PINNACLE WEST CAPITAL CORP, 10-K filed on 2/21/2020
Annual Report
v3.19.3.a.u2
Document and Entity Information - USD ($)
12 Months Ended
Dec. 31, 2019
Feb. 14, 2020
Entity Information [Line Items]    
Entity Interactive Data Current Yes  
Entity File Number 1-8962  
Entity Registrant Name PINNACLE WEST CAPITAL CORPORATION  
Entity Central Index Key 0000764622  
Document Type 10-K  
Document Quarterly Report true  
Document Period End Date Dec. 31, 2019  
Amendment Flag false  
Current Fiscal Year End Date --12-31  
Entity Well-known Seasoned Issuer Yes  
Entity Voluntary Filers No  
Entity Current Reporting Status Yes  
Entity Filer Category Large Accelerated Filer  
Entity Public Float $ 10,536,165,750  
Entity Emerging Growth Company false  
Entity Small Business false  
Entity Shell Company false  
Entity Common Stock, Shares Outstanding   112,439,441
Document Fiscal Year Focus 2019  
Document Fiscal Period Focus FY  
Entity Tax Identification Number 86-0512431  
Entity Address, Address Line One 400 North Fifth Street, P.O. Box 53999  
Entity Address, City or Town Phoenix  
Entity Address, State or Province AZ  
Entity Address, Postal Zip Code 85072-3999  
City Area Code (602)  
Local Phone Number 250-1000  
Trading Symbol PNW  
Security Exchange Name NYSE  
Document Transition Report false  
Entity Incorporation, State or Country Code AZ  
ARIZONA PUBLIC SERVICE COMPANY    
Entity Information [Line Items]    
Entity Interactive Data Current Yes  
Entity File Number 1-4473  
Entity Registrant Name ARIZONA PUBLIC SERVICE COMPANY  
Entity Central Index Key 0000007286  
Document Type 10-K  
Amendment Flag false  
Current Fiscal Year End Date --12-31  
Entity Well-known Seasoned Issuer Yes  
Entity Voluntary Filers No  
Entity Current Reporting Status Yes  
Entity Filer Category Non-accelerated Filer  
Entity Public Float $ 0  
Entity Emerging Growth Company false  
Entity Small Business false  
Entity Shell Company false  
Entity Common Stock, Shares Outstanding   71,264,947
Document Fiscal Year Focus 2019  
Document Fiscal Period Focus FY  
Entity Tax Identification Number 86-0011170  
Entity Address, Address Line One 400 North Fifth Street, P.O. Box 53999  
Entity Address, City or Town Phoenix  
Entity Address, State or Province AZ  
Entity Address, Postal Zip Code 85072-3999  
City Area Code (602)  
Local Phone Number 250-1000  
Title of 12(g) Security Common Stock  
Entity Incorporation, State or Country Code AZ  
v3.19.3.a.u2
CONSOLIDATED STATEMENTS OF INCOME - USD ($)
shares in Thousands, $ in Thousands
12 Months Ended
Dec. 31, 2019
Dec. 31, 2018
Dec. 31, 2017
OPERATING REVENUES (NOTE 2) $ 3,471,209 $ 3,691,247 $ 3,565,296
OPERATING EXPENSES      
Fuel and purchased power 1,042,237 1,076,116 981,301
Operations and maintenance 941,616 1,036,744 949,107
Depreciation and amortization 590,929 582,354 534,118
Taxes other than income taxes 218,579 212,849 184,347
Other expenses 5,888 9,497 6,660
Total 2,799,249 2,917,560 2,655,533
Operating loss 671,960 773,687 909,763
OTHER INCOME (DEDUCTIONS)      
Allowance for equity funds used during construction (Note 1) 31,431 52,319 47,011
Pension and other postretirement non-service credits - net (Note 8) 22,989 49,791 24,664
Other income (Note 18) 50,263 24,896 4,006
Other expense (Note 18) (17,880) (17,966) (21,539)
Total 86,803 109,040 54,142
INTEREST EXPENSE      
Interest charges 235,251 243,465 219,796
Allowance for borrowed funds used during construction (Note 1) (18,528) (25,180) (22,112)
Total 216,723 218,285 197,684
INCOME BEFORE INCOME TAXES 542,040 664,442 766,221
Income tax benefit (15,773) 133,902 258,272
NET INCOME 557,813 530,540 507,949
Less: Net income attributable to noncontrolling interests (Note 19) 19,493 19,493 19,493
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS $ 538,320 $ 511,047 $ 488,456
Net effect of dilutive securities:      
Weighted Average common shares outstanding — basic (in shares) 112,443 112,129 111,839
Weighted Average common shares outstanding — diluted (in shares) 112,758 112,550 112,367
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING      
Net income attributable to common shareholders - basic (in dollars per share) $ 4.79 $ 4.56 $ 4.37
Net income attributable to common shareholders — diluted (in dollars per share) $ 4.77 $ 4.54 $ 4.35
ARIZONA PUBLIC SERVICE COMPANY      
OPERATING REVENUES (NOTE 2) $ 3,471,209 $ 3,688,342 $ 3,557,652
OPERATING EXPENSES      
Fuel and purchased power 1,042,237 1,094,020 992,744
Operations and maintenance 926,716 969,227 917,983
Depreciation and amortization 590,844 580,694 532,423
Taxes other than income taxes 218,540 212,136 183,254
Other expenses 5,888 2,497 6,709
Total 2,784,225 2,858,574 2,633,113
Operating loss 686,984 829,768 924,539
OTHER INCOME (DEDUCTIONS)      
Allowance for equity funds used during construction (Note 1) 31,431 52,319 47,011
Pension and other postretirement non-service credits - net (Note 8) 24,529 51,242 24,371
Other income (Note 18) 46,884 22,746 3,013
Other expense (Note 18) (12,990) (15,292) (13,913)
Total 89,854 111,015 60,482
INTEREST EXPENSE      
Interest charges 220,174 231,391 214,163
Allowance for borrowed funds used during construction (Note 1) (18,528) (25,180) (22,112)
Total 201,646 206,211 192,051
INCOME BEFORE INCOME TAXES 575,192 734,572 792,970
Income tax benefit (9,572) 144,814 269,168
NET INCOME 584,764 589,758 523,802
Less: Net income attributable to noncontrolling interests (Note 19) 19,493 19,493 19,493
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS $ 565,271 $ 570,265 $ 504,309
v3.19.3.a.u2
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($)
$ in Thousands
12 Months Ended
Dec. 31, 2019
Dec. 31, 2018
Dec. 31, 2017
NET INCOME $ 557,813 $ 530,540 $ 507,949
Derivative instruments:      
Net unrealized loss, net of tax benefit (expense) 0    
Net unrealized loss, net of tax benefit (expense)   (78) (35)
Other Comprehensive Income (Loss), Cash Flow Hedge, Gain (Loss), Reclassification, after Tax (1,137)    
Reclassification of net realized loss, net of tax benefit   1,527 2,225
Pension and other postretirement benefits activity, net of tax (expense) benefit (10,525) 4,397 (3,370)
Total other comprehensive income (loss) (9,388) 5,846 (1,180)
COMPREHENSIVE INCOME 548,425 536,386 506,769
Less: Comprehensive income attributable to noncontrolling interests 19,493 19,493 19,493
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS 528,932 516,893 487,276
ARIZONA PUBLIC SERVICE COMPANY      
NET INCOME 584,764 589,758 523,802
Derivative instruments:      
Net unrealized loss, net of tax benefit (expense) 0    
Net unrealized loss, net of tax benefit (expense)   (78) (35)
Other Comprehensive Income (Loss), Cash Flow Hedge, Gain (Loss), Reclassification, after Tax (1,137)    
Reclassification of net realized loss, net of tax benefit   1,527 2,225
Pension and other postretirement benefits activity, net of tax (expense) benefit (9,552) 3,465 (3,750)
Total other comprehensive income (loss) (8,415) 4,914 (1,560)
COMPREHENSIVE INCOME 576,349 594,672 522,242
Less: Comprehensive income attributable to noncontrolling interests 19,493 19,493 19,493
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS $ 556,856 $ 575,179 $ 502,749
v3.19.3.a.u2
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($)
$ in Thousands
12 Months Ended
Dec. 31, 2019
Dec. 31, 2018
Dec. 31, 2017
Net unrealized loss, tax benefit (expense) $ 0    
Net unrealized loss, tax benefit (expense)   $ (78) $ 24
Reclassification of net realized loss, tax benefit 375    
Reclassification of net realized loss, tax benefit   473 1,294
Pension and other postretirement benefits activity, tax benefit (expense) 3,452 (1,585) 693
ARIZONA PUBLIC SERVICE COMPANY      
Net unrealized loss, tax benefit (expense) 0    
Net unrealized loss, tax benefit (expense)   (78) 24
Reclassification of net realized loss, tax benefit 375    
Reclassification of net realized loss, tax benefit   473 1,294
Pension and other postretirement benefits activity, tax benefit (expense) $ 3,136 $ (1,159) $ 977
v3.19.3.a.u2
CONSOLIDATED BALANCE SHEETS - USD ($)
$ in Thousands
Dec. 31, 2019
Dec. 31, 2018
CURRENT ASSETS    
Cash and cash equivalents $ 10,283 $ 5,766
Customer and other receivables 266,426 267,887
Accrued unbilled revenues 128,165 137,170
Allowance for doubtful accounts (8,171) (4,069)
Materials and supplies (at average cost) 331,091 269,065
Fossil fuel (at average cost) 14,829 25,029
Income tax receivable (Note 5) 21,727 0
Assets from risk management activities (Note 17) 515 1,113
Deferred fuel and purchased power regulatory asset (Note 4) 70,137 37,164
Other regulatory assets (Note 4) 133,070 129,738
Other current assets 61,958 56,128
Total current assets 1,030,030 924,991
INVESTMENTS AND OTHER ASSETS    
Nuclear decommissioning trust (Notes 14 and 20) 1,010,775 851,134
Other special use funds (Notes 14 and 20) 245,095 236,101
Other assets 96,953 103,247
Total investments and other assets 1,352,823 1,190,482
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 7 and 10)    
Plant in service and held for future use 19,836,292 18,736,628
Accumulated depreciation and amortization (6,637,857) (6,366,014)
Net 13,198,435 12,370,614
Construction work in progress 808,133 1,170,062
Palo Verde sale leaseback, net of accumulated depreciation of $249,144 and $245,275 (Note 19) 101,906 105,775
Intangible assets, net of accumulated amortization of $652,902 and $591,202 290,564 262,902
Nuclear fuel, net of accumulated amortization of $137,330 and $137,850 123,500 120,217
Total property, plant and equipment 14,522,538 14,029,570
DEFERRED DEBITS    
Regulatory assets (Notes 1, 4 and 5) 1,304,073 1,342,941
Operating Lease, Right-of-Use Asset 145,813 0
Assets for other postretirement benefits (Note 8) 90,570 46,906
Other 33,400 129,312
Total deferred debits 1,573,856 1,519,159
Total Assets 18,479,247 17,664,202
CURRENT LIABILITIES    
Accounts payable 346,448 277,336
Accrued taxes 144,899 154,819
Accrued interest 53,534 61,107
Common dividends payable 87,982 82,675
Short-term borrowings (Note 6) 114,675 76,400
Current maturities of long-term debt (Note 7) 800,000 500,000
Customer deposits 64,908 91,174
Liabilities from risk management activities (Note 17) 38,946 35,506
Liabilities for asset retirements (Note 12) 11,025 19,842
Operating lease liabilities (Note 9) 12,713 0
Regulatory liabilities (Note 4) 234,912 165,876
Other current liabilities 168,323 184,229
Total current liabilities 2,078,365 1,648,964
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 7) 4,832,558 4,638,232
DEFERRED CREDITS AND OTHER    
Deferred income taxes (Note 5) 1,992,339 1,807,421
Regulatory liabilities (Notes 1, 4, 5 and 8) 2,267,835 2,325,976
Liabilities for asset retirements (Note 12) 646,193 706,703
Liabilities for pension benefits (Note 8) 280,185 443,170
Liabilities from risk management activities (Note 17) 33,186 24,531
Customer advances 215,330 137,153
Coal mine reclamation 165,695 212,785
Deferred investment tax credit 196,468 200,405
Unrecognized tax benefits (Note 5) 6,189 22,517
Operating lease liabilities (Note 9) 51,872 0
Other 159,844 147,640
Total deferred credits and other 6,015,136 6,028,301
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
EQUITY    
Common stock, no par value; authorized 150,000,000 shares, 112,540,126 and 112,159,896 issued at respective dates 2,659,561 2,634,265
Treasury stock at cost; 103,546 shares at end of 2019 and 58,135 shares at end of 2018 (9,427) (4,825)
Total common stock 2,650,134 2,629,440
Retained earnings 2,837,610 2,641,183
Accumulated other comprehensive loss (57,096) (47,708)
Total shareholders’ equity 5,430,648 5,222,915
Noncontrolling interests (Note 19) 122,540 125,790
Total equity 5,553,188 5,348,705
Total Liabilities and Equity 18,479,247 17,664,202
ARIZONA PUBLIC SERVICE COMPANY    
CURRENT ASSETS    
Cash and cash equivalents 10,169 5,707
Customer and other receivables 255,479 257,654
Accrued unbilled revenues 128,165 137,170
Allowance for doubtful accounts (8,171) (4,069)
Materials and supplies (at average cost) 331,091 269,065
Fossil fuel (at average cost) 14,829 25,029
Income tax receivable (Note 5) 7,313 0
Assets from risk management activities (Note 17) 515 1,113
Deferred fuel and purchased power regulatory asset (Note 4) 70,137 37,164
Other regulatory assets (Note 4) 133,070 129,738
Other current assets 38,895 35,111
Total current assets 981,492 893,682
INVESTMENTS AND OTHER ASSETS    
Nuclear decommissioning trust (Notes 14 and 20) 1,010,775 851,134
Other special use funds (Notes 14 and 20) 245,095 236,101
Other assets 43,781 40,817
Total investments and other assets 1,299,651 1,128,052
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 7 and 10)    
Plant in service and held for future use 19,832,805 18,733,142
Accumulated depreciation and amortization (6,634,597) (6,362,771)
Net 13,198,208 12,370,371
Construction work in progress 808,133 1,170,062
Palo Verde sale leaseback, net of accumulated depreciation of $249,144 and $245,275 (Note 19) 101,906 105,775
Intangible assets, net of accumulated amortization of $652,902 and $591,202 290,409 262,746
Nuclear fuel, net of accumulated amortization of $137,330 and $137,850 123,500 120,217
Total property, plant and equipment 14,522,156 14,029,171
DEFERRED DEBITS    
Regulatory assets (Notes 1, 4 and 5) 1,304,073 1,342,941
Operating Lease, Right-of-Use Asset 144,024 0
Assets for other postretirement benefits (Note 8) 86,736 43,212
Other 32,591 128,265
Total deferred debits 1,567,424 1,514,418
Total Assets 18,370,723 17,565,323
CURRENT LIABILITIES    
Accounts payable 338,006 266,277
Accrued taxes 136,328 176,357
Accrued interest 52,619 60,228
Common dividends payable 88,000 82,700
Current maturities of long-term debt (Note 7) 350,000 500,000
Customer deposits 64,908 91,174
Liabilities from risk management activities (Note 17) 38,946 35,506
Liabilities for asset retirements (Note 12) 11,025 19,842
Operating lease liabilities (Note 9) 12,549 0
Regulatory liabilities (Note 4) 234,912 165,876
Other current liabilities 164,736 178,137
Total current liabilities 1,492,029 1,576,097
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 7) 4,833,133 4,189,436
DEFERRED CREDITS AND OTHER    
Deferred income taxes (Note 5) 2,033,096 1,812,664
Regulatory liabilities (Notes 1, 4, 5 and 8) 2,267,835 2,325,976
Liabilities for asset retirements (Note 12) 646,193 706,703
Liabilities for pension benefits (Note 8) 262,243 425,404
Liabilities from risk management activities (Note 17) 33,186 24,531
Customer advances 215,330 137,153
Coal mine reclamation 165,695 212,785
Deferred investment tax credit 196,468 200,405
Unrecognized tax benefits (Note 5) 40,188 41,861
Operating lease liabilities (Note 9) 50,092 0
Other 136,432 125,511
Total deferred credits and other 6,046,758 6,012,993
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
EQUITY    
Total common stock 178,162 178,162
Additional paid-in capital 2,721,696 2,721,696
Retained earnings 3,011,927 2,788,256
Accumulated other comprehensive loss (35,522) (27,107)
Total shareholders’ equity 5,876,263 5,661,007
Noncontrolling interests (Note 19) 122,540 125,790
Total equity 5,998,803 5,786,797
Total capitalization 10,831,936 9,976,233
Total Liabilities and Equity $ 18,370,723 $ 17,565,323
v3.19.3.a.u2
CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($)
$ in Thousands
Dec. 31, 2019
Dec. 31, 2018
PROPERTY, PLANT AND EQUIPMENT    
Accumulated depreciation of Palo Verde sale leaseback $ 249,144 $ 245,275
Accumulated amortization on intangible assets 647,276 591,202
Accumulated amortization on nuclear fuel $ 137,330 $ 137,850
EQUITY    
Common stock, par value (in dollars per share) $ 0 $ 0
Common stock, authorized shares (in shares) 150,000,000 150,000,000
Common stock, issued shares (in shares) 112,540,126 112,159,896
Treasury stock at cost, shares (in shares) 103,546 58,135
ARIZONA PUBLIC SERVICE COMPANY    
PROPERTY, PLANT AND EQUIPMENT    
Accumulated depreciation of Palo Verde sale leaseback $ 249,144 $ 245,275
Accumulated amortization on intangible assets 646,142 590,069
Accumulated amortization on nuclear fuel $ 137,330 $ 137,850
v3.19.3.a.u2
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)
$ in Thousands
12 Months Ended
Dec. 31, 2019
Dec. 31, 2018
Dec. 31, 2017
CASH FLOWS FROM OPERATING ACTIVITIES      
Net income $ 557,813 $ 530,540 $ 507,949
Adjustments to reconcile net income to net cash provided by operating activities:      
Depreciation and amortization including nuclear fuel 664,140 650,955 610,629
Deferred fuel and purchased power (82,481) (78,277) (48,405)
Deferred fuel and purchased power amortization 49,508 116,750 (14,767)
Allowance for equity funds used during construction (31,431) (52,319) (47,011)
Deferred income taxes (1,479) 117,355 248,164
Deferred investment tax credit (3,938) (5,170) (4,587)
Change in derivative instruments fair value 0 0 (373)
Stock compensation 18,376 19,547 20,502
Changes in current assets and liabilities:      
Customer and other receivables (12,789) 37,530 (93,797)
Accrued unbilled revenues 9,005 (24,736) (4,485)
Materials, supplies and fossil fuel (51,826) (6,103) (6,683)
Income tax receivable (21,727) 0 3,751
Other current assets (3,507) 33,844 (10,580)
Accounts payable 50,641 (14,602) (23,769)
Accrued taxes (9,920) 6,597 9,982
Other current liabilities (84,651) 28,174 19,154
Change in margin and collateral accounts — assets (247) 143 (300)
Change in margin and collateral accounts — liabilities (125) (2,211) (533)
Change in unrecognized tax benefits 2,704 (1,235) 5,891
Change in long-term regulatory liabilities 124,221 (109,284) 45,764
Change in other long-term assets (82,895) 78,604 (68,480)
Change in other long-term liabilities (132,666) (48,958) (29,980)
Net cash flow provided by operating activities 956,726 1,277,144 1,118,036
CASH FLOWS FROM INVESTING ACTIVITIES      
Capital expenditures (1,191,447) (1,178,169) (1,408,774)
Contributions in aid of construction 70,693 27,716 23,708
Allowance for borrowed funds used during construction (18,528) (25,180) (22,112)
Proceeds from nuclear decommissioning trust sales and other special use funds 719,034 653,033 542,246
Investment in nuclear decommissioning trust and other special use funds (722,181) (672,165) (544,527)
Other 11,452 1,941 (19,078)
Net cash flow used for investing activities (1,130,977) (1,192,824) (1,428,537)
CASH FLOWS FROM FINANCING ACTIVITIES      
Issuance of long-term debt 1,092,188 445,245 848,239
Repayment of long-term debt (600,000) (182,000) (125,000)
Short-term borrowings and (repayments) — net 54,275 (7,000) (107,800)
Short-term debt borrowings under revolving credit facility 49,000 45,000 58,000
Short-term debt repayments under revolving credit facility (65,000) (57,000) (32,000)
Dividends paid on common stock (329,643) (308,892) (289,793)
Common stock equity issuance and purchases - net 692 (5,055) (13,390)
Distributions to noncontrolling interests (22,744) (22,744) (22,744)
Net cash flow provided by (used for) financing activities 178,768 (92,446) 315,512
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 4,517 (8,126) 5,011
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 5,766 13,892 8,881
CASH AND CASH EQUIVALENTS AT END OF YEAR 10,283 5,766 13,892
ARIZONA PUBLIC SERVICE COMPANY      
CASH FLOWS FROM OPERATING ACTIVITIES      
Net income 584,764 589,758 523,802
Adjustments to reconcile net income to net cash provided by operating activities:      
Depreciation and amortization including nuclear fuel 664,055 649,295 608,935
Deferred fuel and purchased power (82,481) (78,277) (48,405)
Deferred fuel and purchased power amortization 49,508 116,750 (14,767)
Allowance for equity funds used during construction (31,431) (52,319) (47,011)
Deferred income taxes 48,367 59,927 249,465
Deferred investment tax credit (3,938) (5,170) (4,587)
Change in derivative instruments fair value 0 0 (373)
Changes in current assets and liabilities:      
Customer and other receivables (12,075) 35,406 (68,040)
Accrued unbilled revenues 9,005 (24,736) (4,485)
Materials, supplies and fossil fuel (51,826) (6,206) (6,503)
Income tax receivable (7,313) 0 11,174
Other current assets (1,461) 31,707 (6,775)
Accounts payable 53,258 (15,608) (26,561)
Accrued taxes (40,029) 19,008 26,773
Other current liabilities (82,138) 25,070 27,912
Change in margin and collateral accounts — assets (247) 143 (300)
Change in margin and collateral accounts — liabilities (125) (2,211) (533)
Change in unrecognized tax benefits 2,704 (1,235) 5,891
Change in long-term regulatory liabilities 124,221 (109,284) 45,764
Change in other long-term assets (85,725) 77,952 (78,540)
Change in other long-term liabilities (129,682) (55,169) (31,106)
Net cash flow provided by operating activities 1,007,411 1,254,801 1,161,730
CASH FLOWS FROM INVESTING ACTIVITIES      
Capital expenditures (1,191,447) (1,169,061) (1,381,930)
Contributions in aid of construction 70,693 27,716 23,708
Allowance for borrowed funds used during construction (18,528) (25,180) (22,112)
Proceeds from nuclear decommissioning trust sales and other special use funds 719,034 653,033 542,246
Investment in nuclear decommissioning trust and other special use funds (722,181) (672,165) (544,527)
Other 6,336 (1,789) (18,538)
Net cash flow used for investing activities (1,136,093) (1,187,446) (1,401,153)
CASH FLOWS FROM FINANCING ACTIVITIES      
Issuance of long-term debt 1,092,188 295,245 549,478
Repayment of long-term debt (600,000) (182,000) 0
Short-term borrowings and (repayments) — net 0 0 (135,500)
Short-term debt borrowings under revolving credit facility 0 25,000 0
Short-term debt repayments under revolving credit facility 0 (25,000) 0
Dividends paid on common stock (336,300) (316,000) (296,800)
Equity infusion from Pinnacle West 0 150,000 150,000
Distributions to noncontrolling interests (22,744) (22,744) (22,744)
Net cash flow provided by (used for) financing activities 133,144 (75,499) 244,434
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 4,462 (8,144) 5,011
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 5,707 13,851 8,840
CASH AND CASH EQUIVALENTS AT END OF YEAR $ 10,169 $ 5,707 $ 13,851
v3.19.3.a.u2
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY - USD ($)
$ in Thousands
Total
Common Stock
Treasury Stock
Retained Earnings
Accumulated Other Comprehensive Income (Loss)
Noncontrolling Interests
ARIZONA PUBLIC SERVICE COMPANY
ARIZONA PUBLIC SERVICE COMPANY
Common Stock
ARIZONA PUBLIC SERVICE COMPANY
Additional Paid-In Capital
ARIZONA PUBLIC SERVICE COMPANY
Retained Earnings
ARIZONA PUBLIC SERVICE COMPANY
Accumulated Other Comprehensive Income (Loss)
ARIZONA PUBLIC SERVICE COMPANY
Noncontrolling Interests
Beginning balance at Dec. 31, 2016 $ 4,935,912 $ 2,596,030 $ (4,133) $ 2,255,547 $ (43,822) $ 132,290 $ 5,037,970 $ 178,162 $ 2,421,696 $ 2,331,245 $ (25,423) $ 132,290
Beginning Balance (in shares) at Dec. 31, 2016   111,392,053 55,317         71,264,947        
Increase (Decrease) in Shareholders' Equity                        
Net income 507,949     488,456   19,493 523,802     504,309   19,493
Other comprehensive income (loss) (1,180)       (1,180)   (1,560)       (1,560)  
Dividends on common stock (301,492)     (301,492)     (301,600)     (301,600)    
Issuance of common stock 18,775 $ 18,775                    
Issuance of common stock (in shares)   424,117                    
Purchase of treasury stock [1] (17,755)   $ (17,755)                  
Purchase of treasury stock (in shares) [1]     (216,911)                  
Reissuance of treasury stock for stock-based compensation and other 16,264   $ 16,264                  
Reissuance of treasury stock for stock-based compensation and other (in shares)     207,765                  
Equity infusion from Pinnacle West             150,000   150,000      
Capital activities by noncontrolling interests (22,743)         (22,743) (22,743)         (22,743)
Ending balance at Dec. 31, 2017 5,135,730 $ 2,614,805 $ (5,624) 2,442,511 (45,002) 129,040 5,385,869 $ 178,162 2,571,696 2,533,954 (26,983) 129,040
Ending Balance (in shares) at Dec. 31, 2017   111,816,170 64,463         71,264,947        
Increase (Decrease) in Shareholders' Equity                        
Net income 530,540     511,047   19,493 589,758     570,265   19,493
Other comprehensive income (loss) 5,846       5,846   4,914       4,914  
Dividends on common stock (320,927)     (320,927)     (321,001)     (321,001)    
Issuance of common stock 19,460 $ 19,460                    
Issuance of common stock (in shares)   343,726                    
Purchase of treasury stock [1] (10,338)   $ (10,338)                  
Purchase of treasury stock (in shares) [1]     (129,903)                  
Reissuance of treasury stock for stock-based compensation and other 11,137   $ 11,137                  
Reissuance of treasury stock for stock-based compensation and other (in shares)     136,231                  
Equity infusion from Pinnacle West             150,000   150,000      
Capital activities by noncontrolling interests (22,743)         (22,743) (22,743)         (22,743)
Reclassification of income tax effects related to new tax reform       8,552 [2] (8,552) [2]         5,038 [3] (5,038) [3]  
Ending balance at Dec. 31, 2018 $ 5,348,705 $ 2,634,265 $ (4,825) 2,641,183 (47,708) 125,790 5,786,797 $ 178,162 2,721,696 2,788,256 (27,107) 125,790
Ending Balance (in shares) at Dec. 31, 2018 112,159,896 112,159,896 58,135         71,264,947        
Increase (Decrease) in Shareholders' Equity                        
Net income $ 557,813     538,320   19,493 584,764     565,271   19,493
Other comprehensive income (loss) (9,388)       (9,388)   (8,415)       (8,415)  
Dividends on common stock (341,893)     (341,893)     (341,600)     (341,600)    
Issuance of common stock 25,296 $ 25,296                    
Issuance of common stock (in shares)   380,230                    
Purchase of treasury stock [1] (11,202)   $ (11,202)                  
Purchase of treasury stock (in shares) [1]     (121,493)                  
Reissuance of treasury stock for stock-based compensation and other 6,600   $ 6,600                  
Reissuance of treasury stock for stock-based compensation and other (in shares)     76,082                  
Capital activities by noncontrolling interests (22,743)         (22,743) (22,743)         (22,743)
Ending balance 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
Ending Balance (in shares) at Dec. 31, 2019 112,540,126 112,540,126 103,546         71,264,947        
[1] Primarily represents shares of common stock withheld from certain stock awards for tax purposes.
[2]
In 2018, the Company adopted new accounting guidance and elected to reclassify income tax effects of the Tax Cuts and Jobs Act of 2017 (the "Tax Act") on items within accumulated other comprehensive income to retained earnings.

[3] In 2018, the Company adopted new accounting guidance and elected to reclassify income tax effects of the Tax Act on
items within accumulated other comprehensive income to retained earnings.
v3.19.3.a.u2
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Parenthetical) - $ / shares
12 Months Ended
Dec. 31, 2019
Dec. 31, 2018
Dec. 31, 2017
Statement of Stockholders' Equity [Abstract]      
DIVIDENDS DECLARED PER SHARE (in dollars per share) $ 3.04 $ 2.87 $ 2.70
v3.19.3.a.u2
Summary of Significant Accounting Policies
12 Months Ended
Dec. 31, 2019
Accounting Policies [Abstract]  
Summary of Significant Accounting Policies Summary of Significant Accounting Policies

Description of Business and Basis of Presentation
 
Pinnacle West is a holding company that conducts business through its subsidiaries, APS, El Dorado, BCE and 4CA. APS, our wholly-owned subsidiary, is a vertically-integrated electric utility that provides either retail or wholesale electric service to substantially all of the state of Arizona, with the major exceptions of about one-half of the Phoenix metropolitan area, the Tucson metropolitan area and Mohave County in northwestern Arizona.  APS accounts for essentially all of our revenues and earnings, and is expected to continue to do so.  El Dorado is an investment firm. BCE is a subsidiary that was formed in 2014 that focuses on growth opportunities that leverage the Company's core expertise in the electric energy industry. 4CA is a subsidiary that was formed in 2016 as a result of the purchase of El Paso's 7% interest in Four Corners. See Note 11 for more information on 4CA matters.
 
Pinnacle West’s Consolidated Financial Statements include the accounts of Pinnacle West and our subsidiaries:  APS, El Dorado, BCE and 4CA. APS’s Consolidated Financial Statements include the accounts of APS and certain VIEs relating to the Palo Verde sale leaseback.  Intercompany accounts and transactions between the consolidated companies have been eliminated.
 
We consolidate VIEs for which we are the primary beneficiary.  We determine whether we are the primary beneficiary of a VIE through a qualitative analysis that identifies which variable interest holder has the controlling financial interest in the VIE.  In performing our primary beneficiary analysis, we consider all relevant facts and circumstances, including the design and activities of the VIE, the terms of the contracts the VIE has entered into, and which parties participated significantly in the design or redesign of the entity.  We continually evaluate our primary beneficiary conclusions to determine if changes have occurred which would impact our primary beneficiary assessments.  We have determined that APS is the primary beneficiary of certain VIE lessor trusts relating to the Palo Verde sale leaseback, and therefore APS consolidates these entities. See Note 19 for additional information.
 
Our consolidated financial statements reflect all adjustments (consisting only of normal recurring adjustments, except as otherwise disclosed in the notes) that we believe are necessary for the fair presentation of our financial position, results of operations and cash flows for the periods presented.

Accounting Records and Use of Estimates
 
Our accounting records are maintained in accordance with accounting principles generally accepted in the United States of America ("GAAP").  The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period.  Actual results could differ from those estimates.

Regulatory Accounting
 
APS is regulated by the ACC and FERC.  The accompanying financial statements reflect the rate-making policies of these commissions.  As a result, we capitalize certain costs that would be included as expense in the current period by unregulated companies.  Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in customer rates. Regulatory liabilities generally represent amounts collected in rates to recover costs expected to be incurred in the future or amounts collected in excess of costs incurred and are refundable to customers.
 
Management judgments include continually assessing the likelihood of future recovery of regulatory assets and/or a disallowance of part of the cost of recently completed plant, by considering factors such as applicable regulatory environment changes and recent rate orders to other regulated entities in the same jurisdiction.  This determination reflects the current political and regulatory climate in Arizona and is subject to change in the future.  If future recovery of costs ceases to be probable, the assets would be written off as a charge in current period earnings. Management judgments also include assessing the impact of potential Commission-ordered refunds to customers on regulatory liabilities.
 
See Note 4 for additional information.
 
Electric Revenues
 
On January 1, 2018, we adopted new revenue guidance ASU 2014-09, Revenue from contracts with customers; accordingly our 2019 and 2018 electric revenues primarily consist of activities that are classified as revenues from contracts with customers. Our electric revenues generally represent a single performance obligation delivered over time. We have elected to apply the practical expedient that allows us to recognize revenue based on the amount to which we have a right to invoice for services performed.

We derive electric revenues primarily from sales of electricity to our regulated retail customers. Revenues related to the sale of electricity are generally recognized when service is rendered or electricity is delivered to customers. Unbilled revenues are estimated by applying an average revenue/kWh by customer class to the number of estimated kWhs delivered but not billed. Differences historically between the actual and estimated unbilled revenues are immaterial. We exclude sales taxes and franchise fees on electric revenues from both revenue and taxes other than income taxes.
 
Revenues from our regulated retail customers and non-derivative instruments are reported on a gross basis on Pinnacle West’s Consolidated Statements of Income. In the electricity business, some contracts to purchase electricity are netted against other contracts to sell electricity. This is called a "book-out" and usually occurs for contracts that have the same terms (quantities, delivery points and delivery periods) and for which power does not flow. We net these book-outs, which reduces both wholesale revenues and fuel and purchased power costs.

Some of our cost recovery mechanisms are alternative revenue programs.  For alternative revenue programs that meet specified accounting criteria, we recognize revenues when the specific events permitting billing of the additional revenues have been completed.

See Notes 2 and 4 for additional information.

Allowance for Doubtful Accounts
 
The allowance for doubtful accounts represents our best estimate of existing accounts receivable that will ultimately be uncollectible.  The allowance is calculated by applying an estimated write-off factor to utility revenues.  The write-off factors used to estimate uncollectible accounts are based upon consideration of both historical collections experience and management’s best estimate of future collections success given the existing collections environment.
 
Property, Plant and Equipment
 
Utility plant is the term we use to describe the business property and equipment that supports electric service, consisting primarily of generation, transmission and distribution facilities.  We report utility plant at its original cost, which includes:
 
material and labor;
contractor costs;
capitalized leases;
construction overhead costs (where applicable); and
allowance for funds used during construction.

Pinnacle West’s property, plant and equipment included in the December 31, 2019 and 2018 Consolidated Balance Sheets is composed of the following (dollars in thousands):

Property, Plant and Equipment:
2019
 
2018
Generation
$
8,916,872

 
$
8,285,514

Transmission
3,095,907

 
3,033,579

Distribution
6,690,697

 
6,378,345

General plant
1,132,816

 
1,039,190

Plant in service and held for future use
19,836,292

 
18,736,628

Accumulated depreciation and amortization
(6,637,857
)
 
(6,366,014
)
Net
13,198,435

 
12,370,614

Construction work in progress
808,133

 
1,170,062

Palo Verde sale leaseback, net of accumulated depreciation
101,906

 
105,775

Intangible assets, net of accumulated amortization
290,564

 
262,902

Nuclear fuel, net of accumulated amortization
123,500

 
120,217

Total property, plant and equipment
$
14,522,538

 
$
14,029,570



Property, plant and equipment balances and classes for APS are not materially different than Pinnacle West.

We expense the costs of plant outages, major maintenance and routine maintenance as incurred.  We charge retired utility plant to accumulated depreciation.  Liabilities associated with the retirement of tangible long-lived assets are recognized at fair value as incurred and capitalized as part of the related tangible long-lived assets.  Accretion of the liability due to the passage of time is an operating expense, and the capitalized cost is depreciated over the useful life of the long-lived asset.  See Note 12 for additional information.
 
APS records a regulatory liability for the excess that has been recovered in regulated rates over the amount calculated in accordance with guidance on accounting for asset retirement obligations.  APS believes it is probable it will recover in regulated rates, the costs calculated in accordance with this accounting guidance.
 
We record depreciation and amortization on utility plant on a straight-line basis over the remaining useful life of the related assets.  The approximate remaining average useful lives of our utility property at December 31, 2019 were as follows:
 
Fossil plant — 17 years;
Nuclear plant — 22 years;
Other generation — 21 years;
Transmission — 40 years;
Distribution — 34 years; and
General plant — 8 years.
 
Depreciation of utility property, plant and equipment is computed on a straight-line, remaining-life basis. Depreciation expense was $522 million in 2019, $486 million in 2018, and $453 million in 2017. For the years 2017 through 2019, the depreciation rates ranged from a low of 0.18% to a high of 24.49%.  The weighted-average depreciation rate was 2.81% in 2019, 2.81% in 2018, and 2.80% in 2017.

Asset Retirement Obligations

APS has asset retirement obligations for its Palo Verde nuclear facilities and certain other generation assets.  The Palo Verde asset retirement obligation primarily relates to final plant decommissioning.  This obligation is based on the NRC’s requirements for disposal of radiated property or plant and agreements APS reached with the ACC for final decommissioning of the plant.  The non-nuclear generation asset retirement obligations primarily relate to requirements for removing portions of those plants at the end of the plant life or lease term and coal ash pond closures. Some of APS’s transmission and distribution assets have asset retirement obligations because they are subject to right of way and easement agreements that require final removal.  These agreements have a history of uninterrupted renewal that APS expects to continue.  As a result, APS cannot reasonably estimate the fair value of the asset retirement obligation related to such transmission and distribution assets. Additionally, APS has aquifer protection permits for some of its generation sites that require the closure of certain facilities at those sites.

See Note 12 for further information on Asset Retirement Obligations.

Allowance for Funds Used During Construction
 
AFUDC represents the approximate net composite interest cost of borrowed funds and an allowed return on the equity funds used for construction of regulated utility plant.  Both the debt and equity components of AFUDC are non-cash amounts within the Consolidated Statements of Income.  Plant construction costs, including AFUDC, are recovered in authorized rates through depreciation when completed projects are placed into commercial operation.
 
AFUDC was calculated by using a composite rate of 6.98% for 2019, 7.03% for 2018, and 6.68% for 2017.  APS compounds AFUDC semi-annually and ceases to accrue AFUDC when construction work is completed and the property is placed in service.
 
Materials and Supplies
 
APS values materials, supplies and fossil fuel inventory using a weighted-average cost method.  APS materials, supplies and fossil fuel inventories are carried at the lower of weighted-average cost or market, unless evidence indicates that the weighted-average cost (even if in excess of market) will be recovered.
 
Fair Value Measurements
 
We apply recurring fair value measurements to cash equivalents, derivative instruments, investments held in the nuclear decommissioning trust and other special use funds. On an annual basis, we apply fair value measurements to plan assets held in our retirement and other benefits plans. Due to the short-term nature of short-term borrowings, the carrying values of these instruments approximate fair value.  Fair value measurements may also be applied on a nonrecurring basis to other assets and liabilities in certain circumstances such as impairments.  We also disclose fair value information for our long-term debt, which is carried at amortized cost. See Note 7 for additional information.
 
Fair value is the price that would be received for an asset or paid to transfer a liability (exit price) in the principal or most advantageous market which we can access for the asset or liability in an orderly transaction between willing market participants on the measurement date.  Inputs to fair value may include observable and unobservable data.  We maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.
 
We determine fair market value using observable inputs such as actively-quoted prices for identical instruments when available.  When actively-quoted prices are not available for the identical instruments, we use other observable inputs, such as prices for similar instruments, other corroborative market information, or prices provided by other external sources.  For options, long-term contracts and other contracts for which observable price data are not available, we use models and other valuation methods, which may incorporate unobservable inputs to determine fair market value.
 
The use of models and other valuation methods to determine fair market value often requires subjective and complex judgment.  Actual results could differ from the results estimated through application of these methods.
 
See Note 14 for additional information about fair value measurements.
 
Derivative Accounting
 
We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas, coal and in interest rates.  We manage risks associated with market volatility by utilizing various physical and financial instruments including futures, forwards, options and swaps.  As part of our overall risk management program, we may use derivative instruments to hedge purchases and sales of electricity and fuels.  The changes in market value of such contracts have a high correlation to price changes in the hedged transactions.  We also enter into derivative instruments for economic hedging purposes.  Contracts that have the same terms (quantities, delivery points and delivery periods) and for which power does not flow are netted, which reduces both revenues and fuel and purchased power expenses in our Consolidated Statements of Income, but does not impact our financial condition, net income or cash flows.
 
We account for our derivative contracts in accordance with derivatives and hedging guidance, which requires all derivatives not qualifying for a scope exception to be measured at fair value on the balance sheet as
either assets or liabilities.  Transactions with counterparties that have master netting arrangements are reported net on the balance sheet.  See Note 17 for additional information about our derivative instruments.
 
Loss Contingencies and Environmental Liabilities
 
Pinnacle West and APS are involved in certain legal and environmental matters that arise in the normal course of business.  Contingent losses and environmental liabilities are recorded when it is determined that it is probable that a loss has occurred and the amount of the loss can be reasonably estimated.  When a range of the probable loss exists and no amount within the range is a better estimate than any other amount, Pinnacle West and APS record a loss contingency at the minimum amount in the range.  Unless otherwise required by GAAP, legal fees are expensed as incurred.
 
Retirement Plans and Other Postretirement Benefits
 
Pinnacle West sponsors a qualified defined benefit and account balance pension plan for the employees of Pinnacle West and its subsidiaries.  We also sponsor another postretirement benefit plan for the employees of Pinnacle West and its subsidiaries that provides medical and life insurance benefits to retired employees.  Pension and other postretirement benefit expense are determined by actuarial valuations, based on assumptions that are evaluated annually.  See Note 8 for additional information on pension and other postretirement benefits.
 
Nuclear Fuel
 
APS amortizes nuclear fuel by using the unit-of-production method.  The unit-of-production method is based on actual physical usage.  APS divides the cost of the fuel by the estimated number of thermal units it expects to produce with that fuel.  APS then multiplies that rate by the number of thermal units produced within the current period.  This calculation determines the current period nuclear fuel expense.
 
APS also charges nuclear fuel expense for the interim storage and permanent disposal of spent nuclear fuel.  The DOE is responsible for the permanent disposal of spent nuclear fuel and charged APS $0.001 per kWh of nuclear generation through May 2014, at which point the DOE reduced the fee to zero.  In accordance with a settlement agreement with the DOE in August 2014, we now accrue a receivable and an offsetting regulatory liability through the settlement period ending December of 2019. See Note 11 for information on spent nuclear fuel disposal costs.
 
Income Taxes
 
Income taxes are provided using the asset and liability approach prescribed by guidance relating to accounting for income taxes and are based on currently enacted tax rates.  We file our federal income tax return on a consolidated basis, and we file our state income tax returns on a consolidated or unitary basis.  In accordance with our intercompany tax sharing agreement, federal and state income taxes are allocated to each first-tier subsidiary as though each first-tier subsidiary filed a separate income tax return.  Any difference between that method and the consolidated (and unitary) income tax liability is attributed to the parent company.  The income tax accounts reflect the tax and interest associated with management’s estimate of the largest amount of tax benefit that is greater than 50% likely of being realized upon settlement for all known and measurable tax exposures. See Note 5 for additional discussion.
 
Cash and Cash Equivalents
 
We consider cash equivalents to be highly liquid investments with a remaining maturity of three months or less at acquisition.

The following table summarizes supplemental Pinnacle West cash flow information for each of the last three years (dollars in thousands):
 
 
Year ended December 31,
 
2019
 
2018
 
2017
Cash paid during the period for:
 

 
 

 
 

Income taxes, net of refunds
$
12,535

 
$
21,173

 
$
2,186

Interest, net of amounts capitalized
218,664

 
208,479

 
189,288

Significant non-cash investing and financing activities:
 

 
 

 
 

Accrued capital expenditures
$
141,297

 
$
132,620

 
$
130,404

Dividends declared but not paid
87,982

 
82,675

 
77,667

Right-of-use operating lease assets obtained in exchange for operating lease liabilities
11,262

 

 

Sale of 4CA 7% interest in Four Corners

 
68,907

 


The following table summarizes supplemental APS cash flow information for each of the last three years (dollars in thousands):
 
 
Year ended December 31,
 
2019
 
2018
 
2017
Cash paid (received) during the period for:
 

 
 

 
 

Income taxes, net of refunds
$
(15,042
)
 
$
77,942

 
$
(14,098
)
Interest, net of amounts capitalized
204,261

 
196,419

 
184,210

Significant non-cash investing and financing activities:
 

 
 

 
 

Accrued capital expenditures
$
141,297

 
$
132,620

 
$
130,057

Dividends declared but not paid
88,000

 
82,700

 
77,700

Right-of-use operating lease assets obtained in exchange for operating lease liabilities
11,262

 

 




Intangible Assets
 
We have no goodwill recorded and have separately disclosed other intangible assets, primarily APS's software, on Pinnacle West’s Consolidated Balance Sheets. The intangible assets are amortized over their finite useful lives.  Amortization expense was $66 million in 2019, $68 million in 2018, and $72 million in 2017.  Estimated amortization expense on existing intangible assets over the next five years is $68 million in 2020, $52 million in 2021, $41 million in 2022, $32 million in 2023, and $22 million in 2024.  At December 31, 2019, the weighted-average remaining amortization period for intangible assets was 8 years.
 
Investments
 
El Dorado holds investments in both debt and equity securities.  Investments in debt securities are generally accounted for as held-to-maturity and investments in equity securities are accounted for using either
the equity method (if significant influence) or the measurement alternative for investments without readily determinable fair values (if less than 20% ownership and no significant influence).

Bright Canyon holds investments in equity securities. Investments in equity securities are accounted for using either the equity method (if significant influence) or the measurement alternative for investments without readily determinable fair values (if less than 20% ownership and no significant influence).
 
Our investments in the nuclear decommissioning trusts, coal reclamation escrow account and active union employee medical account, are accounted for in accordance with guidance on accounting for investments in debt and equity securities. See Notes 14 and 20 for more information on these investments.

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

Preferred Stock

At December 31, 2019, Pinnacle West had 10 million shares of serial preferred stock authorized with no par value, none of which was outstanding, and APS had 15,535,000 shares of various types of preferred stock authorized with $25, $50 and $100 par values, none of which was outstanding.
v3.19.3.a.u2
Revenue
12 Months Ended
Dec. 31, 2019
Revenue from Contract with Customer [Abstract]  
Revenue Revenue

Sources of Revenue

The following table provides detail of Pinnacle West's consolidated revenue disaggregated by revenue sources (dollars in thousands):
 
Year Ended December 31,
 
Year Ended December 31,
 
2019
 
2018
Retail Electric Service
 
 
 
Residential
$
1,761,122

 
$
1,867,370

Non-Residential
1,509,514

 
1,628,891

Wholesale Energy Sales
121,805

 
109,198

Transmission Services for Others
62,460

 
60,261

Other Sources
16,308

 
25,527

Total Operating Revenues
$
3,471,209

 
$
3,691,247



Retail Electric Revenue. Pinnacle West's retail electric revenue is generated by our wholly owned regulated subsidiary APS's sale of electricity to our regulated customers within the authorized service territory at tariff rates approved by the ACC and based on customer usage. Revenues related to the sale of electricity are generally recognized when service is rendered or electricity is delivered to customers. The billing of electricity sales to individual customers is based on the reading of their meters. We obtain customers' meter data on a systematic basis throughout the month, and generally bill customers within a month from when service was provided. Customers are generally required to pay for services within 15 days of when the services are billed.

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

Our revenues primarily consist of activities that are classified as revenues from contracts with customers. We derive our revenues from contracts with customers primarily from sales of electricity to our regulated retail customers. Revenues from contracts with customers also include wholesale and transmission activities. Our revenues from contracts with customers for the year ended December 31, 2019 and 2018 were $3,415 million and $3,644 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 year ended December 31, 2019 and 2018, our revenues that do not qualify as revenue from contracts with customers were $56 million and $47 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 Consolidated Balance Sheets as of December 31, 2019 and 2018.
v3.19.3.a.u2
New Accounting Standards
12 Months Ended
Dec. 31, 2019
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]  
New Accounting Standards New Accounting Standards
 
Standards Adopted in 2019

ASU 2016-02, Leases

In February 2016, a new lease accounting standard was issued. This new standard supersedes the existing lease accounting model, and modifies both lessee and lessor accounting. The new standard requires a lessee to reflect most operating lease arrangements on the balance sheet by recording a right-of-use asset and a lease liability that is initially measured at the present value of lease payments. Among other changes, the new standard also modifies the definition of a lease, and requires expanded lease disclosures. Since the issuance of the new lease standard, additional lease related guidance has been issued relating to land easements and how entities may elect to account for these arrangements at transition, among other items. The new lease standard and related amendments were effective for us on January 1, 2019, with early application permitted. The standard must be adopted using a modified retrospective approach with a cumulative-effect adjustment to the opening balance of retained earnings determined at either the date of adoption, or the earliest period presented in the financial statements. The standard includes various optional practical expedients provided to facilitate transition. We adopted this standard, and related amendments, on January 1, 2019. See Note 9 for additional information.

ASU 2018-15, Internal-Use Software: Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement that is a Service Contract

In August 2018, a new accounting standard was issued that clarifies how customers in a cloud computing service arrangement should account for implementation costs associated with the arrangement. To determine which implementation costs should be capitalized, the new guidance aligns the accounting with existing guidance pertaining to internal-use software. As a result of this new standard, certain cloud computing service arrangement implementation costs will now be subject to capitalization and amortized on a straight-line basis over the cloud computing service arrangement term. The new standard was effective for us on January 1, 2020, with early application permitted, and may have been applied using either a retrospective or prospective transition approach. On July 1, 2019, we early adopted this new accounting standard using the prospective approach. The adoption did not have a material impact on our financial statements.

Standard Adopted in 2020

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

In June 2016, a new accounting standard was issued that amends the measurement of credit losses on certain financial instruments. The new standard requires entities to use a current expected credit loss model to measure impairment of certain investments in debt securities, trade accounts receivables, and other financial instruments. Since the issuance of the new standard, various guidance has been issued that amends the new standard, including clarifications of certain aspects of the standard and targeted transition relief, among other changes. The new standard and related amendments were effective for us on January 1, 2020, and must be adopted using a modified retrospective approach for certain aspects of the standard, and a prospective approach for other aspects of the standard. We adopted the standard on January 1, 2020 using primarily the modified retrospective approach. While the adoption of this guidance changed our process and methodology for determining credit losses, these changes did not have a material impact on our financial statements.
v3.19.3.a.u2
Regulatory Matters
12 Months Ended
Dec. 31, 2019
Regulated Operations [Abstract]  
Regulatory Matters Regulatory Matters
 
2019 Retail Rate Case Filing with the Arizona Corporation Commission

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

The principal provisions of APS's application are:

a test year comprised of twelve months ended June 30, 2019, adjusted as described below;
an original cost rate base of $8.87 billion, which approximates the ACC-jurisdictional portion of the book value of utility assets, net of accumulated depreciation and other credits;
the following proposed capital structure and costs of capital:
 
 
Capital Structure
 
Cost of Capital
 
Long-term debt
 
45.3
%
4.10
%
Common stock equity
 
54.7
%
10.15
%
Weighted-average cost of capital
 
 
 
7.41
%

 
a 1% return on the increment of fair value rate base above APS’s original cost rate base, as provided for by Arizona law;
authorization to defer until APS's next general rate case the increase or decrease in its Arizona property taxes attributable to tax rate changes after the date the rate application is adjudicated;
a number of proposed rate and program changes for residential customers, including:
a super off-peak period during the winter months for APS’s time-of-use with demand rates;
additional $1.25 million in funding for APS's limited-income crisis bill program; and
a flat bill/subscription rate pilot program;
proposed rate design changes for commercial customers, including an experimental program designed to provide access to market pricing for up to 200 MW of medium and large commercial customers;
recovery of the deferral and rate base effects of the construction and operating costs of the Ocotillo modernization project (see discussion below of the 2017 Settlement Agreement); and
continued recovery of the remaining investment and other costs related to the retirement and closure of the Navajo Plant (see "Navajo Plant" below).

APS requested that the increase become effective December 1, 2020.  The hearing for this rate case is currently scheduled to begin in July 2020. APS cannot predict the outcome of its request.

2016 Retail Rate Case Filing with the Arizona Corporation Commission
 
On June 1, 2016, APS filed an application with the ACC for an annual increase in retail base rates. On March 27, 2017, a majority of the stakeholders in the general retail rate case, including the ACC Staff, the Residential Utility Consumer Office, 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 agreement by APS not to file another general retail rate case application before June 1, 2019;
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 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 PSA to include certain environmental chemical costs and third-party energy storage costs;
a new AZ Sun II program (now known as APS Solar Communities) for utility-owned solar distributed generation ("DG") with the purpose of expanding access to rooftop solar for low and moderate income Arizonans, recoverable through the RES, to be no less than $10 million per year in capital costs, and not more than $15 million per year in capital costs;
an increase to the per kWh cap for the environmental improvement surcharge from $0.00016 to $0.00050 and the addition of a balancing account;
rate design changes, including:
a change in the on-peak time of use period from noon - 7 p.m. to 3 p.m. - 8 p.m. Monday through Friday, excluding holidays;
non-grandfathered DG customers would be required to select a rate option that has time of use rates and either a new grid access charge or demand component;
a Resource Comparison Proxy (“RCP”) for exported energy of 12.9 cents per kWh in year one; and
an agreement by APS not to pursue any new self-build generation (with certain exceptions) having an in-service date prior to January 1, 2022 (extended to December 31, 2027 for combined-cycle generating units), unless expressly authorized by the ACC.

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”) and not a request for rehearing. Arizona Revised Statute §40-246 requires the ACC to hold a hearing regarding any complaint alleging that a public service corporation is in violation of any commission order or that the rates being charged are not just and reasonable if the complaint is signed by at least twenty-five customers of the public service corporation. The Complaint alleged that APS is “in violation of commission order” [sic]. On February 13, 2018, the complainant filed an amended Complaint alleging that the rates and charges in the 2017 Rate Case Decision are not just and reasonable.  The complainant requested that the ACC hold a hearing on the amended Complaint to determine if the average bill impact on residential customers of the rates and charges approved in the 2017 Rate Case Decision is greater than 4.54% (the average annual bill impact for a typical APS residential customer estimated by APS) and, if so, what effect the alleged greater bill impact has on APS's revenues and the overall reasonableness and justness of APS's rates and charges, in order to determine if there is sufficient evidence to warrant a full-scale rate hearing.  The ACC held a hearing on this matter beginning in September 2018 and the hearing was concluded on October 1, 2018. On April 9, 2019, the Administrative Law Judge issued a Recommended Opinion and Order recommending that the Complaint be dismissed. The ACC considered the matter at its April and May 2019 open meetings, but no decision was issued. 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 reconsidered the matter and 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.

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 and file a report by May 3, 2019. 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 April 23, 2019, the ACC Staff indicated that they would need additional time beyond May 3, 2019 to file the requested report.

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 cannot predict the outcome or impact of the rate case filed on October 31, 2019. APS is assessing the impact to its financial statements of the implementation of the other key provisions of the amended order regarding the rate review and cannot predict at this time whether they will have a material impact on its financial position, results of operations or cash flows. 

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 June 30, 2017, APS filed its 2018 RES Implementation Plan and proposed a budget of approximately $90 million.  APS’s budget request supports existing approved projects and commitments and includes the anticipated transfer of specific revenue requirements into base rates in accordance with the 2017 Settlement Agreement and also requests a permanent waiver of the residential distributed energy requirement for 2018 contained in the RES rules. APS's 2018 RES budget request was lower than the 2017 RES budget due in part to a certain portion of the RES being collected by APS in base rates rather than through the RES adjustor.

On November 20, 2017, APS filed an updated 2018 RES budget to include budget adjustments for APS Solar Communities (formerly known as AZ Sun II), which was approved as part of the 2017 Rate Case Decision. APS Solar Communities is a 3-year program authorizing APS to spend $10 million to $15 million in capital costs each year to install utility-owned DG systems for low to moderate income residential homes, non-profit entities, Title I schools and rural government facilities. The 2017 Rate Case Decision provided that all operations and maintenance expenses, property taxes, marketing and advertising expenses, and the capital
carrying costs for this program will be recovered through the RES. On June 12, 2018, the ACC approved the 2018 RES Implementation Plan including a waiver of the distributed energy requirements for the 2018 implementation year.

On June 29, 2018, APS filed its 2019 RES Implementation Plan and proposed a budget of approximately $89.9 million.  APS’s budget request supports existing approved projects and commitments and requests a permanent waiver of the residential distributed energy requirement for 2019 contained in the RES rules. On October 29, 2019, the ACC approved the 2019 RES Implementation Plan including a waiver of the residential distributed energy requirements for the 2019 implementation year.

On July 1, 2019, APS filed its 2020 RES Implementation Plan and proposed a budget of approximately $86.3 million. APS’s budget request supports existing approved projects and commitments and requests a permanent waiver of the residential distributed energy requirement for 2020 contained in the RES rules. The ACC has not yet ruled on the 2020 RES Implementation Plan.

On July 2, 2019, ACC Staff issued draft rules, which propose a RES goal of 45% of retail energy served be renewables by 2035 and a goal of 20% of retail sales during peak demand to be from clean energy resources by 2035.  The draft rules would also require a certain amount of the RES goal to be derived from distributed renewable storage, for which utilities would be required to offer performance-based incentives. Nuclear energy would be considered a clean resource under the draft rules. See "Energy Modernization Plan" below for more information.

On January 8, 2020, an ACC commissioner proposed replacing the current RES standard with a new standard ("KREST II"). KREST II sets a RES goal of 50% of retail energy to be served by renewables by 2028, 100% zero carbon resources by 2045, and a 35% energy efficiency resource standard by 2030 with a 10% demand response carve out. APS cannot predict the outcome of this matter.

Demand Side Management Adjustor Charge. The ACC EES requires APS to submit a Demand Side Management Implementation Plan ("DSM Plan") annually for review by and approval of the ACC. Verified energy savings from APS's resource savings projects can be counted toward compliance with the Electric Energy Efficiency Standards; however, APS is not allowed to count savings from systems savings projects toward determination of the achievement of performance incentives, nor may APS include savings from these system savings projects in the calculation of its LFCR mechanism (see below for discussion of the LFCR).

On September 1, 2017, APS filed its 2018 DSM Plan, which proposes modifications to the demand side management portfolio to better meet system and customer needs by focusing on peak demand reductions, storage, load shifting and demand response programs in addition to traditional energy savings measures. The 2018 DSM Plan seeks a requested budget of $52.6 million and requests a waiver of the Electric Energy Efficiency Standard for 2018.   On November 14, 2017, APS filed an amended 2018 DSM Plan, which revised the allocations between budget items to address customer participation levels, but kept the overall budget at $52.6 million. The ACC has not yet ruled on the APS 2018 amended DSM Plan.

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

On December 31, 2019, APS filed its 2020 DSM Plan, which requests a budget of $51.9 million and continues APS's focus on DSM strategies such as peak demand reduction, load shifting, storage and electrification strategies. The 2020 DSM Plan addresses all components of the 2018 and 2019 DSM plans,
which enables the ACC to review the 2020 DSM Plan only. The ACC has not yet ruled on the APS 2020 DSM Plan.
     
Power Supply Adjustor Mechanism and Balance.  The PSA provides for the adjustment of retail rates to reflect variations primarily in retail fuel and purchased power costs. The PSA is subject to specified parameters and procedures, including the following:

APS records deferrals for recovery or refund to the extent actual retail fuel and purchased power costs vary from the Base Fuel Rate;

An adjustment to the PSA rate is made annually each February 1 (unless otherwise approved by the ACC) and goes into effect automatically unless suspended by the ACC;

The PSA uses a forward-looking estimate of fuel and purchased power costs to set the annual PSA rate, which is reconciled to actual costs experienced for each PSA Year (February 1 through January 31) (see the following bullet point);

The PSA rate includes (a) a “Forward Component,” under which APS recovers or refunds differences between expected fuel and purchased power costs for the upcoming calendar year and those embedded in the Base Fuel Rate; (b) a “Historical Component,” under which differences between actual fuel and purchased power costs and those recovered or refunded through the combination of the Base Fuel Rate and the Forward Component are recovered during the next PSA Year; and (c) a “Transition Component,” under which APS may seek mid-year PSA changes due to large variances between actual fuel and purchased power costs and the combination of the Base Fuel Rate and the Forward Component; and

The PSA rate may not be increased or decreased more than $0.004 per kWh in a year without permission of the ACC.

The following table shows the changes in the deferred fuel and purchased power regulatory asset for 2019 and 2018 (dollars in thousands):
 
Twelve Months Ended
December 31,
 
2019
 
2018
Beginning balance
$
37,164

 
$
75,637

Deferred fuel and purchased power costs — current period
82,481

 
78,277

Amounts charged to customers
(49,508
)
 
(116,750
)
Ending balance
$
70,137

 
$
37,164


 

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

The PSA rate for the PSA year beginning February 1, 2019 is $0.001658 per kWh, consisting of a Forward Component of $0.000536 per kWh and a Historical Component of $0.001122 per kWh. This represented a $0.002897 per kWh decrease compared to 2018.

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

On March 15, 2019, APS filed an application with the ACC requesting approval to recover the costs related to two energy storage power purchase tolling agreements through the PSA. This application is pending with the ACC. APS cannot predict the outcome of this matter.
    
Environmental Improvement Surcharge ("EIS"). The EIS permits APS to recover the capital carrying costs (rate of return, depreciation and taxes) plus incremental operations and maintenance expenses associated with environmental improvements made outside of a test year to comply with environmental standards set by federal, state, tribal, or local laws and regulations.  A filing is made on or before February 1st for qualified environmental improvements made during the prior calendar year, and the new charge becomes effective April 1 unless suspended by the ACC.  There is an overall cap of $0.0005 per kWh (approximately $13 - 14 million per year).  APS’s February 1, 2020 application requested an increase in the charge to $8.75 million, or $2.0 million over the charge in effect for the 2019-2020 rate effective year.

 Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters. In July 2008, FERC approved a modification to APS’s Open Access Transmission Tariff to allow APS to move from fixed rates to a formula rate-setting methodology in order to more accurately reflect and recover the costs that APS incurs in providing transmission services.  A large portion of the rate represents charges for transmission services to serve APS's retail customers ("Retail Transmission Charges").  In order to recover the Retail Transmission Charges, APS was previously required to file an application with, and obtain approval from, the ACC to reflect changes in Retail Transmission Charges through the TCA.  Under the terms of the settlement agreement entered into in 2012 regarding APS's rate case ("2012 Settlement Agreement"), however, an adjustment to rates to recover the Retail Transmission Charges will be made annually each June 1 and will go into effect automatically unless suspended by the ACC.

The formula rate is updated each year effective June 1 on the basis of APS's actual cost of service, as disclosed in APS's FERC Form 1 report for the previous fiscal year.  Items to be updated include actual capital expenditures made as compared with previous projections, transmission revenue credits and other items.  The resolution of proposed adjustments can result in significant volatility in the revenues to be collected.  APS reviews the proposed formula rate filing amounts with the ACC Staff.  Any items or adjustments which are not agreed to by APS and the ACC Staff can remain in dispute until settled or litigated at FERC.  Settlement or litigated resolution of disputed issues could require an extended period of time and could have a significant effect on the Retail Transmission Charges because any adjustment, though applied prospectively, may be calculated to account for previously over- or under-collected amounts.

On March 7, 2018, APS made a filing to make modifications to its annual transmission formula to provide transmission customers the benefit of the reduced federal corporate income tax rate resulting from the Tax 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.

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

Effective June 1, 2019, APS's annual wholesale transmission rates for all users of its transmission system increased by approximately $4.9 million for the twelve-month period beginning June 1, 2019 in accordance with the FERC-approved formula. An adjustment to APS’s retail rates to recover FERC approved transmission charges went into effect automatically on June 1, 2019.
 
Lost Fixed Cost Recovery Mechanism. The LFCR mechanism permits APS to recover on an after-the-fact basis a portion of its fixed costs that would otherwise have been collected by APS in the kWh sales lost due to APS energy efficiency programs and to DG such as rooftop solar arrays.  The fixed costs recoverable by the LFCR mechanism were first established in the 2012 Settlement Agreement and amount to approximately 3.1 cents per residential kWh lost and 2.3 cents per non-residential kWh lost.  These amounts were revised in the 2017 Settlement Agreement to 2.5 cents for both lost residential and non-residential kWh. 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). APS cannot predict the outcome or timing of the ACC’s consideration of this filing. Because the LFCR mechanism has a balancing account that trues up any under or over recoveries, the delay in implementation does not have an adverse effect on APS.
    
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 final billing cycle of March 2020. Both the timing of the reduction in revenues refunded through TEAM Phase II and the offsetting income tax benefit are recognized based upon our seasonal kWh sales pattern.

On April 10, 2019, APS filed a third request with the ACC that addressed the amortization of depreciation related excess deferred taxes over a 28.5 year period consistent with IRS normalization rules (“TEAM Phase III”).  On October 29, 2019, the ACC approved TEAM Phase III providing both (i) a one-time bill credit of $64 million which was credited to customers on their December 2019 bills, and (ii) a monthly bill credit effective the first billing cycle in December 2019 which will provide an additional benefit of $39.5 million to customers through December 31, 2020. It is currently anticipated that benefits related to the amortization of depreciation related excess deferred taxes for periods beginning after December 31, 2020 will be fully incorporated into the 2019 rate case filing.

Net Metering

In 2015, the ACC voted to conduct a generic evidentiary hearing on the value and cost of DG to gather information that will inform the ACC on net metering issues and cost of service studies in upcoming utility rate cases.  A hearing was held in April 2016. On October 7, 2016, the Administrative Law Judge issued a recommendation in the docket concerning the value and cost of DG solar installations. On December 20, 2016, the ACC completed its open meeting to consider the recommended opinion and order by the Administrative Law Judge. After making several amendments, the ACC approved the recommended decision by a 4-1 vote. As a result of the ACC’s action, effective with APS’s 2017 Rate Case Decision, the net metering tariff that governs payments for energy exported to the grid from residential rooftop solar systems was replaced by a more formula-driven approach that utilizes inputs from historical wholesale solar power until an avoided cost methodology is developed by the ACC.

As amended, the decision provides that payments by utilities for energy exported to the grid from DG solar facilities will be determined using a RCP methodology, a method that is based on the most recent five-year rolling average price that APS pays for utility-scale solar projects, while a forecasted avoided cost methodology is being developed.  The price established by this RCP method will be updated annually (between general retail rate cases) but will not be decreased by more than 10% per year. Once the avoided cost methodology is developed, the ACC will determine in APS's subsequent rate cases which method (or a combination of methods) is appropriate to determine the actual price to be paid by APS for exported distributed energy.

In addition, the ACC made the following determinations:

Customers who have interconnected a DG system or submitted an application for interconnection for DG systems prior to September 1, 2017, based on APS's 2017 Rate Case Decision, will be grandfathered for a period of 20 years from the date the customer’s interconnection application was accepted by the utility;

Customers with DG solar systems are to be considered a separate class of customers for ratemaking purposes; and

Once an export price is set for APS, no netting or banking of retail credits will be available for new DG customers, and the then-applicable export price will be guaranteed for new customers for a period of 10 years.

This decision of the ACC addresses policy determinations only. The decision states that its principles will be applied in future general retail rate cases, and the policy determinations themselves may be subject to future change, as are all ACC policies. A first-year export energy price of 12.9 cents per kWh was included in the 2017 Settlement Agreement and became effective on September 1, 2017.
    
In accordance with the 2017 Rate Case Decision, APS filed its request for a second-year export energy price of 11.6 cents per kWh on May 1, 2018.  This price reflected the 10% annual reduction discussed above. The new rate rider became effective on October 1, 2018. APS filed its request for a third-year export energy price of 10.5 cents per kWh on May 1, 2019.  This price also reflects the 10% annual reduction discussed above. The new rate rider became effective on October 1, 2019.

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

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

Subpoena from Arizona Corporation Commissioner Robert Burns

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

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

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

On August 4, 2017, Commissioner Burns amended his complaint to add all of the ACC Commissioners and the ACC itself as defendants. All defendants moved to dismiss the amended complaint. On February 15, 2018, the Superior Court dismissed Commissioner Burns’ amended complaint. On March 6, 2018, Commissioner Burns filed an objection to the proposed final order from the Superior Court and a motion to further amend his complaint. The Superior Court permitted Commissioner Burns to amend his complaint to add a claim regarding his attempted investigation into whether his fellow commissioners should have been disqualified from voting on APS’s 2017 rate case. Commissioner Burns filed his second amended complaint, and all defendants filed responses opposing the second amended complaint and requested that it be dismissed. Oral argument occurred in November 2018 regarding the motion to dismiss. On December 18, 2018, the trial court granted the defendants’ motions to dismiss and entered final judgment on January 18, 2019. On February 13, 2019, Commissioner Burns filed a notice of appeal. On July 12, 2019, Commissioner Burns filed his opening brief in the Arizona Court of Appeals. APS filed its answering brief on October 21, 2019. The Arizona Court of Appeals granted the request for oral argument but no date has been set. APS and Pinnacle West cannot predict the outcome of this matter.

Information Requests from Arizona Corporation Commissioners

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

2018 Renewable Energy Ballot Initiative

On February 20, 2018, a renewable energy advocacy organization filed with the Arizona Secretary of State a ballot initiative for an Arizona constitutional amendment requiring Arizona public service corporations to provide at least 50% of their annual retail sales of electricity from renewable sources by 2030. For purposes of the proposed amendment, eligible renewable sources would not include nuclear generating facilities. The initiative was placed on the November 2018 Arizona elections ballot. On November 6, 2018, the initiative failed to receive adequate voter support and was defeated.
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 a set of draft rules in regards to the Energy Modernization Plan and workshops were held on April 29, 2019 regarding these draft rules. On July 2, 2019, the ACC Staff issued a revised set of draft rules, which propose a RES goal of 45% of retail energy served be renewable by 2035 and a goal of 20% of retail sales during peak demand to be from clean energy resources by 2035.  The draft rules also require a certain amount of the RES goal to be derived from distributed renewable storage, for which utilities would be required to offer performance-based incentives.  Nuclear energy would be considered a clean resource under the draft rules. The ACC held various stakeholder meetings and workshops on ACC Staff’s draft energy rules in July through September 2019 and have scheduled a workshop to be held on March 10 - 11, 2020. On February 19, 2020, the ACC Staff issued a revised proposed set of draft rules that will be discussed at the workshop. APS cannot predict the outcome of this matter.

Integrated Resource Planning

ACC rules require utilities to develop fifteen-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.

Public Utility Regulatory Policies Act

In August 2016, APS filed an application requesting that all of its contracts with qualifying facilities over 100 kW be set at a presumptive maximum 2-year term. A qualifying facility is an eligible energy-producing facility as defined by FERC regulations within a host electric utility’s service territory that has a right to sell to the host utility. Host utilities are required to purchase power from qualifying facilities at an avoided cost as determined by the utility subject to state commission oversight. A hearing was held in August 2019 and briefing on this matter was completed in October 2019 regarding APS’s application. On December 17, 2019, the ACC denied the application and mandated a minimum contract length of 18 years for qualifying facilities over 100 kW and the rate paid to the qualifying facilities will be based on the long-term avoided cost.

Residential Electric Utility Customer Service Disconnections

On June 13, 2019, APS voluntarily suspended electric disconnections for residential customers who had not paid their bills.  On June 20, 2019, the ACC voted to enact emergency rule amendments to prevent residential electric utility customer service disconnections during the period from June 1 through October 15. During the moratorium on disconnections, APS could not charge late fees and interest on amounts that were past due from customers.  Customer deposits must also be used to pay delinquent amounts before disconnection can occur and customers will have four months to pay back their deposit and any remaining delinquent amounts.  In accordance with the emergency rules, APS began putting delinquent customers on a mandatory four-month payment plan beginning on October 16, 2019. The emergency rule changes will be effective for 180 days and may be renewed for one additional 180 day period. During that time, the ACC began a formal regular rulemaking process to allow stakeholder input and time for consideration of permanent rule changes.  The ACC further ordered that each regulated electric utility serving retail customers in Arizona update its service conditions by incorporating the emergency rule amendments, restore power to any customers who were disconnected during the month of June 2019 and credit any fees that were charged for a reconnection. The ACC Staff issued draft amendments to the customer service disconnections rules. Stakeholders submitted initial comments to the draft amendments on September 23, 2019. ACC stakeholder meetings were held in September 2019, October 2019 and January 2020 regarding the customer service disconnections rules. The disconnection moratorium resulted in a negative impact to our 2019 operating results of approximately $10 million pre-tax. APS is further assessing the impact to its financial statements beyond 2019, which will be affected by the results of final rulemaking related to disconnections.

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 has scheduled a workshop for February 25-26, 2020 for further consideration and discussion of the retail electric competition rules. APS cannot predict whether these efforts will result in any changes and, if changes to the rules results, what impact these rules would have on APS.

Rate Plan Comparison Tool

On November 14, 2019, APS learned that its rate plan comparison tool was not functioning as intended due to an integration error between the tool and the Company’s meter data management system. APS immediately removed the tool from its website and notified the ACC. The purpose of the tool was to provide customers with a rate plan recommendation that would result in the lowest bills 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. APS is providing 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 and a $25 payment for any inconvenience that the customer may have experienced. The refunds and payment for inconvenience being provided is not expected to have a material impact on APS's financial statements. The ACC is currently investigating this matter. APS received a civil investigative demand from the Office of the Arizona Attorney General, Civil Litigation Division, Consumer Protection & Advocacy Section that seeks information pertaining to the rate plan comparison tool offered to APS customers. APS is fully cooperating with the Attorney General’s Office in this matter. APS cannot predict the outcome of these matters.

Four Corners
 
SCE-Related Matters. As part of APS’s acquisition of SCE’s interest in Units 4 and 5, APS and SCE agreed, via a "Transmission Termination Agreement" that, upon closing of the acquisition, the companies would terminate an existing transmission agreement ("Transmission Agreement") between the parties that provide transmission capacity on a system (the "Arizona Transmission System") for SCE to transmit its portion of the output from Four Corners to California.  APS previously submitted a request to FERC related to this termination, which resulted in a FERC order denying rate recovery of $40 million that APS agreed to pay SCE associated with the termination. On December 22, 2015, APS and SCE agreed to terminate the Transmission Termination Agreement and allow for the Transmission Agreement to expire according to its terms, which includes settling obligations in accordance with the terms of the Transmission Agreement. APS established a regulatory asset of $12 million in 2015 in connection with the payment required under the terms of the Transmission Agreement. On July 1, 2016, FERC issued an order denying APS’s request to recover the regulatory asset through its FERC-jurisdictional rates.  APS and SCE completed the termination of the Transmission Agreement on July 6, 2016. APS made the required payment to SCE and wrote off the $12 million regulatory asset and charged operating revenues to reflect the effects of this order in the second quarter
of 2016.  On July 29, 2016, APS filed a request for rehearing with FERC. In its order denying recovery, FERC also referred to its enforcement division a question of whether the agreement between APS and SCE relating to the settlement of obligations under the Transmission Agreement was a jurisdictional contract that should have been filed with FERC. On October 5, 2017, FERC issued an order denying APS's request for rehearing. FERC also upheld its prior determination that the agreement relating to the settlement was a jurisdictional contract and should have been filed with FERC. APS filed an appeal of FERC's July 1, 2016 and October 5, 2017 orders with the United States Court of Appeals for the Ninth Circuit on December 4, 2017. On June 14, 2019, the United States Court of Appeals for the Ninth Circuit issued an unpublished memorandum order denying APS’s petition for review of FERC’s orders that denied APS’s request to recover the regulatory asset through its FERC-jurisdictional rates and granting APS’s petition for review of FERC’s orders finding the agreement to be a jurisdictional contract. The United States Court of Appeals for the Ninth Circuit vacated FERC’s determination that the agreement was required to be filed with FERC and remanded the issue to FERC for additional proceedings. On December 18, 2019, APS submitted an offer of settlement to FERC to resolve all outstanding issues related to this matter. The offer of settlement provided that APS would not recover in rates any portion of any payment it made to SCE in connection with the expiration of the Transmission Agreement and FERC would close certain dockets related to this matter. On February 5, 2020, FERC issued an order accepting APS’s offer of settlement and resolved this matter.

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. APS cannot predict the outcome or timing of the decision on this matter. APS may be required to record a charge to its results of operations if the ACC issues an unfavorable decision (see SCR deferral in the Regulatory Assets and Liabilities table below).

Cholla

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

Previously, APS estimated Cholla Unit 2’s end of life to be 2033. APS has been recovering a return on and of the net book value of the unit in base rates. Pursuant to the 2017 Settlement Agreement described above, APS will be allowed continued recovery of the net book value of the unit and the unit’s
decommissioning and other retirement-related costs ($73 million as of December 31, 2019), in addition to a return on its investment. In accordance with GAAP, in the third quarter of 2014, Unit 2’s remaining net book value was reclassified from property, plant and equipment to a regulatory asset. The 2017 Settlement Agreement also shortened the depreciation lives of Cholla Units 1 and 3 to 2025.
On March 20, 2019, APS announced that it began evaluating the feasibility and cost of converting a unit at Cholla to burn biomass. Biomass is a fuel comprised of forest trimmings, and a converted unit at Cholla could assist in forest thinning, responsible forest management, an improved watershed, and a reduced wildfire risk. APS’s ability to operate a biomass power plant would depend on third-parties procuring forest biomass for fuel. APS reported the results of its evaluation on May 9, 2019 to the ACC. On July 10, 2019, the ACC voted to not require APS to file a request for proposal to convert the unit at Cholla to burn biomass.
Navajo Plant
The co-owners of the Navajo Plant and the Navajo Nation agreed that the Navajo Plant would remain in operation until December 2019 under the existing plant lease. The co-owners and the Navajo Nation executed a lease extension on November 29, 2017 that allows for decommissioning activities to begin after the plant ceased operations in November 2019.
  
APS is currently recovering depreciation and a return on the net book value of its interest in the Navajo Plant over its previously estimated life through 2026. APS will seek continued recovery in rates for the book value of its remaining investment in the plant ($82 million as of December 31, 2019) plus a return on the net book value as well as other costs related to retirement and closure, which are still being assessed and may be material. APS believes it will be allowed recovery of the net book value, in addition to a return on its investment. In accordance with GAAP, in the second quarter of 2017, APS's remaining net book value of its interest in the Navajo Plant was reclassified from property, plant and equipment to a regulatory asset. If the ACC does not allow full recovery of the remaining net book value of this interest, all or a portion of the regulatory asset will be written off and APS's net income, cash flows, and financial position will be negatively impacted.
Regulatory Assets and Liabilities
 
The detail of regulatory assets is as follows (dollars in thousands):
S
 
 
December 31, 2019
 
December 31, 2018
 
Amortization Through
 
Current
 
Non-Current
 
Current
 
Non-Current
Pension
(a)
 
$

 
$
660,223

 
$

 
$
733,351

Retired power plant costs
2033
 
28,182

 
142,503

 
28,182

 
167,164

Income taxes - AFUDC equity
2049
 
6,800

 
154,974

 
6,457

 
151,467

Deferred fuel and purchased power (b) (c)
2020
 
70,137

 

 
37,164

 

Deferred fuel and purchased power — mark-to-market (Note 17)
2024
 
36,887

 
33,185

 
31,728

 
23,768

Deferred property taxes
2027
 
8,569

 
58,196

 
8,569

 
66,356

SCR deferral
N/A
 

 
52,644

 

 
23,276

Four Corners cost deferral
2024
 
8,077

 
32,152

 
8,077

 
40,228

Ocotillo deferral
N/A
 

 
38,144

 

 

Deferred compensation
2036
 

 
36,464

 

 
36,523

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

 
24,981

 
1,079

 
25,522

Lost fixed cost recovery (b)
2020
 
26,067

 

 
32,435

 

Palo Verde VIEs (Note 19)
2046
 

 
20,635

 

 
20,015

Coal reclamation
2026
 
1,546

 
17,688

 
1,546

 
15,607

Loss on reacquired debt
2038
 
1,637

 
12,031

 
1,637

 
13,668

Mead-Phoenix transmission line - contributions in aid of construction
2050
 
332

 
9,712

 
332

 
10,044

TCA balancing account (b)
2021
 
6,324

 
2,885

 
3,860

 
772

Tax expense of Medicare subsidy
2024
 
1,235

 
4,940

 
1,235

 
6,176

AG-1 deferral
2022
 
2,787

 
2,716

 
2,654

 
5,819

Tax expense adjustor mechanism (b)
2020
 
1,612

 

 

 

Other
Various
 
1,917

 

 
1,947

 
3,185

Total regulatory assets (d)
 
 
$
203,207

 
$
1,304,073

 
$
166,902

 
$
1,342,941

(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 OCI and result in lower future revenues.  See Note 8 for further discussion.
(b)
See “Cost Recovery Mechanisms” discussion above.
(c)
Subject to a carrying charge.
(d)
There are no regulatory assets for which the ACC has allowed recovery of costs, but not allowed a return by exclusion from rate base.  FERC rates are set using a formula rate as described in “Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters.”
The detail of regulatory liabilities is as follows (dollars in thousands):
 
 
 
December 31, 2019
 
December 31, 2018
 
Amortization Through
 
Current
 
Non-Current
 
Current
 
Non-Current
Excess deferred income taxes - ACC - Tax Cuts and Jobs Act (a)
2046
 
$
59,918

 
$
1,054,053

 
$

 
$
1,272,709

Excess deferred income taxes - FERC - Tax Cuts and Jobs Act (a)
2058
 
6,302

 
237,357

 
6,302

 
243,691

Asset retirement obligations
2057
 

 
418,423

 

 
278,585

Removal costs
(c)
 
47,356

 
136,072

 
39,866

 
177,533

Other postretirement benefits
(d)
 
37,575

 
139,634

 
37,864

 
125,903

Income taxes - change in rates
2049
 
2,797

 
68,265

 
2,769

 
70,069

Spent nuclear fuel
2027
 
6,676

 
51,019

 
6,503