PINNACLE WEST CAPITAL CORP, 10-Q filed on 10/30/2020
Quarterly Report
v3.20.2
Document and Entity Information - shares
9 Months Ended
Sep. 30, 2020
Oct. 23, 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 Sep. 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)   112,596,784
Document Fiscal Year Focus 2020  
Document Fiscal Period Focus Q3  
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 Sep. 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 Q3  
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 9 Months Ended
Sep. 30, 2020
Sep. 30, 2019
Sep. 30, 2020
Sep. 30, 2019
OPERATING REVENUES (NOTE 2) $ 1,254,501 $ 1,190,787 $ 2,846,021 $ 2,800,818
OPERATING EXPENSES        
Fuel and purchased power 353,171 344,862 780,074 817,672
Operations and maintenance 236,971 238,582 677,681 711,759
Depreciation and amortization 152,696 149,450 459,257 445,531
Taxes other than income taxes 54,978 53,809 168,514 163,989
Other expenses 1,677 794 3,191 1,904
Total 799,493 787,497 2,088,717 2,140,855
OPERATING INCOME 455,008 403,290 757,304 659,963
OTHER INCOME (DEDUCTIONS)        
Allowance for equity funds used during construction 8,144 5,917 24,652 24,677
Pension and other postretirement non-service credits - net 14,118 5,752 42,171 17,240
Other income (Note 9) 13,881 15,191 42,888 35,245
Other expense (Note 9) (5,838) (5,740) (14,426) (14,448)
Total 30,305 21,120 95,285 62,714
INTEREST EXPENSE        
Interest charges 61,497 57,481 183,421 175,599
Allowance for borrowed funds used during construction (4,663) (3,486) (13,488) (14,645)
Total 56,834 53,995 169,933 160,954
INCOME BEFORE INCOME TAXES 428,479 370,415 682,656 561,723
INCOME TAXES 77,234 53,266 98,086 72,764
NET INCOME 351,245 317,149 584,570 488,959
Less: Net income attributable to noncontrolling interests (Note 6) 4,873 4,873 14,620 14,620
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS $ 346,372 $ 312,276 $ 569,950 $ 474,339
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING        
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - BASIC (in shares) 112,679 112,463 112,639 112,408
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - DILUTED (in shares) 112,987 112,746 112,912 112,739
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING        
Net income attributable to common shareholders - basic (in dollars per share) $ 3.07 $ 2.78 $ 5.06 $ 4.22
Net income attributable to common shareholders - diluted (in dollars per share) $ 3.07 $ 2.77 $ 5.05 $ 4.21
APS        
OPERATING REVENUES (NOTE 2) $ 1,254,501 $ 1,190,787 $ 2,846,021 $ 2,800,818
OPERATING EXPENSES        
Fuel and purchased power 353,171 344,862 780,074 817,672
Operations and maintenance 233,452 235,440 667,938 699,958
Depreciation and amortization 152,676 149,428 459,194 445,467
Taxes other than income taxes 54,966 53,798 168,482 163,957
Other expenses 1,677 794 3,191 1,904
Total 795,942 784,322 2,078,879 2,128,958
OPERATING INCOME 458,559 406,465 767,142 671,860
OTHER INCOME (DEDUCTIONS)        
Allowance for equity funds used during construction 8,144 5,917 24,652 24,677
Pension and other postretirement non-service credits - net 14,334 6,133 43,017 18,389
Other income (Note 9) 13,328 14,534 38,233 32,641
Other expense (Note 9) (2,799) (2,826) (11,326) (10,132)
Total 33,007 23,758 94,576 65,575
INTEREST EXPENSE        
Interest charges 59,132 53,812 171,670 164,068
Allowance for borrowed funds used during construction (4,663) (3,486) (13,488) (14,645)
Total 54,469 50,326 158,182 149,423
INCOME BEFORE INCOME TAXES 437,097 379,897 703,536 588,012
INCOME TAXES 81,861 56,154 106,090 76,070
NET INCOME 355,236 323,743 597,446 511,942
Less: Net income attributable to noncontrolling interests (Note 6) 4,873 4,873 14,620 14,620
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS $ 350,363 $ 318,870 $ 582,826 $ 497,322
v3.20.2
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) - USD ($)
$ in Thousands
3 Months Ended 9 Months Ended
Sep. 30, 2020
Sep. 30, 2019
Sep. 30, 2020
Sep. 30, 2019
NET INCOME $ 351,245 $ 317,149 $ 584,570 $ 488,959
Derivative instruments:        
Net unrealized gain, net of tax expense (659) 0 (1,916) 0
Reclassification of net realized loss, net of tax benefit 0 218 282 950
Pension and other postretirement benefits activity, net of tax expense 1,043 880 1,239 220
Total other comprehensive income (loss) 384 1,098 (395) 1,170
COMPREHENSIVE INCOME 351,629 318,247 584,175 490,129
Less: Comprehensive income attributable to noncontrolling interests 4,873 4,873 14,620 14,620
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS 346,756 313,374 569,555 475,509
APS        
NET INCOME 355,236 323,743 597,446 511,942
Derivative instruments:        
Net unrealized gain, net of tax expense 0 0 292 0
Reclassification of net realized loss, net of tax benefit 0 218 282 950
Pension and other postretirement benefits activity, net of tax expense 900 755 823 (146)
Total other comprehensive income (loss) 900 973 1,397 804
COMPREHENSIVE INCOME 356,136 324,716 598,843 512,746
Less: Comprehensive income attributable to noncontrolling interests 4,873 4,873 14,620 14,620
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS $ 351,263 $ 319,843 $ 584,223 $ 498,126
v3.20.2
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) (Parenthetical) - USD ($)
$ in Thousands
3 Months Ended 9 Months Ended
Sep. 30, 2020
Sep. 30, 2019
Sep. 30, 2020
Sep. 30, 2019
Net unrealized loss, net of tax expense $ 219 $ 0 $ 1,024 $ 0
Reclassification of net realized loss, net of tax benefit 0 (71) (481) (313)
Pension and other postretirement benefits activity, net of tax expense (benefit) (345) (290) (256) (72)
APS        
Net unrealized loss, net of tax expense 0 0 292 0
Reclassification of net realized loss, net of tax benefit 0 (71) (481) (313)
Pension and other postretirement benefits activity, net of tax expense (benefit) $ (298) $ (249) $ (174) $ 48
v3.20.2
CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($)
$ in Thousands
Sep. 30, 2020
Dec. 31, 2019
CURRENT ASSETS    
Cash and cash equivalents $ 181,926 $ 10,283
Customer and other receivables 417,415 266,426
Accrued unbilled revenues 175,341 128,165
Allowance for doubtful accounts (18,069) (8,171)
Materials and supplies (at average cost) 322,017 331,091
Fossil fuel (at average cost) 17,060 14,829
Income tax receivable 4,325 21,727
Assets from risk management activities (Note 7) 13,875 515
Deferred fuel and purchased power regulatory asset (Note 4) 162,111 70,137
Other regulatory assets (Note 4) 110,759 133,070
Other current assets 67,926 61,958
Total current assets 1,454,686 1,030,030
INVESTMENTS AND OTHER ASSETS    
Nuclear decommissioning trust (Notes 11 and 12) 1,069,837 1,010,775
Other special use funds (Notes 11 and 12) 268,292 245,095
Other assets 96,855 96,953
Total investments and other assets 1,434,984 1,352,823
PROPERTY, PLANT AND EQUIPMENT    
Plant in service and held for future use 20,453,437 19,836,292
Accumulated depreciation and amortization (6,999,995) (6,637,857)
Net 13,453,442 13,198,435
Construction work in progress 972,024 808,133
Intangible assets, net of accumulated amortization 266,220 290,564
Nuclear fuel, net of accumulated amortization 128,876 123,500
Total property, plant and equipment 14,919,565 14,522,538
DEFERRED DEBITS    
Regulatory assets (Note 4) 1,305,437 1,304,073
Operating lease right-of-use assets (Note 16) 502,898 145,813
Assets for other postretirement benefits (Note 5) 105,675 90,570
Other 28,176 33,400
Total deferred debits 1,942,186 1,573,856
TOTAL ASSETS 19,751,421 18,479,247
CURRENT LIABILITIES    
Current maturities of long-term debt (Note 3) 0 800,000
Accounts payable 288,265 346,448
Accrued taxes 221,358 144,899
Accrued interest 60,642 53,534
Common dividends payable 0 87,982
Short-term borrowings (Note 3) 57,925 114,675
Customer deposits 47,730 64,908
Liabilities from risk management activities (Note 7) 4,266 38,946
Liabilities for asset retirements 12,226 11,025
Operating lease liabilities (Note 16) 89,064 12,713
Regulatory liabilities (Note 4) 308,019 234,912
Other current liabilities 155,289 168,323
Total current liabilities 1,244,784 2,078,365
Long-term debt less current maturities (Note 3) 6,316,420 4,832,558
DEFERRED CREDITS AND OTHER    
Deferred income taxes 2,163,050 1,992,339
Regulatory liabilities (Note 4) 2,079,323 2,267,835
Liabilities for asset retirements 674,025 646,193
Liabilities for pension benefits (Note 5) 177,855 280,185
Liabilities from risk management activities (Note 7) 9,092 33,186
Customer advances 224,924 215,330
Unrecorded Unconditional Purchase Obligation 168,997 165,695
Deferred investment tax credit 187,926 196,468
Unrecognized tax benefits 6,013 6,189
Operating lease liabilities (Note 16) 358,490 51,872
Other 173,347 159,844
Total deferred credits and other 6,223,042 6,015,136
COMMITMENTS AND CONTINGENCIES (NOTE 8)
EQUITY    
Common stock, no par value; authorized 150,000,000 shares, 112,623,623 and 112,540,126 issued at respective dates 2,670,358 2,659,561
Treasury stock at cost; 33,717 and 103,546 shares at respective dates (2,966) (9,427)
Total common stock 2,667,392 2,650,134
Retained earnings 3,231,485 2,837,610
Accumulated other comprehensive loss (57,491) (57,096)
Total shareholders’ equity 5,841,386 5,430,648
Noncontrolling interests (Note 6) 125,789 122,540
Total equity 5,967,175 5,553,188
TOTAL LIABILITIES AND EQUITY 19,751,421 18,479,247
APS    
CURRENT ASSETS    
Cash and cash equivalents 181,793 10,169
Customer and other receivables 417,362 255,479
Accrued unbilled revenues 175,341 128,165
Allowance for doubtful accounts (18,069) (8,171)
Materials and supplies (at average cost) 322,017 331,091
Fossil fuel (at average cost) 17,060 14,829
Income tax receivable 0 7,313
Assets from risk management activities (Note 7) 13,875 515
Deferred fuel and purchased power regulatory asset (Note 4) 162,111 70,137
Other regulatory assets (Note 4) 110,759 133,070
Other current assets 42,847 38,895
Total current assets 1,425,096 981,492
INVESTMENTS AND OTHER ASSETS    
Nuclear decommissioning trust (Notes 11 and 12) 1,069,837 1,010,775
Other special use funds (Notes 11 and 12) 268,292 245,095
Other assets 48,393 43,781
Total investments and other assets 1,386,522 1,299,651
PROPERTY, PLANT AND EQUIPMENT    
Plant in service and held for future use 20,449,975 19,832,805
Accumulated depreciation and amortization (6,996,748) (6,634,597)
Net 13,453,227 13,198,208
Construction work in progress 972,024 808,133
Intangible assets, net of accumulated amortization 266,065 290,409
Nuclear fuel, net of accumulated amortization 128,876 123,500
Total property, plant and equipment 14,919,195 14,522,156
DEFERRED DEBITS    
Regulatory assets (Note 4) 1,305,437 1,304,073
Operating lease right-of-use assets (Note 16) 501,282 144,024
Assets for other postretirement benefits (Note 5) 101,792 86,736
Other 27,592 32,591
Total deferred debits 1,936,103 1,567,424
TOTAL ASSETS 19,666,916 18,370,723
CURRENT LIABILITIES    
Current maturities of long-term debt (Note 3) 0 350,000
Accounts payable 282,868 338,006
Accrued taxes 268,990 136,328
Accrued interest 58,403 52,619
Common dividends payable 0 88,000
Customer deposits 47,730 64,908
Liabilities from risk management activities (Note 7) 4,266 38,946
Liabilities for asset retirements 12,226 11,025
Operating lease liabilities (Note 16) 88,975 12,549
Regulatory liabilities (Note 4) 308,019 234,912
Other current liabilities 153,986 164,736
Total current liabilities 1,225,463 1,492,029
Long-term debt less current maturities (Note 3) 5,820,303 4,833,133
DEFERRED CREDITS AND OTHER    
Deferred income taxes 2,166,599 2,033,096
Regulatory liabilities (Note 4) 2,079,323 2,267,835
Liabilities for asset retirements 674,025 646,193
Liabilities for pension benefits (Note 5) 161,186 262,243
Liabilities from risk management activities (Note 7) 9,092 33,186
Customer advances 224,924 215,330
Unrecorded Unconditional Purchase Obligation 168,997 165,695
Deferred investment tax credit 187,926 196,468
Unrecognized tax benefits 39,589 40,188
Operating lease liabilities (Note 16) 356,783 50,092
Other 142,431 136,432
Total deferred credits and other 6,210,875 6,046,758
COMMITMENTS AND CONTINGENCIES (NOTE 8)
EQUITY    
Common stock 178,162 178,162
Additional paid-in capital 2,721,696 2,721,696
Retained earnings 3,418,753 3,011,927
Accumulated other comprehensive loss (34,125) (35,522)
Total shareholders’ equity 6,284,486 5,876,263
Noncontrolling interests (Note 6) 125,789 122,540
Total equity 6,410,275 5,998,803
Total capitalization 12,230,578 10,831,936
TOTAL LIABILITIES AND EQUITY 19,666,916 18,370,723
Variable Interest Entity    
PROPERTY, PLANT AND EQUIPMENT    
Total property, plant and equipment 99,003 101,906
Variable Interest Entity | APS    
PROPERTY, PLANT AND EQUIPMENT    
Total property, plant and equipment 99,003 101,906
EQUITY    
Noncontrolling interests (Note 6) $ 125,789 $ 122,540
v3.20.2
CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical) - shares
Sep. 30, 2020
Dec. 31, 2019
EQUITY    
Common stock, authorized shares (in shares) 150,000,000 150,000,000
Common stock, issued shares (in shares) 112,623,623 112,540,126
Treasury stock at cost, shares (in shares) 33,717 103,546
v3.20.2
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($)
$ in Thousands
9 Months Ended
Sep. 30, 2020
Sep. 30, 2019
CASH FLOWS FROM OPERATING ACTIVITIES    
NET INCOME $ 584,570 $ 488,959
Adjustments to reconcile net income to net cash provided by operating activities:    
Depreciation and amortization including nuclear fuel 515,742 500,801
Deferred fuel and purchased power (82,679) (60,911)
Deferred fuel and purchased power amortization (9,295) 38,601
Allowance for equity funds used during construction (24,652) (24,677)
Deferred income taxes 91,077 83,703
Deferred investment tax credit (8,541) (7,288)
Stock compensation 12,119 16,486
Customer and other receivables (118,998) (91,506)
Changes in current assets and liabilities:    
Accrued unbilled revenues (47,176) (18,666)
Materials, supplies and fossil fuel 6,843 (18,332)
Income tax receivable 17,402 (14,063)
Other current assets (20,527) (10,104)
Accounts payable (6,400) 33,899
Accrued taxes 76,459 66,111
Other current liabilities 6,946 (68,927)
Change in other long-term assets (10,152) (52,276)
Change in other long-term liabilities (210,719) (27,049)
Net cash flow provided by operating activities 772,019 834,761
CASH FLOWS FROM INVESTING ACTIVITIES    
Capital expenditures (971,052) (857,883)
Contributions in aid of construction 41,457 34,121
Allowance for borrowed funds used during construction (13,488) (14,645)
Proceeds from nuclear decommissioning trust sales and other special use funds 607,885 520,996
Investment in nuclear decommissioning trust and other special use funds (624,249) (523,573)
Other 3,944 8,971
Net cash flow used for investing activities (955,503) (832,013)
CASH FLOWS FROM FINANCING ACTIVITIES    
Issuance of long-term debt 1,483,822 794,981
Short-term borrowing and payments — net (42,750) (6,025)
Short-term debt borrowings 751,690 49,000
Short-term debt repayments (765,690) (62,000)
Repayment of long-term debt (800,000) (500,000)
Dividends paid on common stock (258,924) (243,116)
Common stock equity issuance - net of purchases (1,649) (130)
Distributions to noncontrolling interests (11,372) (11,372)
Net cash flow provided by financing activities 355,127 21,338
NET INCREASE IN CASH AND CASH EQUIVALENTS 171,643 24,086
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 10,283 5,766
CASH AND CASH EQUIVALENTS AT END OF PERIOD 181,926 29,852
APS    
CASH FLOWS FROM OPERATING ACTIVITIES    
NET INCOME 597,446 511,942
Adjustments to reconcile net income to net cash provided by operating activities:    
Depreciation and amortization including nuclear fuel 515,679 500,737
Deferred fuel and purchased power (82,679) (60,911)
Deferred fuel and purchased power amortization (9,295) 38,601
Allowance for equity funds used during construction (24,652) (24,677)
Deferred income taxes 52,795 97,002
Deferred investment tax credit (8,541) (7,288)
Customer and other receivables (129,892) (90,817)
Changes in current assets and liabilities:    
Accrued unbilled revenues (47,176) (18,666)
Materials, supplies and fossil fuel 6,843 (18,332)
Income tax receivable 7,313 (15,982)
Other current assets (18,512) (8,642)
Accounts payable (3,355) 37,004
Accrued taxes 132,662 38,963
Other current liabilities 7,981 (66,368)
Change in other long-term assets (9,478) (54,872)
Change in other long-term liabilities (216,308) (27,521)
Net cash flow provided by operating activities 770,831 830,173
CASH FLOWS FROM INVESTING ACTIVITIES    
Capital expenditures (971,052) (857,883)
Contributions in aid of construction 41,457 34,121
Allowance for borrowed funds used during construction (13,488) (14,645)
Proceeds from nuclear decommissioning trust sales and other special use funds 607,885 520,996
Investment in nuclear decommissioning trust and other special use funds (624,249) (523,573)
Other (1,260) (3,563)
Net cash flow used for investing activities (960,707) (844,547)
CASH FLOWS FROM FINANCING ACTIVITIES    
Issuance of long-term debt 986,872 794,981
Short-term borrowing and payments — net 0 2,900
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 (264,000) (248,300)
Distributions to noncontrolling interests (11,372) (11,372)
Net cash flow provided by financing activities 361,500 38,209
NET INCREASE IN CASH AND CASH EQUIVALENTS 171,624 23,835
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 10,169 5,707
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 181,793 $ 29,542
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 488,959     474,339   14,620 511,942     497,322   14,620
Other comprehensive income (loss) 1,170       1,170   804       804  
Dividends on common stock (165,631)     (165,631)                
Issuance of common stock (in shares)   243,855                    
Issuance of common stock 20,165 $ 20,165                    
Purchase of treasury stock (in shares) [1]     (75,894)                  
Purchase of treasury stock [1] (6,892)   $ (6,892)                  
Reissuance of treasury stock for stock-based compensation and other (in shares)     76,082                  
Reissuance of treasury stock for stock-based compensation and other 6,600   $ 6,600 0                
Other             0     (1)   1
Capital activities by noncontrolling interests (11,372)     0   (11,372) (11,372)         (11,372)
Ending balance (in shares) at Sep. 30, 2019   112,403,751 57,947         71,264,947        
Balance at end of period at Sep. 30, 2019 5,681,705 $ 2,654,430 $ (5,117) 2,949,891 (46,538) 129,039 6,122,571 $ 178,162 2,721,696 3,119,977 (26,303) 129,039
Beginning balance (in shares) at Jun. 30, 2019   112,361,595 58,219         71,264,947        
Balance at beginning 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
Increase (Decrease) in Shareholders' Equity                        
Net Income 317,149     312,276   4,873 323,743     318,870   4,873
Other comprehensive income (loss) 1,098       1,098   973       973  
Dividends on common stock (5)     (5)     (165,600)     (165,600)    
Issuance of common stock (in shares)   42,156                    
Issuance of common stock 6,196 $ 6,196                    
Purchase of treasury stock (in shares)     (103)                  
Purchase of treasury stock (10)   $ (10)                  
Reissuance of treasury stock for stock-based compensation and other (in shares)     375                  
Reissuance of treasury stock for stock-based compensation and other 33   $ 33 0                
Other 1         1 (2)     (3)   1
Ending balance (in shares) at Sep. 30, 2019   112,403,751 57,947         71,264,947        
Balance at end of period at Sep. 30, 2019 $ 5,681,705 $ 2,654,430 $ (5,117) 2,949,891 (46,538) 129,039 6,122,571 $ 178,162 2,721,696 3,119,977 (26,303) 129,039
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 584,570     569,950   14,620 597,446     582,826   14,620
Other comprehensive income (loss) (395)       (395)   1,397       1,397  
Dividends on common stock (176,079)     (176,079)     (176,000)     (176,000)    
Issuance of common stock (in shares)   83,497                    
Issuance of common stock 10,797 $ 10,797                    
Purchase of treasury stock (in shares)     (34,569)                  
Purchase of treasury stock (3,119)   $ (3,119)                  
Reissuance of treasury stock for stock-based compensation and other (in shares)     104,398                  
Reissuance of treasury stock for stock-based compensation and other 9,580   $ 9,580 0                
Other 5     (4)   1 1     0   1
Capital activities by noncontrolling interests $ (11,372)     0   (11,372)           (11,372)
Ending balance (in shares) at Sep. 30, 2020 112,623,623 112,623,623 33,717         71,264,947        
Balance at end of period at Sep. 30, 2020 $ 5,967,175 $ 2,670,358 $ (2,966) 3,231,485 (57,491) 125,789 6,410,275 $ 178,162 2,721,696 3,418,753 (34,125) 125,789
Beginning balance (in shares) at Jun. 30, 2020   112,591,124 35,983         71,264,947        
Balance at beginning 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
Increase (Decrease) in Shareholders' Equity                        
Net Income 351,245     346,372   4,873 355,236     350,363   4,873
Other comprehensive income (loss) 384       384   900       900  
Dividends on common stock 1     1                
Issuance of common stock (in shares)   32,499                    
Issuance of common stock 4,840 $ 4,840                    
Purchase of treasury stock (in shares) [1]     (1,499)                  
Purchase of treasury stock [1] (109)   $ (109)                  
Reissuance of treasury stock for stock-based compensation and other (in shares)     3,765                  
Reissuance of treasury stock for stock-based compensation and other 333   $ 333 0                
Other $ 4         1 2     1   1
Capital activities by noncontrolling interests       3     (11,372)          
Ending balance (in shares) at Sep. 30, 2020 112,623,623 112,623,623 33,717         71,264,947        
Balance at end of period at Sep. 30, 2020 $ 5,967,175 $ 2,670,358 $ (2,966) $ 3,231,485 $ (57,491) $ 125,789 $ 6,410,275 $ 178,162 $ 2,721,696 $ 3,418,753 $ (34,125) $ 125,789
[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
9 Months Ended
Sep. 30, 2020
Sep. 30, 2019
Statement of Stockholders' Equity [Abstract]    
DIVIDENDS DECLARED PER SHARE (in dollars per share) $ 1.57 $ 1.48
v3.20.2
Consolidation and Nature of Operations
9 Months Ended
Sep. 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):
 Nine Months Ended
September 30,
 20202019
Cash paid during the period for:
Income taxes, net of refunds$(3,028)$12,488 
Interest, net of amounts capitalized155,623 166,907 
Significant non-cash investing and financing activities:
Accrued capital expenditures$84,022 $85,099 

The following table summarizes supplemental APS cash flow information (dollars in thousands):
Nine Months Ended
September 30,
 20202019
Cash paid during the period for:
Income taxes, net of refunds$— $35,573 
Interest, net of amounts capitalized148,713 157,593 
Significant non-cash investing and financing activities:
Accrued capital expenditures$84,022 $85,099 

See Note 16 for cash flow information relating to lease activities.
v3.20.2
Revenue
9 Months Ended
Sep. 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 September 30,Nine Months Ended September 30,
2020201920202019
Retail Electric Revenue
Residential$726,231 $668,467 $1,566,432 $1,452,601 
Non-Residential461,168 465,602 1,145,640 1,194,199 
Wholesale energy sales45,631 36,775 76,226 95,218 
Transmission services for others18,000 15,841 48,693 46,247 
Other sources3,471 4,102 9,030 12,553 
Total operating revenues$1,254,501 $1,190,787 $2,846,021 $2,800,818 

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. See "Allowance for Doubtful Accounts" discussion below for additional details regarding payment terms.

Wholesale Energy Sales and Transmission Services for Others. Revenues from wholesale energy sales and transmission services for others represent energy and transmission sales to wholesale customers. These activities primarily consist of managing fuel and purchased power risks in connection with the cost of serving our retail customers' energy requirements. We may also sell into the wholesale markets generation that is not needed for APS’s retail load. Our wholesale activities and tariff rates are regulated by FERC.

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

Revenue Activities

Our revenues primarily consist of activities that are classified as revenues from contracts with customers. We derive our revenues from contracts with customers primarily from sales of electricity to our regulated retail customers. Revenues from contracts with customers also include wholesale and transmission activities. Our revenues from contracts with customers for the three and nine months ended September 30, 2020 were $1,244 million and $2,806 million, respectively, and for the three and nine months ended September 30, 2019 were $1,178 million and $2,756 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 nine months ended September 30, 2020, our revenues that do not qualify as revenue from contracts with customers were $11 million and $40 million, respectively, and for the three and nine months ended September 30, 2019 were $13 million and $45 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 September 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 includes a write-off component that is calculated by applying an estimated write-off factor to retail electric revenues. The write-off factor used to estimate uncollectible accounts is based upon consideration of historical collections experience, the current and forecasted economic environment, changes to our collection policies, and management’s best estimate of future collections success.
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 may experience 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 allowance for doubtful accounts including our write-off factor. On September 14, 2020, APS extended the suspension of disconnection of customers for nonpayment and waiver of late payment fees related to COVID-19 until December 31, 2020. We will continue to monitor the impacts of COVID-19 and our disconnection policies on our write-off factor and allowance for doubtful accounts. See Note 4 for additional details.

The following table provides a rollforward of Pinnacle West’s allowance for doubtful accounts (dollars in thousands):
Nine Months Ended
September 30, 2020
Twelve Months Ended December 31, 2019
Allowance for doubtful accounts, balance at beginning of period$8,171 $4,069 
Bad debt expense17,399 11,819 
Actual write-offs(7,501)(7,717)
Allowance for doubtful accounts, balance at end of period$18,069 $8,171 
v3.20.2
Long-Term Debt and Liquidity Matters
9 Months Ended
Sep. 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 September 30, 2020, Pinnacle West had $24 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 September 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 September 30, 2020, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding and $34 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.

On September 11, 2020, APS issued $400 million of 2.65% unsecured senior notes that mature September 15, 2050. The net proceeds from the sale will be used to replenish cash used for previous eligible green expenditures and fund future eligible green expenditures.

At September 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 September 30, 2020, APS had no outstanding borrowings under its revolving credit facilities, no letters of credit outstanding, and no 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 September 30, 2020As of December 31, 2019
 Carrying
Amount
Fair ValueCarrying
Amount
Fair Value
Pinnacle West$496,117 $507,500 $449,425 $450,822 
APS5,820,303 6,886,108 5,183,133 5,743,570 
Total$6,316,420 $7,393,608 $5,632,558 $6,194,392 
v3.20.2
Regulatory Matters
9 Months Ended
Sep. 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.  On September 14, 2020, APS extended this suspension of disconnection of customers for nonpayment and waiver of late payment fees until December 31, 2020. 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 experiencing 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 current 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 September 30, 2020, APS had refunded approximately $43 million to customers. The additional $7 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 a total of approximately $8 million to assist customers and local non-profits and community organizations to help with the impact of the COVID-19 pandemic, with $6.8 million of these dollars directly committed to bill assistance programs (the “COVID Customer Support Fund”). The COVID Customer Support Fund is comprised of $5.3 million of non-ratepayer funds that APS voluntarily committed to the ACC that it would contribute to providing assistance to residential and non-residential customers that have been impacted by the COVID-19 pandemic and $1.5 million that APS had already provided to assist customers with a one-time credit of $100 on their bill. Included in the COVID Customer Support Fund are programs that assist customers that have a delinquency of two or more months with a one-time credit of $100, programs 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, and other targeted programs allocated to assist with other COVID-19 needs in support of utility bill assistance. Limited income customers can qualify for assistance without restriction on the timing of past due amounts. As of October 21, 2020, APS had distributed $4.3 million for all COVID Customer Support Fund programs combined. Beyond the COVID Customer Support Fund, APS has also provided $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;
a rate of $0.030168 per kWh for the portion of APS’s retail base rates attributable to fuel and purchased power costs ("Base Fuel Rate");
authorization to defer until APS's next general rate case the increase or decrease in its Arizona property taxes attributable to tax rate changes after the date the rate application is adjudicated;
a number of proposed rate and program changes for residential customers, including:
a super off-peak period during the winter months for APS’s time-of-use with demand rates;
additional $1.25 million in funding for APS's limited-income crisis bill program; and
a flat bill/subscription rate pilot program;
proposed rate design changes for commercial customers, including an experimental program designed to provide access to market pricing for up to 200 MW of medium and large commercial customers;
recovery of the deferral and rate base effects of the construction and operating costs of the Ocotillo modernization project (see discussion below of the 2017 Settlement Agreement); and
continued recovery of the remaining investment and other costs related to the retirement and closure of the Navajo Generating Station (the "Navajo Plant") (see "Navajo Plant" below).

APS requested that the increase become effective December 1, 2020.

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

The filed ACC Staff and intervenor testimony include additional recommendations, some of which materially differ from APS’s filed application. APS is continuing to assess all filed testimony and will file rebuttal testimony with updated positions no later than November 6, 2020. The hearing for this rate case was delayed, at the request of the ACC Staff and RUCO, and is currently scheduled to begin December 14, 2020. Unfavorable ACC Staff and intervenor positions and recommendations could have a material impact to APS’s financial statements if ultimately adopted. APS cannot predict the outcome of this proceeding.

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.

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

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. On September 23, 2020, the ACC approved the 2020 RES Implementation Plan including a waiver of the residential distributed energy requirements for the 2020 implementation year. In addition, the ACC approved the implementation of a new pilot program that incentivizes Arizona households to install at-home battery systems. Recovery of the costs associated with the pilot will be addressed in the 2021 Demand Side Management Implementation Plan ("DSM Plan").

On July 1, 2020, APS filed its 2021 RES Implementation Plan and proposed a budget of approximately $84.7 million.  APS’s budget request supports existing approved projects and commitments and requests a permanent waiver of the 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 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 proposed 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 sought a requested budget of $52.6 million and requested a waiver of the Electric Energy Efficiency Standard for 2018.   On November 14, 2017, APS filed an amended 2018 DSM Plan, which revised the allocations between budget items to address customer participation levels but kept the overall budget at $52.6 million.

On December 31, 2018, APS filed its 2019 DSM Plan, which requested a budget of $34.1 million and continued APS's focus on DSM strategies such as peak demand reduction, load shifting, storage and electrification strategies.

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

On April 17, 2020, APS filed an application with the ACC requesting a COVID-19 emergency relief package to provide additional assistance to its customers. On May 5, 2020, the ACC approved APS returning $36 million that had been collected through the DSM Adjustor Charge, but not allocated for current DSM programs, directly to customers through a bill credit in June 2020. As of September 30, 2020, APS had refunded approximately $43 million to customers. The additional $7 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):
 
 Nine Months Ended
September 30,
 20202019
Beginning balance$70,137 $37,164 
Deferred fuel and purchased power costs — current period82,679 60,911 
Amounts refunded/(charged) to customers9,295 (38,601)
Ending balance$162,111 $59,474 
 
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 1 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 million to $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. On September 23, 2020, the ACC approved the annual reduction of the export energy price but voted to delay the effectiveness of the reduction in export
prices until October 1, 2021. APS's export energy price will remain at 10.5 cents per kWh until October 1, 2021.

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 30, 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. 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.

The ACC has discussed the final draft energy rules at several different meetings in 2020. On October 14, 2020, the ACC passed one amendment to ACC Staff’s final draft energy rules which will require electric utilities to obtain 35% of peak load (as measured in 2020) by 2030 from DSM resources, including traditional energy efficiency, demand response and other programs aimed at reducing energy usage, peak demand management and load shifting. This standard aligns with the proposed rules’ three-year resource planning cycle and allows recovery of costs through existing mechanisms until the ACC issues a decision in a future rate process. On October 29, 2020, the ACC approved an amendment which will require electric utilities to reduce their carbon emissions over 2016-2018 levels by 50% by 2032; 75% by 2040; and 100% by 2050. The ACC also approved an amendment which will require utilities to install energy storage systems with an aggregate capacity equal to 5% of each utility’s 2020 peak demand by 2035, of which 40% shall be derived from customer-owned or customer-leased distributed storage. Another approved amendment modifies the resource planning process, including requirements for the ACC to approve a utility’s load forecast and resource plan, and for a utility to perform an all-source request for information to guide its resource plan. The ACC must vote to approve a final draft energy rules package, and additional procedural steps in the rulemaking process are required to be completed before the rules may take effect. 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 Plan" 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 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. 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.

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.

Due to the COVID-19 pandemic, APS voluntarily suspended disconnections of customers for nonpayment beginning March 13, 2020. On September 14, 2020, APS extended this suspension of disconnection of customers for nonpayment until December 31, 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 and Investigation

On November 14, 2019, APS learned that its rate plan comparison tool was not functioning as intended due to an integration error between the tool and 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 hired an outside consultant to evaluate the extent of the error and the overall effectiveness of the tool. On August 20, 2020, ACC Staff filed the outside consultant’s report on APS’s rate comparison tool. The report concluded APS’s new rate comparison tool is working as intended. The report also identified a small population of additional customers that may have been affected by the error and APS has provided refunds and the $25 inconvenience payment to approximately 3,800 additional customers. These additional refunds and payment for inconvenience did not have a material impact on APS's financial statements. On September 28, 2020, the ACC discussed this report but did not take any action. APS cannot predict if any action will be taken by the ACC at this time.

APS received civil investigative demands from the Office of the Arizona Attorney General, Civil Litigation Division, Consumer Protection & Advocacy Section that seek information pertaining to the rate plan comparison tool offered to APS customers and other related issues including implementation of rates from the 2017 Settlement Agreement. APS is fully cooperating with the Attorney General’s Office in this matter. APS cannot predict the outcome of this matter.

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 ($61 million as of September 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 ($74 million as of September 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 ThroughSeptember 30, 2020December 31, 2019
 CurrentNon-CurrentCurrentNon-Current
Pension(a)$— $656,092 $— $660,223 
Income taxes — allowance for funds used during construction ("AFUDC") equity20506,815 159,005 6,800 154,974 
Deferred fuel and purchased power (b) (c)2021162,111 — 70,137 — 
Retired power plant costs203328,182 121,259 28,182 142,503 
Ocotillo deferralN/A— 80,359 — 38,144 
SCR deferralN/A— 74,576 — 52,644 
Deferred property taxes20278,569 51,769 8,569 58,196 
Lost fixed cost recovery (b)202137,868 — 26,067 — 
Deferred compensation2036— 36,481 — 36,464 
Four Corners cost deferral20248,077 26,094 8,077 32,152 
Income taxes — investment tax credit basis adjustment20481,097 23,850 1,098 24,981 
Palo Verde VIEs (Note 6)2046— 21,100 — 20,635 
Coal reclamation20261,068 17,266 1,546 17,688 
Loss on reacquired debt20381,637 10,846 1,637 12,031 
Mead-Phoenix transmission line contributions in aid of construction ("CIAC")2050332 9,463 332 9,712 
Demand Side Management2021— 7,259 — — 
Tax expense adjuster mechanism (b) (c)20206,121 — 1,612 — 
Deferred fuel and purchased power — mark-to-market (Note 7)2024— 5,664 36,887 33,185 
Tax expense of Medicare subsidy20241,238 3,728 1,235 4,940 
AG-1 deferral20222,787 626 2,787 2,716 
TCA balancing account (b)20214,490 — 6,324 2,885 
OtherVarious2,478 — 1,917 — 
Total regulatory assets (d) $272,870 $1,305,437 $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. See Note 5.
(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 ThroughSeptember 30, 2020December 31, 2019
 CurrentNon-CurrentCurrentNon-Current
Excess deferred income taxes - ACC - Tax Cuts and Jobs Act (a)2046$113,206 $952,531 $59,918 $1,054,053 
Excess deferred income taxes - FERC - Tax Cuts and Jobs Act (a)20587,256 229,753 6,302 237,357 
Asset retirement obligations2057— 442,035 — 418,423 
Removal costs(c)51,519 112,168 47,356 136,072 
Other postretirement benefits(d)37,575 109,035 37,575 139,634 
Four Corners coal reclamation20385,461 49,151 1,059 51,704 
Spent nuclear fuel20276,520 46,526 6,676 51,019 
Income taxes — change in rates20502,802 48,541 2,797 68,265 
Income taxes — deferred investment tax credit20482,199 47,765 2,202 50,034 
Renewable energy standard (b)202135,813 1,128 39,287 10,300 
Demand side management (b)202117,394 — 15,024 24,146 
Sundance maintenance20312,200 12,303 5,698 11,319 
Property tax deferralN/A— 11,784 — 7,046 
Deferred fuel and purchased power — mark-to-market (Note 7)202410,894 — — — 
FERC transmission true up20225,965 4,291 1,045 2,004 
Active union medical trustN/A— 6,993 — 2,041 
Tax expense adjustor mechanism (b) (c)20206,542 — 7,018 — 
Deferred gains on utility property20222,423 2,379 2,423 4,163 
TCA balancing account (b)2022— 2,665 — — 
OtherVarious250 275 532 255 
Total regulatory liabilities $308,019 $2,079,323 $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
9 Months Ended
Sep. 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 BenefitsOther Benefits
 Three Months Ended
September 30,
Nine Months Ended
September 30,
Three Months Ended
September 30,
Nine Months Ended
September 30,
 20202019202020192020201920202019
Service cost — benefits earned during the period$14,058 $12,476 $42,174 $37,427 $5,559 $4,593 $16,677 $13,777 
Non-service costs (credits):
Interest cost on benefit obligation29,642 34,211 88,925 102,632 6,464 7,473 19,393 22,420 
Expected return on plan assets(46,861)(42,971)(140,582)(128,913)(10,019)(9,603)(30,057)(28,809)
  Amortization of:       
  Prior service credit— — — — (9,394)(9,456)(28,182)(28,366)
  Net actuarial loss8,653 10,646 25,959 31,938 — — — — 
Net periodic benefit cost (credit)$5,492 $14,362 $16,476 $43,084 $(7,390)$(6,993)$(22,169)$(20,978)
Portion of cost (credit) charged to expense$736 $7,593 $2,349 $22,837 $(5,286)$(4,966)$(15,798)$(14,846)
 
Contributions
 
We have made voluntary contributions of $100 million to our pension plan year-to-date in 2020. The minimum required contributions for the pension plan are zero for the 2020-2022 period. We expect to make voluntary contributions up to $100 million per year during this period. We do not expect to make any contributions over this period to our other postretirement benefit plans.
v3.20.2
Palo Verde Sale Leaseback Variable Interest Entities
9 Months Ended
Sep. 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 nine months ended September 30, 2020 of $5 million and $15 million, respectively, and for the three and nine months ended September 30, 2019 of $5 million and $15 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 September 30, 2020 and December 31, 2019 include the following amounts relating to the VIEs (dollars in thousands):
 
September 30, 2020December 31, 2019
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation
$99,003