PINNACLE WEST CAPITAL CORP, 10-Q filed on 8/5/2021
Quarterly Report
v3.21.2
Cover Page - shares
6 Months Ended
Jun. 30, 2021
Jul. 29, 2021
Entity Information [Line Items]    
Document Type 10-Q  
Document Quarterly Report true  
Document Period End Date Jun. 30, 2021  
Document Transition Report false  
Entity File Number 1-8962  
Entity Registrant Name PINNACLE WEST CAPITAL CORPORATION  
Entity Tax Identification Number 86-0512431  
Entity Incorporation, State or Country Code AZ  
Entity Address, Address Line One 400 North Fifth Street, P.O. Box 53999  
Entity Address, City or Town Phoenix  
Entity Address, State or Province AZ  
Entity Address, Postal Zip Code 85072-3999  
City Area Code (602)  
Local Phone Number 250-1000  
Title of 12(b) Security Common Stock  
Trading Symbol PNW  
Security Exchange Name NYSE  
Entity Current Reporting Status Yes  
Entity Interactive Data Current Yes  
Entity Filer Category Large Accelerated Filer  
Entity Small Business false  
Entity Emerging Growth Company false  
Entity Shell Company false  
Entity Common Stock, Shares Outstanding   112,785,588
Entity Central Index Key 0000764622  
Amendment Flag false  
Current Fiscal Year End Date --12-31  
Document Fiscal Year Focus 2021  
Document Fiscal Period Focus Q2  
APS    
Entity Information [Line Items]    
Document Type 10-Q  
Document Period End Date Jun. 30, 2021  
Entity File Number 1-4473  
Entity Registrant Name ARIZONA PUBLIC SERVICE COMPANY  
Entity Tax Identification Number 86-0011170  
Entity Incorporation, State or Country Code AZ  
Entity Address, Address Line One 400 North Fifth Street, P.O. Box 53999  
Entity Address, City or Town Phoenix  
Entity Address, State or Province AZ  
Entity Address, Postal Zip Code 85072-3999  
City Area Code (602)  
Local Phone Number 250-1000  
Entity Current Reporting Status Yes  
Entity Interactive Data Current Yes  
Entity Filer Category Non-accelerated Filer  
Entity Small Business false  
Entity Emerging Growth Company false  
Entity Shell Company false  
Entity Common Stock, Shares Outstanding   71,264,947
Entity Central Index Key 0000007286  
Amendment Flag false  
Current Fiscal Year End Date --12-31  
Document Fiscal Year Focus 2021  
Document Fiscal Period Focus Q2  
v3.21.2
CONDENSED CONSOLIDATED STATEMENTS OF INCOME - USD ($)
shares in Thousands, $ in Thousands
3 Months Ended 6 Months Ended
Jun. 30, 2021
Jun. 30, 2020
Jun. 30, 2021
Jun. 30, 2020
OPERATING REVENUES (NOTE 2) $ 1,000,249 $ 929,590 $ 1,696,724 $ 1,591,520
OPERATING EXPENSES        
Fuel and purchased power 269,835 238,382 468,062 426,903
Operations and maintenance 229,690 219,392 459,745 440,710
Depreciation and amortization 158,750 152,482 316,570 306,561
Taxes other than income taxes 59,495 56,768 118,978 113,536
Other expenses 4,093 692 7,449 1,514
Total 721,863 667,716 1,370,804 1,289,224
OPERATING INCOME 278,386 261,874 325,920 302,296
OTHER INCOME (DEDUCTIONS)        
Allowance for equity funds used during construction 9,990 8,811 19,197 16,508
Pension and other postretirement non-service credits — net 28,175 14,142 55,966 28,053
Other income (Note 9) 12,207 16,670 24,636 29,239
Other expense (Note 9) (5,184) (4,036) (9,037) (8,820)
Total 45,188 35,587 90,762 64,980
INTEREST EXPENSE        
Interest charges 62,777 62,690 124,715 121,924
Allowance for borrowed funds used during construction (5,199) (4,749) (10,193) (8,825)
Total 57,578 57,941 114,522 113,099
INCOME BEFORE INCOME TAXES 265,996 239,520 302,160 254,177
INCOME TAXES 46,560 41,061 42,210 20,852
NET INCOME 219,436 198,459 259,950 233,325
Less: Net income attributable to noncontrolling interests (Note 6) 3,739 4,874 8,612 9,747
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS $ 215,697 $ 193,585 $ 251,338 $ 223,578
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING        
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - BASIC (in shares) 112,882 112,638 112,855 112,616
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - DILUTED (in shares) 113,223 112,879 113,158 112,871
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING        
Net income attributable to common shareholders - basic (in dollars per share) $ 1.91 $ 1.72 $ 2.23 $ 1.99
Net income attributable to common shareholders - diluted (in dollars per share) $ 1.91 $ 1.71 $ 2.22 $ 1.98
APS        
OPERATING REVENUES (NOTE 2) $ 1,000,249 $ 929,590 $ 1,696,724 $ 1,591,520
OPERATING EXPENSES        
Fuel and purchased power 269,835 238,382 468,062 426,903
Operations and maintenance 226,698 216,221 453,099 434,486
Depreciation and amortization 158,728 152,460 316,528 306,518
Taxes other than income taxes 59,478 56,758 118,950 113,516
Other expenses 4,093 692 7,449 1,514
Total 718,832 664,513 1,364,088 1,282,937
OPERATING INCOME 281,417 265,077 332,636 308,583
OTHER INCOME (DEDUCTIONS)        
Allowance for equity funds used during construction 9,990 8,811 19,197 16,508
Pension and other postretirement non-service credits — net 28,234 14,421 56,071 28,683
Other income (Note 9) 11,563 13,272 23,523 24,905
Other expense (Note 9) (4,261) (3,859) (7,611) (8,527)
Total 45,526 32,645 91,180 61,569
INTEREST EXPENSE        
Interest charges 59,930 56,802 119,318 112,538
Allowance for borrowed funds used during construction (5,199) (4,749) (10,193) (8,825)
Total 54,731 52,053 109,125 103,713
INCOME BEFORE INCOME TAXES 272,212 245,669 314,691 266,439
INCOME TAXES 48,725 43,677 51,044 24,229
NET INCOME 223,487 201,992 263,647 242,210
Less: Net income attributable to noncontrolling interests (Note 6) 3,739 4,874 8,612 9,747
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS $ 219,748 $ 197,118 $ 255,035 $ 232,463
v3.21.2
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($)
$ in Thousands
3 Months Ended 6 Months Ended
Jun. 30, 2021
Jun. 30, 2020
Jun. 30, 2021
Jun. 30, 2020
NET INCOME $ 219,436 $ 198,459 $ 259,950 $ 233,325
Derivative instruments:        
Net unrealized gain, net of tax benefit (expense) 870 (1,549) 1,132 (1,257)
Reclassification of net realized gain, net of tax benefit (expense) 0 262 0 282
Pension and other postretirement benefit activity, net of tax expense (benefit) 64 (1,009) 1,086 196
Total other comprehensive income 934 (2,296) 2,218 (779)
COMPREHENSIVE INCOME 220,370 196,163 262,168 232,546
Less: Comprehensive income attributable to noncontrolling interests 3,739 4,874 8,612 9,747
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS 216,631 191,289 253,556 222,799
APS        
NET INCOME 223,487 201,992 263,647 242,210
Derivative instruments:        
Net unrealized gain, net of tax benefit (expense) 0 0 0 292
Reclassification of net realized gain, net of tax benefit (expense) 0 262 0 282
Pension and other postretirement benefit activity, net of tax expense (benefit) 159 (1,090) 1,086 (77)
Total other comprehensive income 159 (828) 1,086 497
COMPREHENSIVE INCOME 223,646 201,164 264,733 242,707
Less: Comprehensive income attributable to noncontrolling interests 3,739 4,874 8,612 9,747
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS $ 219,907 $ 196,290 $ 256,121 $ 232,960
v3.21.2
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($)
$ in Thousands
3 Months Ended 6 Months Ended
Jun. 30, 2021
Jun. 30, 2020
Jun. 30, 2021
Jun. 30, 2020
Net unrealized gain, tax benefit (expense) $ (286) $ 513 $ (372) $ 805
Reclassification of net realized gain, tax expense 0 87 0 481
Pension and other postretirement benefits activity, tax benefit (expense) (21) 334 (357) 90
APS        
Net unrealized gain, tax benefit (expense) 0 0 0 292
Reclassification of net realized gain, tax expense 0 87 0 481
Pension and other postretirement benefits activity, tax benefit (expense) $ (53) $ 361 $ (357) $ 124
v3.21.2
CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($)
$ in Thousands
Jun. 30, 2021
Dec. 31, 2020
CURRENT ASSETS    
Cash and cash equivalents $ 14,146 $ 59,968
Customer and other receivables 357,130 313,576
Accrued unbilled revenues 223,918 132,197
Allowance for doubtful accounts (Note 2) (22,769) (19,782)
Materials and supplies (at average cost) 340,672 314,745
Fossil fuel (at average cost) 25,074 19,552
Income tax receivable 0 6,792
Assets from risk management activities (Note 7) 82,309 2,931
Deferred fuel and purchased power regulatory asset (Note 4) 300,912 175,835
Other regulatory assets (Note 4) 119,890 115,878
Other current assets 81,901 76,627
Total current assets 1,523,183 1,198,319
INVESTMENTS AND OTHER ASSETS    
Nuclear decommissioning trusts (Notes 11 and 12) 1,223,088 1,138,435
Other special use funds (Notes 11 and 12) 358,436 254,509
Other assets 112,091 92,922
Total investments and other assets 1,693,615 1,485,866
PROPERTY, PLANT AND EQUIPMENT    
Plant in service and held for future use 21,236,805 20,837,885
Accumulated depreciation and amortization (7,278,877) (7,110,310)
Net 13,957,928 13,727,575
Construction work in progress 1,062,911 937,384
Palo Verde sale leaseback, net of accumulated depreciation (Note 6) 96,101 98,036
Intangible assets, net of accumulated amortization 279,911 282,570
Nuclear fuel, net of accumulated amortization 109,110 113,645
Total property, plant and equipment 15,505,961 15,159,210
DEFERRED DEBITS    
Regulatory assets (Note 4) 1,173,977 1,133,987
Operating lease right-of-use assets (Note 15) 718,948 505,064
Assets for pension and other postretirement benefits (Note 5) 407,821 502,992
Other 38,073 34,983
Total deferred debits 2,338,819 2,177,026
TOTAL ASSETS 21,061,578 20,020,421
CURRENT LIABILITIES    
Accounts payable 377,157 318,585
Accrued taxes 183,037 159,551
Accrued interest 56,864 56,962
Common dividends payable 93,610 93,531
Short-term borrowings (Note 3) 504,700 169,000
Current maturities of long-term debt (Note 3) 150,000 0
Customer deposits 44,419 48,340
Liabilities from risk management activities (Note 7) 1,512 7,557
Liabilities for asset retirements (Note 16) 15,646 15,586
Operating lease liabilities (Note 15) 128,673 74,785
Regulatory liabilities (Note 4) 327,612 229,088
Other current liabilities 140,038 187,448
Total current liabilities 2,023,268 1,360,433
Long-term debt less current maturities (Note 3) 6,315,927 6,314,266
DEFERRED CREDITS AND OTHER    
Deferred income taxes 2,192,169 2,135,403
Regulatory liabilities (Note 4) 2,443,312 2,450,169
Liabilities for asset retirements (Note 16) 716,344 689,497
Liabilities for pension benefits (Note 5) 163,207 166,484
Liabilities from risk management activities (Note 7) 0 11,062
Customer advances 247,531 221,032
Coal mine reclamation 172,357 170,097
Deferred investment tax credit 187,720 191,372
Unrecognized tax benefits 6,002 5,834
Operating lease liabilities (Note 15) 547,164 361,336
Other 211,678 190,643
Total deferred credits and other 6,887,484 6,592,929
COMMITMENTS AND CONTINGENCIES (NOTE 8)
EQUITY    
Common stock, no par value; authorized 150,000,000 shares, 112,819,703 and 112,760,051 issued at respective dates 2,692,015 2,677,482
Treasury stock at cost; 36,153 and 72,006 shares at respective dates (3,079) (6,289)
Total common stock 2,688,936 2,671,193
Retained earnings 3,089,266 3,025,106
Accumulated other comprehensive loss (60,578) (62,796)
Total shareholders’ equity 5,717,624 5,633,503
Noncontrolling interests (Note 6) 117,275 119,290
Total equity 5,834,899 5,752,793
TOTAL LIABILITIES AND EQUITY 21,061,578 20,020,421
APS    
CURRENT ASSETS    
Cash and cash equivalents 11,954 57,310
Customer and other receivables 357,023 312,644
Accrued unbilled revenues 223,918 132,197
Allowance for doubtful accounts (Note 2) (22,769) (19,782)
Materials and supplies (at average cost) 340,672 314,745
Fossil fuel (at average cost) 25,074 19,552
Assets from risk management activities (Note 7) 82,309 2,931
Deferred fuel and purchased power regulatory asset (Note 4) 300,912 175,835
Other regulatory assets (Note 4) 119,890 115,878
Other current assets 51,482 47,593
Total current assets 1,490,465 1,158,903
INVESTMENTS AND OTHER ASSETS    
Nuclear decommissioning trusts (Notes 11 and 12) 1,223,088 1,138,435
Other special use funds (Notes 11 and 12) 358,436 254,509
Other assets 68,248 46,010
Total investments and other assets 1,649,772 1,438,954
PROPERTY, PLANT AND EQUIPMENT    
Plant in service and held for future use 21,233,344 20,834,424
Accumulated depreciation and amortization (7,275,617) (7,107,058)
Net 13,957,727 13,727,366
Construction work in progress 1,062,911 937,384
Palo Verde sale leaseback, net of accumulated depreciation (Note 6) 96,101 98,036
Intangible assets, net of accumulated amortization 279,755 282,415
Nuclear fuel, net of accumulated amortization 109,110 113,645
Total property, plant and equipment 15,505,604 15,158,846
DEFERRED DEBITS    
Regulatory assets (Note 4) 1,173,977 1,133,987
Operating lease right-of-use assets (Note 15) 717,411 503,475
Assets for pension and other postretirement benefits (Note 5) 400,414 495,673
Other 37,210 34,413
Total deferred debits 2,329,012 2,167,548
TOTAL ASSETS 20,974,853 19,924,251
CURRENT LIABILITIES    
Accounts payable 369,905 311,699
Accrued taxes 193,409 148,970
Accrued interest 56,202 56,322
Common dividends payable 93,500 93,500
Short-term borrowings (Note 3) 495,000 0
Customer deposits 44,419 48,340
Liabilities from risk management activities (Note 7) 1,512 7,557
Liabilities for asset retirements (Note 16) 15,646 15,586
Operating lease liabilities (Note 15) 128,578 74,695
Regulatory liabilities (Note 4) 327,612 229,088
Other current liabilities 142,926 190,420
Total current liabilities 1,868,709 1,176,177
Long-term debt less current maturities (Note 3) 5,819,198 5,817,945
DEFERRED CREDITS AND OTHER    
Deferred income taxes 2,192,580 2,143,673
Regulatory liabilities (Note 4) 2,443,312 2,450,169
Liabilities for asset retirements (Note 16) 716,344 689,497
Liabilities for pension benefits (Note 5) 146,728 148,943
Liabilities from risk management activities (Note 7) 0 11,062
Customer advances 247,531 221,032
Coal mine reclamation 172,357 170,097
Deferred investment tax credit 187,720 191,372
Unrecognized tax benefits 39,995 39,410
Operating lease liabilities (Note 15) 545,534 359,653
Other 182,555 160,036
Total deferred credits and other 6,874,656 6,584,944
COMMITMENTS AND CONTINGENCIES (NOTE 8)
EQUITY    
Common stock 178,162 178,162
Additional paid-in capital 2,871,696 2,871,696
Retained earnings 3,284,989 3,216,955
Accumulated other comprehensive loss (39,832) (40,918)
Total shareholders’ equity 6,295,015 6,225,895
Noncontrolling interests (Note 6) 117,275 119,290
Total equity 6,412,290 6,345,185
Total capitalization 12,231,488 12,163,130
TOTAL LIABILITIES AND EQUITY $ 20,974,853 $ 19,924,251
v3.21.2
CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - shares
Jun. 30, 2021
Dec. 31, 2020
EQUITY    
Common stock, authorized shares (in shares) 150,000,000 150,000,000
Common stock, issued shares (in shares) 112,819,703 112,760,051
Treasury stock at cost, shares (in shares) 36,153 72,006
v3.21.2
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)
$ in Thousands
6 Months Ended
Jun. 30, 2021
Jun. 30, 2020
CASH FLOWS FROM OPERATING ACTIVITIES    
Net Income $ 259,950 $ 233,325
Adjustments to reconcile net income to net cash provided by operating activities:    
Depreciation and amortization including nuclear fuel 350,536 343,173
Deferred fuel and purchased power (135,905) (26,473)
Deferred fuel and purchased power amortization 10,828 (4,815)
Allowance for equity funds used during construction (19,197) (16,508)
Deferred income taxes 30,231 22,229
Deferred investment tax credit (3,651) (3,386)
Stock compensation 13,484 9,130
Changes in current assets and liabilities:    
Customer and other receivables (41,138) 7,767
Accrued unbilled revenues (91,721) (63,413)
Materials, supplies and fossil fuel (31,449) 10,295
Income tax receivable 6,792 4,605
Other current assets (14,021) (24,896)
Accounts payable 66,558 17,772
Accrued taxes 23,486 6,588
Other current liabilities (39,638) (45,334)
Change in other long-term assets (118,036) (4,885)
Change in other long-term liabilities 45,241 (96,142)
Net cash flow provided by operating activities 312,350 369,032
CASH FLOWS FROM INVESTING ACTIVITIES    
Capital expenditures (681,148) (676,973)
Contributions in aid of construction 32,104 31,295
Allowance for borrowed funds used during construction (10,193) (8,825)
Proceeds from nuclear decommissioning trusts sales and other special use funds 587,842 391,859
Investment in nuclear decommissioning trusts and other special use funds (588,982) (393,000)
Other 10,809 3,123
Net cash flow used for investing activities (649,568) (652,521)
CASH FLOWS FROM FINANCING ACTIVITIES    
Issuance of long-term debt 150,000 1,088,886
Short-term borrowing and (repayments) — net 354,700 184,225
Short-term debt borrowings under revolving credit facility 0 751,690
Short-term debt repayments under revolving credit facility (19,000) (758,690)
Dividends paid on common stock (183,500) (172,566)
Repayment of long-term debt 0 (800,000)
Common stock equity issuance — net of purchases (176) (2,204)
Distributions to noncontrolling interests (10,628) (11,372)
Net cash flow provided by financing activities 291,396 279,969
NET DECREASE IN CASH AND CASH EQUIVALENTS (45,822) (3,520)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 59,968 10,283
CASH AND CASH EQUIVALENTS AT END OF PERIOD 14,146 6,763
APS    
CASH FLOWS FROM OPERATING ACTIVITIES    
Net Income 263,647 242,210
Adjustments to reconcile net income to net cash provided by operating activities:    
Depreciation and amortization including nuclear fuel 350,494 343,130
Deferred fuel and purchased power (135,905) (26,473)
Deferred fuel and purchased power amortization 10,828 (4,815)
Allowance for equity funds used during construction (19,197) (16,508)
Deferred income taxes 23,161 15,233
Deferred investment tax credit (3,651) (3,386)
Changes in current assets and liabilities:    
Customer and other receivables (41,963) 824
Accrued unbilled revenues (91,721) (63,413)
Materials, supplies and fossil fuel (31,449) 10,295
Income tax receivable 0 7,313
Other current assets (12,636) (19,752)
Accounts payable 66,192 17,915
Accrued taxes 44,439 14,551
Other current liabilities (39,749) (40,381)
Change in other long-term assets (114,154) (7,356)
Change in other long-term liabilities 46,327 (91,983)
Net cash flow provided by operating activities 314,663 377,404
CASH FLOWS FROM INVESTING ACTIVITIES    
Capital expenditures (681,148) (676,973)
Contributions in aid of construction 32,104 31,295
Allowance for borrowed funds used during construction (10,193) (8,825)
Proceeds from nuclear decommissioning trusts sales and other special use funds 587,842 391,859
Investment in nuclear decommissioning trusts and other special use funds (588,982) (393,000)
Other 2,986 (169)
Net cash flow used for investing activities (657,391) (655,813)
CASH FLOWS FROM FINANCING ACTIVITIES    
Issuance of long-term debt 0 591,936
Short-term borrowing and (repayments) — net 495,000 219,900
Short-term debt borrowings under revolving credit facility 0 540,000
Short-term debt repayments under revolving credit facility 0 (540,000)
Dividends paid on common stock (187,000) (176,000)
Repayment of long-term debt 0 (350,000)
Distributions to noncontrolling interests (10,628) (11,372)
Net cash flow provided by financing activities 297,372 274,464
NET DECREASE IN CASH AND CASH EQUIVALENTS (45,356) (3,945)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 57,310 10,169
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 11,954 $ 6,224
v3.21.2
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY - USD ($)
$ in Thousands
Total
Common Stock
Treasury Stock
Retained Earnings
Accumulated Other Comprehensive Income (Loss)
Noncontrolling Interests
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, 2019   112,540,126 103,546         71,264,947        
Balance at beginning of period at Dec. 31, 2019 $ 5,553,188 $ 2,659,561 $ (9,427) $ 2,837,610 $ (57,096) $ 122,540 $ 5,998,803 $ 178,162 $ 2,721,696 $ 3,011,927 $ (35,522) $ 122,540
Increase (Decrease) in Shareholders' Equity                        
Net Income 233,325     223,578   9,747 242,210     232,463   9,747
Other comprehensive income (loss) (779)       (779)   497       497  
Dividends on common stock (176,079)     (176,079)     (176,000)     (176,000)    
Issuance of common stock (in shares)   50,998                    
Issuance of common stock 5,957 $ 5,957                    
Purchase of treasury stock (in shares) [1]     (33,070)                  
Purchase of treasury stock [1] (3,010)   $ (3,010)                  
Reissuance of treasury stock for stock-based compensation and other (in shares)     100,633                  
Reissuance of treasury stock for stock-based compensation and other 9,247   $ 9,247                  
Other             (1)     (1)    
Capital activities by noncontrolling interests (11,372)         (11,372) (11,372)         (11,372)
Ending balance (in shares) at Jun. 30, 2020   112,591,124 35,983         71,264,947        
Balance at end of period at Jun. 30, 2020 5,610,477 $ 2,665,518 $ (3,190) 2,885,109 (57,875) 120,915 6,054,137 $ 178,162 2,721,696 3,068,389 (35,025) 120,915
Beginning balance (in shares) at Mar. 31, 2020   112,563,610 72,302         71,264,947        
Balance at beginning of period at Mar. 31, 2020 5,596,832 $ 2,664,387 $ (7,000) 2,867,610 (55,579) 127,414 6,040,344 $ 178,162 2,721,696 3,047,269 (34,197) 127,414
Increase (Decrease) in Shareholders' Equity                        
Net Income 198,459     193,585   4,874 201,992     197,118   4,874
Other comprehensive income (loss) (2,296)       (2,296)   (828)       (828)  
Dividends on common stock (176,086)     (176,086)     (176,000)     (176,000)    
Issuance of common stock (in shares)   27,514                    
Issuance of common stock 1,131 $ 1,131                    
Purchase of treasury stock (in shares) [2]     (12,346)                  
Purchase of treasury stock [2] (924)   $ (924)                  
Reissuance of treasury stock for stock-based compensation and other (in shares)     48,665                  
Reissuance of treasury stock for stock-based compensation and other 4,734   $ 4,734                  
Other (1)         (1) 1     2   (1)
Capital activities by noncontrolling interests (11,372)         (11,372) (11,372)         (11,372)
Ending balance (in shares) at Jun. 30, 2020   112,591,124 35,983         71,264,947        
Balance at end of period at Jun. 30, 2020 $ 5,610,477 $ 2,665,518 $ (3,190) 2,885,109 (57,875) 120,915 6,054,137 $ 178,162 2,721,696 3,068,389 (35,025) 120,915
Beginning balance (in shares) at Dec. 31, 2020 112,760,051 112,760,051 72,006         71,264,947        
Balance at beginning of period at Dec. 31, 2020 $ 5,752,793 $ 2,677,482 $ (6,289) 3,025,106 (62,796) 119,290 6,345,185 $ 178,162 2,871,696 3,216,955 (40,918) 119,290
Increase (Decrease) in Shareholders' Equity                        
Net Income 259,950     251,338   8,612 263,647     255,035   8,612
Other comprehensive income (loss) 2,218       2,218   1,086       1,086  
Dividends on common stock (187,176)     (187,176)     (187,000)     (187,000)    
Issuance of common stock (in shares)   59,652                    
Issuance of common stock 14,533 $ 14,533                    
Purchase of treasury stock (in shares) [1]     (17,437)                  
Purchase of treasury stock [1] (1,333)   $ (1,333)                  
Reissuance of treasury stock for stock-based compensation and other (in shares)     53,290                  
Reissuance of treasury stock for stock-based compensation and other 4,543   $ 4,543                  
Other (1)     (2)   1 0     (1)   1
Capital activities by noncontrolling interests $ (10,628)         (10,628) (10,628)         (10,628)
Ending balance (in shares) at Jun. 30, 2021 112,819,703 112,819,703 36,153         71,264,947        
Balance at end of period at Jun. 30, 2021 $ 5,834,899 $ 2,692,015 $ (3,079) 3,089,266 (60,578) 117,275 6,412,290 $ 178,162 2,871,696 3,284,989 (39,832) 117,275
Beginning balance (in shares) at Mar. 31, 2021   112,791,565 44,338         71,264,947        
Balance at beginning of period at Mar. 31, 2021 5,806,680 $ 2,687,052 $ (3,776) 3,060,752 (61,512) 124,164 6,386,275 $ 178,162 2,871,696 3,252,244 (39,991) 124,164
Increase (Decrease) in Shareholders' Equity                        
Net Income 219,436     215,697   3,739 223,487     219,748   3,739
Other comprehensive income (loss) 934       934   159       159  
Dividends on common stock (187,181)     (187,181)     (187,000)     (187,000)    
Issuance of common stock (in shares)   28,138                    
Issuance of common stock 4,963 $ 4,963                    
Reissuance of treasury stock for stock-based compensation and other (in shares)     8,185                  
Reissuance of treasury stock for stock-based compensation and other 697   $ 697                  
Other (2)     (2)     (3)     (3)    
Capital activities by noncontrolling interests $ (10,628)         (10,628) (10,628)         (10,628)
Ending balance (in shares) at Jun. 30, 2021 112,819,703 112,819,703 36,153         71,264,947        
Balance at end of period at Jun. 30, 2021 $ 5,834,899 $ 2,692,015 $ (3,079) $ 3,089,266 $ (60,578) $ 117,275 $ 6,412,290 $ 178,162 $ 2,871,696 $ 3,284,989 $ (39,832) $ 117,275
[1] Primarily represents shares of common stock withheld from certain stock awards for tax purposes.
[2] Primarily represents shares of common stock withheld from certain stock awards for tax purposes.
v3.21.2
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Parenthetical) - $ / shares
3 Months Ended 6 Months Ended
Jun. 30, 2021
Jun. 30, 2020
Jun. 30, 2021
Jun. 30, 2020
Statement of Stockholders' Equity [Abstract]        
Dividends on common stock (in dollars per share) $ 1.66 $ 1.57 $ 1.66 $ 1.57
v3.21.2
Consolidation and Nature of Operations
6 Months Ended
Jun. 30, 2021
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 2020 Form 10-K.

On June 30, 2020, the United States Federal Energy Regulatory Commission (“FERC”) issued an order granting a waiver request related to the existing Allowance for Funds Used During Construction (“AFUDC”) rate calculation beginning March 1, 2020 through February 28, 2021.  On February 23, 2021, this waiver was extended until September 30, 2021. 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 both 2020 and 2021 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 2020 Form 10-K for information on the accounting treatment for AFUDC.
Supplemental Cash Flow Information

The following table summarizes supplemental Pinnacle West cash flow information (dollars in thousands):
 Six Months Ended
June 30,
 20212020
Cash paid (received) during the period for:
Income taxes, net of refunds$(788)$(3,028)
Interest, net of amounts capitalized112,010 107,417 
Significant non-cash investing and financing activities:
Accrued capital expenditures$105,515 $87,815 
Dividends accrued but not yet paid93,610 88,066 

The following table summarizes supplemental APS cash flow information (dollars in thousands):
Six Months Ended
June 30,
 20212020
Cash paid (received) during the period for:
Income taxes, net of refunds$3,317 $— 
Interest, net of amounts capitalized107,044 100,991 
Significant non-cash investing and financing activities:
Accrued capital expenditures$105,515 $87,815 
Dividends accrued but not yet paid93,500 88,000 
v3.21.2
Revenue
6 Months Ended
Jun. 30, 2021
Revenue from Contract with Customer [Abstract]  
Revenue Revenue
Sources of Revenue
The following table provides detail of Pinnacle West’s consolidated revenue disaggregated by revenue sources (dollars in thousands):
Three Months Ended June 30,Six Months Ended June 30,
2021202020212020
Retail Electric Revenue
Residential$531,717 $515,128 $872,555 $840,201 
Non-Residential420,995 381,121 735,778 684,472 
Wholesale Energy Sales18,007 15,927 35,604 30,595 
Transmission Services for Others22,579 14,766 41,572 30,693 
Other Sources6,951 2,648 11,215 5,559 
Total operating revenues$1,000,249 $929,590 $1,696,724 $1,591,520 

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 six months ended June 30, 2021 were $980 million and $1,663 million, respectively and for the three and six months ended June 30, 2020 were $915 million and $1,563 million, respectively.

We have certain revenues that do not meet the specific accounting criteria to be classified as revenues from contracts with customers. For the three and six months ended June 30, 2021 our revenues that do not qualify as revenue from contracts with customers were $20 million and $34 million, respectively, and for the three and six months ended June 30, 2020 were $15 million and $29 million, respectively. This relates primarily to certain regulatory cost recovery mechanisms that are considered alternative revenue programs. We recognize revenue associated with alternative revenue programs when specific events permitting recognition are completed. Certain amounts associated with alternative revenue programs will subsequently be billed to customers; however, we do not reclassify billed amounts into revenue from contracts with customers. See Note 4 for a discussion of our regulatory cost recovery mechanisms.

Contract Assets and Liabilities from Contracts with Customers

There were no material contract assets, contract liabilities, or deferred contract costs recorded on the Condensed Consolidated Balance Sheets as of June 30, 2021 or December 31, 2020.

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.
On March 13, 2020, due to the COVID-19 pandemic we voluntarily suspended disconnections of customers for nonpayment. The suspension of customer disconnections was extended from March 13, 2020 through December 31, 2020. The suspension of disconnection of customers for nonpayment ended on January 1, 2021 and certain customers with past due balances were placed on eight-month payment arrangements. During this time our disconnection policies were also impacted by the Summer Disconnection Moratorium. These circumstances and the on-going COVID-19 pandemic have impacted our allowance for doubtful accounts, including our write-off factor. We continue to monitor the impacts of COVID-19, our disconnection policies, payment arrangements, among other considerations impacting our estimated write-off factor and allowance for doubtful accounts. See Note 4 for additional details.

The following table provides a rollforward of Pinnacle West’s allowance for doubtful accounts (dollars in thousands):
June 30, 2021December 31, 2020
Allowance for doubtful accounts, balance at beginning of period$19,782 $8,171 
Bad debt expense10,048 20,633 
Actual write-offs(7,061)(9,022)
Allowance for doubtful accounts, balance at end of period$22,769 $19,782 
v3.21.2
Long-Term Debt and Liquidity Matters
6 Months Ended
Jun. 30, 2021
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 with a new 364-day $31 million term loan agreement that would have matured May 4, 2021. Borrowings under the agreement bore interest at Eurodollar Rate plus 1.40% per annum. Pinnacle West repaid this agreement on April 27, 2021.

On December 23, 2020, Pinnacle West entered into a $150 million term loan facility that matures June 30, 2022. The proceeds were received on January 4, 2021 and used for general corporate purposes.

On May 28, 2021, Pinnacle West replaced its $200 million revolving credit facility that would have matured on July 11, 2023, with a new $200 million revolving credit facility that matures on May 28, 2026. Pinnacle West has the option to increase the amount of the facility up to a maximum of $300 million upon the satisfaction of certain conditions and with the consent of the lenders.  Interest rates are based on Pinnacle West’s senior unsecured debt credit ratings and the agreement includes a sustainability-linked pricing metric which permits an interest rate reduction or increase by meeting or missing targets related to specific environmental and employee health and safety sustainability objectives. The facility is available to support Pinnacle West’s general corporate purposes, including support for Pinnacle West's $200 million commercial paper program, for bank borrowings or for issuances of letters of credits. At June 30, 2021, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding under the credit facility and $9.7 million of outstanding commercial paper borrowings.
APS

On May 28, 2021, APS replaced its two $500 million revolving credit facilities that would have matured in June 2022 and July 2023, with two new $500 million revolving credit facilities that total $1 billion and that mature on May 28, 2026.  APS may increase the amount of each facility up to a maximum of $700 million, for a total of $1.4 billion, upon the satisfaction of certain conditions and with the consent of the lenders.  Interest rates are based on APS’s senior unsecured debt credit ratings and the agreements include a sustainability-linked pricing metric which permits an interest rate reduction or increase by meeting or missing targets related to specific environmental and employee health and safety sustainability objectives. These facilities are available to support APS’s general corporate purposes, including support for APS's $750 million commercial paper program, for bank borrowings or for issuances of letters of credit.  At June 30, 2021, APS had no outstanding borrowings under its revolving credit facilities, no letters of credit outstanding under the credit facilities and $495 million of outstanding commercial paper borrowings.

On December 17, 2020, the ACC issued a financing order in which, subject to specified parameters and procedures, it approved APS’s short-term debt authorization equal to the sum of (i) 7% of APS’s capitalization, and (ii) $500 million (which is required to be used for costs relating to purchases of natural gas and power) and a long-term debt authorization of $7.5 billion.

See “Financial Assurances” in Note 8 for a discussion of other outstanding letters of credit.
 
Debt Fair Value
 
Our long-term debt fair value estimates are classified within Level 2 of the fair value hierarchy. The following table presents the estimated fair value of our long-term debt, including current maturities (dollars in thousands):
 As of June 30, 2021As of December 31, 2020
 Carrying
Amount
Fair ValueCarrying
Amount
Fair Value
Pinnacle West$646,729 $654,095 $496,321 $509,050 
APS5,819,198 6,746,984 5,817,945 7,103,791 
Total$6,465,927 $7,401,079 $6,314,266 $7,612,841 
v3.21.2
Regulatory Matters
6 Months Ended
Jun. 30, 2021
Regulated Operations [Abstract]  
Regulatory Matters Regulatory Matters
 
COVID-19 Pandemic

Due to the COVID-19 pandemic, APS voluntarily suspended disconnections of customers for nonpayment and waived late payment fees beginning March 13, 2020 until December 31, 2020. The suspension of disconnection of customers for nonpayment ended on January 1, 2021 and customers were automatically placed on eight-month payment arrangements if they had past due balances at the end of the disconnection period of $75 or greater. APS will continue to waive late payment fees until October 15, 2021. APS has experienced and is continuing to experience an increase in bad debt expense associated with the COVID-19 pandemic, the Summer Disconnection Moratorium (defined below) and the related write-offs of customer delinquent accounts. In February 2021, due to COVID-19 APS delayed the annual reset of the PSA. Rather than the increase being effective February 2021, the PSA reset was implemented with 50% of the increase effective April 2021 and the remaining 50% increase effective November 2021 (see below for discussion of EIS, TEAM Phase II and PSA).
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. APS has refunded approximately $43 million to customers. The additional $7 million over the approved amount of $36 million was the result of the kWh credit being based on historic consumption, which was different than actual consumption in the refund period. The difference was recorded to the DSM balancing account and was included in the 2021 DSM Implementation Plan, which was approved by the ACC on June 13, 2021 (see below for discussion of the DSM Adjustor Charge).

In 2020, APS spent more than $15 million to assist customers and local non-profits and community organizations to help with the impact of the COVID-19 pandemic, with $12.4 million of these dollars directly committed to bill assistance programs (the “COVID Customer Support Fund”). The COVID Customer Support Fund was comprised of a series of voluntary commitments of funds that are not recoverable through rates throughout 2020 of approximately $8.8 million. An additional $3.6 million in bill credits for limited income customers was ordered by the ACC in December 2020 of which 50%, up to a maximum of $2.5 million, was committed to be funds that are not recoverable through rates with the remaining being deferred for potential future recovery in rates. Included in the COVID Customer Support Fund were programs that assisted customers that had a delinquency of two or more months with a one-time credit of $100, an expanded credit of $300 for limited income customers, programs to assist extra small and small non-residential customers 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. The December 2020 ACC order further assisted delinquent limited income customers with an additional bill credit of up to $250 or their delinquent balance, whichever was less. APS has distributed all funds for all COVID Customer Support Fund programs combined. Beyond the COVID Customer Support Fund, APS has also provided $2.7 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 2019 rate review order described below, APS filed an application with the ACC on October 31, 2019 seeking an increase in annual retail base rates of $69 million. This amount includes recovery of the deferral and rate base effects of the Four Corners 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 annual revenue increase in APS’s application is $184 million. The average annual customer bill impact of APS’s request is an increase of 5.6% (the average annual bill impact for a typical APS residential customer is 5.4%).

The principal provisions of APS’s application were:

a test year comprised of 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).

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 greater than original cost, (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. Upon conclusion of APS's rate case and the completion of the deferral mechanisms, approximately $110 million of on-going operating costs related to the Four Corners SCR project and the Ocotillo modernization project will start to be reflected on APS’s income statement.

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

The CCT plan includes the following proposed components: (i) $100 million that will be paid over 10 years to the Navajo Nation for a sustainable transition to a post-coal economy, which would be funded by customers, (ii) $1.25 million that will be paid over five years to the Navajo Nation to fund an economic development organization, which would be funds not recoverable through rates, (iii) $10 million to facilitate electrification projects within the Navajo Nation, which would be funded equally by funds not recoverable through rates and by customers, (iv) $2.5 million per year in transmission revenue sharing to be paid to the Navajo Nation beginning after the closure of the Four Corners Power Plant through 2038, which would be
funds not recoverable through rates, (v) $12 million that will be paid over five years to the Navajo County Communities surrounding Cholla Power Plant, which would primarily be funded by customers, and (vi) $3.7 million that will be paid over five years to the Hopi Tribe related to APS’s ownership interests in the Navajo Generating Station, which would primarily be funded by customers. The commitment of funds that would not be recoverable through rates of $25 million were recognized in our December 31, 2020 financials.

On December 4, 2020, the ACC Staff and intervenors filed surrebuttal testimony. The ACC Staff reduced its recommended rate increase to $59.8 million, or an average annual customer bill increase of 1.82%. In RUCO’s surrebuttal, the recommended revenue decrease changed to $50.1 million, or an average annual customer bill decrease of 1.52%.

The hearing concluded on March 3, 2021 and the post-hearing briefing schedule concluded on April 30, 2021. In May 2021, the ACC declined to re-open the evidentiary record in APS’s pending rate case to take additional evidence on topics raised by certain ACC Commissioners, including adjustor cost recovery mechanisms.

On August 2, 2021, the Administrative Law Judge issued a Recommended Opinion and Order in APS’s rate case (the “2019 Rate Case ROO”). The 2019 Rate Case ROO recommends, among other things, a (i) $111 million base revenue decrease, (ii) return on equity for original cost rate base of 9.16%, (iii) a 0.15% return on the increment of fair value rate base greater than original cost, with total fair value rate of return further adjusted to include a 0.10% reduction to return on equity resulting in an effective fair value return of 0.05%, (iv) nonrecovery of the deferral and rate base effects of the operating costs and construction of the Four Corners SCR project (see "Four Corners SCR Cost Recovery" below for additional information), (v) recovery of the deferral and rate base effects of the operating costs and construction of the Ocotillo modernization project, which includes a reduction in the return on the deferral and (vi) a 15% disallowance of annual amortization of Navajo Plant regulatory asset recovery. The 2019 Rate Case ROO also recommended that the CCT plan include the following components: (i) $50 million that will be paid over 10 years to the Navajo Nation, (ii) $5 million that will be paid over five years to the Navajo County Communities surrounding Cholla Power Plant, and (iii) $1.675 million that will be paid to the Hopi Tribe related to APS’s ownership interests in the Navajo Generating Station. These amounts would be recoverable from APS’s customers through the RES. APS expects to file an exception regarding the disallowance of the SCR cost deferrals and plant investments that was recommended in the 2019 Rate Case ROO and APS is continuing to evaluate any additional exceptions it may file. The 2019 Rate Case ROO will be discussed at an upcoming ACC open meeting. 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. On November 4, 2020, the ACC voted to administratively close this docket.
Cost Recovery Mechanisms
 
APS has received regulatory decisions that allow for more timely recovery of certain costs outside of a general retail rate case through the following recovery mechanisms.
 
Renewable Energy Standard.  In 2006, the ACC approved the RES.  Under the RES, electric utilities that are regulated by the ACC must supply an increasing percentage of their retail electric energy sales from eligible renewable resources, including solar, wind, biomass, biogas and geothermal technologies.  In order to achieve these requirements, the ACC allows APS to include a RES surcharge as part of customer bills to recover the approved amounts for use on renewable energy projects.  Each year APS is required to file a five-year implementation plan with the ACC and seek approval for funding the upcoming year’s RES budget. In 2015, the ACC revised the RES rules to allow the ACC to consider all available information, including the number of rooftop solar arrays in a utility’s service territory, to determine compliance with the RES.

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

On July 1, 2019, APS filed its 2020 RES Implementation Plan and proposed a budget of approximately $86.3 million. APS’s budget request supports existing approved projects and commitments and requests a permanent waiver of the 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. In the 2021 RES Implementation Plan, APS requested $4.5 million to meet revenue requirements associated with the APS Solar Communities program to complete installations delayed as a result of the COVID-19 pandemic in 2020. On June 7, 2021, the ACC approved the 2021 RES Implementation Plan including a waiver of the residential distributed energy requirements for the 2021 implementation year. As part of the approval, the ACC authorized APS to collect $68.3 million through the Renewable Energy Adjustment Charge to support APS's RES programs.

On May 21, 2021, the ACC adopted a clean energy rules package which would require APS to meet certain clean energy standards and technology procurement mandates, obtain approval for its action plan included in its IRP, and seek cost recovery in a rate process. The adopted rules included substantial changes since the original Recommended Opinion and Order, and thus will require supplemental rulemaking before taking effect. APS cannot predict the outcome of this matter. See “Energy Modernization Plan” below for more information.

On July 1, 2021, APS filed its 2022 RES Implementation Plan and proposed a budget of approximately $93.1 million. APS’s budget proposal supports existing approved projects and commitments and requests a
permanent waiver of the residential and non-residential distributed energy requirements for 2022 contained in the RES rules. The ACC has not yet ruled on the 2022 RES Implementation Plan.

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 focused on DSM strategies to better meet system and customer needs, such as peak demand reduction, load shifting, storage and electrification strategies.

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

On April 17, 2020, APS filed an application with the ACC requesting a COVID-19 emergency relief package to provide additional assistance to its customers. On May 5, 2020, the ACC approved APS returning $36 million that had been collected through the DSM Adjustor Charge, but not allocated for current DSM programs, directly to customers through a bill credit in June 2020. APS has refunded approximately $43 million to customers. The additional $7 million over the approved amount was the result of the kWh credit being based on historic consumption which was different than actual consumption in the refund period. The difference was recorded to the DSM balancing account and was included in the 2021 DSM Implementation Plan, which was approved by the ACC on June 13, 2021.

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

On April 20, 2021, APS filed a request to extend the June 1, 2021 deadline to file its 2022 DSM Plan until 120 days after the ACC has taken action on APS's amended 2021 DSM Plan. The ACC approved this request on June 8, 2021.
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 2021 and 2020 (dollars in thousands):
 
 Six Months Ended
June 30,
 20212020
Beginning balance$175,835 $70,137 
Deferred fuel and purchased power costs — current period135,905 26,473 
Amounts (charged) refunded to customers(10,828)4,815 
Ending balance$300,912 $101,425 
 
The PSA rate for the PSA year beginning February 1, 2019 was $0.001658 per kWh, as compared to the $0.004555 per kWh for the prior year. This rate was comprised 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 November 30, 2020, APS filed its PSA rate for the PSA year beginning February 1, 2021. That rate was $0.003544 per kWh and consisted of a forward component of $0.003434 per kWh and a historical component of $0.000110 per kWh. The 2021 PSA rate is a $0.004 per kWh increase, compared to the 2020 PSA year, which is the maximum permitted under the Plan of Administration for the PSA. This left $215.9 million of fuel and purchased power costs above this annual cap which will be reflected in future year resets of the PSA. These rates were to be effective on February 1, 2021 but APS delayed the effectiveness of these rates until the first billing cycle of April 2021 due to concerns of the impact on customers during COVID-19. In March 2021, the ACC voted to implement the 2021 PSA, with 50% of the rate increase effective in April 2021 and the remaining 50% of the increase effective in November 2021. The PSA rate implemented on April 1, 2021 was $0.001544 per kWh and consisted of a forward component of $(0.004444) per kWh and a historical component of $0.005988 per kWh. On November 1, 2021, the remaining increase will be implemented to a rate of $0.003544 per kWh and will consist of a forward component of $(0.004444) per kWh and a historical component of $0.007988 per kWh. As part of this approval, the ACC ordered ACC Staff to conduct a fuel and purchased power procurement audit, which is currently underway, to better understand the factors that contributed to the increase. APS cannot predict the outcome of this audit.

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. On December 29, 2020, the ACC Staff filed its report and recommended the storage costs be included in the PSA once the systems are in-service. On January 12, 2021, the ACC approved this application but did not rule on the prudency.

Environmental Improvement Surcharge. The EIS permits APS to recover the capital carrying costs (rate of return, depreciation and taxes) plus incremental operations and maintenance expenses associated with environmental improvements made outside of a test year to comply with environmental standards set by federal, state, tribal, or local laws and regulations.  A filing is made on or before February 1 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, 2021 application requested an increase in the charge to
$10.3 million, or $1.5 million over the prior-period charge and it became effective with the first billing cycle in April 2021.
 
Transmission Rates, Transmission Cost Adjustor (“TCA”) and Other Transmission Matters In July 2008, FERC approved a modification to APS’s Open Access Transmission Tariff to allow APS to move from fixed rates to a formula rate-setting methodology in order to more accurately reflect and recover the costs that APS incurs in providing transmission services.  A large portion of the rate represents charges for transmission services to serve APS’s retail customers (“Retail Transmission Charges”).  In order to recover the Retail Transmission Charges, APS was previously required to file an application with, and obtain approval from, the ACC to reflect changes in Retail Transmission Charges through the TCA.  Under the terms of the settlement agreement entered into in 2012 regarding APS’s rate case (“2012 Settlement Agreement”), however, an adjustment to rates to recover the Retail Transmission Charges will be made annually each June 1 and will go into effect automatically unless suspended by the ACC.
 
The formula rate is updated each year effective June 1 on the basis of APS’s actual cost of service, as disclosed in APS’s FERC Form 1 report for the previous fiscal year.  Items to be updated include actual capital expenditures made as compared with previous projections, transmission revenue credits and other items. APS reviews the proposed formula rate filing amounts with the ACC Staff.  Any items or adjustments which are not agreed to by APS and the ACC Staff can remain in dispute until settled or litigated 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. The resolution of proposed adjustments can result in significant volatility in the revenues to be collected.

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, 2019, APS’s annual wholesale transmission revenue requirement 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, wholesale customer rates increased by $21.1 million and retail customer rates would have increased by approximately $4.7 million. However, since changes in retail transmission charges are reflected through the TCA after consideration of transmission recovery in retail base rates and the ACC approved TCA balancing account, the retail revenue requirement increased by a total of $4.9 million, resulting in a decrease to residential rates and an increase to commercial rates. 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 revenue requirement 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 net amount, wholesale customer rates increased by $4.8 million and retail customer rates would have decreased by approximately $10.9 million. However, since changes in retail transmission charges are reflected through the TCA after consideration of transmission recovery in retail base rates and the ACC approved balancing account, the retail revenue requirement decreased by a total of $7.4 million, resulting in reductions to both residential and commercial rates. An adjustment to APS’s retail rates to recover FERC approved transmission charges went into effect automatically on June 1, 2020.
Effective June 1, 2021, APS’s annual wholesale transmission revenue requirement for all users of its transmission system increased by approximately $4 million for the twelve-month period beginning June 1, 2021 in accordance with the FERC-approved formula. Of this net amount, wholesale customer rates decreased by approximately $3.2 million and retail customer rates would have increased by approximately $7.2 million. However, since changes in retail transmission charges are reflected through the TCA after consideration of transmission recovery in retail base rates and the ACC approved balancing account, the retail revenue requirement decreased by $28.4 million, resulting in reductions to both residential and commercial rates. An adjustment to APS’s retail rates to recover FERC-approved transmission charges went into effect automatically on June 1, 2021.

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. On February 15, 2021, APS filed its 2021 annual LFCR adjustment, requesting that effective May 1, 2021, the annual LFCR recovery amount be increased to $38.5 million (an $11.8 million increase from previous levels). On April 13, 2021, the ACC voted not to approve the requested $11.8 million increase to the annual LFCR adjustment, thus the previously approved rates continue to remain intact. The $11.8 million will continue to be maintained in the LFCR regulatory asset balancing account and will be included in APS’s next LFCR application filing in accordance with the compliance requirements.

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. On November 20, 2020, APS filed an application to continue the TEAM Phase III monthly bill credit through the earlier of December 31, 2021, or at the conclusion of APS’s 2019 pending rate case. On December 9, 2020, the ACC approved this request. Both the timing of the reduction in revenues refunded through the TEAM Phase III monthly bill credit and the offsetting income tax benefit are recognized based upon APS’s seasonal kWh sales pattern.

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 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 Former Arizona Corporation Commissioner Robert Burns

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

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 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, 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, 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, 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 Burns’ suit against APS and Pinnacle West. In response to the motion to dismiss, the court stayed the suit and ordered 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, 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 Burns’ amended complaint. On March 6, 2018, 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 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. 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, Burns filed a notice of appeal. On July 12, 2019, 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.

Burns’ position as an ACC commissioner ended on January 4, 2021. Nevertheless, Burns filed a motion with the Court of Appeals arguing that the appeal was not mooted by this fact and the court should decide the matter. Both APS and the ACC filed responses opposing the motion and asserting that the matter is moot. On March 4, 2021, the Court of Appeals found Burns’ motion to be moot because the Court of Appeals had issued an opinion deciding the matter that same day. In its March 4, 2021 opinion, the Court of Appeals affirmed the trial court’s dismissal of Burns’ complaint, concluding that Burns could not overturn the ACC's 4-1 vote refusing to enforce his subpoenas. On May 15, 2021, Burns filed a petition for review with the Arizona Supreme Court asking for reversal of the Court of Appeals opinion and the trial court’s judgment. APS and the ACC filed responses to Burns’ petition on July 14, 2021 requesting that the petition be denied. The grant of review by the Arizona Supreme Court is discretionary. Pinnacle West and APS 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 proposed 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 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 that would have required 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 aligned with the proposed rules’ three-year resource planning cycle and allowed recovery of costs through existing mechanisms until the ACC issues a decision in a future rate proceeding. On October 29, 2020, the ACC approved an amendment that would have required 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 that required 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% must be derived from customer-owned or customer-leased distributed storage. Another approved amendment modified 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. On November 13, 2020, the ACC approved a final draft energy rules package. On April 19, 2021, the Administrative Law Judge issued a Recommended Order and Opinion on the final energy rules. In May 2021, the ACC adopted clean energy rules based on a series of ACC amendments. The adopted rules include a final standard of 100% clean energy by 2070 and the following interim standards for carbon reduction from baseline carbon emissions level: 50% reduction by December 31, 2032; 65% reduction by December 31, 2040; 80% reduction by December 31, 2050 and 95% reduction by December 31, 2060. Since the adopted clean energy rules differ substantially from the original Recommended Order and Opinion, supplemental rulemaking procedures will be required before the rules become effective. 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. In March 2021, the ACC Staff requested additional time to prepare its assessment of utility IRPs. The ACC has taken no action on APS’s IRP. APS cannot predict the outcome of this matter. See “Energy Modernization Plan” above for information regarding proposed changes to the IRP filings.

Public Utility Regulatory Policies Act

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

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

In June 2019, the ACC began a formal regular rulemaking process to allow stakeholder input and time for consideration of permanent rule changes. The ACC further ordered that each regulated utility serving retail customers in Arizona update its service conditions by incorporating the emergency rule amendments, restore power to any customers who were disconnected during the month of June 2019 and credit any fees that were charged for a reconnection. The ACC Staff and ACC proposed draft amendments to the customer service disconnections rules. ACC stakeholder meetings were held in September 2019, October 2019 and January 2020 regarding the customer service disconnections rules. On April 14, 2021, the ACC voted to send to the formal rulemaking process a draft rules package governing customer disconnections that allows utilities to choose between a temperature threshold (above 95 degrees and below 32 degrees) or calendar threshold (June 1 – October 15) for disconnection moratoriums. The ACC held two public comment sessions on the draft rules
and will conduct a final vote before the rules become effective. The Summer Disconnection Moratorium will remain in effect until the ACC formalizes the final rules package.

Due to the COVID-19 pandemic, APS voluntarily suspended disconnections of customers for nonpayment and waived late payment fees beginning March 13, 2020 until December 31, 2020. The suspension of disconnection of customers for nonpayment ended on January 1, 2021 and customers were automatically placed on eight-month payment arrangements if they had past due balances at the end of the disconnection period of $75 or greater. APS will continue to waive late payment fees until October 15, 2021. APS has experienced and is continuing to experience an increase in bad debt expense associated with the COVID-19 pandemic. 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 on further consideration and discussion of the retail electric competition rules. During a July 15, 2020 ACC Staff meeting, the ACC Commissioners discussed the possible development of a retail competition pilot program, but no action was taken. The ACC 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 APS’s meter data management system. APS immediately removed the tool from its website and notified the ACC. The purpose of the tool was to provide customers with a rate plan recommendation based upon historical usage data. Upon investigation, APS determined that the error may have affected rate plan recommendations to customers between February 4, 2019 and November 14, 2019. By the middle of May 2020, APS provided refunds to approximately 13,000 potentially impacted customers equal to the difference between what they paid for electricity and the amount they would have paid had they selected their most economical rate, as applicable, and a $25 payment for any inconvenience that the customer may have experienced. The refunds and payment for inconvenience being provided did not have a material impact on APS’s financial statements. 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 (“Attorney General”) seeking information pertaining to the rate plan comparison tool offered to APS customers and other related issues including implementation of rates from the 2017 Settlement Agreement and its Customer Education and Outreach Plan associated with the 2017 Settlement Agreement. APS fully cooperated with the Attorney General’s Office in this matter. On February 22, 2021 APS entered into a consent agreement with the Attorney General as a way to settle the matter. The settlement resulted in APS paying $24.75 million, $24 million of which is being returned to customers as restitution. While this matter has been resolved with the Attorney General, APS cannot predict whether additional inquiries or actions may be taken by the ACC.

Four Corners SCR Cost Recovery

On December 29, 2017, in accordance with the 2017 Rate Case Decision, APS filed a Notice of Intent to file its SCR Adjustment to permit recovery of costs associated with the installation of SCR equipment at Four Corners Units 4 and 5.  APS filed the SCR Adjustment request in April 2018.  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.

On August 2, 2021, the 2019 Rate Case ROO recommended a disallowance of approximately $399 million of SCR plant investments and $61 million of SCR cost deferrals. The ACC has not issued a decision on this matter, but if the recommendation regarding the Four Corners SCR project in the 2019 Rate Case ROO is adopted and ordered by the ACC, APS would be required to record a write-off related to the SCR cost deferrals. As of June 30, 2021, the SCR cost deferral balance is approximately $75 million net of accumulated deferred income taxes. In addition, if the recommendation regarding the SCR plant investment disallowance in the 2019 Rate Case ROO is adopted and ordered by the ACC, the amount of any loss will be determined based on the value of the SCR plant investment assets at the time the disallowance is probable and estimable and could also be affected by other regulatory and legal considerations. As of June 30, 2021, the value of the SCR plant investments is approximately $320 million, net of accumulated deferred income taxes. If a disallowance of all or a portion of the SCR plant investments is determined to be estimable and probable, or if regulatory recovery of all or a portion of the deferred costs is determined to no longer be probable, it is reasonably possible that APS will recognize a material loss on the SCR investments and cost deferrals. For the period ended June 30, 2021, based on the fact that the 2019 Rate Case ROO is not a final decision and that APS intends to file exceptions to the 2019 Rate Case ROO related to the recommended disallowance of SCR plant investments and cost deferrals, among other factors, APS has not recorded any adjustments to write-off or write-down the SCR plant investments or cost deferrals. The pollution control assets are used and useful and are required to operate Four Corners and APS believes that these SCR investments were prudently
incurred. APS cannot predict the final outcome of the decision on this matter nor reasonably estimate the amount of any potential loss.

Cholla

On September 11, 2014, APS announced that it would close Unit 2 of the Cholla Power Plant (“Cholla”) and cease burning coal at the other APS-owned units (Units 1 and 3) at the plant by the mid-2020s, if the United States Environmental Protection Agency (“EPA”) approved a compromise proposal offered by APS to meet required environmental and emissions standards and rules. On April 14, 2015, the ACC approved APS’s plan to retire Unit 2, without expressing any view on the future recoverability of APS’s remaining investment in the unit. APS closed Unit 2 on October 1, 2015. In early 2017, EPA approved a final rule incorporating APS’s compromise proposal, which took effect on April 26, 2017. In December 2019, PacifiCorp notified APS that it planned to retire Cholla Unit 4 by the end of 2020. Cholla Unit 4 was retired on December 24, 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 ($48.9 million as of June 30, 2021), 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.

Navajo Plant

The Navajo Plant ceased operations in November 2019. The co-owners and the Navajo Nation executed a lease extension on November 29, 2017 that allows for decommissioning activities to begin after the plant ceased operations.
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 ($67 million as of June 30, 2021) plus a return on the net book value as well as other costs related to retirement and closure, including the Navajo coal reclamation regulatory asset ($17.5 million as of June 30, 2021). APS believes it will be allowed recovery of the net book value, retirement and closure costs, 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. On August 2, 2021, the 2019 Rate Case ROO recommended that APS record 15% of the annual amortization of the regulatory asset as a non-operating expense. If the recommendation regarding the Navajo Plant in the 2019 Rate Case ROO is adopted and ordered by the ACC, APS does not expect this to have a material impact on its financial statements.
Regulatory Assets and Liabilities 

The detail of regulatory assets is as follows (dollars in thousands): 
 Amortization ThroughJune 30, 2021December 31, 2020
 CurrentNon-CurrentCurrentNon-Current
Pension(a)$— $496,372 $— $469,953 
Deferred fuel and purchased power (b) (c)2022300,912 — 175,835 — 
Income taxes — allowance for funds used during construction (“AFUDC”) equity20517,169 161,279 7,169 158,776 
Retired power plant costs203328,182 100,123 28,181 114,214 
Ocotillo deferralN/A— 124,919 — 95,723 
SCR deferralN/A— 95,171 — 81,307 
Deferred property taxes20278,569 45,342 8,569 49,626 
Lost fixed cost recovery (b)202253,087 — 41,807 — 
Deferred compensation2036— 35,806 — 36,195 
Four Corners cost deferral20248,077 20,037 8,077 24,075 
Income taxes — investment tax credit basis adjustment20491,113 23,807 1,113 24,291 
Palo Verde VIEs (Note 6)2046— 21,174 — 21,255 
Coal reclamation20261,068 16,465 1,068 16,999 
Loss on reacquired debt20381,648 10,128 1,689 10,877 
Mead-Phoenix transmission line contributions in aid of construction (“CIAC”)2050332 9,214 332 9,380 
Tax expense adjustor mechanism (b)20217,956 — 6,226 — 
Demand side management (b)2022— 7,269 — 7,268 
Tax expense of Medicare subsidy20241,235 3,167 1,235 3,704 
TCA balancing account (b)2023— 1,903 — — 
Deferred fuel and purchased power — mark-to-market (Note 7)2024— — 3,341 9,244 
PSA interest2022133 — 4,355 — 
OtherVarious1,321 1,801 2,716 1,100 
Total regulatory assets (d) $420,802 $1,173,977 $291,713 $1,133,987 

(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 ThroughJune 30, 2021December 31, 2020
 CurrentNon-CurrentCurrentNon-Current
Excess deferred income taxes — ACC - Tax Act (a)2046$41,381 $993,982 $41,330 $1,012,583 
Excess deferred income taxes — FERC - Tax Act (a)20587,240 225,995 7,240 229,147 
Asset retirement obligations2057— 567,900 — 506,049 
Other postretirement benefits(d)47,798 314,218 37,705 349,588 
Removal costs(c)69,348 61,601 52,844 103,008 
Deferred fuel and purchased power — mark-to-market (Note 7)202482,082 27,305 — — 
Income taxes — change in rates20502,839 65,319 2,839 66,553 
Four Corners coal reclamation20385,461 49,904 5,460 49,435 
Income taxes — deferred investment tax credit20492,231 47,677 2,231 48,648 
Spent nuclear fuel20276,510 41,815 6,768 44,221 
Renewable energy standard (b)202230,665 — 39,442 103 
Property tax deferralN/A— 16,188 — 13,856 
Demand side management (b)20223,149 12,457 10,819 — 
Sundance maintenance2031556 12,312 2,989 11,508 
FERC transmission true up20237,547 3,511 6,598 3,008 
TCA balancing account (b)202310,750 159 2,902 4,672 
Tax expense adjustor mechanism (b) (e)20217,148 — 7,089 — 
Deferred gains on utility property20222,423 333 2,423 1,544 
Active union medical trustN/A— 2,347 — 6,057 
OtherVarious484 289 409 189 
Total regulatory liabilities $327,612 $2,443,312 $229,088 $2,450,169 

(a)For purposes of presentation on the Statement of Cash Flows, amortization of the regulatory liabilities for excess deferred income taxes are reflected as “Deferred income taxes” under Cash Flows From Operating Activities.
(b)See “Cost Recovery Mechanisms” discussion above.
(c)In accordance with regulatory accounting guidance, APS accrues removal costs for its regulated assets, even if there is no legal obligation for removal.
(d)See Note 5.
(e)Pursuant to Decision 77852, the ACC has authorized APS to return to customers up to $7 million of liability recorded to the TEAM balancing account through December 31, 2021. Should new base rates become effective prior to December 31, 2021, any remaining unreturned balance is anticipated to be included in the new base rates.
v3.21.2
Retirement Plans and Other Postretirement Benefits
6 Months Ended
Jun. 30, 2021
Retirement Benefits [Abstract]  
Retirement Plans and Other Postretirement Benefits Retirement Plans and Other Postretirement Benefits
 
Pinnacle West sponsors a qualified defined benefit and account balance pension plan, a non-qualified supplemental excess benefit retirement plan, and other postretirement benefit plans for the employees of Pinnacle West and our subsidiaries.  The other postretirement benefit plans include a group life and medical plan and a post-65 retiree health reimbursement arrangement (“HRA”). Pinnacle West uses a December 31
measurement date each year for its pension and other postretirement benefit plans.  The market-related value of our plan assets is their fair value at the measurement date.

Under the HRA, included in the other postretirement benefit plan, the Company provides a subsidy to retirees to defray the cost of a Medicare supplemental policy. In prior years, we had been assuming a 4.75% escalation of these benefits; however, actual escalation has been significantly less than this assumption. Accordingly, during 2020 and for future periods, the escalation assumption was reduced to 2.00%. This escalation factor assumption change, among other factors, resulted in an increase in the over-funded status of the other postretirement benefit plan as of December 31, 2020. As a result, on January 4, 2021, we initiated the transfer of approximately $106 million of assets from the other postretirement benefit plan into the Active Union Employee Medical Account. The Active Union Employee Medical Account is an existing trust account that holds assets restricted for paying active union employee medical costs (see Note 12). The transfer of other postretirement benefit plan assets into the Active Union Employee Medical Account permits access to approximately $106 million of assets for the sole purpose of paying active union employee medical benefits. This transfer of assets into the Active Union Employee Medical Account is consistent with the terms of a similar 2018 transaction.

The following table provides details of the plans’ net periodic benefit costs and the portion of these costs charged to expense (including administrative costs and excluding amounts capitalized as overhead construction or billed to electric plant participants) (dollars in thousands):
 Pension Benefits