PINNACLE WEST CAPITAL CORP, 10-Q filed on 8/6/2020
Quarterly Report
v3.20.2
Document and Entity Information - shares
 6 Months Ended
Jun. 30, 2020
Jul. 30, 2020
Entity Information [Line Items]    
Entity Shell Company false  
Entity Interactive Data Current Yes  
Security Exchange Name NYSE  
Trading Symbol PNW  
Title of 12(b) Security Common Stock  
Entity Tax Identification Number 86-0512431  
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 File Number 1-8962  
Document Transition Report false  
Document Quarterly Report true  
Entity Registrant Name PINNACLE WEST CAPITAL CORPORATION  
Entity Central Index Key 0000764622  
Document Type 10-Q  
Document Period End Date Jun. 30, 2020  
Amendment Flag false  
Current Fiscal Year End Date --12-31  
Entity Current Reporting Status Yes  
Entity Filer Category Large Accelerated Filer  
Entity Emerging Growth Company false  
Entity Small Business false  
Entity Common Stock, Shares Outstanding (in shares)   112,556,967
Document Fiscal Year Focus 2020  
Document Fiscal Period Focus Q2  
Entity Incorporation, State or Country Code AZ  
APS    
Entity Information [Line Items]    
Entity Shell Company false  
Entity Interactive Data Current Yes  
Entity Tax Identification Number 86-0011170  
Entity Address, Address Line One 400 North Fifth Street, P.O. Box 53999  
Entity Address, City or Town Phoenix  
Entity Address, State or Province AZ  
Entity Address, Postal Zip Code 85072-3999  
City Area Code (602)  
Local Phone Number 250-1000  
Entity File Number 1-4473  
Entity Registrant Name ARIZONA PUBLIC SERVICE COMPANY  
Entity Central Index Key 0000007286  
Document Type 10-Q  
Document Period End Date Jun. 30, 2020  
Amendment Flag false  
Current Fiscal Year End Date --12-31  
Entity Current Reporting Status Yes  
Entity Filer Category Non-accelerated Filer  
Entity Emerging Growth Company false  
Entity Small Business false  
Entity Common Stock, Shares Outstanding (in shares)   71,264,947
Document Fiscal Year Focus 2020  
Document Fiscal Period Focus Q2  
Entity Incorporation, State or Country Code AZ  
v3.20.2
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited) - USD ($)
shares in Thousands, $ in Thousands
 3 Months Ended 6 Months Ended
Jun. 30, 2020
Jun. 30, 2019
Jun. 30, 2020
Jun. 30, 2019
OPERATING REVENUES (NOTE 2) $ 929,590 $ 869,501 $ 1,591,520 $ 1,610,031
OPERATING EXPENSES        
Fuel and purchased power 238,382 242,222 426,903 472,810
Operations and maintenance 219,392 227,543 440,710 473,177
Depreciation and amortization 152,482 147,374 306,561 296,081
Taxes other than income taxes 56,768 55,090 113,536 110,180
Other expenses 692 683 1,514 1,110
Total 667,716 672,912 1,289,224 1,353,358
OPERATING INCOME 261,874 196,589 302,296 256,673
OTHER INCOME (DEDUCTIONS)        
Allowance for equity funds used during construction 8,811 7,572 16,508 18,760
Pension and other postretirement non-service credits - net 14,142 6,374 28,053 11,488
Other income (Note 9) 16,670 12,885 29,239 20,054
Other expense (Note 9) (4,036) (4,350) (8,820) (8,708)
Total 35,587 22,481 64,980 41,594
INTEREST EXPENSE        
Interest charges 62,690 57,465 121,924 118,118
Allowance for borrowed funds used during construction (4,749) (4,494) (8,825) (11,159)
Total 57,941 52,971 113,099 106,959
INCOME BEFORE INCOME TAXES 239,520 166,099 254,177 191,308
INCOME TAXES 41,061 17,080 20,852 19,498
NET INCOME 198,459 149,019 233,325 171,810
Less: Net income attributable to noncontrolling interests (Note 6) 4,874 4,874 9,747 9,747
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS $ 193,585 $ 144,145 $ 223,578 $ 162,063
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING        
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - BASIC (in shares) 112,638 112,337 112,616 112,381
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - DILUTED (in shares) 112,879 112,651 112,871 112,734
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING        
Net income attributable to common shareholders - basic (in dollars per share) $ 1.72 $ 1.28 $ 1.99 $ 1.44
Net income attributable to common shareholders - diluted (in dollars per share) $ 1.71 $ 1.28 $ 1.98 $ 1.44
APS        
OPERATING REVENUES (NOTE 2) $ 929,590 $ 869,501 $ 1,591,520 $ 1,610,031
OPERATING EXPENSES        
Fuel and purchased power 238,382 242,222 426,903 472,810
Operations and maintenance 216,221 224,143 434,486 464,518
Depreciation and amortization 152,460 147,354 306,518 296,039
Taxes other than income taxes 56,758 55,081 113,516 110,159
Other expenses 692 683 1,514 1,110
Total 664,513 669,483 1,282,937 1,344,636
OPERATING INCOME 265,077 200,018 308,583 265,395
OTHER INCOME (DEDUCTIONS)        
Allowance for equity funds used during construction 8,811 7,572 16,508 18,760
Pension and other postretirement non-service credits - net 14,421 6,757 28,683 12,256
Other income (Note 9) 13,272 11,691 24,905 18,107
Other expense (Note 9) (3,859) (3,428) (8,527) (7,306)
Total 32,645 22,592 61,569 41,817
INTEREST EXPENSE        
Interest charges 56,802 53,591 112,538 110,256
Allowance for borrowed funds used during construction (4,749) (4,494) (8,825) (11,159)
Total 52,053 49,097 103,713 99,097
INCOME BEFORE INCOME TAXES 245,669 173,513 266,439 208,115
INCOME TAXES 43,677 18,463 24,229 19,916
NET INCOME 201,992 155,050 242,210 188,199
Less: Net income attributable to noncontrolling interests (Note 6) 4,874 4,874 9,747 9,747
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS $ 197,118 $ 150,176 $ 232,463 $ 178,452
v3.20.2
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) - USD ($)
$ in Thousands
 3 Months Ended 6 Months Ended
Jun. 30, 2020
Jun. 30, 2019
Jun. 30, 2020
Jun. 30, 2019
NET INCOME $ 198,459 $ 149,019 $ 233,325 $ 171,810
Derivative instruments:        
Net unrealized gain, net of tax expense (1,549) 0 (1,257) 0
Reclassification of net realized loss, net of tax benefit 262 404 282 732
Pension and other postretirement benefits activity, net of tax expense (1,009) (1,539) 196 (660)
Total other comprehensive income (loss) (2,296) (1,135) (779) 72
COMPREHENSIVE INCOME 196,163 147,884 232,546 171,882
Less: Comprehensive income attributable to noncontrolling interests 4,874 4,874 9,747 9,747
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS 191,289 143,010 222,799 162,135
APS        
NET INCOME 201,992 155,050 242,210 188,199
Derivative instruments:        
Net unrealized gain, net of tax expense 0 0 292 0
Reclassification of net realized loss, net of tax benefit 262 404 282 732
Pension and other postretirement benefits activity, net of tax expense (1,090) (1,653) (77) (901)
Total other comprehensive income (loss) (828) (1,249) 497 (169)
COMPREHENSIVE INCOME 201,164 153,801 242,707 188,030
Less: Comprehensive income attributable to noncontrolling interests 4,874 4,874 9,747 9,747
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS $ 196,290 $ 148,927 $ 232,960 $ 178,283
v3.20.2
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) (Parenthetical) - USD ($)
$ in Thousands
 3 Months Ended 6 Months Ended
Jun. 30, 2020
Jun. 30, 2019
Jun. 30, 2020
Jun. 30, 2019
Net unrealized loss, net of tax expense $ 513 $ 0 $ 805 $ 0
Reclassification of net realized loss, net of tax benefit 87 134 481 242
Pension and other postretirement benefits activity, net of tax expense (benefit) 334 506 90 218
APS        
Net unrealized loss, net of tax expense 0 0 292 0
Reclassification of net realized loss, net of tax benefit 87 134 481 242
Pension and other postretirement benefits activity, net of tax expense (benefit) $ 361 $ 544 $ 124 $ 297
v3.20.2
CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($)
$ in Thousands
Jun. 30, 2020
Dec. 31, 2019
CURRENT ASSETS    
Cash and cash equivalents $ 6,763 $ 10,283
Customer and other receivables 279,480 266,426
Accrued unbilled revenues 191,578 128,165
Allowance for doubtful accounts (11,579) (8,171)
Materials and supplies (at average cost) 318,368 331,091
Fossil fuel (at average cost) 17,257 14,829
Income tax receivable 17,122 21,727
Assets from risk management activities (Note 7) 710 515
Deferred fuel and purchased power regulatory asset (Note 4) 101,425 70,137
Other regulatory assets (Note 4) 150,169 133,070
Other current assets 75,796 61,958
Total current assets 1,147,089 1,030,030
INVESTMENTS AND OTHER ASSETS    
Nuclear decommissioning trust (Notes 11 and 12) 1,024,033 1,010,775
Other special use funds (Notes 11 and 12) 253,332 245,095
Other assets 92,295 96,953
Total investments and other assets 1,369,660 1,352,823
PROPERTY, PLANT AND EQUIPMENT    
Plant in service and held for future use 20,343,151 19,836,292
Accumulated depreciation and amortization (6,905,049) (6,637,857)
Net 13,438,102 13,198,435
Construction work in progress 823,691 808,133
Intangible assets, net of accumulated amortization 275,028 290,564
Nuclear fuel, net of accumulated amortization 152,219 123,500
Total property, plant and equipment 14,789,011 14,522,538
DEFERRED DEBITS    
Regulatory assets (Note 4) 1,315,846 1,304,073
Operating lease right-of-use assets (Note 16) 555,783 145,813
Assets for other postretirement benefits (Note 5) 99,801 90,570
Other 30,198 33,400
Total deferred debits 2,001,628 1,573,856
TOTAL ASSETS 19,307,388 18,479,247
CURRENT LIABILITIES    
Current maturities of long-term debt (Note 3) 0 800,000
Accounts payable 316,230 346,448
Accrued taxes 151,487 144,899
Accrued interest 53,503 53,534
Common dividends payable 88,066 87,982
Short-term borrowings (Note 3) 291,900 114,675
Customer deposits 49,132 64,908
Liabilities from risk management activities (Note 7) 44,805 38,946
Liabilities for asset retirements 10,735 11,025
Operating lease liabilities (Note 16) 83,851 12,713
Regulatory liabilities (Note 4) 279,479 234,912
Other current liabilities 127,175 168,323
Total current liabilities 1,496,363 2,078,365
Long-term debt less current maturities (Note 3) 5,922,161 4,832,558
DEFERRED CREDITS AND OTHER    
Deferred income taxes 2,070,453 1,992,339
Regulatory liabilities (Note 4) 2,089,987 2,267,835
Liabilities for asset retirements 657,217 646,193
Liabilities for pension benefits (Note 5) 284,585 280,185
Liabilities from risk management activities (Note 7) 26,181 33,186
Customer advances 213,572 215,330
Unrecorded Unconditional Purchase Obligation 167,896 165,695
Deferred investment tax credit 193,081 196,468
Unrecognized tax benefits 6,613 6,189
Operating lease liabilities (Note 16) 409,621 51,872
Other 159,181 159,844
Total deferred credits and other 6,278,387 6,015,136
COMMITMENTS AND CONTINGENCIES (SEE NOTE 8)
EQUITY    
Common stock, no par value; authorized 150,000,000 shares, 112,591,124 and 112,540,126 issued at respective dates 2,665,518 2,659,561
Treasury stock at cost; 35,983 and 103,546 shares at respective dates (3,190) (9,427)
Total common stock 2,662,328 2,650,134
Retained earnings 2,885,109 2,837,610
Accumulated other comprehensive loss (57,875) (57,096)
Total shareholders’ equity 5,489,562 5,430,648
Noncontrolling interests (Note 6) 120,915 122,540
Total equity 5,610,477 5,553,188
TOTAL LIABILITIES AND EQUITY 19,307,388 18,479,247
APS    
CURRENT ASSETS    
Cash and cash equivalents 6,224 10,169
Customer and other receivables 275,476 255,479
Accrued unbilled revenues 191,578 128,165
Allowance for doubtful accounts (11,579) (8,171)
Materials and supplies (at average cost) 318,368 331,091
Fossil fuel (at average cost) 17,257 14,829
Income tax receivable 0 7,313
Assets from risk management activities (Note 7) 710 515
Deferred fuel and purchased power regulatory asset (Note 4) 101,425 70,137
Other regulatory assets (Note 4) 150,169 133,070
Other current assets 47,588 38,895
Total current assets 1,097,216 981,492
INVESTMENTS AND OTHER ASSETS    
Nuclear decommissioning trust (Notes 11 and 12) 1,024,033 1,010,775
Other special use funds (Notes 11 and 12) 253,332 245,095
Other assets 43,973 43,781
Total investments and other assets 1,321,338 1,299,651
PROPERTY, PLANT AND EQUIPMENT    
Plant in service and held for future use 20,339,690 19,832,805
Accumulated depreciation and amortization (6,901,805) (6,634,597)
Net 13,437,885 13,198,208
Construction work in progress 823,691 808,133
Intangible assets, net of accumulated amortization 274,873 290,409
Nuclear fuel, net of accumulated amortization 152,219 123,500
Total property, plant and equipment 14,788,639 14,522,156
DEFERRED DEBITS    
Regulatory assets (Note 4) 1,315,846 1,304,073
Operating lease right-of-use assets (Note 16) 554,106 144,024
Assets for other postretirement benefits (Note 5) 95,937 86,736
Other 29,562 32,591
Total deferred debits 1,995,451 1,567,424
TOTAL ASSETS 19,202,644 18,370,723
CURRENT LIABILITIES    
Current maturities of long-term debt (Note 3) 0 350,000
Accounts payable 307,931 338,006
Accrued taxes 150,879 136,328
Accrued interest 52,925 52,619
Common dividends payable 88,000 88,000
Short-term borrowings (Note 3) 219,900 0
Customer deposits 49,132 64,908
Liabilities from risk management activities (Note 7) 44,805 38,946
Liabilities for asset retirements 10,735 11,025
Operating lease liabilities (Note 16) 83,744 12,549
Regulatory liabilities (Note 4) 279,479 234,912
Other current liabilities 128,147 164,736
Total current liabilities 1,415,677 1,492,029
Long-term debt less current maturities (Note 3) 5,425,551 4,833,133
DEFERRED CREDITS AND OTHER    
Deferred income taxes 2,106,268 2,033,096
Regulatory liabilities (Note 4) 2,089,987 2,267,835
Liabilities for asset retirements 657,217 646,193
Liabilities for pension benefits (Note 5) 267,386 262,243
Liabilities from risk management activities (Note 7) 26,181 33,186
Customer advances 213,572 215,330
Unrecorded Unconditional Purchase Obligation 167,896 165,695
Deferred investment tax credit 193,081 196,468
Unrecognized tax benefits 39,039 40,188
Operating lease liabilities (Note 16) 407,888 50,092
Other 138,764 136,432
Total deferred credits and other 6,307,279 6,046,758
COMMITMENTS AND CONTINGENCIES (SEE NOTE 8)
EQUITY    
Common stock 178,162 178,162
Additional paid-in capital 2,721,696 2,721,696
Retained earnings 3,068,389 3,011,927
Accumulated other comprehensive loss (35,025) (35,522)
Total shareholders’ equity 5,933,222 5,876,263
Noncontrolling interests (Note 6) 120,915 122,540
Total equity 6,054,137 5,998,803
Total capitalization 11,479,688 10,831,936
TOTAL LIABILITIES AND EQUITY 19,202,644 18,370,723
Variable Interest Entity    
PROPERTY, PLANT AND EQUIPMENT    
Total property, plant and equipment 99,971 101,906
Variable Interest Entity | APS    
PROPERTY, PLANT AND EQUIPMENT    
Total property, plant and equipment 99,971 101,906
EQUITY    
Noncontrolling interests (Note 6) $ 120,915 $ 122,540
v3.20.2
CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical) - $ / shares
Jun. 30, 2020
Dec. 31, 2019
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest [Abstract]    
Common stock, par value (in dollars per share)
Common stock, authorized shares (in shares) 150,000,000 150,000,000
Common stock, issued shares (in shares) 112,591,124 112,540,126
Treasury stock at cost, shares (in shares) 35,983 103,546
v3.20.2
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($)
$ in Thousands
 6 Months Ended
Jun. 30, 2020
Jun. 30, 2019
CASH FLOWS FROM OPERATING ACTIVITIES    
NET INCOME $ 233,325 $ 171,810
Adjustments to reconcile net income to net cash provided by operating activities:    
Depreciation and amortization including nuclear fuel 343,173 332,185
Deferred fuel and purchased power (26,473) (16,702)
Deferred fuel and purchased power amortization (4,815) 23,307
Allowance for equity funds used during construction (16,508) (18,760)
Deferred income taxes 22,229 4,326
Deferred investment tax credit (3,386) (2,656)
Stock compensation 9,130 13,725
Customer and other receivables 7,767 3,543
Changes in current assets and liabilities:    
Accrued unbilled revenues (63,413) (56,487)
Materials, supplies and fossil fuel 10,295 (21,287)
Income tax receivable 4,605 0
Other current assets (24,896) (16,121)
Accounts payable 17,772 65,874
Accrued taxes 6,588 4,102
Other current liabilities (45,334) (61,270)
Change in other long-term assets (4,885) (82,850)
Change in other long-term liabilities (96,142) 3,195
Net cash flow provided by operating activities 369,032 345,934
CASH FLOWS FROM INVESTING ACTIVITIES    
Capital expenditures (676,973) (541,401)
Contributions in aid of construction 31,295 18,909
Allowance for borrowed funds used during construction (8,825) (11,159)
Proceeds from nuclear decommissioning trust sales and other special use funds 391,859 309,354
Investment in nuclear decommissioning trust and other special use funds (393,000) (310,494)
Other 3,123 7,153
Net cash flow used for investing activities (652,521) (527,638)
CASH FLOWS FROM FINANCING ACTIVITIES    
Issuance of long-term debt 1,088,886 497,324
Short-term borrowing and payments — net 184,225 363,973
Short-term debt borrowings 751,690 49,000
Short-term debt repayments (758,690) (57,000)
Repayment of long-term debt (800,000) (500,000)
Dividends paid on common stock (172,566) (161,979)
Common stock equity issuance - net of purchases (2,204) (2,360)
Distributions to noncontrolling interests (11,372) (11,372)
Net cash flow provided by financing activities 279,969 177,586
NET DECREASE IN CASH AND CASH EQUIVALENTS (3,520) (4,118)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 10,283 5,766
CASH AND CASH EQUIVALENTS AT END OF PERIOD 6,763 1,648
APS    
CASH FLOWS FROM OPERATING ACTIVITIES    
NET INCOME 242,210 188,199
Adjustments to reconcile net income to net cash provided by operating activities:    
Depreciation and amortization including nuclear fuel 343,130 332,143
Deferred fuel and purchased power (26,473) (16,702)
Deferred fuel and purchased power amortization (4,815) 23,307
Allowance for equity funds used during construction (16,508) (18,760)
Deferred income taxes 15,233 (10,625)
Deferred investment tax credit (3,386) (2,656)
Customer and other receivables 824 3,645
Changes in current assets and liabilities:    
Accrued unbilled revenues (63,413) (56,487)
Materials, supplies and fossil fuel 10,295 (21,287)
Income tax receivable 7,313 0
Other current assets (19,752) (14,613)
Accounts payable 17,915 68,399
Accrued taxes 14,551 (435)
Other current liabilities (40,381) (57,709)
Change in other long-term assets (7,356) (84,946)
Change in other long-term liabilities (91,983) 3,253
Net cash flow provided by operating activities 377,404 334,726
CASH FLOWS FROM INVESTING ACTIVITIES    
Capital expenditures (676,973) (541,401)
Contributions in aid of construction 31,295 18,909
Allowance for borrowed funds used during construction (8,825) (11,159)
Proceeds from nuclear decommissioning trust sales and other special use funds 391,859 309,354
Investment in nuclear decommissioning trust and other special use funds (393,000) (310,494)
Other (169) (1,612)
Net cash flow used for investing activities (655,813) (536,403)
CASH FLOWS FROM FINANCING ACTIVITIES    
Issuance of long-term debt 591,936 497,324
Short-term borrowing and payments — net 219,900 376,873
Short-term debt borrowings 540,000 0
Short-term debt repayments (540,000) 0
Repayment of long-term debt (350,000) (500,000)
Dividends paid on common stock (176,000) (165,500)
Distributions to noncontrolling interests (11,372) (11,372)
Net cash flow provided by financing activities 274,464 197,325
NET DECREASE IN CASH AND CASH EQUIVALENTS (3,945) (4,352)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 10,169 5,707
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 6,224 $ 1,355
v3.20.2
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Unaudited) - USD ($)
$ in Thousands
Total
Common Stock
Treasury 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, 2018   (112,159,896) (58,135)         (71,264,947)        
Balance at beginning of period at Dec. 31, 2018 $ 5,348,705 $ 2,634,265 $ (4,825) $ 2,641,183 $ (47,708) $ 125,790 $ 5,786,797 $ 178,162 $ 2,721,696 $ 2,788,256 $ (27,107) $ 125,790
Increase (Decrease) in Shareholders' Equity                        
Net Income 171,810     162,063   9,747 188,199     178,452   9,747
Other comprehensive income (loss) 72       72   (169)       (169)  
Dividends on common stock ($1.48 per share) (165,626)     (165,626)                
Issuance of common stock (in shares)   201,699                    
Issuance of common stock 13,969 $ 13,969                    
Purchase of treasury stock (in shares) [1]     (75,791)                  
Purchase of treasury stock [1] (6,882)   $ (6,882)                  
Reissuance of treasury stock for stock-based compensation and other (in shares)     75,707                  
Reissuance of treasury stock for stock-based compensation and other 6,567   $ 6,567 0                
Capital activities by noncontrolling interests (11,372)     0   (11,372) (11,372)         (11,372)
Ending balance (in shares) at Jun. 30, 2019   (112,361,595) (58,219)         (71,264,947)        
Balance at end of period at Jun. 30, 2019 5,357,243 $ 2,648,234 $ (5,140) 2,637,620 (47,636) 124,165 5,797,857 $ 178,162 2,721,696 2,801,110 (27,276) 124,165
Beginning balance (in shares) at Mar. 31, 2019   (112,340,322) (63,271)         (71,264,947)        
Balance at beginning of period at Mar. 31, 2019 5,381,725 $ 2,644,063 $ (5,586) 2,659,086 (46,501) 130,663 5,821,026 $ 178,162 2,721,696 2,816,532 (26,027) 130,663
Increase (Decrease) in Shareholders' Equity                        
Net Income 149,019     144,145   4,874 155,050     150,176   4,874
Other comprehensive income (loss) (1,135)       (1,135)   (1,249)       (1,249)  
Dividends on common stock ($1.48 per share) (165,611)     (165,611)     (165,598)     (165,598)    
Issuance of common stock (in shares)   21,273                    
Issuance of common stock 4,171 $ 4,171                    
Reissuance of treasury stock for stock-based compensation and other (in shares)     5,052                  
Reissuance of treasury stock for stock-based compensation and other 446   $ 446 0                
Capital activities by noncontrolling interests (11,372)     0   (11,372) (11,372)         (11,372)
Ending balance (in shares) at Jun. 30, 2019   (112,361,595) (58,219)         (71,264,947)        
Balance at end of period at Jun. 30, 2019 $ 5,357,243 $ 2,648,234 $ (5,140) 2,637,620 (47,636) 124,165 5,797,857 $ 178,162 2,721,696 2,801,110 (27,276) 124,165
Beginning balance (in shares) at Dec. 31, 2019 (112,540,126) (112,540,126) (103,546)         (71,264,947)        
Balance at beginning of period at Dec. 31, 2019 $ 5,553,188 $ 2,659,561 $ (9,427) 2,837,610 (57,096) 122,540 5,998,803 $ 178,162 2,721,696 3,011,927 (35,522) 122,540
Increase (Decrease) in Shareholders' Equity                        
Net Income 233,325     223,578   9,747 242,210     232,463   9,747
Other comprehensive income (loss) (779)       (779)   497       497  
Dividends on common stock ($1.48 per share) (176,079)     (176,079)     (176,000)     (176,000)    
Issuance of common stock (in shares)   50,998                    
Issuance of common stock 5,957 $ 5,957                    
Purchase of treasury stock (in shares)     (33,070)                  
Purchase of treasury stock (3,010)   $ (3,010)                  
Reissuance of treasury stock for stock-based compensation and other (in shares)     100,633                  
Reissuance of treasury stock for stock-based compensation and other 9,247   $ 9,247 0                
Other             (1)     (1)   0
Capital activities by noncontrolling interests $ (11,372)     0   (11,372)           (11,372)
Ending balance (in shares) at Jun. 30, 2020 (112,591,124) (112,591,124) (35,983)         (71,264,947)        
Balance at end of period at Jun. 30, 2020 $ 5,610,477 $ 2,665,518 $ (3,190) 2,885,109 (57,875) 120,915 6,054,137 $ 178,162 2,721,696 3,068,389 (35,025) 120,915
Beginning balance (in shares) at Mar. 31, 2020   (112,563,610) (72,302)         (71,264,947)        
Balance at beginning of period at Mar. 31, 2020 5,596,832 $ 2,664,387 $ (7,000) 2,867,610 (55,579) 127,414 6,040,344 $ 178,162 2,721,696 3,047,269 (34,197) 127,414
Increase (Decrease) in Shareholders' Equity                        
Net Income 198,459     193,585   4,874 201,992     197,118   4,874
Other comprehensive income (loss) (2,296)       (2,296)   (828)       (828)  
Dividends on common stock (176,086)     (176,086)                
Dividends on common stock ($1.48 per share)             (176,000)     (176,000)    
Issuance of common stock (in shares)   27,514                    
Issuance of common stock 1,131 $ 1,131                    
Purchase of treasury stock (in shares) [1]     (12,346)                  
Purchase of treasury stock [1] (924)   $ (924)                  
Reissuance of treasury stock for stock-based compensation and other (in shares)     48,665                  
Reissuance of treasury stock for stock-based compensation and other 4,734   $ 4,734 0                
Other (1)         (1) 1     2   (1)
Capital activities by noncontrolling interests $ (11,372)     0   (11,372) (11,372)         (11,372)
Ending balance (in shares) at Jun. 30, 2020 (112,591,124) (112,591,124) (35,983)         (71,264,947)        
Balance at end of period at Jun. 30, 2020 $ 5,610,477 $ 2,665,518 $ (3,190) $ 2,885,109 $ (57,875) $ 120,915 $ 6,054,137 $ 178,162 $ 2,721,696 $ 3,068,389 $ (35,025) $ 120,915
[1]
Primarily represents shares of common stock withheld from certain stock awards for tax purposes.
v3.20.2
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Unaudited) Parenthetical - $ / shares
 3 Months Ended 6 Months Ended
Jun. 30, 2020
Jun. 30, 2019
Jun. 30, 2020
Jun. 30, 2019
Statement of Stockholders' Equity [Abstract]        
DIVIDENDS DECLARED PER SHARE (in dollars per share) $ 1.57 $ 1.48 $ 1.57 $ 1.48
v3.20.2
Consolidation and Nature of Operations
 6 Months Ended
Jun. 30, 2020
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 2019 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.  The order provides 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 has 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 has left all other aspects of the AFUDC formula composite rate calculation unchanged. This change impacts the AFUDC composite rate in 2020, but does not impact prior years.  Furthermore, the change in the composite rate calculation does not impact our accounting treatment for these costs. The change will not have a material impact on our financial statements. See Note 1 in our 2019 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,
 
2020
 
2019
Cash paid during the period for:
 
 
 
Income taxes, net of refunds
$
(3,028
)
 
$
10,788

Interest, net of amounts capitalized
107,417

 
114,717

Significant non-cash investing and financing activities:
 
 
 
Accrued capital expenditures
$
87,815

 
$
108,056

Right-of-use operating lease assets obtained in exchange for operating lease liabilities
434,997

 
4,562

Dividends accrued but not yet paid
88,066

 
82,824



The following table summarizes supplemental APS cash flow information (dollars in thousands):
 
Six Months Ended
June 30,
 
2020
 
2019
Cash paid during the period for:
 
 
 
Income taxes, net of refunds
$
—

 
$
35,573

Interest, net of amounts capitalized
100,991

 
107,169

Significant non-cash investing and financing activities:
 
 
 
Accrued capital expenditures
$
87,815

 
$
108,056

Right-of-use operating lease assets obtained in exchange for operating lease liabilities
434,997

 
4,562

Dividends accrued but not yet paid
88,000

 
82,800
v3.20.2
Revenue
 6 Months Ended
Jun. 30, 2020
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,
 
 
2020
2019
 
2020
2019
Retail Electric Revenue
 
 
 
 
 
 
Residential
 
$
515,128

$
432,568

 
$
840,201

$
784,134

Non-Residential
 
381,121

395,929

 
684,472

728,597

Wholesale energy sales
 
15,927

21,991

 
30,595

58,443

Transmission services for others
 
14,766

15,157

 
30,693

30,406

Other sources
 
2,648

3,856

 
5,559

8,451

Total operating revenues
 
$
929,590

$
869,501

 
$
1,591,520

$
1,610,031



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 15 days of when the services are billed.

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, 2020 were $915 million and $1,563 million, respectively and for the three and six months ended June 30, 2019 were $858 million and $1,578 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, 2020 our revenues that do not qualify as revenue from contracts with customers were $15 million and $29 million, respectively, and for the three and six months ended June 30, 2019 were $12 million and $32 million, respectively. This relates primarily 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, 2020 or December 31, 2019.

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 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.

During March 2020, due to the COVID-19 pandemic, and to assist customers who may be experiencing economic difficulties, we suspended all service shut-offs due to nonpayment. We are experiencing an increase in the number of customers needing to utilize longer-term payment plans to avoid service disruption. These changes, among others, including the Summer Disconnection Moratorium (defined in Note 4), impacted our write-off factor during the period. We will continue to monitor the impacts of COVID-19 on our write-off factor. See Note 4 for additional details.

The following table provides a rollforward of Pinnacle West’s allowance for doubtful accounts (dollars in thousands):

 
 
June 30, 2020
 
December 31, 2019
Allowance for doubtful accounts, balance at beginning of period
 
$
8,171

 
$
4,069

Bad debt expense
 
9,197

 
11,819

Actual write-offs
 
(5,789
)
 
(7,717
)
Allowance for doubtful accounts, balance at end of period
 
$
11,579

 
$
8,171
v3.20.2
Long-Term Debt and Liquidity Matters
 6 Months Ended
Jun. 30, 2020
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 May 5, 2020, Pinnacle West refinanced its 364-day $50 million term loan agreement that would have matured on May 7, 2020 with a new 364-day $31 million term loan agreement that matures May 4, 2021. Borrowings under the agreement bear interest at Eurodollar Rate plus 1.40% per annum. At June 30, 2020, Pinnacle West had $31 million in outstanding borrowings under the current agreement.

On June 17, 2020, Pinnacle West issued $500 million of 1.3% unsecured senior notes that mature June 15, 2025. The net proceeds from the sale were used to repay early its $150 million term loan facility set to mature on December 21, 2020, to repay short-term indebtedness consisting of commercial paper and replenish cash incurred or used to fund capital expenditures, to redeem prior to maturity our $300 million, 2.25% senior notes due November 30, 2020, and for general corporate purposes.

At June 30, 2020, Pinnacle West had a $200 million revolving credit facility that matures in July 2023. 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. The facility is available to support Pinnacle West's $200 million commercial paper program, for bank borrowings or for issuances of letters of credits. At June 30, 2020, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding and $41 million in commercial paper borrowings.

APS

On January 15, 2020, APS repaid at maturity the remaining $150 million of the $250 million aggregate principal amount of its 2.2% Senior Notes.

On May 22, 2020, APS issued $600 million of 3.35% unsecured senior notes that mature May 15, 2050. The net proceeds from the sale were used to repay early its $200 million term loan facility and to repay short-term indebtedness, consisting of commercial paper and revolver borrowings, and to replenish cash used to fund capital expenditures.

At June 30, 2020, APS had two revolving credit facilities totaling $1 billion, including a $500 million credit facility that matures in June 2022 and a $500 million facility that matures in July 2023.  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. These facilities are available to support APS’s $500 million commercial paper program, for bank borrowings or for issuances of letters of credit.  At June 30, 2020, APS had no outstanding borrowings under its revolving credit facilities, no letters of credit outstanding, and $220 million in commercial paper borrowings.

On November 27, 2018, 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 $5.9 billion. On March 27, 2020, APS filed an application with the ACC to increase the long-term debt limit from $5.9 billion to $7.5 billion and to continue its authorization of short-term debt granted in the 2018 financing order. This application is pending ACC review and approval.
 
See "Financial Assurances" in Note 8 for a discussion of other outstanding letters of credit.
 
Debt Fair Value
 
Our long-term debt fair value estimates are classified within Level 2 of the fair value hierarchy. The following table presents the estimated fair value of our long-term debt, including current maturities (dollars in thousands):

 
As of June 30, 2020
 
As of December 31, 2019
 
Carrying
Amount
 
Fair Value
 
Carrying
Amount
 
Fair Value
Pinnacle West
$
496,610

 
$
507,850

 
$
449,425

 
$
450,822

APS
5,425,551

 
6,386,439

 
5,183,133

 
5,743,570

Total
$
5,922,161

 
$
6,894,289

 
$
5,632,558

 
$
6,194,392
v3.20.2
Regulatory Matters
 6 Months Ended
Jun. 30, 2020
Regulated Operations [Abstract]  
Regulatory Matters Regulatory Matters
 
COVID-19 Pandemic

Due to the COVID-19 pandemic, APS voluntarily suspended disconnections of customers for nonpayment beginning March 13, 2020.  In addition, APS waived all late payment fees during this current suspension period.  APS currently estimates that the Summer Disconnection Moratorium (see below for discussion of the Summer Disconnection Moratorium), the suspension of disconnections during the COVID-19 pandemic and the increased bad debt expense associated with both events will result in a negative impact to its 2020 operating results of approximately $20 million to $30 million pre-tax above the impact of disconnections on its operating results for years that did not have the Summer Disconnection Moratorium or COVID-19 pandemic. APS is anticipating an increase in bad debt expense associated with the COVID-19 pandemic, but it still believes that costs associated with the Summer Disconnection Moratorium and the COVID-19 disconnection suspensions and related bad debt expense with both events will fall within this estimated $20 million to $30 million range. These estimated impact amounts depend on certain assumptions, including, but not limited to, customer behaviors, population and employment growth, and the impacts of COVID-19 on the economy. Additionally, due to COVID-19, APS delayed the reset of the Environmental Improvement Surcharge ("EIS") adjustor and suspended the discontinuation of TEAM Phase II to the first billing cycle in May 2020 rather than April 2020 (see below for discussion of EIS and TEAM Phase II).

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 Demand Side Management ("DSM") Adjustor Charge, but not allocated for current DSM programs, directly to customers through a bill credit in June 2020. As of June 30, 2020, APS had refunded approximately $40 million to customers. The additional $4 million over the approved amount was the result of the kWh credit being based on historic consumption which was different than actual consumption in the refund period. This difference was recorded to the DSM balancing account and will be addressed in subsequent DSM filings (see below for discussion of the DSM Adjustor Charge).

APS has committed in total approximately $8 million to assist customers and local non-profits and community organizations to help with the impact of the COVID-19 pandemic. On May 5, 2020, APS also voluntarily committed to the ACC to contribute $5.3 million of non-ratepayer funds to provide assistance to residential and non-residential customers that have been impacted by the COVID-19 pandemic (“Customer COVID Assistance”). As part of this Customer COVID Assistance, APS has established a $2.3 million program to assist extra small and small non-residential customers that have a delinquency of two or more months with a one-time credit of $1,000 on each such customer's bill. The other $3 million of the Customer COVID Assistance has not yet been assigned to specific programs. Beyond the Customer COVID Assistance, APS has also provided $1.5 million to assist customers with a one-time credit of $100 on their bill, with a priority given to customers on limited-income service plans, and $1.25 million to assist local non-profits and community organizations working to mitigate the impacts of the COVID-19 pandemic.
 
2019 Retail Rate Case Filing with the Arizona Corporation Commission

In accordance with the requirements of the 2018 rate review order described below, APS filed an application with the ACC on October 31, 2019 seeking an annual increase in retail base rates of $69 million. This amount includes recovery of the deferral and rate base effects of the Four Corners selective catalytic reduction ("SCR") project that is currently the subject of a separate proceeding (see “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 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 are:

•
a test year comprised of twelve 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;
•
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).

APS requested that the increase become effective December 1, 2020.  The hearing for this rate case was delayed, at the request of ACC Staff and the Residential Utility Consumer Office ("RUCO"), and is currently scheduled to begin December 14, 2020. APS cannot predict the outcome of its request.

2016 Retail Rate Case Filing with the Arizona Corporation Commission
 
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. The average annual customer bill impact under the 2017 Settlement Agreement was calculated as an increase of 3.28% (the average annual bill impact for a typical APS residential customer was calculated as an increase of 4.54%).

Other key provisions of the 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 Power Plant ("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 with the purpose of expanding access to rooftop solar for low and moderate income Arizonans, recoverable through the Arizona Renewable Energy Standard and Tariff ("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 - 7 p.m. to 3 p.m. - 8 p.m. Monday through Friday, excluding holidays;
▪
non-grandfathered distributed generation ("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.

Through a separate agreement, APS, industry representatives, and solar advocates committed to stand by the 2017 Settlement Agreement and refrain from seeking to undermine it through ballot initiatives, legislation or advocacy at the ACC.

On August 15, 2017, the ACC approved (by a vote of 4-1), the 2017 Settlement Agreement without material modifications.  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"), which is subject to requests for rehearing and potential appeal. The new rates went into effect on August 19, 2017.

On January 3, 2018, an APS customer filed a petition with the ACC that was determined by the ACC Staff to be a complaint filed pursuant to Arizona Revised Statute §40-246 (the “Complaint”). The Complaint was later amended alleging that the rates and charges in the 2017 Rate Case Decision are not just and reasonable. The ACC held a hearing on this matter, and the Administrative Law Judge issued a Recommended Opinion and Order recommending that the Complaint be dismissed. On July 3, 2019, the Administrative Law Judge issued an amendment to the Recommended Opinion and Order that incorporated the requirements of the rate review of the 2017 Rate Case Decision (see below discussion regarding the rate review). On July 10, 2019, the ACC adopted the Administrative Law Judge's amended Recommended Opinion and Order along with several ACC Commissioner amendments and an amendment incorporating the results of the rate review and resolved the Complaint.

ACC Review of APS 2017 Rate Case Decision

On December 24, 2018, certain ACC Commissioners filed a letter stating that because the ACC had received a substantial number of complaints that the rate increase authorized by the 2017 Rate Case Decision was much more than anticipated, they believe there is a possibility that APS is earning more than was authorized by the 2017 Rate Case Decision.  Accordingly, the ACC Commissioners requested the ACC Staff to perform a rate review of APS using calendar year 2018 as a test year. The ACC Commissioners also asked the ACC Staff to evaluate APS’s efforts to educate its customers regarding the new rates approved in the 2017 Rate Case Decision.

On June 4, 2019, the ACC Staff filed a proposed order regarding the rate review of the 2017 Rate Case Decision. On June 11, 2019, the ACC Commissioners approved the proposed ACC Staff order with amendments. The key provisions of the amended order include the following:

•
APS must file a rate case no later than October 31, 2019, using a June 30, 2019 test-year;
•
until the conclusion of the rate case being filed no later than October 31, 2019, APS must provide information on customer bills that shows how much a customer would pay on their most economical rate given their actual usage during each month;
•
APS customers can switch rate plans during an open enrollment period of six months;
•
APS must identify customers whose bills have increased by more than 9% and that are not on the most economical rate and provide such customers with targeted education materials and an opportunity to switch rate plans;
•
APS must provide grandfathered net metering customers on legacy demand rates an opportunity to switch to another legacy rate to enable such customers to fully benefit from legacy net metering rates;
•
APS must fund and implement a supplemental customer education and outreach program to be developed with and administered by ACC Staff and a third-party consultant; and
•
APS must fund and organize, along with the third-party consultant, a stakeholder group to suggest better ways to communicate the impact of changes to adjustor cost recovery mechanisms (see below for discussion on cost recovery mechanisms), including more effective ways to educate customers on rate plans and to reduce energy usage.

APS filed its rate case on October 31, 2019 (see "2019 Retail Rate Case Filing with the Arizona Corporation Commission" above for more information). APS does not believe that the implementation of the other key provisions of the amended order regarding the rate review will have a material impact on its financial position, results of operations or cash flows.

On May 19, 2020, the ACC Staff filed a third-party consultant’s report which evaluated the effectiveness of APS’s customer outreach and education program related to the 2017 Rate Case Decision. On May 29, 2020, the Chairman of the ACC filed a letter with the ACC in response to this report and is alleging that APS is out of compliance with the 2017 Rate Case Decision and is over-earning. The Chairman proposed that the current rates should be classified as interim rates and customers held harmless if APS’s activities have caused the rates set in the 2017 Rate Case Decision to not be just and reasonable. Also, on May 29, 2020, a second commissioner filed a letter with the ACC agreeing with the Chairman’s assertions and further asserting that the 2017 Rate Case Decision should be re-opened. On June 18, 2020 at an ACC Open Meeting, the matters raised in these letters were discussed. The ACC did not vote to move forward with any adjustments to APS’s current rates. APS is monitoring this matter, but believes that the proposals are not legal and further that APS has not over-earned. APS cannot predict the outcome of this matter at this time or whether or how further action may be taken by the ACC.

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 June 29, 2018, APS filed its 2019 RES Implementation Plan and proposed a budget of approximately $89.9 million.  APS’s budget request supports existing approved projects and commitments and requests a permanent waiver of the residential distributed energy requirement for 2019 contained in the RES rules. On October 29, 2019, the ACC approved the 2019 RES Implementation Plan including a waiver of the residential distributed energy requirements for the 2019 implementation year.
    
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 residential distributed energy requirement for 2020 contained in the RES rules. The ACC has not yet ruled on the 2020 RES Implementation 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 residential distributed energy requirement for 2021 contained in the RES rules.  The ACC has not yet ruled on the 2021 RES Implementation Plan.

On July 15, 2020, ACC Staff issued final draft rules which, if approved, would require APS to meet certain clean energy standards, obtain approval for its action plan included in its IRP, and seek cost recovery in a rate process. APS cannot predict the outcome of this matter. See "Energy Modernization Plan" below for more information.

Demand Side Management Adjustor Charge.  The ACC Electric Energy Efficiency Standards require APS to submit a Demand Side Management Implementation Plan ("DSM Plan") annually for review by and approval of 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 proposes modifications to the demand side management 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 seeks a requested budget of $52.6 million and requests 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. The ACC has not yet ruled on the APS 2018 amended DSM Plan.

On December 31, 2018, APS filed its 2019 DSM Plan, which requests a budget of $34.1 million and continues APS's focus on DSM strategies such as peak demand reduction, load shifting, storage and electrification strategies. The ACC has not yet ruled on the APS 2019 DSM Plan.

On December 31, 2019, APS filed its 2020 DSM Plan, which requests a budget of $51.9 million and continues APS's focus on DSM strategies such as peak demand reduction, load shifting, storage and electrification strategies. The 2020 DSM Plan addresses all components of the pending 2018 and 2019 DSM plans, which enables 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 requests the same budget amount of $51.9 million. The ACC has not yet ruled on the APS 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. As of June 30, 2020, APS had refunded approximately $40 million to customers. The additional $4 million over the approved amount was the result of the kWh credit being based on historic consumption which was different than actual consumption in the refund period. This difference was recorded to the DSM balancing account and will be addressed in subsequent DSM filings. See "COVID-19 Pandemic" above for more information.

 Power Supply Adjustor Mechanism and Balance.  The PSA provides for the adjustment of retail rates to reflect variations primarily in retail fuel and purchased power costs.  The following table shows the changes in the deferred fuel and purchased power regulatory asset for 2020 and 2019 (dollars in thousands):
 
 
Six Months Ended
June 30,
 
2020
 
2019
Beginning balance
$
70,137

 
$
37,164

Deferred fuel and purchased power costs — current period
26,473

 
16,702

Amounts charged to customers
4,815

 
(23,307
)
Ending balance
$
101,425

 
$
30,559


 
The PSA rate for the PSA year beginning February 1, 2018 is $0.004555 per kWh, consisting of a forward component of $0.002009 per kWh and a historical component of $0.002546 per kWh. This represented a $0.004 per kWh increase over the August 19, 2017 PSA, the maximum permitted under the Plan of Administration for the PSA. This left $16.4 million of 2017 fuel and purchased power costs above this annual cap. These costs rolled over into the following year and were reflected in the 2019 reset of the PSA.

The PSA rate for the PSA year beginning February 1, 2019 was $0.001658 per kWh, consisting of a Forward Component of $0.000536 per kWh and a Historical Component of $0.001122 per kWh. This represented a $0.002897 per kWh decrease compared to 2018. These rates went into effect as filed on February 1, 2019.

On November 27, 2019, APS filed its PSA rate for the PSA year beginning February 1, 2020. That rate was $(0.000456) per kWh and 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 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. This application is pending with the ACC. APS cannot predict the outcome of this matter.

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 1st for qualified environmental improvements made during the prior calendar 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 - 14 million per year).  APS’s February 1, 2020 application requested an increase in the charge to $8.75 million, or $2.0 million over the charge in effect for the 2019-2020 rate effective year. On March 19, 2020, due to the COVID-19 pandemic, APS delayed the reset of the EIS adjustor to the first billing cycle in May 2020 rather than April 2020.
 
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.  The resolution of proposed adjustments can result in significant volatility in the revenues to be collected.  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 at 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.

On March 7, 2018, APS made a filing to make modifications to its annual transmission formula to provide transmission customers the benefit of the reduced federal corporate income tax rate resulting from the Tax Cuts and Jobs Act ("Tax Act") beginning in its 2018 annual transmission formula rate update filing. These modifications were approved by FERC on May 22, 2018 and reduced APS’s transmission rates compared to the rate that would have gone into effect absent these changes. On March 17, 2020, APS made a filing to make further modifications to its annual transmission formula to provide additional transparency for excess and deficient Accumulated Deferred Income Taxes resulting from the Tax Act, as well as for future local, state, and federal statutory tax rate changes. This filing is pending with FERC.

Effective June 1, 2018, APS's annual wholesale transmission rates for all users of its transmission system decreased by approximately $22.7 million for the twelve-month period beginning June 1, 2018 in accordance with the FERC-approved formula.  Of this amount, retail customer rates decreased by approximately $26.9 million. An adjustment to APS’s retail rates to recover FERC approved transmission charges went into effect automatically on June 1, 2018.

Effective June 1, 2019, APS's annual wholesale transmission rates for all users of its transmission system increased by approximately $25.8 million for the twelve-month period beginning June 1, 2019 in accordance with the FERC-approved formula. Of this amount, retail customer rates increased by approximately $4.7 million. An adjustment to APS’s retail rates to recover FERC approved transmission charges went into effect automatically on June 1, 2019.

Effective June 1, 2020, APS's annual wholesale transmission rates for all users of its transmission system decreased by approximately $6.1 million for the twelve-month period beginning June 1, 2020 in accordance with the FERC-approved formula.  Of this amount, retail customer rates decreased by approximately $10.9 million. An adjustment to APS’s retail rates to recover FERC approved transmission charges went into effect automatically on June 1, 2020.

 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 are currently 2.5 cents for both lost residential and non-residential kWh as set forth in
the 2017 Settlement Agreement.  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 15, 2018, APS filed its 2018 annual LFCR adjustment, requesting that effective May 1, 2018, the LFCR be adjusted to $60.7 million. On February 6, 2019, the ACC approved the 2018 annual LFCR adjustment to become effective March 1, 2019. On February 15, 2019, APS filed its 2019 annual LFCR adjustment, requesting that effective May 1, 2019, the annual LFCR recovery amount be reduced to $36.2 million (a $24.5 million decrease from previous levels). On July 10, 2019, the ACC approved APS’s 2019 LFCR adjustment as filed, effective with the next billing cycle of July 2019. 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.

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 January 8, 2018, APS filed an application with the ACC that addressed the change in the marginal federal tax rate from 35% to 21% resulting from the Tax Act and reduced rates by $119.1 million annually through an equal cents per kWh credit ("TEAM Phase I").  On February 22, 2018, the ACC approved the reduction of rates through an equal cents per kWh credit. The rate reduction was effective for the first billing cycle in March 2018.

The impact of the TEAM Phase I, over time, is expected to be earnings neutral. However, on a quarterly basis, there is a difference between the timing and amount of the income tax benefit and the reduction in revenues refunded through the TEAM Phase I related to the lower federal income tax rate. The amount of the benefit of the lower federal income tax rate is based on quarterly pre-tax results, while the reduction in revenues refunded through the TEAM Phase I is based on a per kWh sales credit which follows our seasonal kWh sales pattern and is not impacted by earnings of the Company.

On August 13, 2018, APS filed a second request with the ACC that addressed the return of an additional $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 will be recorded as a part of the balancing account and will be addressed for recovery as part of APS's 2019 ACC rate case. Both the timing of the reduction in revenues refunded through TEAM Phase II and the offsetting income tax benefit are 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 will provide an additional benefit of $39.5 million to customers through December 31, 2020. It is currently anticipated that benefits related to the amortization of depreciation related excess deferred taxes for periods beginning after December 31, 2020 will be fully incorporated into the 2019 rate case.

Net Metering

APS's 2017 Rate Case Decision provides that payments by utilities for energy exported to the grid from DG solar facilities will be determined using a RCP methodology, a method that is based on the most recent five-year rolling average price that APS pays for utility-scale solar projects, while a forecasted avoided cost methodology is being developed.  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. Once the avoided cost methodology is developed, the ACC will determine in APS's subsequent rate cases which method (or a combination of methods) is appropriate to determine the actual price to be paid by APS for exported distributed energy.

In addition, the ACC made the following determinations:

•
Customers who have interconnected a DG system or submitted an application for interconnection for DG systems prior to September 1, 2017, based on APS's 2017 Rate Case Decision, will be grandfathered for a period of 20 years from the date the customer’s interconnection application was accepted by the utility;
•
Customers with DG solar systems are to be considered a separate class of customers for ratemaking purposes; and
•
Once an export price is set for APS, 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. A first-year export energy price of 12.9 cents per kWh was included in the 2017 Settlement Agreement and became effective on September 1, 2017.

In accordance with the 2017 Rate Case Decision, APS filed its request for a second-year export energy price of 11.6 cents per kWh on May 1, 2018.  This price reflected the 10% annual reduction discussed above. The new rate rider became effective on October 1, 2018. APS filed its request for a third-year 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. The ACC has not yet ruled on this request.

On January 23, 2017, The Alliance for Solar Choice ("TASC") sought rehearing of the ACC's decision regarding the value and cost of DG. TASC asserted that the ACC improperly ignored the Administrative Procedure Act, failed to give adequate notice regarding the scope of the proceedings, and relied on information that was not submitted as evidence, among other alleged defects. TASC filed a Notice of Appeal in the Arizona Court of Appeals and filed a Complaint and Statutory Appeal in the Maricopa County Superior Court on March 10, 2017. As part of the 2017 Settlement Agreement described above, TASC agreed to withdraw these appeals when the ACC decision implementing the 2017 Settlement Agreement is no longer subject to appellate review.

See "2016 Retail Rate Case Filing with the Arizona Corporation Commission" 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 Arizona Corporation Commissioner Robert Burns

On August 25, 2016, Commissioner 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.

On September 9, 2016, APS filed with the ACC a motion to quash the subpoenas or, alternatively, to stay APS's obligations to comply with the subpoenas and decline to decide APS's motion pending court proceedings. Contemporaneously with the filing of this motion, APS and Pinnacle West filed a complaint for special action and declaratory judgment in the Superior Court of Arizona for Maricopa County, seeking a declaratory judgment that Commissioner Burns’ subpoenas are contrary to law. On September 15, 2016, APS produced all non-confidential and responsive documents and offered to produce any remaining responsive documents that are confidential after an appropriate confidentiality agreement is signed.

On February 7, 2017, Commissioner Burns opened a new ACC docket and indicated that its purpose is to study and rectify problems with transparency and disclosure regarding financial contributions from regulated monopolies or other stakeholders who may appear before the ACC that may directly or indirectly benefit an ACC Commissioner, a candidate for ACC Commissioner, or key ACC Staff.  As part of this docket, Commissioner Burns set March 24, 2017 as a deadline for the production of all information previously requested through the subpoenas. Neither APS nor Pinnacle West produced the information requested and instead objected to the subpoena. On March 10, 2017, Commissioner Burns filed suit against APS and Pinnacle West in the Superior Court of Arizona for Maricopa County in an effort to enforce his subpoenas. On March 30, 2017, APS filed a motion to dismiss Commissioner Burns' suit against APS and Pinnacle West. In response to the motion to dismiss, the court stayed the suit and ordered Commissioner Burns to file a motion to compel the production of the information sought by the subpoenas with the ACC. On June 20, 2017, the ACC denied the motion to compel.

On August 4, 2017, Commissioner Burns amended his complaint to add all of the ACC Commissioners and the ACC itself as defendants. All defendants moved to dismiss the amended complaint. On February 15, 2018, the Superior Court dismissed Commissioner Burns’ amended complaint. On March 6, 2018, Commissioner Burns filed an objection to the proposed final order from the Superior Court and a motion to further amend his complaint. The Superior Court permitted Commissioner Burns to amend his complaint to add a claim regarding his attempted investigation into whether his fellow commissioners should have been disqualified from voting on APS’s 2017 rate case. Commissioner Burns filed his second amended complaint, and all defendants filed responses opposing the second amended complaint and requested that it be dismissed. Oral argument occurred in November 2018 regarding the motion to dismiss. On December 18, 2018, the trial court granted the defendants’ motions to dismiss and entered final judgment on January 18, 2019. On February 13, 2019, Commissioner Burns filed a notice of appeal. On July 12, 2019, Commissioner Burns filed his opening brief in the Arizona Court of Appeals. APS filed its answering brief on October 21, 2019. The
Arizona Court of Appeals originally granted the request for oral argument; however, on March 31, 2020, the court vacated the date scheduled for oral argument given the COVID-19 pandemic.  The court determined that the matter could be submitted without oral argument and has taken the matter under advisement and will issue a decision without oral argument. APS and Pinnacle West cannot predict the outcome of this matter.

Information Requests from Arizona Corporation Commissioners

On January 14, 2019, ACC Commissioner Kennedy opened a docket to investigate campaign expenditures and political participation of APS and Pinnacle West. In addition, on February 27, 2019, ACC Commissioners Burns and Dunn opened a new docket and requested documents from APS and Pinnacle West related to ACC elections and charitable contributions related to the ACC. On March 1, 2019, ACC Commissioner Kennedy issued a subpoena to APS seeking several categories of information for both Pinnacle West and APS including political contributions, lobbying expenditures, marketing and advertising expenditures, and contributions made to 501(c)(3) and 501(c)(4) entities, for the years 2013-2018. Pinnacle West and APS voluntarily responded to both sets of requests on March 29, 2019. APS also received and responded to various follow-on requests from ACC Commissioners on these matters. Pinnacle West and APS cannot predict the outcome of these matters. The Company's CEO, Mr. Guldner, appeared at the ACC's January 14, 2020 Open Meeting regarding ACC Commissioners' questions about political spending.  Mr. Guldner committed to the ACC that during his tenure, Pinnacle West and APS, and any of their affiliated companies, will not participate in ACC campaign elections through financial contributions or in-kind contributions.
    
Energy Modernization Plan

On January 30, 2018, former ACC Commissioner Tobin proposed the Energy Modernization Plan, 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. In August 2018, the ACC directed ACC Staff to open a new rulemaking docket which will address a wide range of energy issues, including the Energy Modernization Plan proposals. The rulemaking will consider possible modifications to existing ACC rules, such as the RES, Electric and Gas Energy Efficiency Standards, Net Metering, Resource Planning, and the Biennial Transmission Assessment, as well as the development of new rules regarding forest bioenergy, electric vehicles, interconnection of distributed generation, baseload security, blockchain technology and other technological developments, retail competition, and other energy-related topics.

On April 25, 2019, the ACC Staff issued an initial set of draft energy rules and held various workshops to incorporate feedback from stakeholders and ACC Commissioners from April 2019 through July 2020. At the March 11-12, 2020 workshop, the ACC Staff committed to filing a final draft of proposed rules by July 2020. On July 16, 2020, the ACC Staff issued final draft energy rules which propose 100% of retail kWh sales from clean energy resources by the end of 2050. Nuclear is defined as a clean energy resource. The proposed rules also require 50% of retail energy served be renewable by the end of 2035, including a 10% carve out for customer-sited distributed generation with storage. A new energy efficiency standard was not included in the proposed rules. APS would be required to obtain approval of its action plan included in its IRP and seek recovery of prudently incurred costs in a rate process. If approved by the ACC Commissioners, the rules would require 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, the ACC Staff proposed changing the IRP planning horizon from 15 years to 10 years. On July 30, 2020, the ACC discussed the final draft energy rules but no action was taken by the ACC. 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.  In March of 2018, the ACC reviewed the 2017 IRPs of its jurisdictional utilities and voted to not acknowledge any of the plans.  APS does not believe that this lack of acknowledgment will have a material impact on our financial position, results of operations or cash flows.  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 IRP’s 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. See "Energy Modernization Rules" above for information regarding proposed changes to the IRP filings.

Public Utility Regulatory Policies Act ("PURPA")

In August 2016, APS filed an application requesting that all of its contracts with qualifying facilities over 100 kW be set at a presumptive maximum 2 year term. A qualifying facility is an eligible energy-producing facility as defined by FERC regulations within a host electric utility’s service territory that has a right to sell to the host utility. Host utilities are required to purchase power from qualifying facilities at an avoided cost as determined by the utility subject to state commission oversight. A hearing was held in August 2019 and briefing on this matter was completed in October 2019 regarding APS’s application. On December 17, 2019, the ACC denied the application and mandated a minimum contract length of 18 years for qualifying facilities over 100 kW and the rate paid to the qualifying facilities will be based on the long-term avoided cost. APS is in discussions with qualifying facility developers but has not entered into any new qualifying facility agreements that would be subject to the new requirements of the ACC's decision.

On July 16, 2020, FERC issued a final rule revising FERC’s regulations implementing PURPA. The final rule will go into effect 120 days following publication in the Federal Register. APS is evaluating how the revised regulations may impact its operations.

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 from 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. The emergency rule changes will be effective for 180 days and may be renewed for one additional 180-day period.

In addition, 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 electric 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 issued draft amendments to the customer service disconnections rules. Stakeholders submitted initial comments to the draft amendments on
September 23, 2019. ACC stakeholder meetings were held in September 2019, October 2019 and January 2020 regarding the customer service disconnections rules.

Although the emergency rules expired in December 2019, the Summer Disconnection Moratorium will remain in effect through utility tariffs for 2020 and beyond until the ACC adopts permanent rules or determines otherwise.

Due to the COVID-19 pandemic, APS voluntarily suspended disconnections of customers for nonpayment beginning March 13, 2020. APS currently estimates that the Summer Disconnection Moratorium, the suspension of disconnections during the COVID-19 pandemic and the increased bad debt expense associated with both events will result in a negative impact to its 2020 operating results of approximately $20 million to $30 million pre-tax above the impact of disconnections on its operating results for years that did not have the Summer Disconnection Moratorium or COVID-19 pandemic. These estimated impact amounts depend on certain assumptions, including, but not limited to, customer behaviors, population and employment growth, the impacts of COVID-19 on the economy and the results of final rulemaking related to the Summer Disconnection Moratorium. See "COVID-19 Pandemic" above for more information.

Retail Electric Competition Rules
On November 17, 2018, the ACC voted to re-examine the facilitation of a deregulated retail electric market in Arizona. An ACC special open meeting workshop was held on December 3, 2018. No substantive action was taken, but interested parties were asked to submit written comments and respond to a list of questions from ACC Staff. 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. Interested parties filed comments to the ACC Staff report and a stakeholder meeting and workshop to discuss the retail electric competition rules was held on July 30, 2019. ACC Commissioners submitted additional questions regarding this matter. 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. The ACC held a workshop on February 25-26, 2020 for further consideration and discussion of the retail electric competition rules. During the 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 Commissioners are continuing to explore the retail electric competition rules. APS cannot predict whether these efforts will result in any changes and, if changes to the rules results, what impact these rules would have on APS.

Rate Plan Comparison Tool

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 the Company’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. APS developed a new tool for comparing customers’ rate plan options.  APS had an independent third party verify that the new rate comparison tool works correctly.  In February 2020, APS launched the new online rate comparison tool, which
is now available for its customers. The ACC is currently investigating this matter and has hired an outside consultant to evaluate the extent of the error and the overall effectiveness of the tool. APS received a civil investigative demand from the Office of the Arizona Attorney General, Civil Litigation Division, Consumer Protection & Advocacy Section that seeks information pertaining to the rate plan comparison tool offered to APS customers and other related issues. APS is fully cooperating with the Attorney General’s Office in this matter. APS cannot predict the outcome of these matters.

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.  Consistent with the 2017 Rate Case Decision, the request was narrow in scope and addressed only costs associated with this specific environmental compliance equipment.  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. Exceptions to the Recommended Opinion and Order were filed by the parties and intervenors on December 7, 2018.  The ACC has not issued a decision on this matter. APS included the costs for the SCR project in the retail rate base in its 2019 retail rate case filing with the ACC. On March 18, 2020, the ACC agreed to take administrative notice to include in the pending rate case portions of the record in this prior proceeding that are relevant to the SCRs. APS cannot predict the outcome or timing of the decision on this matter. APS may be required to record a charge to its results of operations if the ACC issues an unfavorable decision (see SCR deferral in the Regulatory Assets and Liabilities table below).

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 plans to retire Cholla Unit 4 by the end of 2020.

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 ($65 million as of June 30, 2020), 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. The 2017 Settlement Agreement also shortened the depreciation lives of Cholla Units 1 and 3 to 2025.
On March 20, 2019, APS announced that it began evaluating the feasibility and cost of converting a unit at Cholla to burn biomass. Biomass is a fuel comprised of forest trimmings, and a converted unit at Cholla could assist in forest thinning, responsible forest management, an improved watershed, and a reduced wildfire risk. APS’s ability to operate a biomass power plant would depend on third-parties procuring forest biomass for fuel. APS reported the results of its evaluation on May 9, 2019 to the ACC. On July 10, 2019, the ACC voted to not require APS to file a request for proposal to convert the unit at Cholla to burn biomass.
Navajo Plant
The co-owners of the Navajo Plant and the Navajo Nation agreed that the Navajo Plant would remain in operation until December 2019 under the existing plant lease. 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 November 2019.
  
APS is currently recovering depreciation and a return on the net book value of its interest in the Navajo Plant over its previously estimated life through 2026. APS will seek continued recovery in rates for the book value of its remaining investment in the plant ($77 million as of June 30, 2020) plus a return on the net book value as well as other costs related to retirement and closure, which are still being assessed and may be material. APS believes it will be allowed recovery of the net book value, in addition to a return on its investment. 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. If the ACC does not allow full recovery of the remaining net book value of this interest, all or a portion of the regulatory asset will be written off and APS's net income, cash flows, and financial position will be negatively impacted.    
Regulatory Assets and Liabilities 
The detail of regulatory assets is as follows (dollars in thousands): 
 
Amortization Through
 
June 30, 2020
 
December 31, 2019
 
 
Current
 
Non-Current
 
Current
 
Non-Current
Pension
(a)
 
$
—

 
$
663,327

 
$
—

 
$
660,223

Income taxes — allowance for funds used during construction ("AFUDC") equity
2050
 
6,815

 
156,528

 
6,800

 
154,974

Retired power plant costs
2033
 
28,182

 
128,304

 
28,182

 
142,503

Deferred fuel and purchased power (b) (c)
2021
 
101,425

 
—

 
70,137

 
—

Deferred fuel and purchased power — mark-to-market (Note 7)
2024
 
42,911

 
26,151

 
36,887

 
33,185

Ocotillo deferral
N/A
 
—

 
65,571

 
—

 
38,144

SCR deferral
N/A
 
—

 
64,971

 
—

 
52,644

Deferred property taxes
2027
 
8,569

 
53,911

 
8,569

 
58,196

Deferred compensation
2036
 
—

 
36,481

 
—

 
36,464

Four Corners cost deferral
2024
 
8,077

 
28,113

 
8,077

 
32,152

Lost fixed cost recovery (b)
2021
 
34,144

 
—

 
26,067

 
—

Income taxes — investment tax credit basis adjustment
2048
 
1,098

 
24,532

 
1,098

 
24,981

Palo Verde VIEs (Note 6)
2046
 
—

 
20,945

 
—

 
20,635

Coal reclamation
2026
 
1,068

 
17,533

 
1,546

 
17,688

Loss on reacquired debt
2038
 
1,637

 
11,241

 
1,637

 
12,031

TCA balancing account (b)
2022
 
8,272

 
2,926

 
6,324

 
2,885

Mead-Phoenix transmission line contributions in aid of construction ("CIAC")
2050
 
332

 
9,546

 
332

 
9,712

Tax expense of Medicare subsidy
2024
 
1,238

 
4,444

 
1,235

 
4,940

AG-1 deferral
2022
 
2,787

 
1,322

 
2,787

 
2,716

Tax expense adjuster mechanism (b)
2020
 
3,640

 
—

 
1,612

 
—

Other
Various
 
1,399

 
—

 
1,917

 
—

Total regulatory assets (d)
 
 
$
251,594

 
$
1,315,846

 
$
203,207

 
$
1,304,073


(a)
This asset represents the future recovery of pension benefit obligations through retail rates.  If these costs are disallowed by the ACC, this regulatory asset would be charged to other comprehensive income ("OCI") and result in lower future revenues.
(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."


The detail of regulatory liabilities is as follows (dollars in thousands):
 
 
Amortization Through
 
June 30, 2020
 
December 31, 2019
 
 
Current
 
Non-Current
 
Current
 
Non-Current
Excess deferred income taxes - ACC - Tax Cuts and Jobs Act (a)
2046
 
$
113,168

 
$
966,576

 
$
59,918

 
$
1,054,053

Excess deferred income taxes - FERC - Tax Cuts and Jobs Act (a)
2058
 
7,256

 
233,953

 
6,302

 
237,357

Asset retirement obligations
2057
 
—

 
408,126

 
—

 
418,423

Removal costs
(c)
 
47,300

 
126,036

 
47,356

 
136,072

Other postretirement benefits
(d)
 
37,575

 
118,398

 
37,575

 
139,634

Four Corners coal reclamation
2038
 
5,461

 
48,795

 
1,059

 
51,704

Spent nuclear fuel
2027
 
6,068

 
47,901

 
6,676

 
51,019

Income taxes — change in rates
2050
 
2,802

 
50,163

 
2,797

 
68,265

Income taxes — deferred investment tax credit
2048
 
2,202

 
49,133

 
2,202

 
50,034

Renewable energy standard (b)
2021
 
38,934

 
22

 
39,287

 
10,300

Sundance maintenance
2031
 
1,100

 
13,001

 
5,698

 
11,319

Demand side management (b)
2021
 
3,068

 
6,138

 
15,024

 
24,146

Property tax deferral
N/A
 
—

 
8,603

 
—

 
7,046

FERC transmission true up
2022
 
5,452

 
2,209

 
1,045

 
2,004

Active union medical trust
N/A
 
—

 
7,629

 
—

 
2,041

Tax expense adjustor mechanism (b)
2020
 
6,450

 
—

 
7,018

 
—

Deferred gains on utility property
2022
 
2,423

 
2,973

 
2,423

 
4,163

Other
Various
 
220

 
331

 
532

 
255

Total regulatory liabilities
 
 
$
279,479

 
$
2,089,987

 
$
234,912

 
$
2,267,835


(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.
v3.20.2
Retirement Plans and Other Postretirement Benefits
 6 Months Ended
Jun. 30, 2020
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 an other postretirement benefit plan for the employees of Pinnacle West and our subsidiaries.  Pinnacle West uses a December 31 measurement date for its pension and other postretirement benefit plans.  The market-related value of our plan assets is their fair value at the measurement dates.

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 Benefits
 
Other Benefits
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
2020
 
2019
 
2020
 
2019
 
2020
 
2019
 
2020
 
2019
Service cost — benefits earned during the period
$
13,859

 
$
12,408

 
$
28,116

 
$
24,951

 
$
5,401

 
$
4,470

 
$
11,118

 
$
9,184

Non-service costs (credits):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Interest cost on benefit obligation
29,522

 
34,069

 
59,283

 
68,421

 
6,417

 
7,421

 
12,929

 
14,947

Expected return on plan assets
(46,915
)
 
(43,049
)
 
(93,721
)
 
(85,942
)
 
(10,019
)
 
(9,603
)
 
(20,038
)
 
(19,206
)
  Amortization of:
 

 
 
 
 

 
 

 
 

 
 

 
 

 
 

  Prior service credit
—

 
—

 
—

 
—

 
(9,394
)
 
(9,455
)
 
(18,788
)
 
(18,910
)
  Net actuarial loss
8,295

 
10,053

 
17,306

 
21,292

 
—

 
—

 
—

 
—

Net periodic benefit cost (credit)
$
4,761

 
$
13,481

 
$
10,984

 
$
28,722

 
$
(7,595
)
 
$
(7,167
)
 
$
(14,779
)
 
$
(13,985
)
Portion of cost (credit) charged to expense
$
271

 
$
7,000

 
$
1,613

 
$
15,244

 
$
(5,056
)
 
$
(5,063
)
 
$
(10,512
)
 
$
(9,880
)

 
Contributions
 
We have not made voluntary contributions to our pension plan year-to-date in 2020. The minimum required contributions for the pension plan are zero for the next three years. We expect to make voluntary contributions up to $100 million per year during the 2020-2022 period. We do not expect to make any contributions over the next three years to our other postretirement benefit plans.
v3.20.2
Palo Verde Sale Leaseback Variable Interest Entities
 6 Months Ended
Jun. 30, 2020
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 2023 under one lease and 2033 under the other two leases. APS will be required to make payments relating to these leases of approximately $23 million annually for the period 2020 through 2023, and $16 million annually for the period 2024 through 2033. At the end of the lease period, APS will have the option to purchase the leased assets at their fair market value, extend the leases for up to two years, or return the assets to the lessors.

The leases' terms give APS the ability to utilize the assets for a significant portion of the assets’ economic life, and therefore provide APS with the power to direct activities of the VIEs that most significantly impact the VIEs’ economic performance.  Predominantly due to the lease terms, APS has been deemed the primary beneficiary of these VIEs and therefore consolidates the VIEs.
 
As a result of consolidation, we eliminate lease accounting and instead recognize depreciation expense, resulting in an increase in net income for the three and six months ended June 30, 2020 of $5 million and $10 million, respectively, and for the three and six months ended June 30, 2019 of $5 million and $10 million, respectively, 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, 2020 and December 31, 2019 include the following amounts relating to the VIEs (dollars in thousands):
 
 
June 30, 2020
 
December 31, 2019
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation
$
99,971

 
$
101,906

Equity — Noncontrolling interests
120,915

 
122,540


 
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 $304 million beginning in 2020, and up to $456 million over the lease extension terms.
 
For regulatory ratemaking purposes, the agreements continue to be treated as operating leases and, as a result, we have recorded a regulatory asset relating to the arrangements.
v3.20.2
Derivative Accounting
 6 Months Ended
Jun. 30, 2020
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 in 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 fuels.  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.
 
As of June 30, 2020 and December 31, 2019, we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position): 
 
 
 
Quantity
Commodity
 
Unit of Measure
June 30, 2020
 
December 31, 2019
Power
 
GWh
294

 
193

Gas
 
Billion cubic feet
249

 
257


 
Gains and Losses from Derivative Instruments
 
The following table provides information about gains and losses from derivative instruments in designated cash flow accounting hedging relationships during the three and six months ended June 30, 2020 and 2019 (dollars in thousands):
 
 
 
Financial Statement Location
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
Commodity Contracts
 
 
2020
 
2019
 
2020
 
2019
Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a)
 
Fuel and purchased power (b)
 
$
(349
)
 
$
(538
)
 
$
(763
)
 
$
(974
)

(a)
During the three and six months ended June 30, 2020 and 2019, we had no gains or losses reclassified from accumulated OCI to earnings related to discontinued cash flow hedges.
(b)
Amounts are before the effect of PSA deferrals.
 
During the next twelve months we estimate that no amounts will be reclassified from accumulated OCI into income. For APS, the delivery period for all derivative instruments in designated cash flow accounting hedging relationship have lapsed.
 
The following table provides information about gains and losses from derivative instruments not designated as accounting hedging instruments during the three and six months ended June 30, 2020 and 2019 (dollars in thousands):
 
 
 
Financial Statement Location
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
Commodity Contracts
 
 
2020
 
2019
 
2020
 
2019
Net Loss Recognized in Income
 
Fuel and purchased power (a)
 
$
(4,894
)
 
$
(49,686
)
 
$
(34,971
)
 
$
(41,516
)

(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 as of June 30, 2020 and December 31, 2019.  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, 2020:
(dollars in thousands)
 
Gross
 Recognized
 Derivatives
 (a)
 
Amounts
Offset
 (b)
 
Net
 Recognized
 Derivatives
 
Other
 (c)
 
Amount Reported on Balance Sheets
Current assets
 
$
2,989

 
$
(2,279
)
 
$
710

 
$
—

 
$
710

Investments and other assets
 
540

 
(510
)
 
30

 
—

 
30

Total assets
 
3,529

 
(2,789
)
 
740

 
—

 
740

 
 
 
 
 
 
 
 
 
 
 
Current liabilities
 
(45,899
)
 
2,279

 
(43,620
)
 
(1,185
)
 
(44,805
)
Deferred credits and other
 
(26,691
)
 
510

 
(26,181
)
 
—

 
(26,181
)
Total liabilities
 
(72,590
)
 
2,789

 
(69,801
)
 
(1,185
)
 
(70,986
)
Total
 
$
(69,061
)
 
$
—

 
$
(69,061
)
 
$
(1,185
)
 
$
(70,246
)

(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 $1,185 and cash margin provided to counterparties of $0.

As of December 31, 2019:
(dollars in thousands)
 
Gross
Recognized
Derivatives
 (a)
 
Amounts
Offset
(b)
 
Net
 Recognized
 Derivatives
 
Other
 (c)
 
Amount
Reported on
Balance Sheets
Current assets
 
$
584

 
$
(474
)
 
$
110

 
$
405

 
$
515

 
 
 
 
 
 
 
 
 
 
 
Current liabilities
 
(38,235
)
 
474

 
(37,761
)
 
(1,185
)
 
(38,946
)
Deferred credits and other
 
(33,186
)
 
—

 
(33,186
)
 
—

 
(33,186
)
Total liabilities
 
(71,421
)
 
474

 
(70,947
)
 
(1,185
)
 
(72,132
)
Total
 
$
(70,837
)
 
$
—

 
$
(70,837
)
 
$
(780
)
 
$
(71,617
)

(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 $1,185 and cash margin provided to counterparties of $405.

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, 2020 we have one counterparty for which our exposure represents approximately 79% of Pinnacle West's $0.7 million of risk management assets. This exposure relates to a master agreement with a counterparty that has a very high credit rating. Our risk management process assesses and monitors the financial exposure of all counterparties.  Despite the fact that the great majority of our trading counterparties' debt is rated as investment grade by the credit rating agencies, there is still a possibility that one or more of these counterparties could default, resulting in a material impact on consolidated earnings for a given period. Counterparties in the portfolio consist principally of financial institutions, major energy companies, municipalities and local distribution companies.  We maintain credit policies that we believe minimize overall credit risk to within acceptable limits.  Determination of the credit quality of our counterparties is based upon a number of factors, including credit ratings and our evaluation of their financial condition.  To manage credit risk, we employ collateral requirements and standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty.  Valuation adjustments are established representing our estimated credit losses on our overall exposure to counterparties.
 
Certain of our 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 at June 30, 2020 (dollars in thousands):
 
June 30, 2020
Aggregate fair value of derivative instruments in a net liability position
$
72,590

Cash collateral posted
—

Additional cash collateral in the event credit-risk-related contingent features were fully triggered (a)
63,880


(a)
This amount is after counterparty netting and includes those contracts which qualify for scope exceptions, which are excluded from the derivative details above.
 
We also have energy-related non-derivative instrument contracts with investment grade credit-related contingent features, which could also require us to post additional collateral of approximately $88 million if our debt credit ratings were to fall below investment grade.
v3.20.2
Commitments and Contingencies
 6 Months Ended
Jun. 30, 2020
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, 2019. In July 2020, APS accepted DOE's extension of the settlement agreement for recovery of costs incurred through December 31, 2022.

APS has submitted five claims pursuant to the terms of the August 18, 2014 settlement agreement, for five separate time periods during July 1, 2011 through June 30, 2018. The DOE has approved and paid $84.3 million for these claims (APS’s share is $24.5 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 October 31, 2019, APS filed its sixth claim pursuant to the terms of the August 18, 2014 settlement agreement in the amount of $16 million (APS’s share is $4.7 million). On February 11, 2020, the DOE approved a payment of $15.4 million (APS's share is $4.5 million) and on April 20, 2020, 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 $13.8 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 $13.3 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 $25.8 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 $75.1 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, 2020, there have been no material changes outside the normal course of business in contractual obligations from the information provided in our 2019 Form 10-K. See Note 3 for discussion regarding changes in our short-term and long-term debt obligations.

Superfund-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 ("PRPs").  PRPs may be strictly, and often are 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 in the fall of 2020. We estimate that our costs related to this investigation and study will be approximately $3 million.  We anticipate 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, 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.
  
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. 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 below for details of the Cholla BART approval.

Four Corners. 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, APS and El Paso Electric Company ("El Paso") entered into an asset purchase agreement providing for the purchase by APS, or an affiliate of APS, of El Paso's 7% interest in Four Corners Units 4 and 5. 4CA purchased the El Paso interest on July 6, 2016. Navajo Transitional Energy Company, LLC ("NTEC") purchased the interest from 4CA on July 3, 2018. See "Four Corners - 4CA Matter" below for a discussion of the NTEC purchase. The cost of the pollution controls related to the 7% interest is approximately $45 million, which was assumed by NTEC through its purchase of the 7% interest.

Cholla. APS believed that EPA’s original 2012 final rule establishing controls constituting BART for Cholla, which would require installation of SCR controls, was unsupported and that EPA had no basis for disapproving Arizona’s State Implementation Plan ("SIP") and promulgating a FIP that was inconsistent with the state’s considered BART determinations under the regional haze program.  In September 2014, APS met with EPA to propose a compromise BART strategy, whereby APS would permanently close Cholla Unit 2 and cease burning coal at Units 1 and 3 by the mid-2020s. (See "Cholla" in Note 4 for information regarding future plans for the Cholla plant and details related to the resulting regulatory asset.) APS made the proposal with the understanding that additional emission control equipment is unlikely to be required in the future because retiring and/or converting the units as contemplated in the proposal is more cost effective than, and will result in increased visibility improvement over, the BART requirements for oxides of nitrogen ("NOx") imposed through EPA's BART FIP. In early 2017, EPA approved a final rule incorporating APS's compromise proposal, which took effect for Cholla on April 26, 2017.
 
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 that is contaminating groundwater above a regulated constituent’s groundwater protection standard 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, 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.

•
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.

•
Based on an August 21, 2018 D.C. Circuit decision, which vacated and remanded those provisions of the EPA CCR regulations that allow for the operation of unlined CCR surface impoundments, EPA recently proposed corresponding changes to federal CCR regulations. On July 29, 2020, EPA took final action on new regulations establishing April 11, 2021 as the deadline for initiating the closure of unlined CCR surface impoundments.

•
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.

We cannot at this time predict the outcome of these regulatory proceedings or when the EPA will take final action. 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 $22 million and its share of incremental costs to comply with the CCR rule for Cholla is approximately $15 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 cease operating and initiate closure by October 31, 2020. APS initiated an assessment of corrective measures on January 14, 2019 and expects such assessment will continue through mid- to late-2020. As part of this assessment, APS continues to gather additional groundwater data and perform remedial evaluations as to the CCR disposal units at Cholla and Four Corners undergoing corrective action. In addition, APS will solicit input from the public, host public hearings, and select remedies 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.
 
Clean Power Plan/Affordable Clean Energy 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 those regulations had been stayed pending judicial review.

The ACE regulations are based upon measures that can be implemented to improve the heat rate of steam-electric power plants, specifically coal-fired EGUs. In contrast with the CPP, EPA's ACE regulations would not involve utility-level generation dispatch shifting away from coal-fired generation and toward renewable energy resources and natural gas-fired combined cycle power plants. EPA’s ACE regulations provide states and EPA regions such as the Navajo Nation with three years to develop plans establishing source-specific standards of performance based upon application of the ACE rule’s heat-rate improvement emission guidelines.

We cannot at this time predict the outcome of EPA's regulatory actions repealing and replacing the CPP. Various state governments, industry organizations, and environmental and public-health public interest groups have filed lawsuits in the D.C. Circuit challenging the legality of EPA’s action, both in repealing the CPP and issuing the ACE regulations. In addition, to the extent that the ACE regulations go into effect as finalized, it is not yet clear how the state of Arizona or EPA will implement these regulations as applied to APS’s coal-fired EGUs. In light of these uncertainties, APS is still evaluating the impact of the ACE regulations on its coal-fired generation fleet.

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.
  
Federal Agency Environmental Lawsuit Related to Four Corners

On April 20, 2016, several environmental groups filed a lawsuit against the Office of Surface Mining Reclamation and Enforcement ("OSM") and other federal agencies in the District of Arizona in connection with their issuance of the approvals that extended the life of Four Corners and the adjacent mine.  The lawsuit alleges that these federal agencies violated both the Endangered Species Act ("ESA") and the National Environmental Policy Act ("NEPA") in providing the federal approvals necessary to extend operations at the Four Corners Power Plant and the adjacent Navajo Mine past July 6, 2016.  APS filed a motion to intervene in the proceedings, which was granted on August 3, 2016.

On September 15, 2016, NTEC, the company that owns the adjacent mine, filed a motion to intervene for the purpose of dismissing the lawsuit based on NTEC's tribal sovereign immunity. On September 11, 2017, the Arizona District Court issued an order granting NTEC's motion, dismissing the litigation with prejudice, and terminating the proceedings. On November 9, 2017, the environmental group plaintiffs appealed the district court order dismissing their lawsuit. On July 29, 2019, the Ninth Circuit Court of Appeals affirmed the September 2017 dismissal of the lawsuit, after which the environmental group plaintiffs petitioned the Ninth Circuit for rehearing on September 12, 2019. The Ninth Circuit denied this petition for rehearing on December 11, 2019. On March 24 , 2020, the environmental group plaintiffs filed a Petition for a Writ of Certiorari with the U.S. Supreme Court seeking review of the Ninth Circuit decision. This petition was denied by the U.S. Supreme Court on June 29, 2020. No further legal proceedings related to this matter are expected at this time.

Four Corners National Pollutant Discharge Elimination System ("NPDES") Permit

On July 16, 2018, several environmental groups filed a petition for review before the EPA Environmental Appeals Board ("EAB") concerning the NPDES wastewater discharge permit for Four Corners, which was reissued on June 12, 2018.  The environmental groups allege that the permit was reissued in contravention of several requirements under the Clean Water Act and did not contain required provisions concerning EPA’s 2015 revised effluent limitation guidelines for steam-electric EGUs, 2014 existing-source regulations governing cooling-water intake structures, and effluent limits for surface seepage and subsurface discharges from coal-ash disposal facilities.  To address certain of these issues through a reconsidered permit, EPA took action on December 19, 2018 to withdraw the NPDES permit reissued in June 2018. Withdrawal of the permit moots the EAB appeal, and EPA filed a motion to dismiss on that basis. The EAB thereafter dismissed the environmental group appeal on February 12, 2019. EPA then issued a revised final NPDES permit for Four Corners on September 30, 2019. This permit is now subject to a petition for review before the EAB, based upon a November 1, 2019 filing by several environmental groups. Oral argument on this appeal has been scheduled for September 3, 2020. We cannot predict the outcome of this review and whether the review 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 is paying 4CA the purchase price over a period of four years pursuant to a secured interest-bearing promissory note. The note is secured by a portion of APS’s payments to be owed to NTEC under the 2016 Coal Supply Agreement. As of June 30, 2020, the note has a remaining balance of $39 million. NTEC continues to make payments in accordance with the terms of the note. Due to its short-remaining term, among other factors, there are no expected credit losses associated with the note.
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.
The 2016 Coal Supply Agreement contained alternate pricing terms for the 7% interest in the event NTEC did not purchase the interest. Until the time that NTEC purchased the 7% interest, the alternate pricing provisions were applicable to 4CA as the holder of the 7% interest. These terms included a formula under which NTEC must make certain payments to 4CA for reimbursement of operations and maintenance costs and a specified rate of return, offset by revenue generated by 4CA’s power sales. The amount under this formula for calendar year 2018 (up to the date that NTEC purchased the 7% interest) was approximately $10 million, which was due to 4CA on December 31, 2019. Such payment was satisfied in January 2020 by NTEC directing to 4CA a prepayment from APS of future coal payment obligations of which the prepayment has been fully utilized as of June 2020.
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, 2020, standby letters of credit totaled $4.9 million and will expire in 2021. As of June 30, 2020, surety bonds expiring through 2021 totaled $16 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, 2020. 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 reduce as payments are made under the respective guarantee agreements.  The Equity Contribution Guarantees are currently anticipated to be terminated upon completion of construction of the respective projects, which is anticipated to occur prior to December 31, 2020, and the PTC Guarantees (approximately $40 million as of June 30, 2020) are currently expected to be terminated ten years following the commercial operation date of the applicable project.
v3.20.2
Other Income and Other Expense
 6 Months Ended
Jun. 30, 2020
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,
 
2020
 
2019
 
2020
 
2019
Other income:
 

 
 

 
 

 
 

Interest income
$
2,755

 
$
2,699

 
$
6,032

 
$
5,001

Investment gains (losses) - net
2,826

 
—

 
2,826

 
—

Debt return on Four Corners SCR deferrals (Note 4)
4,249


4,887

 
7,389

 
9,731

Debt return on Ocotillo modernization project (Note 4)
6,703

 
5,294

 
12,847

 
5,294

Miscellaneous
137

 
5

 
145

 
28

Total other income
$
16,670

 
$
12,885

 
$
29,239

 
$
20,054

Other expense:
 

 
 

 
 

 
 

Non-operating costs
$
(2,290
)
 
$
(3,481
)
 
$
(4,948
)
 
$
(6,185
)
Investment gains (losses) — net
—

 
(491
)
 
60

 
(729
)
Miscellaneous
(1,746
)
 
(378
)
 
(3,932
)
 
(1,794
)
Total other expense
$
(4,036
)
 
$
(4,350
)
 
$
(8,820
)
 
$
(8,708
)

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,
 
2020
 
2019
 
2020
 
2019
Other income:
 

 
 

 
 

 
 

Interest income
$
2,183

 
$
1,504

 
$
4,524

 
$
3,054

Debt return on Four Corners SCR deferrals (Note 4)
4,249

 
4,887

 
7,389


9,731

Debt return on Ocotillo modernization project (Note 4)
6,703

 
5,294

 
12,847

 
5,294

Miscellaneous
137

 
6

 
145

 
28

Total other income
$
13,272

 
$
11,691

 
$
24,905

 
$
18,107

Other expense:
 

 
 

 
 

 
 

Non-operating costs
$
(2,113
)
 
$
(3,049
)
 
$
(4,595
)
 
$
(5,517
)
Miscellaneous
(1,746
)
 
(379
)
 
(3,932
)
 
(1,789
)
Total other expense
$
(3,859
)
 
$
(3,428
)
 
$
(8,527
)
 
$
(7,306
)
v3.20.2
Earnings Per Share
 6 Months Ended
Jun. 30, 2020
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,
 
2020
 
2019
 
2020
 
2019
Net income attributable to common shareholders
$
193,585

 
$
144,145

 
$
223,578

 
$
162,063

Weighted average common shares outstanding — basic
112,638

 
112,337

 
112,616

 
112,381

Net effect of dilutive securities:
 
 
 
 
 
 
 
Contingently issuable performance shares and restricted stock units
241

 
314

 
255

 
353

Weighted average common shares outstanding — diluted
112,879

 
112,651

 
112,871

 
112,734

Earnings per weighted-average common share outstanding
 
 
 
 
 
 
 
Net income attributable to common shareholders — basic
$
1.72

 
$
1.28

 
$
1.99

 
$
1.44

Net income attributable to common shareholders — diluted
$
1.71

 
$
1.28

 
$
1.98

 
$
1.44
v3.20.2
Fair Value Measurements
 6 Months Ended
Jun. 30, 2020
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 2019 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's 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, 2020 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
 
 
Total
Assets
 

 
 

 
 

 
 

 
 
 
 

Risk management activities — derivative instruments:
 
 
 
 
 
 
 
 
 
 
 
Commodity contracts
$
—

 
$
3,165

 
$
365

 
$
(2,790
)
 
(a)
 
$
740

Nuclear decommissioning trust:
 
 
 
 
 
 
 
 
 
 
 
Equity securities
15,985

 
—

 
—

 
(6,130
)
 
(b)
 
9,855

U.S. commingled equity funds
—

 
—

 
—

 
502,251

 
(c)
 
502,251

U.S. Treasury debt
143,673

 
—

 
—

 
—

 
 
 
143,673

Corporate debt
—

 
149,672

 
—

 
—

 
 
 
149,672

Mortgage-backed securities
—

 
99,407

 
—

 
—

 
 
 
99,407

Municipal bonds
—

 
106,971

 
—

 
—

 
 
 
106,971

Other fixed income
—

 
12,204

 
—

 
—

 
 
 
12,204

Subtotal nuclear decommissioning trust
159,658

 
368,254

 
—

 
496,121

 
 
 
1,024,033

 
 
 
 
 
 
 
 
 
 
 
 
Other special use funds:
 
 
 
 
 
 
 
 
 
 
 
Equity securities
8,955

 
—

 
—

 
526

 
(b)
 
9,481

U.S. Treasury debt
229,858

 
—

 
—

 
—

 

 
229,858

Municipal bonds
—

 
13,993

 
—

 
—

 
 
 
13,993

Subtotal other special use funds
238,813

 
13,993

 
—

 
526

 
 
 
253,332

 
 
 
 
 
 
 
 
 
 
 
 
Total assets
$
398,471

 
$
385,412

 
$
365

 
$
493,857

 
 
 
$
1,278,105

Liabilities
 

 
 

 
 

 
 

 
 
 
 

Risk management activities — derivative instruments:
 

 
 

 
 

 
 

 
 
 
 

Commodity contracts
$
—

 
$
(61,974
)
 
$
(10,617
)
 
$
1,605

 
(a)
 
$
(70,986
)

(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, 2019 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
 
 
Total
Assets
 

 
 

 
 

 
 

 
 
 
 

Risk management activities — derivative instruments:
 
 
 
 
 
 
 
 
 
 
 
Commodity contracts
$
—

 
$
551

 
$
33

 
$
(69
)
 
(a)
 
$
515

Nuclear decommissioning trust:
 

 
 

 
 

 
 

 
 
 
 

Equity securities
10,872

 
—

 
—

 
2,401

 
(b)
 
13,273

U.S. commingled equity funds
—

 
—

 
—

 
518,844

 
(c)
 
518,844

U.S. Treasury debt
160,607

 
—

 
—

 
—

 
 
 
160,607

Corporate debt
—

 
115,869

 
—

 
—

 
 
 
115,869

Mortgage-backed securities
—

 
118,795

 
—

 
—

 
 
 
118,795

Municipal bonds
—

 
73,040

 
—

 
—

 
 
 
73,040

Other fixed income
—

 
10,347

 
—

 
—

 
 
 
10,347

Subtotal nuclear decommissioning trust
171,479

 
318,051

 
—

 
521,245

 
 
 
1,010,775

 
 
 
 
 
 
 
 
 
 
 
 
Other special use funds:
 
 
 
 
 
 
 
 
 
 
 
Equity securities
7,142

 
—

 
—

 
474

 
(b)
 
7,616

U.S. Treasury debt
232,848

 
—

 
—

 
—

 
 
 
232,848

Municipal bonds
—

 
4,631

 
—

 
—

 
 
 
4,631

Subtotal other special use funds
239,990

 
4,631

 
—

 
474

 
 
 
245,095

 
 
 
 
 
 
 
 
 
 
 
 
Total assets
$
411,469

 
$
323,233

 
$
33

 
$
521,650

 
 
 
$
1,256,385

Liabilities
 

 
 

 
 

 
 

 
 
 
 

Risk management activities — derivative instruments:
 

 
 

 
 

 
 

 
 
 
 

Commodity contracts
$
—

 
$
(67,992
)
 
$
(3,429
)
 
$
(711
)
 
(a)
 
$
(72,132
)

(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. The NTEC note receivable related to the sale of 4CA’s interest in Four Corners bears interest at 3.9% per annum and has a book value of $39 million as of June 30, 2020 and $44 million as of December 31, 2019, as presented on the Condensed Consolidated Balance Sheets.  The carrying amount is not materially different from the fair value of the note receivable and is classified within Level 3 of the fair value hierarchy.  See Note 8 for more information on 4CA matters.
v3.20.2
Investments in Nuclear Decommissioning Trusts and Other Special Use Funds
 6 Months Ended
Jun. 30, 2020
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 Mine 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 Mine 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 mine 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. 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, 2020
 
Fair Value
 
Total
Unrealized
Gains
 
Total
Unrealized
Losses
Investment Type:
Nuclear Decommissioning Trusts
 
Other Special Use Funds
 
Total
 
 
Equity securities
$
518,236

 
$
8,955

 
$
527,191

 
$
316,494

 
$
(58
)
Available for sale-fixed income securities
511,927

 
243,851

 
755,778

(a)
49,693

 
(524
)
Other
(6,130
)
 
526

 
(5,604
)
(b)
—

 
—

Total
$
1,024,033

 
$
253,332

 
$
1,277,365

 
$
366,187

 
$
(582
)

(a)
As of June 30, 2020, the amortized cost basis of these available-for-sale investments is $707 million.
(b)
Represents net pending securities sales and purchases.

 
December 31, 2019
 
Fair Value
 
Total
Unrealized
Gains
 
Total
Unrealized
Losses
Investment Type:
Nuclear Decommissioning Trusts
 
Other Special Use Funds
 
Total
 
 
Equity securities
$
529,716

 
$
7,142

 
$
536,858

 
$
337,681

 
$
—

Available for sale-fixed income securities
478,658

 
237,479

 
716,137

(a)
25,795

 
(669
)
Other
2,401

 
474

 
2,875

(b)
—

 
—

Total
$
1,010,775

 
$
245,095

 
$
1,255,870

 
$
363,476

 
$
(669
)

(a)
As of December 31, 2019, the amortized cost basis of these available-for-sale investments is $691 million.
(b)
Represents net pending securities sales and purchases.

    
The following table sets forth APS's realized gains and losses relating to the sale and maturity of available-for-sale debt securities and equity securities, and the proceeds from the sale and maturity of these investment securities (dollars in thousands):
 
Three Months Ended June 30,
 
Nuclear Decommissioning Trusts
 
Other Special Use Funds
 
Total
2020
 
 
 
 
 
Realized gains
$
4,500

 
$
—

 
$
4,500

Realized losses
(1,621
)
 
—

 
(1,621
)
Proceeds from the sale of securities (a)
176,942

 
19,830

 
196,772

2019
 
 
 
 
 
Realized gains
$
2,643

 
$
—

 
$
2,643

Realized losses
(1,700
)
 
—

 
(1,700
)
Proceeds from the sale of securities (a)
93,559

 
36,747

 
130,306


(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 Trusts
 
Other Special Use Funds
 
Total
2020
 
 
 
 
 
Realized gains
$
7,813

 
$
—

 
$
7,813

Realized losses
(3,848
)
 
—

 
(3,848
)
Proceeds from the sale of securities (a)
355,138

 
36,721

 
391,859

2019
 
 
 
 
 
Realized gains
$
3,746

 
$
—

 
$
3,746

Realized losses
(3,105
)
 
—

 
(3,105
)
Proceeds from the sale of securities (a)
216,152

 
93,202

 
309,354


(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.

    
The fair value of APS's fixed income securities, summarized by contractual maturities, at June 30, 2020, is as follows (dollars in thousands):
 
Nuclear Decommissioning Trust
 
Coal Mine Reclamation Escrow Account
 
Active Union Employee Medical Account
 
Total
Less than one year
$
21,767

 
$
37,494

 
$
40,673

 
$
99,934

1 year – 5 years
137,754

 
11,371

 
143,406

 
292,531

5 years – 10 years
125,807

 
1,904

 
—

 
127,711

Greater than 10 years
226,599

 
9,003

 
—

 
235,602

Total
$
511,927

 
$
59,772

 
$
184,079

 
$
755,778
v3.20.2
New Accounting Standards
 6 Months Ended
Jun. 30, 2020
Accounting Standards Update and Change in Accounting Principle [Abstract]  
New Accounting Standards New Accounting Standards

ASU 2016-13, Financial Instruments: Measurement of Credit Losses

In June 2016, a new accounting standard was issued that amends the measurement of credit losses on certain financial instruments. The new standard requires entities to use a current expected credit loss model to measure impairment of certain investments in debt securities, trade accounts receivables, and other financial instruments. Since the issuance of the new standard, various guidance has been issued that amends the new standard, including clarifications of certain aspects of the standard and targeted transition relief, among other changes. The new standard and related amendments were effective for us on January 1, 2020, and must be adopted using a modified retrospective approach for certain aspects of the standard, and a prospective approach for other aspects of the standard. We adopted the standard on January 1, 2020 using primarily the modified retrospective approach. While the adoption of this guidance changed our process and methodology for determining credit losses and resulted in additional disclosures, these changes did not have a material impact on our financial statements. See Note 2 for allowance for doubtful accounts related credit loss disclosures.
v3.20.2
Changes in Accumulated Other Comprehensive Loss
 6 Months Ended
Jun. 30, 2020
Comprehensive Income (Loss), Net of Tax, Attributable to Parent [Abstract]  
Changes in Accumulated Other Comprehensive Loss Changes in Accumulated Other Comprehensive Loss
 
The following table shows the changes in Pinnacle West's consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component (dollars in thousands):
 
 Pension and Other Postretirement Benefits
 
 
 
 Derivative Instruments
 
 
 
 Total
Three Months Ended June 30
 
 
 
 
 
 
 
 
 
Balance March 31, 2020
$
(55,317
)
 
 
 
$
(262
)
 
 
 
$
(55,579
)
OCI (loss) before reclassifications
(2,008
)
 
 
 
(1,549
)
 
 
 
(3,557
)
Amounts reclassified from accumulated other comprehensive loss
999

 
 (a)
 
262

 
(b)
 
1,261

Balance June 30, 2020
$
(56,326
)
 
 
 
$
(1,549
)
 
 
 
$
(57,875
)


 
 
 

 
 
 

Balance March 31, 2019
$
(45,118
)
 
 
 
$
(1,383
)
 
 
 
$
(46,501
)
OCI (loss) before reclassifications
(2,422
)
 
 
 
—

 
 
 
(2,422
)
Amounts reclassified from accumulated other comprehensive loss
883

 
 (a)
 
404

 
(b)
 
1,287

Balance June 30, 2019
$
(46,657
)
 
 
 
$
(979
)
 
 
 
$
(47,636
)

 
Pension and Other Postretirement Benefits
 
 
 
Derivative Instruments
 
 
 
Total
Six Months Ended June 30
 
 
 
 
 
 
 
 
 
Balance December 31, 2019
$
(56,522
)
 
 
 
$
(574
)
 
 
 
$
(57,096
)
OCI (loss) before reclassifications
(2,008
)
 
 
 
(1,257
)
 
 
 
(3,265
)
Amounts reclassified from accumulated other comprehensive loss
2,204

 
(a)
 
282

 
(b)
 
2,486

Balance June 30, 2020
$
(56,326
)
 
 
 
$
(1,549
)
 
 
 
$
(57,875
)
 
 
 
 
 
 
 
 
 
 
Balance December 31, 2018
$
(45,997
)
 
 
 
$
(1,711
)
 
 
 
$
(47,708
)
OCI (loss) before reclassifications
(2,422
)
 
 
 
—

 
 
 
(2,422
)
Amounts reclassified from accumulated other comprehensive loss
1,762

 
(a)
 
732

 
(b)
 
2,494

Balance June 30, 2019
$
(46,657
)
 
 
 
$
(979
)
 
 
 
$
(47,636
)

(a)
These amounts primarily represent amortization of actuarial loss and are included in the computation of net periodic pension cost.  See Note 5.
(b)
These amounts primarily represent realized gains and losses and are included in the computation of fuel and purchased power costs and are subject to the PSA.  See Note 7.
The following table shows the changes in APS's consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the three and six months ended June 30, 2020 and 2019 (dollars in thousands): 
 
 Pension and Other Postretirement Benefits
 
 
 
 Derivative Instruments
 
 
 
 Total
Three Months Ended June 30
 
 
 
 
 
 
 
 
 
Balance March 31, 2020
$
(33,935
)
 
 
 
$
(262
)
 
 
 
$
(34,197
)
OCI (loss) before reclassifications
(1,951
)
 
 
 
—

 
 
 
(1,951
)
Amounts reclassified from accumulated other comprehensive loss
861

 
 (a)
 
262

 
 (b)
 
1,123

Balance June 30, 2020
$
(35,025
)
 
 
 
$
—

 
 
 
$
(35,025
)


 
 
 

 
 
 

Balance March 31, 2019
$
(24,644
)
 
 
 
$
(1,383
)
 
 
 
$
(26,027
)
OCI (loss) before reclassifications
(2,414
)
 
 
 
—

 
 
 
(2,414
)
Amounts reclassified from accumulated other comprehensive loss
761

 
 (a)
 
404

 
 (b)
 
1,165

Balance June 30, 2019
$
(26,297
)
 
 
 
$
(979
)
 
 
 
$
(27,276
)

 
 Pension and Other Postretirement Benefits
 
 
 
 Derivative Instruments
 
 
 
 Total
Six Months Ended June 30
 
 
 
 
 
 
 
 
 
Balance December 31, 2019
$
(34,948
)
 
 
 
$
(574
)
 
 
 
$
(35,522
)
OCI (loss) before reclassifications
(1,951
)
 
 
 
292

 
 
 
(1,659
)
Amounts reclassified from accumulated other comprehensive loss
1,874

 
(a)
 
282

 
 (b)
 
2,156

Balance June 30, 2020
$
(35,025
)
 
 
 
$
—

 
 
 
$
(35,025
)
 
 
 
 
 
 
 
 
 
 
Balance December 31, 2018
$
(25,396
)
 
 
 
$
(1,711
)
 
 
 
$
(27,107
)
OCI (loss) before reclassifications
(2,414
)
 
 
 
—

 
 
 
(2,414
)
Amounts reclassified from accumulated other comprehensive loss
1,513

 
(a)
 
732

 
 (b)
 
2,245

Balance June 30, 2019
$
(26,297
)
 
 
 
$
(979
)
 
 
 
$
(27,276
)

(a)
These amounts primarily represent amortization of actuarial loss and are included in the computation of net periodic pension cost.  See Note 5.
(b)
These amounts primarily represent realized gains and losses and are included in the computation of fuel and purchased power costs and are subject to the PSA.  See Note 7.
v3.20.2
Income Taxes
 6 Months Ended
Jun. 30, 2020
Income Tax Disclosure [Abstract]  
Income Taxes
Income Taxes
 
The Tax Act reduced the corporate tax rate to 21% effective January 1, 2018. As a result of this rate reduction, the Company recognized a $1.14 billion reduction in its net deferred income tax liabilities as of December 31, 2017. In accordance with accounting for regulated companies, the effect of this rate reduction was substantially offset by a net regulatory liability.

Federal income tax laws require the amortization of a majority of the balance over the remaining regulatory life of the related property. As a result of the modifications made to the annual transmission formula rate during the second quarter of 2018, the Company began amortization of FERC jurisdictional net excess deferred tax liabilities in 2018. On March 13, 2019, the ACC approved the Company's proposal to amortize non-depreciation related net excess deferred tax liabilities subject to its jurisdiction over a twelve-month period. As a result, the Company began amortization in March 2019. As of June 30, 2020, the Company has recorded $14 million of income tax benefit related to the amortization of these non-depreciation related net excess deferred tax liabilities. On October 29, 2019, the ACC approved the Company’s proposal to amortize depreciation related net excess deferred tax liabilities subject to its jurisdiction over a 28.5-year period with amortization to retroactively begin as of January 1, 2018. As of June 30, 2020, the Company has recorded $13.5 million of income tax benefit related to amortization of these depreciation related liabilities. See Note 4 for more details.
    
In August 2018, U.S. Treasury proposed regulations that clarified bonus depreciation transition rules under the Tax Act for regulated public utility property placed in service after September 27, 2017 and before January 1, 2018.  However, these proposed regulations were ambiguous with respect to regulated public utility property placed in service on or after January 1, 2018. In September 2019, U.S. Treasury issued final regulations, which replaced the August 2018 proposed regulations. These final regulations did not materially impact any tax position taken by the Company for property placed in service after September 27, 2017 and before January 1, 2018.

Along with the September 2019 final regulations, U.S. Treasury also issued new proposed regulations which clarify bonus depreciation transition rules under the Tax Act for property placed in service by regulated public utilities after December 31, 2017. The proposed regulations provide that certain regulated public utility property which was under construction prior to September 28, 2017 and placed in service between January 1, 2018 and December 31, 2020 would continue to be eligible for bonus depreciation under the rules and bonus depreciation phase-downs in effect prior to enactment of the Tax Act. 

Net income associated with the Palo Verde sale leaseback VIEs is not subject to tax.  As a result, there is no income tax expense associated with the VIEs recorded on the Pinnacle West Consolidated and APS Consolidated Statements of Income. See Note 6 for additional details related to the Palo Verde sale leaseback VIEs.

As of the balance sheet date, the tax year ended December 31, 2016 and all subsequent tax years remain subject to examination by the IRS.  With a few exceptions, the Company is no longer subject to state income tax examinations by tax authorities for years before 2015.
v3.20.2
Leases
 6 Months Ended
Jun. 30, 2020
Leases [Abstract]  
Leases
Leases
 
We lease certain land, buildings, vehicles, equipment and other property through operating rental agreements with varying terms, provisions, and expiration dates. APS also has certain purchased power
agreements that qualify as lease arrangements. Our leases have remaining terms that expire in 2020 through 2050. Substantially all of our leasing activities relate to APS.

In 1986, APS entered into agreements with three separate lessor trust entities in order to sell and lease back interests in Palo Verde Unit 2 and related common facilities.  These lessor trust entities have been deemed VIEs for which APS is the primary beneficiary.  As the primary beneficiary, APS consolidated these lessor trust entities.  The impacts of these sale leaseback transactions are excluded from our lease disclosures as lease accounting is eliminated upon consolidation.  See Note 6 for a discussion of VIEs.
On June 1, 2020 APS had two separate purchased power lease contracts that commenced. The lease terms end on September 30, 2025 and September 30, 2026, respectively. Both of these leases allow APS the right to the generation capacity from certain natural-gas fueled generators during the months of June through September over the contract term.  APS does not operate or maintain these leased assets. APS controls the dispatch of the leased assets during the months of June through September and is required to pay a fixed monthly capacity payment during these periods of use. For these types of leased assets APS has elected to combine both the lease and non-lease payment components and accounts for the entire fixed payment as a lease obligation. These purchased power lease contracts are accounted for as operating leases. The contracts do not contain purchase options or term extension options.  In addition to the fixed monthly capacity payment, APS must also pay variable charges based on the actual production volume of the asset. The variable consideration is not included in the measurement of our lease obligation.
The following tables provide information related to our lease costs (dollars in thousands):

 
 
Three Months Ended
June 30, 2020
 
Three Months Ended
June 30, 2019
 
 
Purchased Power Lease Contracts
 
Land, Property & Equipment Leases
 
Total
 
Purchased Power Lease Contracts
 
Land, Property & Equipment Leases
 
Total
Operating lease cost
 
$
17,221

 
$
4,651

 
$
21,872

 
$
14,063

 
$
4,414

 
$
18,477

Variable lease cost
 
40,821

 
255

 
41,076

 
41,529

 
360

 
41,889

Short-term lease cost
 
—

 
996

 
996

 
—

 
1,812

 
1,812

Total lease cost
 
$
58,042

 
$
5,902

 
$
63,944

 
$
55,592

 
$
6,586

 
$
62,178




 
 
Six Months Ended
June 30, 2020
 
Six Months Ended
June 30, 2019
 
 
Purchased Power Lease Contracts
 
Land, Property & Equipment Leases
 
Total
 
Purchased Power Lease Contracts
 
Land, Property & Equipment Leases
 
Total
Operating lease cost
 
$
17,221

 
$
9,304

 
$
26,525

 
$
14,063

 
$
8,762

 
$
22,825

Variable lease cost
 
61,394

 
498

 
61,892

 
58,820

 
360

 
59,180

Short-term lease cost
 
—

 
1,786

 
1,786

 
—

 
2,665

 
2,665

Total lease cost
 
$
78,615

 
$
11,588

 
$
90,203

 
$
72,883

 
$
11,787

 
$
84,670



Lease costs are primarily included as a component of operating expenses on our Condensed Consolidated Statements of Income.  Lease costs relating to purchased power lease contracts are recorded in fuel and purchased power on the Condensed Consolidated Statements of Income, and are subject to recovery under the PSA or RES (see Note 4).  The tables above reflect the lease cost amounts before the effect of regulatory deferral under the PSA and RES.  Variable lease costs are recognized in the period the costs are incurred, and primarily relate to renewable purchased power lease contracts.  Payments under most renewable purchased power lease contracts are dependent upon environmental factors, and due to the inherent uncertainty associated with the reliability of the fuel source, the payments are considered variable and are excluded from the measurement of lease liabilities and right-of-use lease assets. Certain of our lease agreements have lease terms with non-consecutive periods of use. For these agreements we recognize lease costs during the periods of use.  Leases with initial terms of 12 months or less are considered short-term leases and are not recorded on the balance sheet.
 
The following table provides information related to the maturity of our operating lease liabilities (dollars in thousands):
 
 
June 30, 2020
Year
 
Purchased Power Lease Contracts
 
Land, Property & Equipment Leases
 
Total
2020 (remaining six months of 2020)
 
$
59,555

 
$
7,817

 
$
67,372

2021
 
66,658

 
13,123

 
79,781

2022
 
68,325

 
9,495

 
77,820

2023
 
70,033

 
7,191

 
77,224

2024
 
71,784

 
4,945

 
76,729

2025
 
73,578

 
3,245

 
76,823

Thereafter
 
36,759

 
36,615

 
73,374

Total lease commitments
 
446,692

 
82,431

 
529,123

Less imputed interest
 
16,844

 
18,807

 
35,651

Total lease liabilities
 
$
429,848

 
$
63,624

 
$
493,472


 
We recognize lease assets and liabilities upon lease commencement. At June 30, 2020, we have additional lease arrangements that have been executed, but have not yet commenced. These arrangements primarily relate to purchased power lease contracts with lease commencement dates beginning in May 2021 with terms ending in October 2027. We expect the total fixed consideration paid for these arrangements, which includes both lease and nonlease payments, will approximate $258 million over the term of the arrangements.

The following tables provide other additional information related to operating lease liabilities:
 
June 30, 2020
 
December 31, 2019
Weighted average remaining lease term
7 years

 
13 years

Weighted average discount rate (a)
1.66
%
 
3.71
%


(a) Most of our lease agreements do not contain an implicit rate that is readily determinable. For these agreements we use our incremental borrowing rate to measure the present value of lease liabilities.  We determine our incremental borrowing rate at lease commencement based on the rate of interest that we would have to pay to borrow, on a collateralized basis over a similar term, an amount equal to the lease payments in a similar economic environment. We use the implicit rate when it is readily determinable.

 
Six Months Ended
June 30, 2020
 
Six Months Ended June 30, 2019
Cash paid for amounts included in the measurement of lease liabilities - operating cash flows (dollars in thousands):
$
7,624

 
$
11,987
v3.20.2
Asset Retirement Obligations
 6 Months Ended
Jun. 30, 2020
Asset Retirement Obligation Disclosure [Abstract]  
Asset Retirement Obligations Asset Retirement Obligations

In the first quarter of 2020, APS recognized an ARO for its share of corrective action and water monitoring costs at Four Corners and the Navajo Plant (see additional details in Notes 4 and 8), which resulted in a decrease to the ARO of $11 million for Four Corners and an increase to the ARO of $5 million for the Navajo Plant.

The following schedule shows the change in our asset retirement obligations for the six months ended June 30, 2020 (dollars in thousands): 

 
2020
Asset retirement obligations at January 1, 2020
$
657,218

Changes attributable to:
 

Accretion expense
20,410

Settlements
(4,324
)
Estimated cash flow revisions
(5,352
)
Asset retirement obligations at June 30, 2020
$
667,952



In accordance with regulatory accounting, APS accrues removal costs for its regulated utility assets, even if there is no legal obligation for removal.  See detail of regulatory liabilities in Note 4.
v3.20.2
New Accounting Standards (Policies)
 6 Months Ended
Jun. 30, 2020
Accounting Standards Update and Change in Accounting Principle [Abstract]  
New Accounting Standards

ASU 2016-13, Financial Instruments: Measurement of Credit Losses

In June 2016, a new accounting standard was issued that amends the measurement of credit losses on certain financial instruments. The new standard requires entities to use a current expected credit loss model to measure impairment of certain investments in debt securities, trade accounts receivables, and other financial instruments. Since the issuance of the new standard, various guidance has been issued that amends the new standard, including clarifications of certain aspects of the standard and targeted transition relief, among other changes. The new standard and related amendments were effective for us on January 1, 2020, and must be adopted using a modified retrospective approach for certain aspects of the standard, and a prospective approach for other aspects of the standard. We adopted the standard on January 1, 2020 using primarily the modified retrospective approach. While the adoption of this guidance changed our process and methodology for determining credit losses and resulted in additional disclosures, these changes did not have a material impact on our financial statements. See Note 2 for allowance for doubtful accounts related credit loss disclosures.
v3.20.2
Consolidation and Nature of Operations (Tables)
 6 Months Ended
Jun. 30, 2020
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,
 
2020
 
2019
Cash paid during the period for:
 
 
 
Income taxes, net of refunds
$
(3,028
)
 
$
10,788

Interest, net of amounts capitalized
107,417

 
114,717

Significant non-cash investing and financing activities:
 
 
 
Accrued capital expenditures
$
87,815

 
$
108,056

Right-of-use operating lease assets obtained in exchange for operating lease liabilities
434,997

 
4,562

Dividends accrued but not yet paid
88,066

 
82,824



The following table summarizes supplemental APS cash flow information (dollars in thousands):
 
Six Months Ended
June 30,
 
2020
 
2019
Cash paid during the period for:
 
 
 
Income taxes, net of refunds
$
—

 
$
35,573

Interest, net of amounts capitalized
100,991

 
107,169

Significant non-cash investing and financing activities:
 
 
 
Accrued capital expenditures
$
87,815

 
$
108,056

Right-of-use operating lease assets obtained in exchange for operating lease liabilities
434,997

 
4,562

Dividends accrued but not yet paid
88,000

 
82,800
v3.20.2
Revenue (Tables)
 6 Months Ended
Jun. 30, 2020
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,
 
 
2020
2019
 
2020
2019
Retail Electric Revenue
 
 
 
 
 
 
Residential
 
$
515,128

$
432,568

 
$
840,201

$
784,134

Non-Residential
 
381,121

395,929

 
684,472

728,597

Wholesale energy sales
 
15,927

21,991

 
30,595

58,443

Transmission services for others
 
14,766

15,157

 
30,693

30,406

Other sources
 
2,648

3,856

 
5,559

8,451

Total operating revenues
 
$
929,590

$
869,501

 
$
1,591,520

$
1,610,031
Schedule of Accounts Receivable
The following table provides a rollforward of Pinnacle West’s allowance for doubtful accounts (dollars in thousands):

 
 
June 30, 2020
 
December 31, 2019
Allowance for doubtful accounts, balance at beginning of period
 
$
8,171

 
$
4,069

Bad debt expense
 
9,197

 
11,819

Actual write-offs
 
(5,789
)
 
(7,717
)
Allowance for doubtful accounts, balance at end of period
 
$
11,579

 
$
8,171
v3.20.2
Long-Term Debt and Liquidity Matters (Tables)
 6 Months Ended
Jun. 30, 2020
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, 2020
 
As of December 31, 2019
 
Carrying
Amount
 
Fair Value
 
Carrying
Amount
 
Fair Value
Pinnacle West
$
496,610

 
$
507,850

 
$
449,425

 
$
450,822

APS
5,425,551

 
6,386,439

 
5,183,133

 
5,743,570

Total
$
5,922,161

 
$
6,894,289

 
$
5,632,558

 
$
6,194,392
v3.20.2
Regulatory Matters (Tables)
 6 Months Ended
Jun. 30, 2020
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 2020 and 2019 (dollars in thousands):
 
 
Six Months Ended
June 30,
 
2020
 
2019
Beginning balance
$
70,137

 
$
37,164

Deferred fuel and purchased power costs — current period
26,473

 
16,702

Amounts charged to customers
4,815

 
(23,307
)
Ending balance
$
101,425

 
$
30,559
Schedule of regulatory assets
The detail of regulatory assets is as follows (dollars in thousands): 
 
Amortization Through
 
June 30, 2020
 
December 31, 2019
 
 
Current
 
Non-Current
 
Current
 
Non-Current
Pension
(a)
 
$
—

 
$
663,327

 
$
—

 
$
660,223

Income taxes — allowance for funds used during construction ("AFUDC") equity
2050
 
6,815

 
156,528

 
6,800

 
154,974

Retired power plant costs
2033
 
28,182

 
128,304

 
28,182

 
142,503

Deferred fuel and purchased power (b) (c)
2021
 
101,425

 
—

 
70,137

 
—

Deferred fuel and purchased power — mark-to-market (Note 7)
2024
 
42,911

 
26,151

 
36,887

 
33,185

Ocotillo deferral
N/A
 
—

 
65,571

 
—

 
38,144

SCR deferral
N/A
 
—

 
64,971

 
—

 
52,644

Deferred property taxes
2027
 
8,569

 
53,911

 
8,569

 
58,196

Deferred compensation
2036
 
—

 
36,481

 
—

 
36,464

Four Corners cost deferral
2024
 
8,077

 
28,113

 
8,077

 
32,152

Lost fixed cost recovery (b)
2021
 
34,144

 
—

 
26,067

 
—

Income taxes — investment tax credit basis adjustment
2048
 
1,098

 
24,532

 
1,098

 
24,981

Palo Verde VIEs (Note 6)
2046
 
—

 
20,945

 
—

 
20,635

Coal reclamation
2026
 
1,068

 
17,533

 
1,546

 
17,688

Loss on reacquired debt
2038
 
1,637

 
11,241

 
1,637

 
12,031

TCA balancing account (b)
2022
 
8,272

 
2,926

 
6,324

 
2,885

Mead-Phoenix transmission line contributions in aid of construction ("CIAC")
2050
 
332

 
9,546

 
332

 
9,712

Tax expense of Medicare subsidy
2024
 
1,238

 
4,444

 
1,235

 
4,940

AG-1 deferral
2022
 
2,787

 
1,322

 
2,787

 
2,716

Tax expense adjuster mechanism (b)
2020
 
3,640

 
—

 
1,612

 
—

Other
Various
 
1,399

 
—

 
1,917

 
—

Total regulatory assets (d)
 
 
$
251,594

 
$
1,315,846

 
$
203,207

 
$
1,304,073


(a)
This asset represents the future recovery of pension benefit obligations through retail rates.  If these costs are disallowed by the ACC, this regulatory asset would be charged to other comprehensive income ("OCI") and result in lower future revenues.
(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."
Schedule of regulatory liabilities
The detail of regulatory liabilities is as follows (dollars in thousands):
 
 
Amortization Through
 
June 30, 2020
 
December 31, 2019
 
 
Current
 
Non-Current
 
Current
 
Non-Current
Excess deferred income taxes - ACC - Tax Cuts and Jobs Act (a)
2046
 
$
113,168

 
$
966,576

 
$
59,918

 
$
1,054,053

Excess deferred income taxes - FERC - Tax Cuts and Jobs Act (a)
2058
 
7,256

 
233,953

 
6,302

 
237,357

Asset retirement obligations
2057
 
—

 
408,126

 
—

 
418,423

Removal costs
(c)
 
47,300

 
126,036

 
47,356

 
136,072

Other postretirement benefits
(d)
 
37,575

 
118,398

 
37,575

 
139,634

Four Corners coal reclamation
2038
 
5,461

 
48,795

 
1,059

 
51,704

Spent nuclear fuel
2027
 
6,068

 
47,901

 
6,676

 
51,019

Income taxes — change in rates
2050
 
2,802

 
50,163

 
2,797

 
68,265

Income taxes — deferred investment tax credit
2048
 
2,202

 
49,133

 
2,202

 
50,034

Renewable energy standard (b)
2021
 
38,934

 
22

 
39,287

 
10,300

Sundance maintenance
2031
 
1,100

 
13,001

 
5,698

 
11,319

Demand side management (b)
2021
 
3,068

 
6,138

 
15,024

 
24,146

Property tax deferral
N/A
 
—

 
8,603

 
—

 
7,046

FERC transmission true up
2022
 
5,452

 
2,209

 
1,045

 
2,004

Active union medical trust
N/A
 
—

 
7,629

 
—

 
2,041

Tax expense adjustor mechanism (b)
2020
 
6,450

 
—

 
7,018

 
—

Deferred gains on utility property
2022
 
2,423

 
2,973

 
2,423

 
4,163

Other
Various
 
220

 
331

 
532

 
255

Total regulatory liabilities
 
 
$
279,479

 
$
2,089,987

 
$
234,912

 
$
2,267,835


(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.
v3.20.2
Retirement Plans and Other Postretirement Benefits (Tables)
 6 Months Ended
Jun. 30, 2020
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 Benefits
 
Other Benefits
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
2020
 
2019
 
2020
 
2019
 
2020
 
2019
 
2020
 
2019
Service cost — benefits earned during the period
$
13,859

 
$
12,408

 
$
28,116

 
$
24,951

 
$
5,401

 
$
4,470

 
$
11,118

 
$
9,184

Non-service costs (credits):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Interest cost on benefit obligation
29,522

 
34,069

 
59,283

 
68,421

 
6,417

 
7,421

 
12,929

 
14,947

Expected return on plan assets
(46,915
)
 
(43,049
)
 
(93,721
)
 
(85,942
)
 
(10,019
)
 
(9,603
)
 
(20,038
)
 
(19,206
)
  Amortization of:
 

 
 
 
 

 
 

 
 

 
 

 
 

 
 

  Prior service credit
—

 
—

 
—

 
—

 
(9,394
)
 
(9,455
)
 
(18,788
)
 
(18,910
)
  Net actuarial loss
8,295

 
10,053

 
17,306

 
21,292

 
—

 
—

 
—

 
—

Net periodic benefit cost (credit)
$
4,761

 
$
13,481

 
$
10,984

 
$
28,722

 
$
(7,595
)
 
$
(7,167
)
 
$
(14,779
)
 
$
(13,985
)
Portion of cost (credit) charged to expense
$
271

 
$
7,000

 
$
1,613

 
$
15,244

 
$
(5,056
)
 
$
(5,063
)
 
$
(10,512
)
 
$
(9,880
)
v3.20.2
Palo Verde Sale Leaseback Variable Interest Entities (Tables)
 6 Months Ended
Jun. 30, 2020
Variable Interest Entities [Abstract]  
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets

Our Condensed Consolidated Balance Sheets at June 30, 2020 and December 31, 2019 include the following amounts relating to the VIEs (dollars in thousands):
 
 
June 30, 2020
 
December 31, 2019
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation
$
99,971

 
$
101,906

Equity — Noncontrolling interests
120,915

 
122,540
v3.20.2
Derivative Accounting (Tables)
 6 Months Ended
Jun. 30, 2020
Derivative Instruments and Hedging Activities Disclosure [Abstract]  
Outstanding gross notional amount of derivatives, which represents both purchases and sales (does not reflect net position)
As of June 30, 2020 and December 31, 2019, we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position): 
 
 
 
Quantity
Commodity
 
Unit of Measure
June 30, 2020
 
December 31, 2019
Power
 
GWh
294

 
193

Gas
 
Billion cubic feet
249

 
257
Gains and losses from derivative instruments in designated cash flow accounting hedges relationships
The following table provides information about gains and losses from derivative instruments in designated cash flow accounting hedging relationships during the three and six months ended June 30, 2020 and 2019 (dollars in thousands):
 
 
 
Financial Statement Location
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
Commodity Contracts
 
 
2020
 
2019
 
2020
 
2019
Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a)
 
Fuel and purchased power (b)
 
$
(349
)
 
$
(538
)
 
$
(763
)
 
$
(974
)

(a)
During the three and six months ended June 30, 2020 and 2019, we had no gains or losses reclassified from accumulated OCI to earnings related to discontinued cash flow hedges.
(b)
Amounts are before the effect of PSA deferrals.
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 during the three and six months ended June 30, 2020 and 2019 (dollars in thousands):
 
 
 
Financial Statement Location
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
Commodity Contracts
 
 
2020
 
2019
 
2020
 
2019
Net Loss Recognized in Income
 
Fuel and purchased power (a)
 
$
(4,894
)
 
$
(49,686
)
 
$
(34,971
)
 
$
(41,516
)

(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 as of June 30, 2020 and December 31, 2019.  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, 2020:
(dollars in thousands)
 
Gross
 Recognized
 Derivatives
 (a)
 
Amounts
Offset
 (b)
 
Net
 Recognized
 Derivatives
 
Other
 (c)
 
Amount Reported on Balance Sheets
Current assets
 
$
2,989

 
$
(2,279
)
 
$
710

 
$
—

 
$
710

Investments and other assets
 
540

 
(510
)
 
30

 
—

 
30

Total assets
 
3,529

 
(2,789
)
 
740

 
—

 
740

 
 
 
 
 
 
 
 
 
 
 
Current liabilities
 
(45,899
)
 
2,279

 
(43,620
)
 
(1,185
)
 
(44,805
)
Deferred credits and other
 
(26,691
)
 
510

 
(26,181
)
 
—

 
(26,181
)
Total liabilities
 
(72,590
)
 
2,789

 
(69,801
)
 
(1,185
)
 
(70,986
)
Total
 
$
(69,061
)
 
$
—

 
$
(69,061
)
 
$
(1,185
)
 
$
(70,246
)

(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 $1,185 and cash margin provided to counterparties of $0.

As of December 31, 2019:
(dollars in thousands)
 
Gross
Recognized
Derivatives
 (a)
 
Amounts
Offset
(b)
 
Net
 Recognized
 Derivatives
 
Other
 (c)
 
Amount
Reported on
Balance Sheets
Current assets
 
$
584

 
$
(474
)
 
$
110

 
$
405

 
$
515

 
 
 
 
 
 
 
 
 
 
 
Current liabilities
 
(38,235
)
 
474

 
(37,761
)
 
(1,185
)
 
(38,946
)
Deferred credits and other
 
(33,186
)
 
—

 
(33,186
)
 
—

 
(33,186
)
Total liabilities
 
(71,421
)
 
474

 
(70,947
)
 
(1,185
)
 
(72,132
)
Total
 
$
(70,837
)
 
$
—

 
$
(70,837
)
 
$
(780
)
 
$
(71,617
)

(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 $1,185 and cash margin provided to counterparties of $405.
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 as of June 30, 2020 and December 31, 2019.  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, 2020:
(dollars in thousands)
 
Gross
 Recognized
 Derivatives
 (a)
 
Amounts
Offset
 (b)
 
Net
 Recognized
 Derivatives
 
Other
 (c)
 
Amount Reported on Balance Sheets
Current assets
 
$
2,989

 
$
(2,279
)
 
$
710

 
$
—

 
$
710

Investments and other assets
 
540

 
(510
)
 
30

 
—

 
30

Total assets
 
3,529

 
(2,789
)
 
740

 
—

 
740

 
 
 
 
 
 
 
 
 
 
 
Current liabilities
 
(45,899
)
 
2,279

 
(43,620
)
 
(1,185
)
 
(44,805
)
Deferred credits and other
 
(26,691
)
 
510

 
(26,181
)
 
—

 
(26,181
)
Total liabilities
 
(72,590
)
 
2,789

 
(69,801
)
 
(1,185
)
 
(70,986
)
Total
 
$
(69,061
)
 
$
—

 
$
(69,061
)
 
$
(1,185
)
 
$
(70,246
)

(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 $1,185 and cash margin provided to counterparties of $0.

As of December 31, 2019:
(dollars in thousands)
 
Gross
Recognized
Derivatives
 (a)
 
Amounts
Offset
(b)
 
Net
 Recognized
 Derivatives
 
Other
 (c)
 
Amount
Reported on
Balance Sheets
Current assets
 
$
584

 
$
(474
)
 
$
110

 
$
405

 
$
515

 
 
 
 
 
 
 
 
 
 
 
Current liabilities
 
(38,235
)
 
474

 
(37,761
)
 
(1,185
)
 
(38,946
)
Deferred credits and other
 
(33,186
)
 
—

 
(33,186
)
 
—

 
(33,186
)
Total liabilities
 
(71,421
)
 
474

 
(70,947
)
 
(1,185
)
 
(72,132
)
Total
 
$
(70,837
)
 
$
—

 
$
(70,837
)
 
$
(780
)
 
$
(71,617
)

(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 $1,185 and cash margin provided to counterparties of $405.
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 at June 30, 2020 (dollars in thousands):
 
June 30, 2020
Aggregate fair value of derivative instruments in a net liability position
$
72,590

Cash collateral posted
—

Additional cash collateral in the event credit-risk-related contingent features were fully triggered (a)
63,880


(a)
This amount is after counterparty netting and includes those contracts which qualify for scope exceptions, which are excluded from the derivative details above.
v3.20.2
Other Income and Other Expense (Tables)
 6 Months Ended
Jun. 30, 2020
Other Income and Expenses [Abstract]  
Detail 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,
 
2020
 
2019
 
2020
 
2019
Other income:
 

 
 

 
 

 
 

Interest income
$
2,755

 
$
2,699

 
$
6,032

 
$
5,001

Investment gains (losses) - net
2,826

 
—

 
2,826

 
—

Debt return on Four Corners SCR deferrals (Note 4)
4,249


4,887

 
7,389

 
9,731

Debt return on Ocotillo modernization project (Note 4)
6,703

 
5,294

 
12,847

 
5,294

Miscellaneous
137

 
5

 
145

 
28

Total other income
$
16,670

 
$
12,885

 
$
29,239

 
$
20,054

Other expense:
 

 
 

 
 

 
 

Non-operating costs
$
(2,290
)
 
$
(3,481
)
 
$
(4,948
)
 
$
(6,185
)
Investment gains (losses) — net
—

 
(491
)
 
60

 
(729
)
Miscellaneous
(1,746
)
 
(378
)
 
(3,932
)
 
(1,794
)
Total other expense
$
(4,036
)
 
$
(4,350
)
 
$
(8,820
)
 
$
(8,708
)

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,
 
2020
 
2019
 
2020
 
2019
Other income:
 

 
 

 
 

 
 

Interest income
$
2,183

 
$
1,504

 
$
4,524

 
$
3,054

Debt return on Four Corners SCR deferrals (Note 4)
4,249

 
4,887

 
7,389


9,731

Debt return on Ocotillo modernization project (Note 4)
6,703

 
5,294

 
12,847

 
5,294

Miscellaneous
137

 
6

 
145

 
28

Total other income
$
13,272

 
$
11,691

 
$
24,905

 
$
18,107

Other expense:
 

 
 

 
 

 
 

Non-operating costs
$
(2,113
)
 
$
(3,049
)
 
$
(4,595
)
 
$
(5,517
)
Miscellaneous
(1,746
)
 
(379
)
 
(3,932
)
 
(1,789
)
Total other expense
$
(3,859
)
 
$
(3,428
)
 
$
(8,527
)
 
$
(7,306
)
v3.20.2
Earnings Per Share (Tables)
 6 Months Ended
Jun. 30, 2020
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,
 
2020
 
2019
 
2020
 
2019
Net income attributable to common shareholders
$
193,585

 
$
144,145

 
$
223,578

 
$
162,063

Weighted average common shares outstanding — basic
112,638

 
112,337

 
112,616

 
112,381

Net effect of dilutive securities:
 
 
 
 
 
 
 
Contingently issuable performance shares and restricted stock units
241

 
314

 
255

 
353

Weighted average common shares outstanding — diluted
112,879

 
112,651

 
112,871

 
112,734

Earnings per weighted-average common share outstanding
 
 
 
 
 
 
 
Net income attributable to common shareholders — basic
$
1.72

 
$
1.28

 
$
1.99

 
$
1.44

Net income attributable to common shareholders — diluted
$
1.71

 
$
1.28

 
$
1.98

 
$
1.44
v3.20.2
Fair Value Measurements (Tables)
 6 Months Ended
Jun. 30, 2020
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, 2020 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
 
 
Total
Assets
 

 
 

 
 

 
 

 
 
 
 

Risk management activities — derivative instruments:
 
 
 
 
 
 
 
 
 
 
 
Commodity contracts
$
—

 
$
3,165

 
$
365

 
$
(2,790
)
 
(a)
 
$
740

Nuclear decommissioning trust:
 
 
 
 
 
 
 
 
 
 
 
Equity securities
15,985

 
—

 
—

 
(6,130
)
 
(b)
 
9,855

U.S. commingled equity funds
—

 
—

 
—

 
502,251

 
(c)
 
502,251

U.S. Treasury debt
143,673

 
—

 
—

 
—

 
 
 
143,673

Corporate debt
—

 
149,672

 
—

 
—

 
 
 
149,672

Mortgage-backed securities
—

 
99,407

 
—

 
—

 
 
 
99,407

Municipal bonds
—

 
106,971

 
—

 
—

 
 
 
106,971

Other fixed income
—

 
12,204

 
—

 
—

 
 
 
12,204

Subtotal nuclear decommissioning trust
159,658

 
368,254

 
—

 
496,121

 
 
 
1,024,033

 
 
 
 
 
 
 
 
 
 
 
 
Other special use funds:
 
 
 
 
 
 
 
 
 
 
 
Equity securities
8,955

 
—

 
—

 
526

 
(b)
 
9,481

U.S. Treasury debt
229,858

 
—

 
—

 
—

 

 
229,858

Municipal bonds
—

 
13,993

 
—

 
—

 
 
 
13,993

Subtotal other special use funds
238,813

 
13,993

 
—

 
526

 
 
 
253,332

 
 
 
 
 
 
 
 
 
 
 
 
Total assets
$
398,471

 
$
385,412

 
$
365

 
$
493,857

 
 
 
$
1,278,105

Liabilities
 

 
 

 
 

 
 

 
 
 
 

Risk management activities — derivative instruments:
 

 
 

 
 

 
 

 
 
 
 

Commodity contracts
$
—

 
$
(61,974
)
 
$
(10,617
)
 
$
1,605

 
(a)
 
$
(70,986
)

(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, 2019 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
 
 
Total
Assets
 

 
 

 
 

 
 

 
 
 
 

Risk management activities — derivative instruments:
 
 
 
 
 
 
 
 
 
 
 
Commodity contracts
$
—

 
$
551

 
$
33

 
$
(69
)
 
(a)
 
$
515

Nuclear decommissioning trust:
 

 
 

 
 

 
 

 
 
 
 

Equity securities
10,872

 
—

 
—

 
2,401

 
(b)
 
13,273

U.S. commingled equity funds
—

 
—

 
—

 
518,844

 
(c)
 
518,844

U.S. Treasury debt
160,607

 
—

 
—

 
—

 
 
 
160,607

Corporate debt
—

 
115,869

 
—

 
—

 
 
 
115,869

Mortgage-backed securities
—

 
118,795

 
—

 
—

 
 
 
118,795

Municipal bonds
—

 
73,040

 
—

 
—

 
 
 
73,040

Other fixed income
—

 
10,347

 
—

 
—

 
 
 
10,347

Subtotal nuclear decommissioning trust
171,479

 
318,051

 
—

 
521,245

 
 
 
1,010,775

 
 
 
 
 
 
 
 
 
 
 
 
Other special use funds:
 
 
 
 
 
 
 
 
 
 
 
Equity securities
7,142

 
—

 
—

 
474

 
(b)
 
7,616

U.S. Treasury debt
232,848

 
—

 
—

 
—

 
 
 
232,848

Municipal bonds
—

 
4,631

 
—

 
—

 
 
 
4,631

Subtotal other special use funds
239,990

 
4,631

 
—

 
474

 
 
 
245,095

 
 
 
 
 
 
 
 
 
 
 
 
Total assets
$
411,469

 
$
323,233

 
$
33

 
$
521,650

 
 
 
$
1,256,385

Liabilities
 

 
 

 
 

 
 

 
 
 
 

Risk management activities — derivative instruments:
 

 
 

 
 

 
 

 
 
 
 

Commodity contracts
$
—

 
$
(67,992
)
 
$
(3,429
)
 
$
(711
)
 
(a)
 
$
(72,132
)

(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.
v3.20.2
Investments in Nuclear Decommissioning Trusts and Other Special Use Funds (Tables)
 6 Months Ended
Jun. 30, 2020
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, 2020
 
Fair Value
 
Total
Unrealized
Gains
 
Total
Unrealized
Losses
Investment Type:
Nuclear Decommissioning Trusts
 
Other Special Use Funds
 
Total
 
 
Equity securities
$
518,236

 
$
8,955

 
$
527,191

 
$
316,494

 
$
(58
)
Available for sale-fixed income securities
511,927

 
243,851

 
755,778

(a)
49,693

 
(524
)
Other
(6,130
)
 
526

 
(5,604
)
(b)
—

 
—

Total
$
1,024,033

 
$
253,332

 
$
1,277,365

 
$
366,187

 
$
(582
)

(a)
As of June 30, 2020, the amortized cost basis of these available-for-sale investments is $707 million.
(b)
Represents net pending securities sales and purchases.

 
December 31, 2019
 
Fair Value
 
Total
Unrealized
Gains
 
Total
Unrealized
Losses
Investment Type:
Nuclear Decommissioning Trusts
 
Other Special Use Funds
 
Total
 
 
Equity securities
$
529,716

 
$
7,142

 
$
536,858

 
$
337,681

 
$
—

Available for sale-fixed income securities
478,658

 
237,479

 
716,137

(a)
25,795

 
(669
)
Other
2,401

 
474

 
2,875

(b)
—

 
—

Total
$
1,010,775

 
$
245,095

 
$
1,255,870

 
$
363,476

 
$
(669
)

(a)
As of December 31, 2019, the amortized cost basis of these available-for-sale investments is $691 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 table sets forth APS's realized gains and losses relating to the sale and maturity of available-for-sale debt securities and equity securities, and the proceeds from the sale and maturity of these investment securities (dollars in thousands):
 
Three Months Ended June 30,
 
Nuclear Decommissioning Trusts
 
Other Special Use Funds
 
Total
2020
 
 
 
 
 
Realized gains
$
4,500

 
$
—

 
$
4,500

Realized losses
(1,621
)
 
—

 
(1,621
)
Proceeds from the sale of securities (a)
176,942

 
19,830

 
196,772

2019
 
 
 
 
 
Realized gains
$
2,643

 
$
—

 
$
2,643

Realized losses
(1,700
)
 
—

 
(1,700
)
Proceeds from the sale of securities (a)
93,559

 
36,747

 
130,306


(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 Trusts
 
Other Special Use Funds
 
Total
2020
 
 
 
 
 
Realized gains
$
7,813

 
$
—

 
$
7,813

Realized losses
(3,848
)
 
—

 
(3,848
)
Proceeds from the sale of securities (a)
355,138

 
36,721

 
391,859

2019
 
 
 
 
 
Realized gains
$
3,746

 
$
—

 
$
3,746

Realized losses
(3,105
)
 
—

 
(3,105
)
Proceeds from the sale of securities (a)
216,152

 
93,202

 
309,354


(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, 2020, is as follows (dollars in thousands):
 
Nuclear Decommissioning Trust
 
Coal Mine Reclamation Escrow Account
 
Active Union Employee Medical Account
 
Total
Less than one year
$
21,767

 
$
37,494

 
$
40,673

 
$
99,934

1 year – 5 years
137,754

 
11,371

 
143,406

 
292,531

5 years – 10 years
125,807

 
1,904

 
—

 
127,711

Greater than 10 years
226,599

 
9,003

 
—

 
235,602

Total
$
511,927

 
$
59,772

 
$
184,079

 
$
755,778
v3.20.2
Changes in Accumulated Other Comprehensive Loss (Tables)
 6 Months Ended
Jun. 30, 2020
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 table shows the changes in Pinnacle West's consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component (dollars in thousands):
 
 Pension and Other Postretirement Benefits
 
 
 
 Derivative Instruments
 
 
 
 Total
Three Months Ended June 30
 
 
 
 
 
 
 
 
 
Balance March 31, 2020
$
(55,317
)
 
 
 
$
(262
)
 
 
 
$
(55,579
)
OCI (loss) before reclassifications
(2,008
)
 
 
 
(1,549
)
 
 
 
(3,557
)
Amounts reclassified from accumulated other comprehensive loss
999

 
 (a)
 
262

 
(b)
 
1,261

Balance June 30, 2020
$
(56,326
)
 
 
 
$
(1,549
)
 
 
 
$
(57,875
)


 
 
 

 
 
 

Balance March 31, 2019
$
(45,118
)
 
 
 
$
(1,383
)
 
 
 
$
(46,501
)
OCI (loss) before reclassifications
(2,422
)
 
 
 
—

 
 
 
(2,422
)
Amounts reclassified from accumulated other comprehensive loss
883

 
 (a)
 
404

 
(b)
 
1,287

Balance June 30, 2019
$
(46,657
)
 
 
 
$
(979
)
 
 
 
$
(47,636
)

 
Pension and Other Postretirement Benefits
 
 
 
Derivative Instruments
 
 
 
Total
Six Months Ended June 30
 
 
 
 
 
 
 
 
 
Balance December 31, 2019
$
(56,522
)
 
 
 
$
(574
)
 
 
 
$
(57,096
)
OCI (loss) before reclassifications
(2,008
)
 
 
 
(1,257
)
 
 
 
(3,265
)
Amounts reclassified from accumulated other comprehensive loss
2,204

 
(a)
 
282

 
(b)
 
2,486

Balance June 30, 2020
$
(56,326
)
 
 
 
$
(1,549
)
 
 
 
$
(57,875
)
 
 
 
 
 
 
 
 
 
 
Balance December 31, 2018
$
(45,997
)
 
 
 
$
(1,711
)
 
 
 
$
(47,708
)
OCI (loss) before reclassifications
(2,422
)
 
 
 
—

 
 
 
(2,422
)
Amounts reclassified from accumulated other comprehensive loss
1,762

 
(a)
 
732

 
(b)
 
2,494

Balance June 30, 2019
$
(46,657
)
 
 
 
$
(979
)
 
 
 
$
(47,636
)

(a)
These amounts primarily represent amortization of actuarial loss and are included in the computation of net periodic pension cost.  See Note 5.
(b)
These amounts primarily represent realized gains and losses and are included in the computation of fuel and purchased power costs and are subject to the PSA.  See Note 7.
The following table shows the changes in APS's consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the three and six months ended June 30, 2020 and 2019 (dollars in thousands): 
 
 Pension and Other Postretirement Benefits
 
 
 
 Derivative Instruments
 
 
 
 Total
Three Months Ended June 30
 
 
 
 
 
 
 
 
 
Balance March 31, 2020
$
(33,935
)
 
 
 
$
(262
)
 
 
 
$
(34,197
)
OCI (loss) before reclassifications
(1,951
)
 
 
 
—

 
 
 
(1,951
)
Amounts reclassified from accumulated other comprehensive loss
861

 
 (a)
 
262

 
 (b)
 
1,123

Balance June 30, 2020
$
(35,025
)
 
 
 
$
—

 
 
 
$
(35,025
)


 
 
 

 
 
 

Balance March 31, 2019
$
(24,644
)
 
 
 
$
(1,383
)
 
 
 
$
(26,027
)
OCI (loss) before reclassifications
(2,414
)
 
 
 
—

 
 
 
(2,414
)
Amounts reclassified from accumulated other comprehensive loss
761

 
 (a)
 
404

 
 (b)
 
1,165

Balance June 30, 2019
$
(26,297
)
 
 
 
$
(979
)
 
 
 
$
(27,276
)

 
 Pension and Other Postretirement Benefits
 
 
 
 Derivative Instruments
 
 
 
 Total
Six Months Ended June 30
 
 
 
 
 
 
 
 
 
Balance December 31, 2019
$
(34,948
)
 
 
 
$
(574
)
 
 
 
$
(35,522
)
OCI (loss) before reclassifications
(1,951
)
 
 
 
292

 
 
 
(1,659
)
Amounts reclassified from accumulated other comprehensive loss
1,874

 
(a)
 
282

 
 (b)
 
2,156

Balance June 30, 2020
$
(35,025
)
 
 
 
$
—

 
 
 
$
(35,025
)
 
 
 
 
 
 
 
 
 
 
Balance December 31, 2018
$
(25,396
)
 
 
 
$
(1,711
)
 
 
 
$
(27,107
)
OCI (loss) before reclassifications
(2,414
)
 
 
 
—

 
 
 
(2,414
)
Amounts reclassified from accumulated other comprehensive loss
1,513

 
(a)
 
732

 
 (b)
 
2,245

Balance June 30, 2019
$
(26,297
)
 
 
 
$
(979
)
 
 
 
$
(27,276
)

(a)
These amounts primarily represent amortization of actuarial loss and are included in the computation of net periodic pension cost.  See Note 5.
(b)
These amounts primarily represent realized gains and losses and are included in the computation of fuel and purchased power costs and are subject to the PSA.  See Note 7.
v3.20.2
Leases (Tables)
 6 Months Ended
Jun. 30, 2020
Leases [Abstract]  
Lease cost
The following tables provide information related to our lease costs (dollars in thousands):

 
 
Three Months Ended
June 30, 2020
 
Three Months Ended
June 30, 2019
 
 
Purchased Power Lease Contracts
 
Land, Property & Equipment Leases
 
Total
 
Purchased Power Lease Contracts
 
Land, Property & Equipment Leases
 
Total
Operating lease cost
 
$
17,221

 
$
4,651

 
$
21,872

 
$
14,063

 
$
4,414

 
$
18,477

Variable lease cost
 
40,821

 
255

 
41,076

 
41,529

 
360

 
41,889

Short-term lease cost
 
—

 
996

 
996

 
—

 
1,812

 
1,812

Total lease cost
 
$
58,042

 
$
5,902

 
$
63,944

 
$
55,592

 
$
6,586

 
$
62,178




 
 
Six Months Ended
June 30, 2020
 
Six Months Ended
June 30, 2019
 
 
Purchased Power Lease Contracts
 
Land, Property & Equipment Leases
 
Total
 
Purchased Power Lease Contracts
 
Land, Property & Equipment Leases
 
Total
Operating lease cost
 
$
17,221

 
$
9,304

 
$
26,525

 
$
14,063

 
$
8,762

 
$
22,825

Variable lease cost
 
61,394

 
498

 
61,892

 
58,820

 
360

 
59,180

Short-term lease cost
 
—

 
1,786

 
1,786

 
—

 
2,665

 
2,665

Total lease cost
 
$
78,615

 
$
11,588

 
$
90,203

 
$
72,883

 
$
11,787

 
$
84,670
Schedule of future minimum payments
The following tables provide other additional information related to operating lease liabilities:
 
June 30, 2020
 
December 31, 2019
Weighted average remaining lease term
7 years

 
13 years

Weighted average discount rate (a)
1.66
%
 
3.71
%


(a) Most of our lease agreements do not contain an implicit rate that is readily determinable. For these agreements we use our incremental borrowing rate to measure the present value of lease liabilities.  We determine our incremental borrowing rate at lease commencement based on the rate of interest that we would have to pay to borrow, on a collateralized basis over a similar term, an amount equal to the lease payments in a similar economic environment. We use the implicit rate when it is readily determinable.
The following table provides information related to the maturity of our operating lease liabilities (dollars in thousands):
 
 
June 30, 2020
Year
 
Purchased Power Lease Contracts
 
Land, Property & Equipment Leases
 
Total
2020 (remaining six months of 2020)
 
$
59,555

 
$
7,817

 
$
67,372

2021
 
66,658

 
13,123

 
79,781

2022
 
68,325

 
9,495

 
77,820

2023
 
70,033

 
7,191

 
77,224

2024
 
71,784

 
4,945

 
76,729

2025
 
73,578

 
3,245

 
76,823

Thereafter
 
36,759

 
36,615

 
73,374

Total lease commitments
 
446,692

 
82,431

 
529,123

Less imputed interest
 
16,844

 
18,807

 
35,651

Total lease liabilities
 
$
429,848

 
$
63,624

 
$
493,472


 
Six Months Ended
June 30, 2020
 
Six Months Ended June 30, 2019
Cash paid for amounts included in the measurement of lease liabilities - operating cash flows (dollars in thousands):
$
7,624

 
$
11,987
v3.20.2
Asset Retirement Obligations (Tables)
 6 Months Ended
Jun. 30, 2020
Asset Retirement Obligation Disclosure [Abstract]  
Change in asset retirement obligations

The following schedule shows the change in our asset retirement obligations for the six months ended June 30, 2020 (dollars in thousands): 

 
2020
Asset retirement obligations at January 1, 2020
$
657,218

Changes attributable to:
 

Accretion expense
20,410

Settlements
(4,324
)
Estimated cash flow revisions
(5,352
)
Asset retirement obligations at June 30, 2020
$
667,952
v3.20.2
Consolidation and Nature of Operations (Details) - USD ($)
$ in Thousands
 6 Months Ended
Jun. 30, 2020
Jun. 30, 2019
Cash paid during the period for:    
Income taxes, net of refunds $ (3,028) $ 10,788
Interest, net of amounts capitalized 107,417 114,717
Significant non-cash investing and financing activities:    
Accrued capital expenditures 87,815 108,056
Right-of-use operating lease assets obtained in exchange for operating lease liabilities 434,997 4,562
Dividends accrued but not yet paid 88,066 82,824
APS    
Cash paid during the period for:    
Income taxes, net of refunds 0 35,573
Interest, net of amounts capitalized 100,991 107,169
Significant non-cash investing and financing activities:    
Accrued capital expenditures 87,815 108,056
Right-of-use operating lease assets obtained in exchange for operating lease liabilities 434,997 4,562
Dividends accrued but not yet paid $ 88,000 $ 82,800
v3.20.2
Revenue (Details) - USD ($)
$ in Thousands
 3 Months Ended 6 Months Ended
Jun. 30, 2020
Jun. 30, 2019
Jun. 30, 2020
Jun. 30, 2019
Disaggregation of Revenue [Line Items]        
Operating revenues $ 929,590 $ 869,501 $ 1,591,520 $ 1,610,031
Regulatory cost recovery revenue 15,000 12,000 29,000 32,000
Electric Service | Residential        
Disaggregation of Revenue [Line Items]        
Operating revenues 515,128 432,568 840,201 784,134
Electric Service | Non-Residential        
Disaggregation of Revenue [Line Items]        
Operating revenues 381,121 395,929 684,472 728,597
Electric Service | Wholesale energy sales        
Disaggregation of Revenue [Line Items]        
Operating revenues 15,927 21,991 30,595 58,443
Transmission services for others        
Disaggregation of Revenue [Line Items]        
Operating revenues 14,766 15,157 30,693 30,406
Other sources        
Disaggregation of Revenue [Line Items]        
Operating revenues 2,648 3,856 5,559 8,451
Electric and Transmission Service        
Disaggregation of Revenue [Line Items]        
Operating revenues $ 915,000 $ 858,000 $ 1,563,000 $ 1,578,000
v3.20.2
Revenue Allowance for Doubtful Accounts (Details) - USD ($)
$ in Thousands
 6 Months Ended 12 Months Ended
Jun. 30, 2020
Dec. 31, 2019
Jun. 30, 2020
Accounts Receivable, Allowance for Credit Loss [Roll Forward]      
Allowance for doubtful accounts, balance at beginning of period $ 8,171 $ 4,069  
Bad debt expense 9,197 11,819  
Actual write-offs (5,789) (7,717)  
Allowance for doubtful accounts, balance at end of period $ 8,171 $ 4,069 $ 11,579
v3.20.2
Long-Term Debt and Liquidity Matters - Narrative (Details)
 6 Months Ended
Jun. 17, 2020
USD ($)
May 22, 2020
USD ($)
Jan. 15, 2020
USD ($)
Jun. 30, 2020
USD ($)
Facility
Jun. 30, 2019
USD ($)
Jun. 16, 2020
USD ($)
May 05, 2020
USD ($)
May 04, 2020
USD ($)
Mar. 26, 2020
USD ($)
Nov. 27, 2018
USD ($)
Long-Term Debt and Liquidity Matters                    
Percentage of capitalization                   7.00%
Capacity available for trade purchases                   $ 500,000,000
Repayment of long-term debt       $ 800,000,000 $ 500,000,000          
Long-term debt limit       7,500,000,000            
Senior Unsecured Notes                    
Long-Term Debt and Liquidity Matters                    
Debt instrument, interest rate 1.30%         2.25%        
Senior Unsecured Notes | Senior notes                    
Long-Term Debt and Liquidity Matters                    
Debt instrument, face amount $ 500,000,000         $ 300,000,000        
Term Loan                    
Long-Term Debt and Liquidity Matters                    
Repayment of long-term debt $ 150,000,000                  
Pinnacle West | Revolving Credit Facility | Revolving credit Facility maturing July 2023                    
Long-Term Debt and Liquidity Matters                    
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            
Current borrowing capacity on credit facility       200,000,000            
Pinnacle West | Letter of Credit | Revolving credit Facility maturing July 2023                    
Long-Term Debt and Liquidity Matters                    
Outstanding letters of credit       0            
Pinnacle West | Commercial paper | Revolving credit Facility maturing July 2023                    
Long-Term Debt and Liquidity Matters                    
Commercial paper       41,000,000            
Pinnacle West | Term Loan                    
Long-Term Debt and Liquidity Matters                    
Long-term line of credit       $ 31,000,000            
Debt instrument, face amount             $ 31,000,000 $ 50,000,000    
Variable rate       1.40%            
APS                    
Long-Term Debt and Liquidity Matters                    
Repayment of long-term debt       $ 350,000,000 $ 500,000,000          
Long-term debt limit                 $ 5,900,000,000  
APS | Senior Unsecured Notes                    
Long-Term Debt and Liquidity Matters                    
Debt instrument, interest rate   3.35%                
APS | Senior Unsecured Notes | Senior notes                    
Long-Term Debt and Liquidity Matters                    
Debt instrument, face amount   $ 600,000,000 $ 250,000,000              
Extinguishment of debt     $ 150,000,000              
APS | Revolving Credit Facility | Revolving credit Facility maturing July 2023                    
Long-Term Debt and Liquidity Matters                    
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders (up to)       700,000,000            
Current borrowing capacity on credit facility       500,000,000            
APS | Revolving Credit Facility | Revolving Credit Facility Maturing in 2022 and 2023                    
Long-Term Debt and Liquidity Matters                    
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders (up to)       1,400,000,000            
Long-term line of credit       0            
Current borrowing capacity on credit facility       $ 1,000,000,000            
Number of line of credit facilities | Facility       2            
APS | Revolving Credit Facility | Revolving credit facility maturing June 2022                    
Long-Term Debt and Liquidity Matters                    
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders (up to)       $ 700,000,000            
Current borrowing capacity on credit facility       500,000,000            
APS | Commercial paper                    
Long-Term Debt and Liquidity Matters                    
Maximum commercial paper support available under credit facility       500,000,000            
APS | Commercial paper | Revolving Credit Facility Maturing in 2022 and 2023                    
Long-Term Debt and Liquidity Matters                    
Commercial paper       $ 220,000,000            
APS | Term Loan                    
Long-Term Debt and Liquidity Matters                    
Repayment of long-term debt   $ 200,000,000                
Minimum | APS | Senior Unsecured Notes                    
Long-Term Debt and Liquidity Matters                    
Debt instrument, interest rate     2.20%              
v3.20.2
Long-Term Debt and Liquidity Matters - Estimated Fair Value of Long-Term Debt (Details) - USD ($)
$ in Thousands
Jun. 30, 2020
Dec. 31, 2019
Estimated fair value of long-term debt, including current maturities    
Carrying Amount $ 5,922,161 $ 5,632,558
Fair Value 6,894,289 6,194,392
Pinnacle West    
Estimated fair value of long-term debt, including current maturities    
Carrying Amount 496,610 449,425
Fair Value 507,850 450,822
APS    
Estimated fair value of long-term debt, including current maturities    
Carrying Amount 5,425,551 5,183,133
Fair Value $ 6,386,439 $ 5,743,570
v3.20.2
Regulatory Matters Regulatory Matters - COVID-19 (Details) - USD ($)
 3 Months Ended 6 Months Ended 12 Months Ended
Jun. 30, 2020
Jun. 30, 2019
Jun. 30, 2020
Jun. 30, 2019
Dec. 31, 2020
May 05, 2020
Public Utilities, General Disclosures [Line Items]            
Pre-tax income $ 239,520,000 $ 166,099,000 $ 254,177,000 $ 191,308,000    
Customer support, not yet assigned 3,000,000   3,000,000      
APS            
Public Utilities, General Disclosures [Line Items]            
Pre-tax income 245,669,000 $ 173,513,000 266,439,000 $ 208,115,000    
Customer support fund           $ 1,500,000
Customer support fund, bill credit           100
Demand side management funds           36,000,000
Customer credits 40,000,000   40,000,000      
Customer credits, additional funds 4,000,000   4,000,000      
Voluntary funds $ 8,000,000   $ 8,000,000     5,300,000
Customer assistance, small customers           2,300,000
Customer assistance, small customers, bill credit           1,000
Customer support fund, non-profits and community organizations           $ 1,250,000
Minimum | Damage from Fire, Explosion or Other Hazard | Forecast | APS            
Public Utilities, General Disclosures [Line Items]            
Pre-tax income         $ 20,000,000  
Maximum | Damage from Fire, Explosion or Other Hazard | Forecast | APS            
Public Utilities, General Disclosures [Line Items]            
Pre-tax income         $ 30,000,000  
v3.20.2
Regulatory Matters - Retail Rate Case Filing (Details) - ACC - APS
Oct. 31, 2019
USD ($)
GW
Jun. 30, 2019
USD ($)
Mar. 27, 2017
USD ($)
$ / kWh
Retail Rate Case Filing with Arizona Corporation Commission      
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%   3.28%
Rate matter, cost base rate   $ 8,870,000,000  
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     $ 61,000,000.0
Approximate percentage of increase in average residential customer bill 5.40%   4.54%
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
Funding limited income crisis bill program $ 1,250,000    
Commercial customers, market pricing, threshold | GW 0.2    
AZ Sun Program Phase 2 | Retail Rate Case Filing with Arizona Corporation Commission      
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
Minimum      
Public Utilities, General Disclosures [Line Items]      
Operating Results $ 69,000,000    
Minimum | Retail Rate Case Filing with Arizona Corporation Commission      
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      
Public Utilities, General Disclosures [Line Items]      
Rate matter, environmental surcharge cap rate (in dollars per kWh) | $ / kWh     0.00050
v3.20.2
Regulatory Matters Regulatory Matters - Capital Structure and Costs of Capital (Details)
Oct. 31, 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 | APS  
Capital Structure  
Common stock equity 54.70%
Retail Rate Case Filing with Arizona Corporation Commission | ACC | APS  
Capital Structure  
Long-term debt 45.30%
v3.20.2
Regulatory Matters - Cost Recovery Mechanism and Net Metering (Details)
Customer in Thousands
 1 Months Ended 3 Months Ended 6 Months Ended 12 Months Ended
Jun. 01, 2020
USD ($)
May 01, 2020
$ / kWh
Feb. 14, 2020
USD ($)
Feb. 01, 2020
USD ($)
$ / kWh
Nov. 14, 2019
USD ($)
Customer
Oct. 31, 2019
USD ($)
Oct. 29, 2019
USD ($)
Jun. 01, 2019
USD ($)
May 01, 2019
$ / kWh
Apr. 10, 2019
Feb. 15, 2019
USD ($)
Feb. 01, 2019
$ / kWh
Aug. 13, 2018
USD ($)
Jun. 01, 2018
USD ($)
May 01, 2018
$ / kWh
Feb. 15, 2018
USD ($)
Feb. 01, 2018
$ / kWh
Jan. 08, 2018
USD ($)
Nov. 20, 2017
USD ($)
Dec. 20, 2016
$ / kWh
Aug. 31, 2016
Jun. 30, 2020
USD ($)
Jun. 30, 2019
USD ($)
Jun. 30, 2020
USD ($)
Jun. 30, 2019
USD ($)
Dec. 31, 2020
USD ($)
Dec. 31, 2017
$ / kWh
Jul. 01, 2020
USD ($)
May 15, 2020
USD ($)
May 05, 2020
USD ($)
Dec. 31, 2019
USD ($)
Jul. 01, 2019
USD ($)
Mar. 15, 2019
agreement
Dec. 31, 2018
USD ($)
Jun. 29, 2018
USD ($)
Nov. 14, 2017
USD ($)
Sep. 01, 2017
USD ($)
Settlement Agreement                                                                          
Pre-tax income                                           $ 239,520,000 $ 166,099,000 $ 254,177,000 $ 191,308,000                        
Change in regulatory asset                                                                          
Deferred fuel and purchased power costs — current period                                               26,473,000 16,702,000                        
Amounts charged to customers                                               4,815,000 (23,307,000)                        
Rate plan comparison tool, number of customers | Customer         13                                                                
Rate plan comparison tool, inconvenience payment         $ 25                                                                
APS                                                                          
Settlement Agreement                                                                          
Pre-tax income                                           245,669,000 173,513,000 266,439,000 208,115,000                        
Change in regulatory asset                                                                          
Deferred fuel and purchased power costs — current period                                               26,473,000 16,702,000                        
Amounts charged to customers                                               4,815,000 (23,307,000)                        
Demand side management funds                                                           $ 36,000,000              
Customer credits                                           40,000,000   40,000,000                          
Customer credits, additional funds                                           $ 4,000,000   $ 4,000,000                          
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%   1.00%                          
Amount of adjustment representing prorated sales losses pending approval     $ 26,600,000               $ 36,200,000         $ 60,700,000                                          
Increase (decrease) in amount of adjustment representing prorated sales losses     $ (9,600,000)               $ (24,500,000)                                                    
ACC | APS                                                                          
Settlement Agreement                                                                          
Program term                                         2 years                                
Change in regulatory asset                                                                          
Gross-up for revenue requirement of rate regulation           $ (184,000,000)             $ 86,500,000         $ 119,100,000                                      
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                                                            
ACC | RES | APS                                                                          
Settlement Agreement                                                                          
Plan term                                               5 years                          
ACC | RES 2018 | APS                                                                          
Settlement Agreement                                                                          
Amount of proposed budget                                                               $ 86,300,000     $ 89,900,000    
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                                               $ 70,137,000 37,164,000 $ 70,137,000                      
Deferred fuel and purchased power costs — current period                                               26,473,000 16,702,000                        
Amounts charged to customers                                               4,815,000 (23,307,000)                        
Ending balance                                           $ 101,425,000 $ 30,559,000 101,425,000 $ 30,559,000                        
PSA rate (in dollars per kWh) | $ / kWh       (0.000456)               0.001658         0.004555                                        
PSA rate for prior year (in dollars per kWh) | $ / kWh       (0.002086)               0.000536         0.002009                                        
Forward component of increase in PSA (in dollars per kWh) | $ / kWh       0.001630               0.001122         0.002546                                        
Maximum increase (decrease) in PSA rate | $ / kWh                                 0.004                                        
Fuel and purchased power costs, excess annual limit                                           $ 16,400,000   $ 16,400,000                          
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                                  
First-year export energy price (in dollars per kWh) | $ / kWh                                       0.129                                  
Second-year export energy price (in dollars per kWh) | $ / kWh   0.094             0.105           0.116                                            
United States Federal Energy Regulatory Commission | Environmental Improvement Surcharge | APS                                                                          
Change in regulatory asset                                                                          
Increase (decrease) in annual wholesale transmission rates       $ 8,750,000                                                                  
United States Federal Energy Regulatory Commission | Open Access Transmission Tariff | APS                                                                          
Change in regulatory asset                                                                          
Increase (decrease) in annual wholesale transmission rates $ (6,100,000)             $ 25,800,000           $ (22,700,000)                                              
Retail customer rates $ 10,900,000             $ 4,700,000           $ (26,900,000)                                              
Cost Recovery Mechanisms | ACC | Power Supply Adjustor (PSA) | APS                                                                          
Change in regulatory asset                                                                          
Historical component of increase in PSA (in dollars per kWh) | $ / kWh       (0.002115)               (0.002897)                                                  
Cost recovery, number of agreements | agreement                                                                 2        
Forecast | United States Federal Energy Regulatory Commission | Environmental Improvement Surcharge | APS                                                                          
Change in regulatory asset                                                                          
Rate matters, increase (decrease) in cost recovery, excess of annual amount                                                   (2,000,000.0)                      
Minimum | ACC | APS                                                                          
Change in regulatory asset                                                                          
Operating Results           $ (69,000,000)                                                              
Minimum | ACC | RES 2018 | APS | Solar Communities                                                                          
Settlement Agreement                                                                          
Required annual capital investment                                     $ 10,000,000                                    
Maximum | ACC | RES 2018 | APS | Solar Communities                                                                          
Settlement Agreement                                                                          
Required annual capital investment                                     $ 15,000,000                                    
Subsequent Event | ACC | RES 2018 | APS                                                                          
Settlement Agreement                                                                          
Amount of proposed budget                                                       $ 84,700,000                  
Damage from Fire, Explosion or Other Hazard | Minimum | Forecast | APS                                                                          
Settlement Agreement                                                                          
Pre-tax income                                                   20,000,000                      
Damage from Fire, Explosion or Other Hazard | Maximum | Forecast | APS                                                                          
Settlement Agreement                                                                          
Pre-tax income                                                   $ 30,000,000                      
v3.20.2
Regulatory Matters - Four Corners and Cholla (Details) - APS - USD ($)
$ in Millions
 1 Months Ended
Sep. 30, 2018
Apr. 30, 2018
Jun. 30, 2020
SCE | Four Corners Units 4 and 5      
Business Acquisition [Line Items]      
Settlement agreement, ACC approved rate adjustment, annualized customer impact $ 58.5 $ 67.5  
Retired power plant costs      
Business Acquisition [Line Items]      
Net book value     $ 65.0
Navajo Plant      
Business Acquisition [Line Items]      
Net book value     $ 77.0
v3.20.2
Regulatory Matters - Schedule of Regulatory Assets (Details) - USD ($)
$ in Thousands
Jun. 30, 2020
Dec. 31, 2019
Detail of regulatory assets    
Current $ 251,594 $ 203,207
Non-Current 1,315,846 1,304,073
Pension    
Detail of regulatory assets    
Current 0 0
Non-Current 663,327 660,223
Income taxes — allowance for funds used during construction (AFUDC) equity    
Detail of regulatory assets    
Current 6,815 6,800
Non-Current 156,528 154,974
Retired power plant costs    
Detail of regulatory assets    
Current 28,182 28,182
Non-Current 128,304 142,503
Deferred fuel and purchased power    
Detail of regulatory assets    
Current 101,425 70,137
Non-Current 0 0
Deferred fuel and purchased power — mark-to-market (Note 7)    
Detail of regulatory assets    
Current 42,911 36,887
Non-Current 26,151 33,185
Ocotillo deferral    
Detail of regulatory assets    
Current 0 0
Non-Current 65,571 38,144
SCR deferral    
Detail of regulatory assets    
Current 0 0
Non-Current 64,971 52,644
Deferred property taxes    
Detail of regulatory assets    
Current 8,569 8,569
Non-Current 53,911 58,196
Deferred compensation    
Detail of regulatory assets    
Current 0 0
Non-Current 36,481 36,464
Four Corners cost deferral    
Detail of regulatory assets    
Current 8,077 8,077
Non-Current 28,113 32,152
Lost fixed cost recovery    
Detail of regulatory assets    
Current 34,144 26,067
Non-Current 0 0
Income taxes — investment tax credit basis adjustment    
Detail of regulatory assets    
Current 1,098 1,098
Non-Current 24,532 24,981
Palo Verde VIEs (Note 6)    
Detail of regulatory assets    
Current 0 0
Non-Current 20,945 20,635
Coal reclamation    
Detail of regulatory assets    
Current 1,068 1,546
Non-Current 17,533 17,688
Loss on reacquired debt    
Detail of regulatory assets    
Current 1,637 1,637
Non-Current 11,241 12,031
TCA balancing account    
Detail of regulatory assets    
Current 8,272 6,324
Non-Current 2,926 2,885
Mead-Phoenix transmission line contributions in aid of construction (CIAC)    
Detail of regulatory assets    
Current 332 332
Non-Current 9,546 9,712
Tax expense of Medicare subsidy    
Detail of regulatory assets    
Current 1,238 1,235
Non-Current 4,444 4,940
AG-1 deferral    
Detail of regulatory assets    
Current 2,787 2,787
Non-Current 1,322 2,716
Tax expense adjustor mechanism    
Detail of regulatory assets    
Current 3,640 1,612
Non-Current 0 0
Other    
Detail of regulatory assets    
Current 1,399 1,917
Non-Current $ 0 $ 0
v3.20.2
Regulatory Matters - Schedule of Regulatory Liabilities (Details) - USD ($)
$ in Thousands
Jun. 30, 2020
Dec. 31, 2019
Detail of regulatory liabilities    
Current $ 279,479 $ 234,912
Non-Current 2,089,987 2,267,835
Asset retirement obligations    
Detail of regulatory liabilities    
Current 0 0
Non-Current 408,126 418,423
Removal costs    
Detail of regulatory liabilities    
Current 47,300 47,356
Non-Current 126,036 136,072
Other postretirement benefits    
Detail of regulatory liabilities    
Current 37,575 37,575
Non-Current 118,398 139,634
Four Corners coal reclamation    
Detail of regulatory liabilities    
Current 5,461 1,059
Non-Current 48,795 51,704
Spent nuclear fuel    
Detail of regulatory liabilities    
Current 6,068 6,676
Non-Current 47,901 51,019
Income taxes — change in rates    
Detail of regulatory liabilities    
Current 2,802 2,797
Non-Current 50,163 68,265
Income taxes — deferred investment tax credit    
Detail of regulatory liabilities    
Current 2,202 2,202
Non-Current 49,133 50,034
Renewable energy standard    
Detail of regulatory liabilities    
Current 38,934 39,287
Non-Current 22 10,300
Sundance maintenance    
Detail of regulatory liabilities    
Current 1,100 5,698
Non-Current 13,001 11,319
Demand side management    
Detail of regulatory liabilities    
Current 3,068 15,024
Non-Current 6,138 24,146
Property tax deferral    
Detail of regulatory liabilities    
Current 0 0
Non-Current 8,603 7,046
FERC transmission true up    
Detail of regulatory liabilities    
Current 5,452 1,045
Non-Current 2,209 2,004
Active union medical trust    
Detail of regulatory liabilities    
Current 0 0
Non-Current 7,629 2,041
Tax expense adjustor mechanism    
Detail of regulatory liabilities    
Current 6,450 7,018
Non-Current 0 0
Deferred gains on utility property    
Detail of regulatory liabilities    
Current 2,423 2,423
Non-Current 2,973 4,163
Other    
Detail of regulatory liabilities    
Current 220 532
Non-Current 331 255
ACC | Excess deferred income taxes - ACC - Tax Cuts and Jobs Act    
Detail of regulatory liabilities    
Current 113,168 59,918
Non-Current 966,576 1,054,053
United States Federal Energy Regulatory Commission | Excess deferred income taxes - ACC - Tax Cuts and Jobs Act    
Detail of regulatory liabilities    
Current 7,256 6,302
Non-Current $ 233,953 $ 237,357
v3.20.2
Retirement Plans and Other Postretirement Benefits - Schedule of Net Benefit Cost (Details) - USD ($)
$ in Thousands
 3 Months Ended 6 Months Ended
Jun. 30, 2020
Jun. 30, 2019
Jun. 30, 2020
Jun. 30, 2019
Amortization of:        
Portion of cost (credit) charged to expense $ (14,142) $ (6,374) $ (28,053) $ (11,488)
Pension Benefits        
Retirement Plans and Other Benefits        
Service cost — benefits earned during the period 13,859 12,408 28,116 24,951
Interest cost on benefit obligation 29,522 34,069 59,283 68,421
Expected return on plan assets (46,915) (43,049) (93,721) (85,942)
Amortization of:        
Prior service credit 0 0 0 0
Net actuarial loss 8,295 10,053 17,306 21,292
Net periodic benefit cost (credit) 4,761 13,481 10,984 28,722
Portion of cost (credit) charged to expense 271 7,000 1,613 15,244
Other Benefits        
Retirement Plans and Other Benefits        
Service cost — benefits earned during the period 5,401 4,470 11,118 9,184
Interest cost on benefit obligation 6,417 7,421 12,929 14,947
Expected return on plan assets (10,019) (9,603) (20,038) (19,206)
Amortization of:        
Prior service credit (9,394) (9,455) (18,788) (18,910)
Net actuarial loss 0 0 0 0
Net periodic benefit cost (credit) (7,595) (7,167) (14,779) (13,985)
Portion of cost (credit) charged to expense $ (5,056) $ (5,063) $ (10,512) $ (9,880)
v3.20.2
Retirement Plans and Other Postretirement Benefits - Narrative (Details)
 6 Months Ended
Jun. 30, 2020
USD ($)
Pension Benefits  
Contributions  
Minimum employer contributions for the next three years $ 0
Maximum employer contributions for the next two years (up to) 100,000,000
Other Benefits  
Contributions  
Estimated future employer contributions in next three years $ 0
v3.20.2
Palo Verde Sale Leaseback Variable Interest Entities - Narrative (Details)
 3 Months Ended 6 Months Ended
Jun. 30, 2020
USD ($)
power_plant
Jun. 30, 2019
USD ($)
Jun. 30, 2020
USD ($)
power_plant
Lease
Jun. 30, 2019
USD ($)
Dec. 31, 1986
Trust
Palo Verde Sale Leaseback Variable Interest Entities          
Increase in net income due to consolidation of Palo Verde Sale Leaseback Trusts $ 4,874,000 $ 4,874,000 $ 9,747,000 $ 9,747,000  
APS          
Palo Verde Sale Leaseback Variable Interest Entities          
Number of VIE lessor trusts 3   3   3
Increase in net income due to consolidation of Palo Verde Sale Leaseback Trusts $ 4,874,000 4,874,000 $ 9,747,000 9,747,000  
Palo Verde VIE | APS          
Palo Verde Sale Leaseback Variable Interest Entities          
Increase in net income due to consolidation of Palo Verde Sale Leaseback Trusts $ 5,000,000 $ 5,000,000 10,000,000 $ 10,000,000  
Initial loss exposure to the VIE's noncontrolling equity participants during lease extension period     304,000,000    
Maximum loss exposure to the VIE's noncontrolling equity participants during lease extension period     $ 456,000,000    
Palo Verde VIE | APS | Through 2023          
Palo Verde Sale Leaseback Variable Interest Entities          
Number of leases under which assets are retained | Lease     1    
Palo Verde VIE | APS | Through 2033          
Palo Verde Sale Leaseback Variable Interest Entities          
Number of leases under which assets are retained | Lease     2    
Palo Verde VIE | APS | Period 2017 through 2023          
Palo Verde Sale Leaseback Variable Interest Entities          
Annual lease payments     $ 23,000,000    
Palo Verde VIE | APS | Period 2024 through 2033          
Palo Verde Sale Leaseback Variable Interest Entities          
Annual lease payments     $ 16,000,000    
Palo Verde VIE | APS | Period 2024 through 2033 | Maximum          
Palo Verde Sale Leaseback Variable Interest Entities          
Lease period (up to)     2 years    
v3.20.2
Palo Verde Sale Leaseback Variable Interest Entities - Schedule of VIEs (Details) - USD ($)
$ in Thousands
Jun. 30, 2020
Dec. 31, 2019
Palo Verde Sale Leaseback Variable Interest Entities    
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation $ 14,789,011 $ 14,522,538
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets    
Equity — Noncontrolling interests 120,915 122,540
APS    
Palo Verde Sale Leaseback Variable Interest Entities    
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation 14,788,639 14,522,156
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets    
Equity — Noncontrolling interests 120,915 122,540
Palo Verde VIE    
Palo Verde Sale Leaseback Variable Interest Entities    
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation 99,971 101,906
Palo Verde VIE | APS    
Palo Verde Sale Leaseback Variable Interest Entities    
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation 99,971 101,906
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets    
Equity — Noncontrolling interests $ 120,915 $ 122,540
v3.20.2
Derivative Accounting - Narrative (Details) - USD ($)
 3 Months Ended 6 Months Ended
Jun. 30, 2020
Jun. 30, 2020
Jun. 30, 2019
Jun. 30, 2020
Jun. 30, 2019
Dec. 31, 2019
Derivative Accounting            
Derivative liability $ 70,986,000 $ 70,986,000   $ 70,986,000   $ 72,132,000
Commodity Contracts            
Derivative Accounting            
Derivative liability 70,986,000 70,986,000   70,986,000   $ 72,132,000
Additional collateral to counterparties for energy related non-derivative instrument contracts 88,000,000 88,000,000   88,000,000    
Aggregate fair value of derivative instruments in a net liability position $ 72,590,000 72,590,000   72,590,000    
Commodity Contracts | Designated as Hedging Instruments            
Derivative Accounting            
Amount reclassified from accumulated other comprehensive income to earnings related to discontinued cash flow hedges   $ 0 $ 0 $ 0 $ 0  
APS            
Derivative Accounting            
Percentage of unrealized gains and losses on certain derivatives deferred for future rate treatment 100.00% 100.00%   100.00%    
Risk Management Assets | Credit Concentration Risk            
Derivative Accounting            
Concentration risk 79.00%          
Aggregate fair value of derivative instruments in a net liability position $ 700,000 $ 700,000   $ 700,000    
v3.20.2
Derivative Accounting - Schedule of Gross Notional Amounts Outstanding (Details) - Commodity Contracts
GWh in Thousands, Bcf in Thousands
Jun. 30, 2020
GWh
Bcf
Dec. 31, 2019
GWh
Bcf
Outstanding gross notional amount of derivatives    
Power | GWh 294 193
Gas | Bcf 249 257
v3.20.2
Derivative Accounting - Gains and Losses from Derivative Instruments (Details) - Commodity Contracts - USD ($)
 3 Months Ended 6 Months Ended
Jun. 30, 2020
Jun. 30, 2019
Jun. 30, 2020
Jun. 30, 2019
Designated as Hedging Instruments        
Gains and losses from derivative instruments        
Amount reclassified from accumulated other comprehensive income to earnings related to discontinued cash flow hedges $ 0 $ 0 $ 0 $ 0
Designated as Hedging Instruments | Fuel and purchased power        
Gains and losses from derivative instruments        
Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) 349,000 538,000 763,000 974,000
Not Designated as Hedging Instruments | Fuel and purchased power        
Gains and losses from derivative instruments        
Net Loss Recognized in Income $ (4,894,000) $ (49,686,000) $ (34,971,000) $ (41,516,000)
v3.20.2
Derivative Accounting - Derivative Instruments in the Balance Sheets (Details) - USD ($)
Jun. 30, 2020
Dec. 31, 2019
Assets    
Gross Recognized Derivatives $ 740,000 $ 515,000
Liabilities    
Amount Reported on Balance Sheets (70,986,000) (72,132,000)
Commodity Contracts    
Assets    
Gross Recognized Derivatives 3,529,000  
Amounts Offset (2,789,000)  
Net Recognized Derivatives 740,000  
Other 0 405,000
Amount Reported on Balance Sheets 740,000  
Liabilities    
Gross Recognized Derivatives (72,590,000) (71,421,000)
Amounts Offset 2,789,000 474,000
Net Recognized Derivatives (69,801,000) (70,947,000)
Other (1,185,000) (1,185,000)
Amount Reported on Balance Sheets (70,986,000) (72,132,000)
Assets and Liabilities    
Gross Recognized Derivatives (69,061,000) (70,837,000)
Amounts Offset 0 0
Net Recognized Derivatives (69,061,000) (70,837,000)
Other (1,185,000) (780,000)
Amount Reported on Balance Sheets (70,246,000) (71,617,000)
Cash collateral received from counterparties 1,185,000 1,185,000
Commodity Contracts | Current assets    
Assets    
Gross Recognized Derivatives 2,989,000 584,000
Amounts Offset (2,279,000) (474,000)
Net Recognized Derivatives 710,000 110,000
Other 0 405,000
Amount Reported on Balance Sheets 710,000 515,000
Commodity Contracts | Investments and other assets    
Assets    
Gross Recognized Derivatives 540,000  
Amounts Offset (510,000)  
Net Recognized Derivatives 30,000  
Other 0  
Amount Reported on Balance Sheets 30,000  
Commodity Contracts | Current liabilities    
Liabilities    
Gross Recognized Derivatives (45,899,000) (38,235,000)
Amounts Offset 2,279,000 474,000
Net Recognized Derivatives (43,620,000) (37,761,000)
Other (1,185,000) (1,185,000)
Amount Reported on Balance Sheets (44,805,000) (38,946,000)
Assets and Liabilities    
Cash collateral received from counterparties 1,185,000 1,185,000
Commodity Contracts | Deferred credits and other    
Liabilities    
Gross Recognized Derivatives (26,691,000) (33,186,000)
Amounts Offset 510,000 0
Net Recognized Derivatives (26,181,000) (33,186,000)
Other 0 0
Amount Reported on Balance Sheets (26,181,000) (33,186,000)
Assets and Liabilities    
Cash collateral received from counterparties $ 0 $ 0
v3.20.2
Derivative Accounting - Credit Risk and Credit Related Contingent Features (Details) - Commodity Contracts
$ in Thousands
Jun. 30, 2020
USD ($)
Credit Risk and Credit-Related Contingent Features  
Aggregate fair value of derivative instruments in a net liability position $ 72,590
Cash collateral posted 0
Additional cash collateral in the event credit-risk-related contingent features were fully triggered $ 63,880
v3.20.2
Commitments and Contingencies - Palo Verde Nuclear Generating Station and Contractual Obligations (Details)
 6 Months Ended 84 Months Ended
Feb. 11, 2020
USD ($)
Oct. 31, 2019
USD ($)
Jun. 30, 2020
USD ($)
power_plant
Jun. 30, 2018
USD ($)
time_period
claim
Dec. 31, 1986
Trust
Breach of Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste          
Commitments and Contingencies          
Litigation settlement amount $ 15,400,000 $ 16,000,000   $ 84,300,000  
APS          
Commitments and Contingencies          
Maximum insurance against public liability per occurrence for a nuclear incident (up to)     $ 13,800,000,000    
Maximum available nuclear liability insurance (up to)     450,000,000    
Remaining nuclear liability insurance through mandatory industry wide retrospective assessment program     13,300,000,000    
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     25,800,000    
Collateral assurance provided based on rating triggers     $ 75,100,000    
Period to provide collateral assurance based on rating triggers     20 days    
APS | Breach of Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste          
Commitments and Contingencies          
Litigation settlement amount $ 4,500,000 $ 4,700,000   $ 24,500,000  
Number of claims submitted | claim       5  
Number of settlement agreement time periods | time_period       5  
v3.20.2
Commitments and Contingencies - Superfund-Related Matters, Southwest Power Outage and Clean Air Act (Details) - APS - Contaminated groundwater wells
$ in Millions
 6 Months Ended
Apr. 05, 2018
Defendant
plaintiff
Dec. 16, 2016
plaintiff
Aug. 06, 2013
Defendant
Jun. 30, 2020
USD ($)
Loss Contingencies [Line Items]        
Costs related to investigation and study under Superfund site | $       $ 3
Number of defendants against whom Roosevelt Irrigation District (RID) filed lawsuit | Defendant 28   24  
Number of plaintiffs   2    
Settled Litigation        
Loss Contingencies [Line Items]        
Number of plaintiffs 2      
v3.20.2
Commitments and Contingencies - Environmental Matters and Financial Assurances (Details) - USD ($)
$ in Millions
 6 Months Ended 12 Months Ended
Jul. 03, 2018
Jul. 06, 2016
Jun. 30, 2020
Dec. 31, 2019
Financial Assurances        
Equity contribution guarantees     $ 40.0  
APS | Letters of Credit Expiring in 2020        
Financial Assurances        
Outstanding letters of credit     4.9  
APS | Surety Bonds Expiring in 2020        
Financial Assurances        
Surety bonds expiring, amount     16.0  
4C Acquisition, LLC | Four Corners        
Environmental Matters        
Percentage of share of cost of control   7.00%    
Four Corners Coal Supply Agreement        
Notes receivable, related parties     39.0  
4C Acquisition, LLC | Coal Supply Agreement Arbitration | Four Corners        
Four Corners Coal Supply Agreement        
Reimbursement payments due to 4CA     $ 10.0  
NTEC | Four Corners        
Four Corners Coal Supply Agreement        
Option to purchase ownership interest (as a percent) 7.00% 7.00%    
Proceeds from operating and maintenance cost reimbursement $ 70.0      
NTEC | Coal Supply Agreement Arbitration | Four Corners        
Four Corners Coal Supply Agreement        
Option to purchase ownership interest (as a percent)   7.00%    
Regional Haze Rules | APS | Four Corners Units 4 and 5        
Environmental Matters        
Percentage of share of cost of control     63.00%  
Expected environmental cost     $ 400.0  
Regional Haze Rules | APS | Natural gas tolling contract obligations | Four Corners Units 4 and 5        
Environmental Matters        
Additional percentage share of cost of control     7.00%  
Regional Haze Rules | APS | Four Corners | Four Corners Units 4 and 5        
Environmental Matters        
Site contingency increase in loss exposure not accrued, best estimate     $ 45.0  
Coal combustion waste | APS | Four Corners        
Environmental Matters        
Site contingency increase in loss exposure not accrued, best estimate     22.0  
Coal combustion waste | APS | Navajo Plant        
Environmental Matters        
Site contingency increase in loss exposure not accrued, best estimate     1.0  
Minimum | Coal combustion waste | APS | Cholla        
Environmental Matters        
Site contingency increase in loss exposure not accrued, best estimate     $ 15.0  
Minimum | Coal combustion waste | APS | Cholla and Four Corners        
Environmental Matters        
Site contingency increase in loss exposure not accrued, best estimate       $ 10.0
Maximum | Coal combustion waste | APS | Cholla and Four Corners        
Environmental Matters        
Site contingency increase in loss exposure not accrued, best estimate       $ 15.0
v3.20.2
Other Income and Other Expense (Details) - USD ($)
$ in Thousands
 3 Months Ended 6 Months Ended
Jun. 30, 2020
Jun. 30, 2019
Jun. 30, 2020
Jun. 30, 2019
Other income:        
Interest income $ 2,755 $ 2,699 $ 6,032 $ 5,001
Investment gains (losses) - net 2,826 0 2,826 0
Miscellaneous 137 5 145 28
Total other income 16,670 12,885 29,239 20,054
Other expense:        
Non-operating costs (2,290) (3,481) (4,948) (6,185)
Investment losses (gains) — net 0 (491) 60 (729)
Miscellaneous (1,746) (378) (3,932) (1,794)
Total other expense (4,036) (4,350) (8,820) (8,708)
APS        
Other income:        
Interest income 2,183 1,504 4,524 3,054
Miscellaneous 137 6 145 28
Total other income 13,272 11,691 24,905 18,107
Other expense:        
Non-operating costs (2,113) (3,049) (4,595) (5,517)
Miscellaneous (1,746) (379) (3,932) (1,789)
Total other expense (3,859) (3,428) (8,527) (7,306)
SCR deferral        
Other income:        
Debt return on Four Corners SCR deferrals (Note 4) 4,249 4,887 7,389 9,731
SCR deferral | APS        
Other income:        
Debt return on Four Corners SCR deferrals (Note 4) 4,249 4,887 7,389 9,731
Ocotillo deferral        
Other income:        
Debt return on Four Corners SCR deferrals (Note 4) 6,703 5,294 12,847 5,294
Ocotillo deferral | APS        
Other income:        
Debt return on Four Corners SCR deferrals (Note 4) $ 6,703 $ 5,294 $ 12,847 $ 5,294
v3.20.2
Earnings Per Share (Details) - USD ($)
$ / shares in Units, shares in Thousands, $ in Thousands
 3 Months Ended 6 Months Ended
Jun. 30, 2020
Jun. 30, 2019
Jun. 30, 2020
Jun. 30, 2019
Earnings Per Share [Abstract]        
Net income attributable to common shareholders $ 193,585 $ 144,145 $ 223,578 $ 162,063
Weighted average common shares outstanding - basic (in shares) 112,638 112,337 112,616 112,381
Net effect of dilutive securities:        
Contingently issuable performance shares and restricted stock units (in shares) 241 314 255 353
Weighted average common shares outstanding — diluted (in shares) 112,879 112,651 112,871 112,734
Earnings per weighted-average common share outstanding        
Net income attributable to common shareholders - basic (in dollars per share) $ 1.72 $ 1.28 $ 1.99 $ 1.44
Net income attributable to common shareholders - diluted (in dollars per share) $ 1.71 $ 1.28 $ 1.98 $ 1.44
v3.20.2
Fair Value Measurements - Assets and Liabilities Measured on a Recurring Basis (Details) - USD ($)
$ in Thousands
Jun. 30, 2020
Dec. 31, 2019
Assets    
Commodity contracts, assets $ 740 $ 515
Commodity contracts, liabilities (2,790) (69)
Nuclear decommissioning trust 1,024,033 1,010,775
Nuclear decommissioning trust, other 496,121 521,245
Other special use funds 253,332 245,095
Other special use funds, other 526 474
Total assets 1,278,105 1,256,385
Total assets, other 493,857 521,650
Liabilities    
Total, other 1,605 711
Amount reported on balance sheet (70,986) (72,132)
Equity securities    
Assets    
Nuclear decommissioning trust 9,855 13,273
Nuclear decommissioning trust, other (6,130) 2,401
Other special use funds 9,481 7,616
Other special use funds, other 526 474
U.S. commingled equity funds    
Assets    
Nuclear decommissioning trust 502,251 518,844
U.S. Treasury debt    
Assets    
Nuclear decommissioning trust 143,673 160,607
Other special use funds 229,858 232,848
Corporate debt    
Assets    
Nuclear decommissioning trust 149,672 115,869
Mortgage-backed securities    
Assets    
Nuclear decommissioning trust 99,407 118,795
Municipal bonds    
Assets    
Nuclear decommissioning trust 106,971 73,040
Other special use funds 13,993 4,631
Other fixed income    
Assets    
Nuclear decommissioning trust 12,204 10,347
Level 1    
Assets    
Commodity contracts, assets 0 0
Nuclear decommissioning trust 159,658 171,479
Other special use funds 238,813 239,990
Total assets 398,471 411,469
Liabilities    
Gross derivative liability 0 0
Level 1 | Equity securities    
Assets    
Nuclear decommissioning trust 15,985 10,872
Other special use funds 8,955 7,142
Level 1 | U.S. commingled equity funds    
Assets    
Nuclear decommissioning trust 0 0
Level 1 | U.S. Treasury debt    
Assets    
Nuclear decommissioning trust 143,673 160,607
Other special use funds 229,858 232,848
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 3,165 551
Nuclear decommissioning trust 368,254 318,051
Other special use funds 13,993 4,631
Total assets 385,412 323,233
Liabilities    
Gross derivative liability (61,974) (67,992)
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 149,672 115,869
Level 2 | Mortgage-backed securities    
Assets    
Nuclear decommissioning trust 99,407 118,795
Level 2 | Municipal bonds    
Assets    
Nuclear decommissioning trust 106,971 73,040
Other special use funds 13,993 4,631
Level 2 | Other fixed income    
Assets    
Nuclear decommissioning trust 12,204 10,347
Level 3    
Assets    
Commodity contracts, assets 365 33
Nuclear decommissioning trust 0 0
Other special use funds 0 0
Total assets 365 33
Liabilities    
Gross derivative liability (10,617) (3,429)
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 $ 502,251 $ 518,844
v3.20.2
Fair Value Measurements - Financial Instruments Not Carried at Fair Value (Details) - USD ($)
$ in Millions
Jun. 30, 2020
Dec. 31, 2019
Fair Value Disclosures [Abstract]    
Stated interest rate for notes receivable 3.90%  
Note receivable, net book value $ 39 $ 44
v3.20.2
Investments in Nuclear Decommissioning Trusts and Other Special Use Funds (Details) - APS - USD ($)
$ in Thousands
 3 Months Ended 6 Months Ended
Jun. 30, 2020
Jun. 30, 2019
Jun. 30, 2020
Jun. 30, 2019
Dec. 31, 2019
Nuclear decommissioning trust fund assets          
Fair Value $ 1,277,365   $ 1,277,365   $ 1,255,870
Total Unrealized Gains 366,187   366,187   363,476
Total Unrealized Losses (582)   (582)   (669)
Amortized cost 707,000   707,000   691,000
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds          
Realized gains 4,500 $ 2,643 7,813 $ 3,746  
Realized losses (1,621) (1,700) (3,848) (3,105)  
Proceeds from the sale of securities 196,772 130,306 391,859 309,354  
Equity securities          
Nuclear decommissioning trust fund assets          
Equity securities 527,191   527,191   536,858
Total Unrealized Gains 316,494   316,494   337,681
Total Unrealized Losses (58)   (58)   0
Available for sale-fixed income securities          
Nuclear decommissioning trust fund assets          
Fair Value 755,778   755,778   716,137
Total Unrealized Gains 49,693   49,693   25,795
Total Unrealized Losses (524)   (524)   (669)
Fair value of fixed income securities, summarized by contractual maturities          
Less than one year 99,934   99,934    
1 year – 5 years 292,531   292,531    
5 years – 10 years 127,711   127,711    
Greater than 10 years 235,602   235,602    
Total 755,778   755,778    
Other          
Nuclear decommissioning trust fund assets          
Other (5,604)   (5,604)   2,875
Total Unrealized Gains 0   0   0
Total Unrealized Losses 0   0   0
Nuclear Decommissioning Trust          
Nuclear decommissioning trust fund assets          
Fair Value 1,024,033   1,024,033   1,010,775
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds          
Realized gains 4,500 2,643 7,813 3,746  
Realized losses (1,621) (1,700) (3,848) (3,105)  
Proceeds from the sale of securities 176,942 93,559 355,138 216,152  
Nuclear Decommissioning Trust | Equity securities          
Nuclear decommissioning trust fund assets          
Equity securities 518,236   518,236   529,716
Nuclear Decommissioning Trust | Available for sale-fixed income securities          
Nuclear decommissioning trust fund assets          
Fair Value 511,927   511,927   478,658
Fair value of fixed income securities, summarized by contractual maturities          
Less than one year 21,767   21,767    
1 year – 5 years 137,754   137,754    
5 years – 10 years 125,807   125,807    
Greater than 10 years 226,599   226,599    
Total 511,927   511,927    
Nuclear Decommissioning Trust | Other          
Nuclear decommissioning trust fund assets          
Other (6,130)   (6,130)   2,401
Other Special Use Funds          
Nuclear decommissioning trust fund assets          
Fair Value 253,332   253,332   245,095
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 19,830 $ 36,747 36,721 $ 93,202  
Other Special Use Funds | Equity securities          
Nuclear decommissioning trust fund assets          
Equity securities 8,955   8,955   7,142
Other Special Use Funds | Available for sale-fixed income securities          
Nuclear decommissioning trust fund assets          
Fair Value 243,851   243,851   237,479
Other Special Use Funds | Other          
Nuclear decommissioning trust fund assets          
Other 526   526   $ 474
Coal Mine Reclamation Escrow Account | Available for sale-fixed income securities          
Fair value of fixed income securities, summarized by contractual maturities          
Less than one year 37,494   37,494    
1 year – 5 years 11,371   11,371    
5 years – 10 years 1,904   1,904    
Greater than 10 years 9,003   9,003    
Total 59,772   59,772    
Active union medical trust | Available for sale-fixed income securities          
Fair value of fixed income securities, summarized by contractual maturities          
Less than one year 40,673   40,673    
1 year – 5 years 143,406   143,406    
5 years – 10 years 0   0    
Greater than 10 years 0   0    
Total $ 184,079   $ 184,079    
v3.20.2
Changes in Accumulated Other Comprehensive Loss (Details) - USD ($)
$ in Thousands
 3 Months Ended 6 Months Ended
Jun. 30, 2020
Jun. 30, 2019
Jun. 30, 2020
Jun. 30, 2019
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]        
Balance at beginning of period $ 5,596,832 $ 5,381,725 $ 5,553,188 $ 5,348,705
OCI (loss) before reclassifications (3,557) (2,422) (3,265) (2,422)
Amounts reclassified from accumulated other comprehensive loss 1,261 1,287 2,486 2,494
Balance at end of period 5,610,477 5,357,243 5,610,477 5,357,243
Pension and Other Postretirement Benefits        
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]        
Balance at beginning of period (55,317) (45,118) (56,522) (45,997)
OCI (loss) before reclassifications (2,008) (2,422) (2,008) (2,422)
Amounts reclassified from accumulated other comprehensive loss 999 883 2,204 1,762
Balance at end of period (56,326) (46,657) (56,326) (46,657)
Derivative Instruments        
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]        
Balance at beginning of period (262) (1,383) (574) (1,711)
OCI (loss) before reclassifications (1,549) 0 (1,257) 0
Amounts reclassified from accumulated other comprehensive loss 262 404 282 732
Balance at end of period (1,549) (979) (1,549) (979)
Accumulated Other Comprehensive Income (Loss)        
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]        
Balance at beginning of period (55,579) (46,501) (57,096) (47,708)
Balance at end of period (57,875) (47,636) (57,875) (47,636)
APS        
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]        
Balance at beginning of period 6,040,344 5,821,026 5,998,803 5,786,797
OCI (loss) before reclassifications (1,951) (2,414) (1,659) (2,414)
Amounts reclassified from accumulated other comprehensive loss 1,123 1,165 2,156 2,245
Balance at end of period 6,054,137 5,797,857 6,054,137 5,797,857
APS | Pension and Other Postretirement Benefits        
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]        
Balance at beginning of period (33,935) (24,644) (34,948) (25,396)
OCI (loss) before reclassifications (1,951) (2,414) (1,951) (2,414)
Amounts reclassified from accumulated other comprehensive loss 861 761 1,874 1,513
Balance at end of period (35,025) (26,297) (35,025) (26,297)
APS | Derivative Instruments        
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]        
Balance at beginning of period (262) (1,383) (574) (1,711)
OCI (loss) before reclassifications 0 0 292 0
Amounts reclassified from accumulated other comprehensive loss 262 404 282 732
Balance at end of period 0 (979) 0 (979)
APS | Accumulated Other Comprehensive Income (Loss)        
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]        
Balance at beginning of period (34,197) (26,027) (35,522) (27,107)
Balance at end of period $ (35,025) $ (27,276) $ (35,025) $ (27,276)
v3.20.2
Income Taxes (Details) - USD ($)
$ in Millions
 6 Months Ended 12 Months Ended
Jun. 30, 2020
Dec. 31, 2017
Income Tax [Line Items]    
Reduction in net deferred income tax liabilities   $ 1,140.0
Amortization of an excess deferred tax liability $ 13.5  
Regulatory liability, amortization period 28 years 6 months  
Domestic Tax Authority    
Income Tax [Line Items]    
Amortization of an excess deferred tax liability $ 14.0  
v3.20.2
Leases - Additional information (Details)
$ in Millions
Jun. 30, 2020
USD ($)
Lease
Jun. 01, 2020
Lease
Leases [Abstract]    
Number of lease agreements, lease and sell back 3  
Number of lease agreements   2
Lease not yet commenced | $ $ 258  
v3.20.2
Leases - Lease costs (Details) - USD ($)
$ in Thousands
 3 Months Ended 6 Months Ended
Jun. 30, 2020
Jun. 30, 2019
Jun. 30, 2020
Jun. 30, 2019
Operating Leased Assets [Line Items]        
Operating lease cost $ 21,872 $ 18,477 $ 26,525 $ 22,825
Variable lease cost 41,076 41,889 61,892 59,180
Short-term lease cost 996 1,812 1,786 2,665
Total lease cost 63,944 62,178 90,203 84,670
Purchased Power Lease Contracts        
Operating Leased Assets [Line Items]        
Operating lease cost 17,221 14,063 17,221 14,063
Variable lease cost 40,821 41,529 61,394 58,820
Short-term lease cost 0 0 0 0
Total lease cost 58,042 55,592 78,615 72,883
Land, Property & Equipment Leases        
Operating Leased Assets [Line Items]        
Operating lease cost 4,651 4,414 9,304 8,762
Variable lease cost 255 360 498 360
Short-term lease cost 996 1,812 1,786 2,665
Total lease cost $ 5,902 $ 6,586 $ 11,588 $ 11,787
v3.20.2
Leases - Maturity of our operating lease liabilities (Details)
$ in Thousands
Jun. 30, 2020
USD ($)
Lessee, Lease, Description [Line Items]  
2020 (remaining six months of 2020) $ 67,372
2021 79,781
2022 77,820
2023 77,224
2024 76,729
2025 76,823
Thereafter 73,374
Total lease commitments 529,123
Less imputed interest 35,651
Total lease liabilities 493,472
Purchased Power Lease Contracts  
Lessee, Lease, Description [Line Items]  
2020 (remaining six months of 2020) 59,555
2021 66,658
2022 68,325
2023 70,033
2024 71,784
2025 73,578
Thereafter 36,759
Total lease commitments 446,692
Less imputed interest 16,844
Total lease liabilities 429,848
Land, Property & Equipment Leases  
Lessee, Lease, Description [Line Items]  
2020 (remaining six months of 2020) 7,817
2021 13,123
2022 9,495
2023 7,191
2024 4,945
2025 3,245
Thereafter 36,615
Total lease commitments 82,431
Less imputed interest 18,807
Total lease liabilities $ 63,624
v3.20.2
Leases - Other additional information related to operating lease liabilities (Details) - USD ($)
$ in Thousands
 6 Months Ended
Jun. 30, 2020
Jun. 30, 2019
Dec. 31, 2019
Leases [Abstract]      
Weighted average remaining lease term 7 years   13 years
Weighted average discount rate 1.66%   3.71%
Cash paid for amounts included in the measurement of lease liabilities - operating cash flows $ 7,624 $ 11,987  
v3.20.2
Asset Retirement Obligations - Narrative (Details) - APS
$ in Millions
 3 Months Ended
Jun. 30, 2020
USD ($)
Four Corners  
Asset Retirement Obligations  
Asset retirement obligation, period increase (decrease) $ (11)
Navajo Generating Station  
Asset Retirement Obligations  
Asset retirement obligation, period increase (decrease) $ 5
v3.20.2
Asset Retirement Obligations - Roll-Forward (Details) - APS
$ in Thousands
 6 Months Ended
Jun. 30, 2020
USD ($)
Change in asset retirement obligations  
Asset retirement obligations at the beginning of year $ 657,218
Changes attributable to:  
Accretion expense 20,410
Settlements (4,324)
Newly incurred liabilities (5,352)
Asset retirement obligations at the end of year $ 667,952