capital investment                                                 $ 10,000,000                                  
Maximum | Retail Rate Case Filing with Arizona Corporation Commission | APS                                                                                    
Change in regulatory asset                                                                                    
Fixed cost recoverable per power lost (in dollars per kWh) | $ / kWh                                       0.0268                                            
Maximum | ACC | RES 2018 | APS                                                                                    
Change in regulatory asset                                                                                    
Authorized spending             $ 30,000,000                                                                      
Maximum | ACC | RES 2018 | APS | Solar Communities                                                                                    
Settlement Agreement                                                                                    
Required annual capital investment                                                 $ 15,000,000                                  
v3.22.2
Regulatory Matters - Four Corners, Cholla and Navajo Plant (Details) - APS - USD ($)
$ in Millions
 1 Months Ended 6 Months Ended
Nov. 02, 2021
Sep. 30, 2018
Apr. 30, 2018
Jun. 30, 2022
Aug. 02, 2021
Navajo Nation, Economic Development Organization | Coal Community Transition Plan | Retail Rate Case Filing with Arizona Corporation Commission | ACC          
Business Acquisition [Line Items]          
Disallowance of annual amortization percentage         15.00%
SCE | Four Corners Units 4 and 5          
Business Acquisition [Line Items]          
Settlement agreement, ACC approved rate adjustment, annualized customer impact   $ 58.5 $ 67.5    
Disallowance of plant investments $ 194.0        
Cost deferrals $ 215.5        
Amount not recoverable       $ 154.4  
Retired power plant costs          
Business Acquisition [Line Items]          
Net book value       39.5  
Navajo Plant          
Business Acquisition [Line Items]          
Net book value       57.4  
Navajo Plant, Coal Reclamation Regulatory Asset          
Business Acquisition [Line Items]          
Net book value       $ 15.4  
v3.22.2
Regulatory Matters - Schedule of Regulatory Assets (Details) - USD ($)
$ in Thousands
Jun. 30, 2022
Dec. 31, 2021
Detail of regulatory assets    
Current $ 509,176 $ 518,524
Non-Current 1,180,656 1,192,987
Pension    
Detail of regulatory assets    
Current 0 0
Non-Current 514,330 509,751
Deferred fuel and purchased power    
Detail of regulatory assets    
Current 390,013 388,148
Non-Current 0 0
Income taxes — allowance for funds used during construction (“AFUDC”) equity    
Detail of regulatory assets    
Current 7,625 7,625
Non-Current 167,644 164,768
Ocotillo deferral    
Detail of regulatory assets    
Current 9,507 9,507
Non-Current 133,390 138,143
Retired power plant costs    
Detail of regulatory assets    
Current 15,157 15,160
Non-Current 91,113 99,681
SCR deferral    
Detail of regulatory assets    
Current 8,147 8,147
Non-Current 93,551 97,624
Deferred property taxes    
Detail of regulatory assets    
Current 8,569 8,569
Non-Current 36,772 41,057
Lost fixed cost recovery    
Detail of regulatory assets    
Current 43,788 63,889
Non-Current 0 0
Deferred compensation    
Detail of regulatory assets    
Current 0 0
Non-Current 34,251 33,997
Income taxes — investment tax credit basis adjustment    
Detail of regulatory assets    
Current 826 1,129
Non-Current 23,606 23,639
Palo Verde VIEs (Note 6)    
Detail of regulatory assets    
Current 0 0
Non-Current 21,013 21,094
Four Corners cost deferral    
Detail of regulatory assets    
Current 8,077 8,077
Non-Current 11,960 15,998
Coal reclamation    
Detail of regulatory assets    
Current 2,978 2,978
Non-Current 12,372 13,862
Active Union Medical Trust    
Detail of regulatory assets    
Current 0 0
Non-Current 13,704 1,175
Loss on reacquired debt    
Detail of regulatory assets    
Current 1,648 1,648
Non-Current 8,579 9,372
Mead-Phoenix transmission line contributions in aid of construction (“CIAC”)    
Detail of regulatory assets    
Current 332 332
Non-Current 8,882 9,048
TCA balancing account    
Detail of regulatory assets    
Current 8,805 170
Non-Current 0 3,663
Tax expense adjustor mechanism    
Detail of regulatory assets    
Current 656 656
Non-Current 5,518 5,845
Tax expense of Medicare subsidy    
Detail of regulatory assets    
Current 1,235 1,235
Non-Current 1,968 2,469
Other    
Detail of regulatory assets    
Current 1,813 1,254
Non-Current $ 2,003 $ 1,801
v3.22.2
Regulatory Matters - Schedule of Regulatory Liabilities (Details) - USD ($)
$ in Thousands
Jun. 30, 2022
Dec. 31, 2021
Detail of regulatory liabilities    
Current $ 404,107 $ 296,271
Non-Current 2,268,148 2,499,213
Asset retirement obligations    
Detail of regulatory liabilities    
Current 0 0
Non-Current 376,575 614,683
Other postretirement benefits    
Detail of regulatory liabilities    
Current 50,624 37,789
Non-Current 305,045 337,027
Deferred fuel and purchased power — mark-to-market (Note 7)    
Detail of regulatory liabilities    
Current 173,712 60,693
Non-Current 111,847 46,908
Removal costs    
Detail of regulatory liabilities    
Current 57,454 69,476
Non-Current 55,570 50,104
Income taxes — change in rates    
Detail of regulatory liabilities    
Current 2,876 2,876
Non-Current 63,636 64,802
Four Corners coal reclamation    
Detail of regulatory liabilities    
Current 2,316 2,316
Non-Current 50,860 53,076
Income taxes — deferred investment tax credit    
Detail of regulatory liabilities    
Current 2,264 2,264
Non-Current 46,663 47,337
Spent nuclear fuel    
Detail of regulatory liabilities    
Current 6,730 6,701
Non-Current 35,227 38,581
FERC transmission true up (b)    
Detail of regulatory liabilities    
Current 29,238 21,379
Non-Current 3,620 12,924
Renewable energy standard    
Detail of regulatory liabilities    
Current 25,401 38,453
Non-Current 492 187
Property tax deferral (e)    
Detail of regulatory liabilities    
Current 4,671 4,671
Non-Current 13,186 15,521
Sundance maintenance    
Detail of regulatory liabilities    
Current 0 0
Non-Current 15,345 13,797
Demand side management    
Detail of regulatory liabilities    
Current 0 0
Non-Current 9,214 5,417
Tax expense adjustor mechanism    
Detail of regulatory liabilities    
Current 0 0
Non-Current 4,835 4,835
Other    
Detail of regulatory liabilities    
Current 679 1,511
Non-Current 2,155 592
ACC | Excess deferred income taxes - Tax Act    
Detail of regulatory liabilities    
Current 40,903 40,903
Non-Current 954,939 971,545
FERC | Excess deferred income taxes - Tax Act    
Detail of regulatory liabilities    
Current 7,239 7,239
Non-Current $ 218,939 $ 221,877
v3.22.2
Retirement Plans and Other Postretirement Benefits - Narrative (Details)
$ in Millions
 6 Months Ended
Jun. 30, 2022
USD ($)
Pension Benefits  
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]  
Minimum employer contributions for the next three years $ 0
v3.22.2
Retirement Plans and Other Postretirement Benefits - Schedule of Net Benefit Cost (Details) - USD ($)
$ in Thousands
 3 Months Ended 6 Months Ended
Jun. 30, 2022
Jun. 30, 2021
Jun. 30, 2022
Jun. 30, 2021
Amortization of:        
Portion of benefit charged to expense $ (25,257) $ (28,175) $ (49,066) $ (55,966)
Pension Benefits        
Retirement Plans and Other Benefits        
Service cost — benefits earned during the period 13,406 14,939 27,737 30,618
Interest cost on benefit obligation 26,723 24,614 53,746 49,283
Expected return on plan assets (46,494) (50,706) (92,888) (101,314)
Amortization of:        
Prior service credit 0 0 0 0
Net actuarial loss (gain) 3,989 3,989 8,757 7,974
Net periodic benefit (2,376) (7,164) (2,648) (13,439)
Portion of benefit charged to expense (4,722) (8,614) (8,012) (16,625)
Other Benefits        
Retirement Plans and Other Benefits        
Service cost — benefits earned during the period 4,017 4,341 8,235 8,898
Interest cost on benefit obligation 4,283 4,095 8,746 8,257
Expected return on plan assets (11,511) (10,361) (23,021) (20,722)
Amortization of:        
Prior service credit (9,447) (9,427) (18,894) (18,854)
Net actuarial loss (gain) (3,436) (2,641) (6,418) (5,046)
Net periodic benefit (16,094) (13,993) (31,352) (27,467)
Portion of benefit charged to expense $ (11,523) $ (9,608) $ (22,418) $ (19,136)
v3.22.2
Palo Verde Sale Leaseback Variable Interest Entities - Narrative (Details)
 3 Months Ended 6 Months Ended
Jun. 30, 2022
USD ($)
powerPlant
Jun. 30, 2021
USD ($)
Jun. 30, 2022
USD ($)
lease
powerPlant
Jun. 30, 2021
USD ($)
Dec. 31, 1986
trust
Palo Verde Sale Leaseback Variable Interest Entities          
Net income attributable to noncontrolling interest $ 4,306,000 $ 3,739,000 $ 8,612,000 $ 8,612,000  
APS          
Palo Verde Sale Leaseback Variable Interest Entities          
Number of VIE lessor trusts 3   3   3
Net income attributable to noncontrolling interest $ 4,306,000 3,739,000 $ 8,612,000 8,612,000  
Palo Verde VIE | APS          
Palo Verde Sale Leaseback Variable Interest Entities          
Net income attributable to noncontrolling interest $ 4,000,000 $ 4,000,000 9,000,000 $ 9,000,000  
Initial loss exposure to the VIE's noncontrolling equity participants during lease extension period     315,000,000    
Palo Verde VIE | APS | Maximum          
Palo Verde Sale Leaseback Variable Interest Entities          
Maximum loss exposure to the VIE's noncontrolling equity participants during lease extension period (up to)     $ 501,000,000    
Palo Verde VIE | APS | Period through 2033          
Palo Verde Sale Leaseback Variable Interest Entities          
Number of leases under which assets are retained | lease     3    
Annual lease payments     $ 21,000,000    
Palo Verde VIE | APS | Period through 2033 | Maximum          
Palo Verde Sale Leaseback Variable Interest Entities          
Lease period (up to)     2 years    
v3.22.2
Palo Verde Sale Leaseback Variable Interest Entities - Schedule of VIEs (Details) - USD ($)
$ in Thousands
Jun. 30, 2022
Dec. 31, 2021
Palo Verde Sale Leaseback Variable Interest Entities    
Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation $ 16,376,203 $ 15,987,434
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets    
Equity — Noncontrolling interests 113,244 115,260
APS    
Palo Verde Sale Leaseback Variable Interest Entities    
Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation 16,355,168 15,985,346
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets    
Equity — Noncontrolling interests 113,244 115,260
Palo Verde VIE | APS    
Palo Verde Sale Leaseback Variable Interest Entities    
Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation 92,231 94,166
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets    
Equity — Noncontrolling interests $ 113,244 $ 115,260
v3.22.2
Derivative Accounting - Narrative (Details)
$ in Thousands
Jun. 30, 2022
USD ($)
Commodity Contracts  
Derivative Accounting  
Aggregate fair value of derivative instruments in a net liability position $ 1,882
Additional collateral to counterparties for energy related non-derivative instrument contracts 77,000
Risk Management Assets | Credit Concentration Risk  
Derivative Accounting  
Aggregate fair value of derivative instruments in a net liability position $ 249,000
Risk Management Assets | Credit Concentration Risk | Two Counterparties  
Derivative Accounting  
Concentration risk 19.00%
APS  
Derivative Accounting  
Percentage of unrealized gains and losses on certain derivatives deferred for future rate treatment 100.00%
v3.22.2
Derivative Accounting - Schedule of Gross Notional Amounts Outstanding (Details) - Commodity Contracts
GWh in Thousands, Bcf in Thousands
Jun. 30, 2022
GWh
Bcf
Dec. 31, 2021
GWh
Bcf
Outstanding gross notional amount of derivatives    
Power | GWh 1,208 0
Gas | Bcf 168 155
v3.22.2
Derivative Accounting - Gains and Losses from Derivative Instruments (Details) - USD ($)
$ in Thousands
 3 Months Ended 6 Months Ended
Jun. 30, 2022
Jun. 30, 2021
Jun. 30, 2022
Jun. 30, 2021
Not Designated as Hedging Instruments | Commodity Contracts | Fuel and purchased power        
Gains and losses from derivative instruments        
Net Gain Recognized in Income $ 62,525 $ 95,116 $ 286,267 $ 121,975
v3.22.2
Derivative Accounting - Derivative Instruments in the Balance Sheets (Details) - USD ($)
Jun. 30, 2022
Dec. 31, 2021
Assets    
Gross Recognized Derivatives $ 248,875,000 $ 110,389,000
Liabilities    
Gross Recognized Derivatives (1,543,000)  
Amount Reported on Balance Sheets (5,596,000) (4,373,000)
Commodity Contracts    
Assets    
Gross Recognized Derivatives 289,612,000 115,079,000
Amounts Offset (40,787,000) (4,740,000)
Net Recognized Derivatives 248,825,000 110,339,000
Other 50,000 50,000
Amount Reported on Balance Sheets 248,875,000 110,389,000
Liabilities    
Gross Recognized Derivatives (4,053,000) (7,478,000)
Amounts Offset 357,000 4,740,000
Net Recognized Derivatives (3,696,000) (2,738,000)
Other (1,900,000) (1,635,000)
Amount Reported on Balance Sheets (5,596,000) (4,373,000)
Assets and Liabilities    
Gross Recognized Derivatives 285,559,000 107,601,000
Amounts Offset (40,430,000) 0
Net Recognized Derivatives 245,129,000 107,601,000
Other (1,850,000) (1,585,000)
Amount Reported on Balance Sheets 243,279,000 106,016,000
Cash collateral received subject to offsetting 40,430,000  
Cash collateral received from counterparties 1,900,000 1,635,000
Commodity Contracts | Current assets    
Assets    
Gross Recognized Derivatives 177,765,000 66,777,000
Amounts Offset (40,787,000) (3,346,000)
Net Recognized Derivatives 136,978,000 63,431,000
Other 50,000 50,000
Amount Reported on Balance Sheets 137,028,000 63,481,000
Commodity Contracts | Investments and other assets    
Assets    
Gross Recognized Derivatives 111,847,000 48,302,000
Amounts Offset 0 (1,394,000)
Net Recognized Derivatives 111,847,000 46,908,000
Other 0 0
Amount Reported on Balance Sheets $ 111,847,000 46,908,000
Commodity Contracts | Current liabilities    
Liabilities    
Gross Recognized Derivatives   (6,084,000)
Amounts Offset   3,346,000
Net Recognized Derivatives   (2,738,000)
Other   (1,635,000)
Amount Reported on Balance Sheets   (4,373,000)
Assets and Liabilities    
Cash collateral received from counterparties   1,635,000
Commodity Contracts | Deferred credits and other    
Liabilities    
Gross Recognized Derivatives   (1,394,000)
Amounts Offset   1,394,000
Net Recognized Derivatives   0
Other   0
Amount Reported on Balance Sheets   0
Assets and Liabilities    
Cash collateral received from counterparties   $ 0
v3.22.2
Derivative Accounting - Credit Risk and Credit Related Contingent Features (Details) - Commodity Contracts
$ in Thousands
Jun. 30, 2022
USD ($)
Credit Risk and Credit-Related Contingent Features  
Aggregate fair value of derivative instruments in a net liability position $ 1,882
Additional cash collateral in the event credit-risk-related contingent features were fully triggered (a) $ 883
v3.22.2
Commitments and Contingencies (Details)
 6 Months Ended 108 Months Ended
Mar. 22, 2022
USD ($)
Nov. 02, 2021
USD ($)
Nov. 01, 2021
USD ($)
claim
Feb. 22, 2021
USD ($)
Jul. 03, 2018
USD ($)
Apr. 05, 2018
plaintiff
defendant
Dec. 16, 2016
plaintiff
Jul. 06, 2016
Aug. 06, 2013
defendant
Jun. 30, 2022
USD ($)
powerPlant
Jun. 30, 2020
USD ($)
timePeriod
claim
Dec. 31, 1986
trust
Commitments and Contingencies                        
Production tax credit guarantees                   $ 35,000,000    
APS                        
Commitments and Contingencies                        
Maximum insurance against public liability per occurrence for a nuclear incident (up to)                   13,500,000,000    
Maximum available nuclear liability insurance (up to)                   450,000,000    
Remaining nuclear liability insurance through mandatory industry wide retrospective assessment program                   13,100,000,000    
Maximum retrospective premium assessment per reactor for each nuclear liability incident                   137,600,000    
Annual limit per incident with respect to maximum retrospective premium assessment                   $ 20,500,000    
Number of VIE lessor trusts                   3   3
Maximum potential retrospective assessment per incident of APS                   $ 120,100,000    
Annual payment limitation with respect to maximum potential retrospective premium assessment                   17,900,000    
Amount of "all risk" (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde                   2,800,000,000    
Maximum amount that APS could incur under the current NEIL policies for each retrospective assessment                   22,300,000    
Collateral assurance provided based on rating triggers                   $ 62,800,000    
Period to provide collateral assurance based on rating triggers                   20 days    
APS | Letters of Credit Expiring in 2023                        
Commitments and Contingencies                        
Outstanding letters of credit                   $ 9,000,000    
APS | Surety Bonds Expiring in 2023                        
Commitments and Contingencies                        
Surety bonds expiring, amount                   6,000,000    
APS | Coal combustion waste | Four Corners                        
Commitments and Contingencies                        
Site contingency increase in loss exposure not accrued, best estimate                   30,000,000    
APS | Coal combustion waste | Cholla | Minimum                        
Commitments and Contingencies                        
Site contingency increase in loss exposure not accrued, best estimate                   16,000,000    
APS | Coal combustion waste | Navajo Plant                        
Commitments and Contingencies                        
Site contingency increase in loss exposure not accrued, best estimate                   1,000,000    
APS | Coal combustion waste | Cholla and Four Corners | Minimum                        
Commitments and Contingencies                        
Site contingency increase in loss exposure not accrued, best estimate                   10,000,000    
APS | Coal combustion waste | Cholla and Four Corners | Maximum                        
Commitments and Contingencies                        
Site contingency increase in loss exposure not accrued, best estimate                   $ 15,000,000    
APS | Four Corners Units 4 and 5 | Regional Haze Rules                        
Commitments and Contingencies                        
Percentage of share of cost of control                   63.00%    
Expected environmental cost                   $ 400,000,000    
APS | SCE | Four Corners Units 4 and 5                        
Commitments and Contingencies                        
Disallowance of plant investments   $ 194,000,000                    
Cost deferrals   $ 215,500,000                    
Amount not recoverable                   154,400,000    
APS | Contaminated groundwater wells                        
Commitments and Contingencies                        
Costs related to investigation and study under Superfund site                   3,000,000    
Number of defendants against whom Roosevelt Irrigation District (RID) filed lawsuit | defendant           28     24      
Number of plaintiffs | plaintiff             2          
APS | Contaminated groundwater wells | Settled Litigation                        
Commitments and Contingencies                        
Number of plaintiffs | plaintiff           2            
APS | Public Utilities, Inventory, Fuel                        
Commitments and Contingencies                        
Increase in contractual obligations                   1,200,000,000    
Increase in contractual obligations, lease arrangements                   500,000,000    
Total fixed consideration paid for lease arrangements                   $ 1,800,000,000    
4C Acquisition, LLC | Four Corners                        
Commitments and Contingencies                        
Percentage of share of cost of control               7.00%        
NTEC | Four Corners                        
Commitments and Contingencies                        
Option to purchase ownership interest (as a percent)         7.00%     7.00%        
Proceeds from operating and maintenance cost reimbursement         $ 70,000,000              
Breach of Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste                        
Commitments and Contingencies                        
Litigation Settlement, Amount Awarded from Other Party $ 12,100,000   $ 12,200,000               $ 111,800,000  
Breach of Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste | APS                        
Commitments and Contingencies                        
Number of claims submitted | claim     8               7  
Number of settlement agreement time periods | timePeriod                     7  
Litigation Settlement, Amount Awarded from Other Party $ 3,500,000   $ 3,600,000               $ 32,500,000  
2017 Settlement Agreement and its Customer Education and Outreach Plan | APS                        
Commitments and Contingencies                        
Settlement amount       $ 24,750,000                
Settlement amount returned to customers       $ 24,000,000                
v3.22.2
Other Income and Other Expense (Details) - USD ($)
$ in Thousands
 3 Months Ended 6 Months Ended
Jun. 30, 2022
Jun. 30, 2021
Jun. 30, 2022
Jun. 30, 2021
Other income:        
Interest income $ 1,691 $ 1,687 $ 3,333 $ 3,635
Miscellaneous (9) 40 53 43
Total other income 1,682 12,207 3,386 24,636
Other expense:        
Non-operating costs (3,701) (4,102) (6,154) (6,039)
Investment losses — net (575) (431) (1,256) (774)
Miscellaneous (308) (651) (596) (2,224)
Total other expense (4,584) (5,184) (8,006) (9,037)
APS        
Other income:        
Interest income 1,396 1,047 2,495 2,528
Miscellaneous 0 36 53 37
Total other income 1,396 11,563 2,548 23,523
Other expense:        
Non-operating costs (2,477) (3,615) (4,038) (5,392)
Miscellaneous (309) (646) (596) (2,219)
Total other expense (2,786) (4,261) (4,634) (7,611)
SCR deferral        
Other income:        
Debt return 0 4,089 0 8,175
SCR deferral | APS        
Other income:        
Debt return 0 4,089 0 8,175
Octotillo modernization project        
Other income:        
Debt return 0 6,391 0 12,783
Octotillo modernization project | APS        
Other income:        
Debt return $ 0 $ 6,391 $ 0 $ 12,783
v3.22.2
Earnings Per Share (Details) - USD ($)
$ / shares in Units, shares in Thousands, $ in Thousands
 3 Months Ended 6 Months Ended
Jun. 30, 2022
Jun. 30, 2021
Jun. 30, 2022
Jun. 30, 2021
Earnings Per Share [Abstract]        
Net income attributable to common shareholders $ 164,312 $ 215,697 $ 181,268 $ 251,338
Weighted average common shares outstanding - basic (in shares) 113,172 112,882 113,137 112,855
Net effect of dilutive securities:        
Contingently issuable performance shares and restricted stock units (in shares) 197 341 195 303
Weighted average common shares outstanding — diluted (in shares) 113,369 113,223 113,332 113,158
Earnings per weighted-average common share outstanding        
Net income attributable to common shareholders - basic (in dollars per share) $ 1.45 $ 1.91 $ 1.60 $ 2.23
Net income attributable to common shareholders - diluted (in dollars per share) $ 1.45 $ 1.91 $ 1.60 $ 2.22
v3.22.2
Fair Value Measurements - Assets and Liabilities Measured on a Recurring Basis (Details) - USD ($)
$ in Thousands
Jun. 30, 2022
Dec. 31, 2021
Assets    
Commodity contracts, assets $ 248,875 $ 110,389
Commodity contracts, liabilities (40,737) (4,690)
Nuclear decommissioning trust 1,076,088 1,294,757
Nuclear decommissioning trust, other 462,020 567,266
Other special use funds 346,406 358,410
Other special use funds, other 938 936
Total assets 1,671,369 1,763,556
Total assets, other 422,221 563,512
Liabilities    
Gross derivative liability (1,543)  
Gross derivative liability, other   3,105
Amount reported on balance sheet (5,596) (4,373)
Equity securities    
Assets    
Nuclear decommissioning trust 14,174 17,482
Nuclear decommissioning trust, other 1,401 (27,782)
Other special use funds 30,031 48,506
Other special use funds, other 938 936
U.S. commingled equity funds    
Assets    
Nuclear decommissioning trust 460,619 595,048
U.S. Treasury debt    
Assets    
Nuclear decommissioning trust 211,284 240,745
Other special use funds 310,667 298,170
Corporate debt    
Assets    
Nuclear decommissioning trust 177,297 203,454
Mortgage-backed securities    
Assets    
Nuclear decommissioning trust 135,858 155,574
Municipal bonds    
Assets    
Nuclear decommissioning trust 67,943 72,189
Other special use funds 5,708 11,734
Other fixed income    
Assets    
Nuclear decommissioning trust 8,913 10,265
Level 1    
Assets    
Commodity contracts, assets 0 0
Nuclear decommissioning trust 224,057 286,009
Other special use funds 339,760 345,740
Total assets 563,817 631,749
Liabilities    
Gross derivative liability 0 0
Level 1 | Equity securities    
Assets    
Nuclear decommissioning trust 12,773 45,264
Other special use funds 29,093 47,570
Level 1 | U.S. commingled equity funds    
Assets    
Nuclear decommissioning trust 0 0
Level 1 | U.S. Treasury debt    
Assets    
Nuclear decommissioning trust 211,284 240,745
Other special use funds 310,667 298,170
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 funds 0 0
Level 1 | Other fixed income    
Assets    
Nuclear decommissioning trust 0 0
Level 2    
Assets    
Commodity contracts, assets 281,107 115,079
Nuclear decommissioning trust 390,011 441,482
Other special use funds 5,708 11,734
Total assets 676,826 568,295
Liabilities    
Gross derivative liability (94) (4,740)
Level 2 | Equity securities    
Assets    
Nuclear decommissioning trust 0 0
Other special use funds 0 0
Level 2 | U.S. commingled equity funds    
Assets    
Nuclear decommissioning trust 0 0
Level 2 | U.S. Treasury debt    
Assets    
Nuclear decommissioning trust 0 0
Other special use funds 0 0
Level 2 | Corporate debt    
Assets    
Nuclear decommissioning trust 177,297 203,454
Level 2 | Mortgage-backed securities    
Assets    
Nuclear decommissioning trust 135,858 155,574
Level 2 | Municipal bonds    
Assets    
Nuclear decommissioning trust 67,943 72,189
Other special use funds 5,708 11,734
Level 2 | Other fixed income    
Assets    
Nuclear decommissioning trust 8,913 10,265
Level 3    
Assets    
Commodity contracts, assets 8,505 0
Nuclear decommissioning trust 0 0
Other special use funds 0 0
Total assets 8,505 0
Liabilities    
Gross derivative liability (3,959) (2,738)
Level 3 | Equity securities    
Assets    
Nuclear decommissioning trust 0 0
Other special use funds 0 0
Level 3 | U.S. commingled equity funds    
Assets    
Nuclear decommissioning trust 0 0
Level 3 | U.S. Treasury debt    
Assets    
Nuclear decommissioning trust 0 0
Other special use funds 0 0
Level 3 | Corporate debt    
Assets    
Nuclear decommissioning trust 0 0
Level 3 | Mortgage-backed securities    
Assets    
Nuclear decommissioning trust 0 0
Level 3 | Municipal bonds    
Assets    
Nuclear decommissioning trust 0 0
Other special use funds 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 $ 460,619 $ 595,048
v3.22.2
Investments in Nuclear Decommissioning Trusts and Other Special Use Funds - Narrative (Details)
$ in Millions
 12 Months Ended
Dec. 31, 2021
USD ($)
APS  
Schedule of Equity Method Investments [Line Items]  
Employee medical claims amount $ 15
v3.22.2
Investments in Nuclear Decommissioning Trusts and Other Special Use Funds (Details) - APS - USD ($)
$ in Thousands
 3 Months Ended 6 Months Ended 12 Months Ended
Jun. 30, 2022
Jun. 30, 2021
Jun. 30, 2022
Jun. 30, 2021
Dec. 31, 2021
Nuclear decommissioning trust fund assets          
Fair Value $ 1,422,494   $ 1,422,494   $ 1,653,167
Total Unrealized Gains     330,029   475,670
Total Unrealized Losses     (57,009)   (4,063)
Amortized cost 971,000   971,000   972,000
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds          
Realized gains 6,282 $ 1,406 7,305 $ 4,374  
Realized losses (12,439) (1,146) (19,674) (5,294)  
Proceeds from the sale of securities 330,432 207,864 691,670 587,842  
Nuclear Decommissioning Trusts          
Nuclear decommissioning trust fund assets          
Fair Value 1,076,088   1,076,088   1,294,757
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds          
Realized gains 6,282 1,406 7,305 4,374  
Realized losses (12,439) (1,146) (19,674) (5,294)  
Proceeds from the sale of securities 309,966 190,340 629,659 425,068  
Other Special Use Funds          
Nuclear decommissioning trust fund assets          
Fair Value 346,406   346,406   358,410
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds          
Realized gains 0 0 0 0  
Realized losses 0 0 0 0  
Proceeds from the sale of securities 20,466 $ 17,524 62,011 $ 162,774  
Equity securities          
Nuclear decommissioning trust fund assets          
Equity securities 502,485   502,485   687,882
Total Unrealized Gains     327,032   451,387
Total Unrealized Losses     (183)   0
Equity securities | Nuclear Decommissioning Trusts          
Nuclear decommissioning trust fund assets          
Equity securities 473,392   473,392   640,312
Equity securities | Other Special Use Funds          
Nuclear decommissioning trust fund assets          
Equity securities 29,093   29,093   47,570
Available for sale-fixed income securities          
Nuclear decommissioning trust fund assets          
Fair Value 917,670   917,670   992,131
Total Unrealized Gains     2,997   24,283
Total Unrealized Losses     (56,826)   (4,063)
Fair value of fixed income securities, summarized by contractual maturities          
Less than one year 100,866   100,866    
1 year – 5 years 373,996   373,996    
5 years – 10 years 170,310   170,310    
Greater than 10 years 272,498   272,498    
Total 917,670   917,670    
Available for sale-fixed income securities | Nuclear Decommissioning Trusts          
Nuclear decommissioning trust fund assets          
Fair Value 601,295   601,295   682,227
Fair value of fixed income securities, summarized by contractual maturities          
Less than one year 13,114   13,114    
1 year – 5 years 192,566   192,566    
5 years – 10 years 127,287   127,287    
Greater than 10 years 268,328   268,328    
Total 601,295   601,295    
Available for sale-fixed income securities | Other Special Use Funds          
Nuclear decommissioning trust fund assets          
Fair Value 316,375   316,375   309,904
Available for sale-fixed income securities | Coal Reclamation Escrow Account          
Fair value of fixed income securities, summarized by contractual maturities          
Less than one year 47,528   47,528    
1 year – 5 years 31,422   31,422    
5 years – 10 years 0   0    
Greater than 10 years 4,170   4,170    
Total 83,120   83,120    
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 40,224   40,224    
1 year – 5 years 150,008   150,008    
5 years – 10 years 43,023   43,023    
Greater than 10 years 0   0    
Total 233,255   233,255    
Other          
Nuclear decommissioning trust fund assets          
Fair Value 2,339   2,339   (26,846)
Total Unrealized Gains     0   0
Total Unrealized Losses     0   0
Other | Nuclear Decommissioning Trusts          
Nuclear decommissioning trust fund assets          
Fair Value 1,401   1,401   (27,782)
Other | Other Special Use Funds          
Nuclear decommissioning trust fund assets          
Fair Value $ 938   $ 938   $ 936
v3.22.2
Changes in Accumulated Other Comprehensive Loss (Details) - USD ($)
$ in Thousands
 3 Months Ended 6 Months Ended
Jun. 30, 2022
Jun. 30, 2021
Jun. 30, 2022
Jun. 30, 2021
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]        
Beginning balance $ 6,050,136 $ 5,806,680 $ 6,021,460 $ 5,752,793
OCI (loss) before reclassifications (2,206) (255) (1,954) 7
Amounts reclassified from accumulated other comprehensive loss 1,100 1,189 2,001 2,211
Ending balance 6,021,523 5,834,899 6,021,523 5,834,899
APS        
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]        
Beginning balance 6,929,796 6,386,275 6,750,473 6,345,185
Ending balance 6,899,284 6,412,290 6,899,284 6,412,290
Pension and Other Postretirement Benefits        
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]        
Beginning balance (52,984) (59,703) (53,885) (60,725)
OCI (loss) before reclassifications (3,213) (1,125) (3,213) (1,125)
Amounts reclassified from accumulated other comprehensive loss 1,100 1,189 2,001 2,211
Ending balance (55,097) (59,639) (55,097) (59,639)
Pension and Other Postretirement Benefits | APS        
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]        
Beginning balance (34,060) (39,991) (34,880) (40,918)
OCI (loss) before reclassifications (3,160) (914) (3,160) (914)
Amounts reclassified from accumulated other comprehensive loss 999 1,073 1,819 2,000
Ending balance (36,221) (39,832) (36,221) (39,832)
Derivative Instruments        
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]        
Beginning balance (724) (1,809) (976) (2,071)
OCI (loss) before reclassifications 1,007 870 1,259 1,132
Amounts reclassified from accumulated other comprehensive loss 0 0 0 0
Ending balance 283 (939) 283 (939)
Accumulated Other Comprehensive Loss        
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]        
Beginning balance (53,708) (61,512) (54,861) (62,796)
Ending balance (54,814) (60,578) (54,814) (60,578)
Accumulated Other Comprehensive Loss | APS        
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]        
Beginning balance (34,060) (39,991) (34,880) (40,918)
Ending balance $ (36,221) $ (39,832) $ (36,221) $ (39,832)