PINNACLE WEST CAPITAL CORP, 10-K filed on 2/22/2019
Annual Report
v3.10.0.1
Document and Entity Information - USD ($)
12 Months Ended
Dec. 31, 2018
Feb. 15, 2019
Jun. 30, 2018
Entity Information [Line Items]      
Entity Registrant Name PINNACLE WEST CAPITAL CORPORATION    
Entity Central Index Key 0000764622    
Document Type 10-K    
Document Period End Date Dec. 31, 2018    
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     $ 9,020,511,769.84
Entity Emerging Growth Company false    
Entity Small Business false    
Entity Shell Company false    
Entity Common Stock, Shares Outstanding   112,146,511  
Document Fiscal Year Focus 2018    
Document Fiscal Period Focus FY    
ARIZONA PUBLIC SERVICE COMPANY      
Entity Information [Line Items]      
Entity Registrant Name ARIZONA PUBLIC SERVICE COMPANY    
Entity Central Index Key 0000007286    
Document Type 10-K    
Document Period End Date Dec. 31, 2018    
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 2018    
Document Fiscal Period Focus FY    
v3.10.0.1
CONSOLIDATED STATEMENTS OF INCOME - USD ($)
shares in Thousands, $ in Thousands
12 Months Ended
Dec. 31, 2018
Dec. 31, 2017
Dec. 31, 2016
OPERATING REVENUES $ 3,691,247 $ 3,565,296 $ 3,498,682
OPERATING EXPENSES      
Fuel and purchased power 1,076,116 981,301 1,075,510
Operations and maintenance 1,036,744 949,107 931,692
Depreciation and amortization 582,354 534,118 485,829
Taxes other than income taxes 212,849 184,347 166,499
Other expenses 9,497 6,660 3,541
Total 2,917,560 2,655,533 2,663,071
OPERATING INCOME 773,687 909,763 835,611
OTHER INCOME (DEDUCTIONS)      
Allowance for equity funds used during construction (Note 1) 52,319 47,011 42,140
Pension and other postretirement non-service credits - net (Note 7) 49,791 24,664 20,373
Other income (Note 17) 24,896 4,006 901
Other expense (Note 17) (17,966) (21,539) (15,337)
Total 109,040 54,142 48,077
INTEREST EXPENSE      
Interest charges 243,465 219,796 205,720
Allowance for borrowed funds used during construction (Note 1) (25,180) (22,112) (19,970)
Total 218,285 197,684 185,750
INCOME BEFORE INCOME TAXES 664,442 766,221 697,938
INCOME TAXES (Note 4) 133,902 258,272 236,411
NET INCOME 530,540 507,949 461,527
Less: Net income attributable to noncontrolling interests (Note 18) 19,493 19,493 19,493
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS $ 511,047 $ 488,456 $ 442,034
Weighted Average common shares outstanding — basic (in shares) 112,129 111,839 111,409
Weighted Average common shares outstanding — diluted (in shares) 112,550 112,367 112,046
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING      
Net income attributable to common shareholders - basic (in dollars per share) $ 4.56 $ 4.37 $ 3.97
Net income attributable to common shareholders — diluted (in dollars per share) $ 4.54 $ 4.35 $ 3.95
ARIZONA PUBLIC SERVICE COMPANY      
OPERATING REVENUES $ 3,688,342 $ 3,557,652 $ 3,498,090
OPERATING EXPENSES      
Fuel and purchased power 1,094,020 992,744 1,082,625
Operations and maintenance 969,227 917,983 902,467
Depreciation and amortization 580,694 532,423 484,909
Taxes other than income taxes 212,136 183,254 166,064
Other expenses 2,497 6,709 3,540
Total 2,858,574 2,633,113 2,639,605
OPERATING INCOME 829,768 924,539 858,485
OTHER INCOME (DEDUCTIONS)      
Allowance for equity funds used during construction (Note 1) 52,319 47,011 42,140
Pension and other postretirement non-service credits - net (Note 7) 51,242 24,371 20,224
Other income (Note 17) 22,746 3,013 271
Other expense (Note 17) (15,292) (13,913) (10,554)
Total 111,015 60,482 52,081
INTEREST EXPENSE      
Interest charges 231,391 214,163 202,571
Allowance for borrowed funds used during construction (Note 1) (25,180) (22,112) (19,481)
Total 206,211 192,051 183,090
INCOME BEFORE INCOME TAXES 734,572 792,970 727,476
INCOME TAXES (Note 4) 144,814 269,168 245,842
NET INCOME 589,758 523,802 481,634
Less: Net income attributable to noncontrolling interests (Note 18) 19,493 19,493 19,493
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS $ 570,265 $ 504,309 $ 462,141
v3.10.0.1
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($)
$ in Thousands
12 Months Ended
Dec. 31, 2018
Dec. 31, 2017
Dec. 31, 2016
NET INCOME $ 530,540 $ 507,949 $ 461,527
Derivative instruments:      
Net unrealized loss, net of tax benefit (expense) (78) (35) (538)
Reclassification of net realized loss, net of tax benefit 1,527 2,225 2,941
Pension and other postretirement benefits activity, net of tax (expense) benefit 4,397 (3,370) (1,477)
Total other comprehensive income (loss) 5,846 (1,180) 926
COMPREHENSIVE INCOME 536,386 506,769 462,453
Less: Comprehensive income attributable to noncontrolling interests 19,493 19,493 19,493
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS 516,893 487,276 442,960
ARIZONA PUBLIC SERVICE COMPANY      
NET INCOME 589,758 523,802 481,634
Derivative instruments:      
Net unrealized loss, net of tax benefit (expense) (78) (35) (538)
Reclassification of net realized loss, net of tax benefit 1,527 2,225 2,941
Pension and other postretirement benefits activity, net of tax (expense) benefit 3,465 (3,750) (729)
Total other comprehensive income (loss) 4,914 (1,560) 1,674
COMPREHENSIVE INCOME 594,672 522,242 483,308
Less: Comprehensive income attributable to noncontrolling interests 19,493 19,493 19,493
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS $ 575,179 $ 502,749 $ 463,815
v3.10.0.1
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($)
$ in Thousands
12 Months Ended
Dec. 31, 2018
Dec. 31, 2017
Dec. 31, 2016
Net unrealized loss, tax benefit (expense) $ (78) $ 24 $ (585)
Reclassification of net realized loss, tax benefit 473 1,294 985
Pension and other postretirement benefits activity, tax benefit (expense) (1,585) 693 633
ARIZONA PUBLIC SERVICE COMPANY      
Net unrealized loss, tax benefit (expense) (78) 24 (585)
Reclassification of net realized loss, tax benefit 473 1,294 985
Pension and other postretirement benefits activity, tax benefit (expense) $ (1,159) $ 977 $ 293
v3.10.0.1
CONSOLIDATED BALANCE SHEETS - USD ($)
$ in Thousands
Dec. 31, 2018
Dec. 31, 2017
CURRENT ASSETS    
Cash and cash equivalents $ 5,766 $ 13,892
Customer and other receivables 267,887 305,147
Accrued unbilled revenues 137,170 112,434
Allowance for doubtful accounts (4,069) (2,513)
Materials and supplies (at average cost) 269,065 264,012
Fossil fuel (at average cost) 25,029 25,258
Assets from risk management activities (Note 16) 1,113 1,931
Deferred fuel and purchased power regulatory asset (Note 3) 37,164 75,637
Other regulatory assets (Note 3) 129,738 172,451
Other current assets 56,128 48,039
Total current assets 924,991 1,016,288
INVESTMENTS AND OTHER ASSETS    
Nuclear decommissioning trust (Notes 13 and 19) 851,134 871,000
Other special use funds (Notes 13 and 19) 236,101 32,542
Other assets 103,247 52,040
Total investments and other assets 1,190,482 955,582
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6 and 9)    
Plant in service and held for future use 18,736,628 17,798,061
Accumulated depreciation and amortization (6,366,014) (6,128,535)
Net 12,370,614 11,669,526
Construction work in progress 1,170,062 1,291,498
Palo Verde sale leaseback, net of accumulated depreciation of $245,275 and $241,405 (Note 18) 105,775 109,645
Intangible assets, net of accumulated amortization 262,902 257,189
Nuclear fuel, net of accumulated amortization of $137,850 and $144,070 120,217 117,408
Total property, plant and equipment 14,029,570 13,445,266
DEFERRED DEBITS    
Regulatory assets (Notes 1, 3 and 4) 1,342,941 1,202,302
Assets for other postretirement benefits (Note 7) 46,906 268,978
Other 129,312 130,666
Total deferred debits 1,519,159 1,601,946
Total Assets 17,664,202 17,019,082
CURRENT LIABILITIES    
Accounts payable 277,336 256,442
Accrued taxes 154,819 148,946
Accrued interest 61,107 56,397
Common dividends payable 82,675 77,667
Short-term borrowings (Note 5) 76,400 95,400
Customer deposits 91,174 70,388
Current maturities of long-term debt (Note 6) 500,000 82,000
Liabilities from risk management activities (Note 16) 35,506 59,252
Liabilities for asset retirements (Note 11) 19,842 4,745
Regulatory liabilities (Note 3) 165,876 100,086
Other current liabilities 184,229 246,529
Total current liabilities 1,648,964 1,197,852
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 6) 4,638,232 4,789,713
DEFERRED CREDITS AND OTHER    
Deferred income taxes (Note 4) 1,807,421 1,690,805
Regulatory liabilities (Notes 1, 3, 4 and 7) 2,325,976 2,452,536
Liabilities for asset retirements (Note 11) 706,703 674,784
Liabilities for pension benefits (Note 7) 443,170 327,300
Liabilities from risk management activities (Note 16) 24,531 37,170
Customer advances 137,153 113,996
Coal mine reclamation 212,785 231,597
Deferred investment tax credit 200,405 205,575
Unrecognized tax benefits (Note 4) 22,517 13,115
Other 147,640 148,909
Total deferred credits and other 6,028,301 5,895,787
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
EQUITY    
Common stock, no par value; authorized 150,000,000 shares, 112,159,896 and 111,816,170 issued at respective dates 2,634,265 2,614,805
Treasury stock at cost; 58,135 shares at end of 2018 and 64,463 shares at end of 2017 (4,825) (5,624)
Total common stock 2,629,440 2,609,181
Retained earnings 2,641,183 2,442,511
Accumulated other comprehensive loss (47,708) (45,002)
Total shareholders’ equity 5,222,915 5,006,690
Noncontrolling interests (Note 18) 125,790 129,040
Total equity 5,348,705 5,135,730
Total Liabilities and Equity 17,664,202 17,019,082
ARIZONA PUBLIC SERVICE COMPANY    
CURRENT ASSETS    
Cash and cash equivalents 5,707 13,851
Customer and other receivables 257,654 292,791
Accrued unbilled revenues 137,170 112,434
Allowance for doubtful accounts (4,069) (2,513)
Materials and supplies (at average cost) 269,065 262,630
Fossil fuel (at average cost) 25,029 25,258
Assets from risk management activities (Note 16) 1,113 1,931
Deferred fuel and purchased power regulatory asset (Note 3) 37,164 75,637
Other regulatory assets (Note 3) 129,738 172,451
Other current assets 35,111 41,055
Total current assets 893,682 995,525
INVESTMENTS AND OTHER ASSETS    
Nuclear decommissioning trust (Notes 13 and 19) 851,134 871,000
Other special use funds (Notes 13 and 19) 236,101 30,358
Other assets 40,817 36,796
Total investments and other assets 1,128,052 938,154
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6 and 9)    
Plant in service and held for future use 18,733,142 17,654,078
Accumulated depreciation and amortization (6,362,771) (6,041,965)
Net 12,370,371 11,612,113
Construction work in progress 1,170,062 1,266,636
Palo Verde sale leaseback, net of accumulated depreciation of $245,275 and $241,405 (Note 18) 105,775 109,645
Intangible assets, net of accumulated amortization 262,746 257,028
Nuclear fuel, net of accumulated amortization of $137,850 and $144,070 120,217 117,408
Total property, plant and equipment 14,029,171 13,362,830
DEFERRED DEBITS    
Regulatory assets (Notes 1, 3 and 4) 1,342,941 1,202,302
Assets for other postretirement benefits (Note 7) 43,212 265,139
Other 128,265 129,801
Total deferred debits 1,514,418 1,597,242
Total Assets 17,565,323 16,893,751
CURRENT LIABILITIES    
Accounts payable 266,277 247,852
Accrued taxes 176,357 157,349
Accrued interest 60,228 55,533
Common dividends payable 82,700 77,700
Customer deposits 91,174 70,388
Current maturities of long-term debt (Note 6) 500,000 82,000
Liabilities from risk management activities (Note 16) 35,506 59,252
Liabilities for asset retirements (Note 11) 19,842 4,192
Regulatory liabilities (Note 3) 165,876 100,086
Other current liabilities 178,137 243,922
Total current liabilities 1,576,097 1,098,274
DEFERRED CREDITS AND OTHER    
Deferred income taxes (Note 4) 1,812,664 1,742,485
Regulatory liabilities (Notes 1, 3, 4 and 7) 2,325,976 2,452,536
Liabilities for asset retirements (Note 11) 706,703 666,527
Liabilities for pension benefits (Note 7) 425,404 306,542
Liabilities from risk management activities (Note 16) 24,531 37,170
Customer advances 137,153 113,996
Coal mine reclamation 212,785 215,830
Deferred investment tax credit 200,405 205,575
Unrecognized tax benefits (Note 4) 41,861 43,876
Other 125,511 133,779
Total deferred credits and other 6,012,993 5,918,316
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
EQUITY    
Total common stock 178,162 178,162
Additional paid-in capital 2,721,696 2,571,696
Retained earnings 2,788,256 2,533,954
Accumulated other comprehensive loss (27,107) (26,983)
Total shareholders’ equity 5,661,007 5,256,829
Noncontrolling interests (Note 18) 125,790 129,040
Total equity 5,786,797 5,385,869
Long-term debt less current maturities (Note 6) 4,189,436 4,491,292
Total capitalization 9,976,233 9,877,161
Total Liabilities and Equity $ 17,565,323 $ 16,893,751
v3.10.0.1
CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($)
$ in Thousands
Dec. 31, 2018
Dec. 31, 2017
PROPERTY, PLANT AND EQUIPMENT    
Accumulated depreciation of Palo Verde sale leaseback $ 245,275 $ 241,405
Accumulated amortization on intangible assets 591,202 582,272
Accumulated amortization on nuclear fuel $ 137,850 $ 144,070
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) 112,159,896 111,816,170
Treasury stock at cost, shares (in shares) 58,135 64,463
ARIZONA PUBLIC SERVICE COMPANY    
PROPERTY, PLANT AND EQUIPMENT    
Accumulated depreciation of Palo Verde sale leaseback $ 245,275 $ 241,405
Accumulated amortization on intangible assets 590,069 581,135
Accumulated amortization on nuclear fuel $ 137,850 $ 144,070
v3.10.0.1
CONSOLIDATED STATEMENTS OF CASH FLOWS
$ in Thousands
12 Months Ended
Dec. 31, 2018
USD ($)
Dec. 31, 2017
USD ($)
Dec. 31, 2016
USD ($)
CASH FLOWS FROM OPERATING ACTIVITIES      
Net income $ 530,540 $ 507,949 $ 461,527
Adjustments to reconcile net income to net cash provided by operating activities:      
Depreciation and amortization including nuclear fuel 650,955 610,629 565,011
Deferred fuel and purchased power (78,277) (48,405) (60,303)
Deferred fuel and purchased power amortization 116,750 (14,767) 38,152
Allowance for equity funds used during construction (52,319) (47,011) (42,140)
Deferred income taxes 117,355 248,164 206,870
Deferred investment tax credit (5,170) (4,587) 23,082
Change in derivative instruments fair value 0 (373) (403)
Stock compensation 19,547 20,502 18,883
Changes in current assets and liabilities:      
Customer and other receivables 37,530 (93,797) (2,489)
Accrued unbilled revenues (24,736) (4,485) (11,709)
Materials, supplies and fossil fuel (6,103) (6,683) (1,491)
Income tax receivable 0 3,751 (3,162)
Other current assets 33,844 (10,580) (23,324)
Accounts payable (14,602) (23,769) (66,917)
Accrued taxes 6,597 9,982 447
Other current liabilities 28,174 19,154 29,594
Change in margin and collateral accounts — assets 143 (300) 673
Change in margin and collateral accounts — liabilities (2,211) (533) 17,735
Change in unrecognized tax benefits (1,235) 5,891 1,628
Change in long-term regulatory liabilities (109,284) 45,764 14,682
Change in other long-term assets 78,604 (68,480) (60,163)
Change in other long-term liabilities (48,958) (29,980) (82,793)
Net cash flow provided by operating activities 1,277,144 1,118,036 1,023,390
CASH FLOWS FROM INVESTING ACTIVITIES      
Capital expenditures (1,178,169) (1,408,774) (1,275,472)
Contributions in aid of construction 27,716 23,708 64,296
Allowance for borrowed funds used during construction (25,180) (22,112) (19,970)
Proceeds from nuclear decommissioning trust sales and other special use funds 653,033 542,246 633,410
Investment in nuclear decommissioning trust and other special use funds (672,165) (544,527) (635,691)
Other 1,941 (19,078) (18,651)
Net cash flow used for investing activities (1,192,824) (1,428,537) (1,252,078)
CASH FLOWS FROM FINANCING ACTIVITIES      
Issuance of long-term debt 445,245 848,239 693,151
Repayment of long-term debt (182,000) (125,000) (370,430)
Short-term borrowings and (repayments) — net (7,000) (107,800) 137,200
Short-term debt borrowings under revolving credit facility 45,000 58,000 40,000
Short-term debt repayments under revolving credit facility (57,000) (32,000) 0
Dividends paid on common stock (308,892) (289,793) (274,229)
Common stock equity issuance and purchases - net (5,055) (13,390) (4,867)
Distributions to noncontrolling interests (22,744) (22,744) (22,744)
Net cash flow (used for) provided by financing activities (92,446) 315,512 198,081
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (8,126) 5,011 (30,607)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 13,892 8,881 39,488
CASH AND CASH EQUIVALENTS AT END OF YEAR 5,766 13,892 8,881
Supplemental disclosure of cash flow information:      
Income taxes, net of refunds 21,173 2,186 9,956
Interest, net of amounts capitalized 208,479 189,288 184,462
Significant non-cash investing and financing activities:      
Accrued capital expenditures 132,620 130,404 114,855
Dividends declared but not paid 82,675 77,667 72,926
ARIZONA PUBLIC SERVICE COMPANY      
CASH FLOWS FROM OPERATING ACTIVITIES      
Net income 589,758 523,802 481,634
Adjustments to reconcile net income to net cash provided by operating activities:      
Depreciation and amortization including nuclear fuel 649,295 608,935 564,091
Deferred fuel and purchased power (78,277) (48,405) (60,303)
Deferred fuel and purchased power amortization 116,750 (14,767) 38,152
Allowance for equity funds used during construction (52,319) (47,011) (42,140)
Deferred income taxes 59,927 249,465 221,167
Deferred investment tax credit (5,170) (4,587) 23,082
Change in derivative instruments fair value 0 (373) (403)
Changes in current assets and liabilities:      
Customer and other receivables 35,406 (68,040) (1,601)
Accrued unbilled revenues (24,736) (4,485) (11,709)
Materials, supplies and fossil fuel (6,206) (6,503) (1,454)
Income tax receivable 0 11,174 (14,567)
Other current assets 31,707 (6,775) (21,640)
Accounts payable (15,608) (26,561) (67,543)
Accrued taxes 19,008 26,773 (13,912)
Other current liabilities 25,070 27,912 5,097
Change in margin and collateral accounts — assets 143 (300) 673
Change in margin and collateral accounts — liabilities (2,211) (533) 17,735
Change in unrecognized tax benefits (1,235) 5,891 1,628
Change in long-term regulatory liabilities (109,284) 45,764 14,682
Change in other long-term assets 77,952 (78,540) (45,866)
Change in other long-term liabilities (55,169) (31,106) (76,855)
Net cash flow provided by operating activities 1,254,801 1,161,730 1,009,948
CASH FLOWS FROM INVESTING ACTIVITIES      
Capital expenditures (1,169,061) (1,381,930) (1,248,010)
Contributions in aid of construction 27,716 23,708 64,296
Allowance for borrowed funds used during construction (25,180) (22,112) (19,481)
Proceeds from nuclear decommissioning trust sales and other special use funds 653,033 542,246 633,410
Investment in nuclear decommissioning trust and other special use funds (672,165) (544,527) (635,691)
Other (1,789) (18,538) (13,865)
Net cash flow used for investing activities (1,187,446) (1,401,153) (1,219,341)
CASH FLOWS FROM FINANCING ACTIVITIES      
Issuance of long-term debt 295,245 549,478 693,151
Repayment of long-term debt (182,000) 0 (370,430)
Short-term borrowings and (repayments) — net 0 (135,500) 135,500
Short-term debt borrowings under revolving credit facility 25,000 0 0
Short-term debt repayments under revolving credit facility (25,000) 0 0
Dividends paid on common stock (316,000) (296,800) (281,300)
Equity infusion from Pinnacle West 150,000 150,000 42,000
Distributions to noncontrolling interests (22,744) (22,744) (22,744)
Net cash flow (used for) provided by financing activities (75,499) 244,434 196,177
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (8,144) 5,011 (13,216)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 13,851 8,840 22,056
CASH AND CASH EQUIVALENTS AT END OF YEAR 5,707 13,851 8,840
Supplemental disclosure of cash flow information:      
Income taxes, net of refunds 77,942 (14,098) 26,864
Interest, net of amounts capitalized 196,419 184,210 181,809
Significant non-cash investing and financing activities:      
Accrued capital expenditures 132,620 130,057 114,874
Dividends declared but not paid $ 82,700 $ 77,700 $ 72,900
v3.10.0.1
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
Increase (Decrease) in Shareholders' Equity                        
Stock compensation cumulative effect adjustments [1] $ 45,855 $ 40,380   $ 5,475                
Beginning balance at Dec. 31, 2015 4,719,457 $ 2,541,668 $ (5,806) 2,092,803 $ (44,748) $ 135,540 $ 4,814,794 $ 178,162 $ 2,379,696 $ 2,148,493 $ (27,097) $ 135,540
Beginning Balance (in shares) at Dec. 31, 2015   111,095,402 115,030         71,264,947        
Increase (Decrease) in Shareholders' Equity                        
Net income 461,527     442,034   19,493 481,634     462,141   19,493
Other comprehensive income (loss) 926       926   1,674       1,674  
Dividends on common stock (284,765)     (284,765)     (284,800)     (284,800)    
Issuance of common stock 13,982 $ 13,982                    
Issuance of common stock (in shares)   296,651                    
Purchase of treasury stock [2] (9,087)   $ (9,087)                  
Purchase of treasury stock (in shares) [2]     (128,105)                  
Reissuance of treasury stock for stock-based compensation and other 10,760   $ 10,760                  
Reissuance of treasury stock for stock-based compensation and other (in shares)     187,818                  
Equity infusion from Pinnacle West             42,000   42,000      
Net capital activities by noncontrolling interests (22,743)         (22,743) (22,743)         (22,743)
Ending 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
Ending Balance (in shares) at Dec. 31, 2016   111,392,053 55,317         71,264,947        
Increase (Decrease) in Shareholders' Equity                        
Stock compensation cumulative effect adjustments [3]             5,411     5,411    
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 [2] (17,755)   $ (17,755)                  
Purchase of treasury stock (in shares) [2]     (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      
Net 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 111,816,170 111,816,170 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 [2] (10,338)   $ (10,338)                  
Purchase of treasury stock (in shares) [2]     (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      
Net capital activities by noncontrolling interests (22,743)         (22,743) (22,743)         (22,743)
Reclassification of income tax effects related to new tax reform (See Note 2) (8,552)     8,552 (8,552)   (5,038)     5,038 (5,038)  
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        
[1] During 2016, we adopted new stock-based compensation accounting guidance.
[2] Primarily represents shares of common stock withheld from certain stock awards for tax purposes.
[3] During 2016, we adopted new stock-based compensation accounting guidance.
v3.10.0.1
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Parenthetical) - $ / shares
12 Months Ended
Dec. 31, 2018
Dec. 31, 2017
Dec. 31, 2016
Statement of Stockholders' Equity [Abstract]      
Common stock dividends declared (in dollars per share) $ 2.87 $ 2.70 $ 2.56
v3.10.0.1
Summary of Significant Accounting Policies
12 Months Ended
Dec. 31, 2018
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. BCE is currently pursuing transmission opportunities through a joint venture arrangement. 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 10 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 18).
 
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.
    
These consolidated financial statements and notes have been prepared consistently, with the exception of the reclassification of certain prior year amounts on our Consolidated Statements of Income and APS's Consolidated Statements of Income. Beginning in the quarter ended March 31, 2018, APS changed the format of presentation of its Consolidated Statements of Income from a utility ratemaking format to a commercial format. Minor changes were made in the description of certain income statement line items and the amounts presented in the comparable prior period also changed by immaterial amounts due to the change from a utility to a non-utility format and also from the adoption of the new accounting guidance for net periodic pension cost and net periodic postretirement benefit cost. In addition, the prior year amounts were reclassified to conform to the current year presentation for the other special use funds in the investment and other assets section on the Consolidated Balance Sheets.
 
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 continually assesses whether our regulatory assets are probable of future recovery by considering factors such as changes in the applicable regulatory environment and recent rate orders applicable to APS or 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.
 
See Note 3 for additional information.
 
Electric Revenues
 
We derive electric revenues primarily from sales of electricity to our regulated Native Load customers. 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 Native Load 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. 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.
 
On January 1, 2018, we adopted new revenue guidance ASU 2014-09, Revenue from contracts with customers, accordingly our 2018 electric revenues primarily consist of activities that now 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 invoice practical expedient and, as such, we recognize revenue based on the amount to which we have a right to invoice for services performed. See Note 2.

Revenues from our Native Load 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 20 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 estimated write-off factors to various classes of outstanding receivables, including accrued 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, 2018 and 2017 Consolidated Balance Sheets is composed of the following (dollars in thousands):

Property, Plant and Equipment:
2018
 
2017
Generation
$
8,285,514

 
$
7,963,998

Transmission
3,033,579

 
2,836,578

Distribution
6,378,345

 
6,025,856

General plant
1,039,190

 
971,629

Plant in service and held for future use
18,736,628

 
17,798,061

Accumulated depreciation and amortization
(6,366,014
)
 
(6,128,535
)
Net
12,370,614

 
11,669,526

Construction work in progress
1,170,062

 
1,291,498

Palo Verde sale leaseback, net of accumulated depreciation
105,775

 
109,645

Intangible assets, net of accumulated amortization
262,902

 
257,189

Nuclear fuel, net of accumulated amortization
120,217

 
117,408

Total property, plant and equipment
$
14,029,570

 
$
13,445,266



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 11.
 
APS records a regulatory liability for the excess of the amount 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, 2018 were as follows:
 
Fossil plant — 17 years;
Nuclear plant — 23 years;
Other generation — 19 years;
Transmission — 39 years;
Distribution — 34 years; and
General plant — 6 years.
 
Depreciation of utility property, plant and equipment is computed on a straight-line, remaining-life basis. Depreciation expense was $486 million in 2018, $453 million in 2017, and $422 million in 2016. For the years 2016 through 2018, the depreciation rates ranged from a low of 0.18% to a high of 19.67%.  The weighted-average depreciation rate was 2.81% in 2018, 2.80% in 2017, and 2.66% in 2016.

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 11 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 7.03% for 2018, 6.68% for 2017, and 7.17% for 2016.  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 6).
 
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 13 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 Notes 2 and 16 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 7 for additional information on pension and other postretirement benefits. On January 1, 2018, we adopted new accounting guidance ASU 2017-07, Compensation-Retirement Benefits: Improving the presentation of net periodic pension cost and net periodic postretirement benefit cost. See Note 2 for additional discussion.
 
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 will now accrue a receivable for incurred
claims and an offsetting regulatory liability through the settlement period ending December of 2019. See Note 10 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. On January 1, 2018, we adopted new guidance ASU 2018-02, Income Statement-Reporting Comprehensive Income: Reclassification of certain tax effects from accumulated other comprehensive income. See Note 4 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,
 
2018
 
2017
 
2016
Cash paid during the period for:
 

 
 

 
 

Income taxes, net of refunds
$
21,173

 
$
2,186

 
$
9,956

Interest, net of amounts capitalized
208,479

 
189,288

 
184,462

Significant non-cash investing and financing activities:
 

 
 

 
 

Accrued capital expenditures
$
132,620

 
$
130,404

 
$
114,855

Dividends declared but not paid
82,675

 
77,667

 
72,926

Sale of 4CA 7% interest in Four Corners
68,907

 

 


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 $68 million in 2018, $72 million in 2017, and $58 million in 2016.  Estimated amortization expense on existing intangible assets over the next five years is $58 million in 2019, $47 million in 2020, $34 million in 2021, $25 million in 2022, and $22 million in 2023.  At December 31, 2018, 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).
 
Our investments in the nuclear decommissioning trust fund, coal reclamation escrow and active union employee medical account, are accounted for in accordance with guidance on accounting for investments in debt and equity securities. See Notes 13 and 19 for more information on these investments.

On January 1, 2018, we adopted new accounting guidance ASU 2016-01, Financial Instruments: Recognition and measurement. See Note 2.

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, 2018, 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.
v3.10.0.1
New Accounting Standards
12 Months Ended
Dec. 31, 2018
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]  
New Accounting Standards New Accounting Standards
 
Standards Adopted in 2018

 ASU 2014-09, Revenue from Contracts with Customers

In May 2014, a new revenue recognition accounting standard was issued. This standard provides a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance. Since the issuance of the new revenue standard, additional guidance was issued to clarify certain aspects of the new revenue standard, including principal versus agent considerations, identifying performance obligations, and other narrow scope improvements. The new revenue standard, and related amendments, became effective for us on January 1, 2018. The standard may be adopted using a full retrospective application or a simplified transition method that allows entities to record a cumulative effect adjustment in retained earnings at the date of initial application.

We adopted this standard and related amendments on January 1, 2018 using the modified retrospective transition approach. The adoption of the new revenue guidance resulted in expanded disclosures, but otherwise did not have a material impact on our financial statements. See Note 20.

ASU 2016-01, Financial Instruments: Recognition and Measurement

In January 2016, a new accounting standard was issued relating to the recognition and measurement of financial instruments. The new guidance requires certain investments in equity securities to be measured at fair value with changes in fair value recognized in net income, and modifies the impairment assessment of certain equity securities. The new standard was effective for us on January 1, 2018. The standard required modified retrospective application, with the exception of certain aspects of the standard that required prospective
application. We adopted this standard on January 1, 2018, using primarily a retrospective approach. Due to regulatory accounting treatment, the adoption of this standard did not have a material impact on our financial statements. See Notes 13 and 19 for disclosures relating to our investments in debt and equity securities.

ASU 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments

In August 2016, a new accounting standard was issued that clarifies how entities should present certain specific cash flow activities on the statement of cash flows. The guidance is intended to eliminate diversity in practice in how entities classify these specific activities between cash flows from operating activities, investing activities and financing activities. The specific activities addressed include debt prepayments and extinguishment costs, proceeds from the settlement of insurance claims, proceeds from corporate-owned life insurance policies, and other activities. The standard also addresses how entities should apply the predominance principle when a transaction includes separately identifiable cash flows. The new standard was effective for us, and was adopted on January 1, 2018, using a retrospective transition method. The adoption of this guidance did not have a significant impact on our financial statements, as either our statement of cash flow presentation is consistent with the new prescribed guidance or we do not have significant activities relating to the specific transactions that are addressed by the new standard.

ASU 2016-18, Statement of Cash Flows: Restricted Cash

In November 2016, a new accounting standard was issued that clarifies how restricted cash and restricted cash equivalents should be presented on the statement of cash flows. The new guidance requires entities to include restricted cash and restricted cash equivalents as a component of the beginning and ending cash and cash equivalent balances on the statement of cash flows. The new standard is effective for us, and was adopted on January 1, 2018, using a retrospective transition method. The adoption of this guidance did not impact our financial statements, as our holdings and activities designated as restricted cash and restricted cash equivalents at transition and in prior periods are insignificant.

ASU 2017-01, Business Combinations: Clarifying the Definition of a Business

In January 2017, a new accounting standard was issued that clarifies the definition of a business. This standard is intended to assist entities with evaluating whether a transaction should be accounted for as an acquisition (or disposal) of assets or a business.  The definition of a business affects many areas of accounting, including acquisitions, disposals, goodwill, and consolidation. The new standard was effective for us and was adopted on January 1, 2018 using a prospective transition approach. This standard did not have an impact on our financial statements on the date of adoption.

ASU 2017-05, Other Income: Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets

In February 2017, a new accounting standard was issued that intended to clarify the scope of accounting guidance pertaining to gains and losses from the derecognition of nonfinancial assets, and to add guidance for partial sales of nonfinancial assets. The new standard was effective for us, and was adopted on January 1, 2018, using a modified retrospective transition approach. This standard did not have a significant impact on our financial statements on the date of adoption. On July 3, 2018, 4CA sold its 7% interest in Four Corners. The sale transaction was accounted for in accordance with the guidance in ASU 2017-05, see Note 10.

ASU 2017-07, Compensation-Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost

In March 2017, a new accounting standard was issued that modifies how plan sponsors present net periodic pension cost and net periodic postretirement benefit cost (net benefit costs). The presentation changes require net benefit costs to be disaggregated on the income statement by the various components that comprise these costs. Specifically, only the service cost component is eligible for presentation as an operating income item, and all other cost components are now presented as non-operating items. This presentation change was applied retrospectively. Furthermore, the new standard allows only the service cost component to be eligible for capitalization. The change in capitalization requirements was applied prospectively. The new guidance was effective for us on January 1, 2018.

We adopted this new accounting standard on January 1, 2018. As a result of adopting this standard we have presented the non-service cost components of net benefits costs in other income instead of operating income. Prior year non-service cost components have also been reclassified to conform to this new presentation. We elected to apply the practical expedient guidance. As such, prior period costs have been estimated based on amounts previously disclosed in our pension and other postretirement benefit plan notes. The changes impacting capitalization have been adopted prospectively. As such, upon adoption, we are no longer capitalizing a portion of the non-service cost components of net benefit costs.

In 2018 the non-service credit components are a reduction to total benefit costs. Excluding non-service credits from eligible capitalization costs resulted in the capitalization of an additional $15 million of net benefit costs, with a corresponding increase to pretax income for the year. See Note 7 for additional information related to our pension plans and other postretirement benefits.

ASU 2018-02, Income Statement-Reporting Comprehensive Income: Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income

In February 2018, new accounting guidance was issued that allows entities an optional election to reclassify the income tax effects of the Tax Act on items within accumulated other comprehensive income to retained earnings. Amounts eligible for reclassification must relate to the effects from the Tax Act remaining in accumulated other comprehensive income. The new guidance also requires expanded disclosures. This guidance is effective for us on January 1, 2019 with early application permitted. The guidance should be applied either in the period of adoption or retrospectively to each period in which the effect of the Tax Act was recognized.

We early adopted this guidance in the quarter ended March 31, 2018, and we have elected to reclassify the income tax effects of the Tax Act related to other comprehensive income to retained earnings. As of December 31, 2018, on a consolidated basis our accumulated other comprehensive income decreased $9 million, and APS's accumulated other comprehensive income decreased $5 million, as a result of adopting this guidance. Amounts were reclassified from accumulated other comprehensive income to retained earnings, and related to tax rate changes. The adoption of this guidance did not impact our income from continuing operations. See Note 4 for additional discussion of the Tax Act.

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. We elected the transition method that allows us to apply the guidance on the date of adoption, January 1, 2019, and will not retrospectively adjust prior periods. We also elected certain transition practical expedients that allow us to not reassess (a) whether any expired or existing contracts are or contain leases, (b) the lease classification for any expired or existing leases and (c) initial direct costs for any existing leases. These practical expedients apply to leases that commenced prior to January 1, 2019. Furthermore, we elected the practical expedient transition provisions relating to the treatment of existing land easements.

On January 1, 2019 the adoption of this new accounting standard resulted in the recognition on our Consolidated Balance Sheets of approximately $194 million of right-of-use lease assets and $119 million of lease liabilities relating to our operating lease arrangements. The right-of-use lease assets include $85 million of prepaid lease costs that have been reclassified from other deferred debits, and $10 million of deferred lease costs that have been reclassified from other current liabilities. In addition to these balance sheet impacts the adoption of the guidance will also result in expanded lease related disclosures in our 2019 financial statements.

ASU 2017-12, Derivatives and Hedging: Targeted Improvements to Accounting for Hedging Activities

In August 2017, a new accounting standard was issued that modifies hedge accounting guidance with the intent of simplifying the application of hedge accounting. The new standard became effective for us on January 1, 2019, with early application permitted. At transition, the guidance requires the changes to be applied to hedging relationships existing on the date of adoption, with the effect of adoption reflected as of the beginning of the fiscal year of adoption using a cumulative effect adjustment approach. The presentation and disclosure changes may be applied prospectively. We adopted this standard on January 1, 2019 and because we are not currently applying hedge accounting, the adoption of the standard did not impact our financial statements.

Standards Pending Adoption

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 will require 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. The new standard is 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 are currently evaluating this new accounting standard and the impacts it may have on our financial statements.

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 is effective for us on January 1, 2020, with early application permitted, and may be applied using either a retrospective or prospective transition approach. We are currently evaluating this new accounting standard and the impacts it may have on our financial statements.
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Regulatory Matters
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Regulated Operations [Abstract]  
Regulatory Matters Regulatory Matters
 
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 of $165.9 million. This amount excluded amounts that were then collected on customer bills through adjustor mechanisms. The application requested that some of the balances in these adjustor accounts (aggregating to approximately $267.6 million as of December 31, 2015) be transferred into base rates through the ratemaking process. This transfer would not have had an incremental effect on average customer bills. The average annual customer bill impact of APS’s request was an increase of 5.74% (the average annual bill impact for a typical APS residential customer was 7.96%).

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 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 selective catalytic reduction ("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 battery storage costs;
a new AZ Sun II program (now known as APS Solar Communities) for utility-owned solar 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, and not more than $15 million per year;
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 October 17, 2017, Warren Woodward (an intervener in APS's general retail rate case) filed a Notice of Appeal in the Arizona Court of Appeals, Division One. The notice raises a single issue related to the application of certain rate schedules to new APS residential customers after May 1, 2018. Mr. Woodward filed a second notice of appeal on November 13, 2017 challenging APS’s $5 per month automated metering infrastructure opt-out program. Mr. Woodward’s two appeals have been consolidated, and APS requested and was granted intervention. Mr. Woodward filed his opening brief on March 28, 2018.  The ACC and APS filed responsive briefs on June 21, 2018. The Arizona Court of Appeals issued a Memorandum Decision on December 11, 2018 affirming the ACC decisions challenged by Mr. Woodward.  Mr. Woodward filed a petition for review with the Arizona Supreme Court on January 9, 2019. Review by the Arizona Supreme Court is discretionary. APS cannot predict the outcome of this consolidated appeal but does not believe it will have a material impact on our financial position, results of operations or cash flows.

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. Post-hearing briefing was concluded on December 14, 2018. APS expects a recommended opinion and order from the judge within the first quarter of 2019. APS cannot predict the outcome of this matter.

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 January 9, 2019, the ACC Commissioners voted to open a docket for this matter.  APS does not believe that the rate review will have a material impact on our financial position, results of operations or cash flows.  However, depending upon the results of the rate review, the ACC may take further actions, including potentially attempting to reopen the 2017 Rate Case Decision.  APS cannot predict the outcome of this matter.

Prior Rate Case Filing with the Arizona Corporation Commission
 
On June 1, 2011, APS filed an application with the ACC for a net retail base rate increase of $95.5 million.  On January 6, 2012, APS and other parties to the general retail rate case entered into an agreement (the "2012 Settlement Agreement") detailing the terms upon which the parties agreed to settle the rate case.  On May 15, 2012, the ACC approved the 2012 Settlement Agreement without material modifications.
 
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 2013, the ACC conducted a hearing to consider APS’s proposal to establish compliance with distributed energy requirements by tracking and recording distributed energy, rather than acquiring and retiring renewable energy credits. On February 6, 2014, the ACC established a proceeding to modify the renewable energy rules to establish a process for compliance with the renewable energy requirement that is not based solely on the use of renewable energy credits. On September 9, 2014, the ACC authorized a rulemaking process to modify the RES rules. The proposed changes would permit the ACC to find that utilities have
complied with the distributed energy requirement in light of all available information. The ACC adopted these changes on December 18, 2014.  The revised rules went into effect on April 21, 2015.    

In December 2014, the ACC voted that it had no objection to APS implementing an APS-owned rooftop solar research and development program aimed at learning how to efficiently enable the integration of rooftop solar and battery storage with the grid.  The first stage of the program, called the "Solar Partner Program," placed 8 MW of residential rooftop solar on strategically selected distribution feeders in an effort to maximize potential system benefits, as well as made systems available to limited-income customers who could not easily install solar through transactions with third parties. The second stage of the program, which included an additional 2 MW of rooftop solar and energy storage, placed two energy storage systems sized at 2 MW on two different high solar penetration feeders to test various grid-related operation improvements and system interoperability, and was in operation by the end of 2016.  The costs for this program have been included in APS's rate base as part of the 2017 Rate Case Decision.

On July 1, 2016, APS filed its 2017 RES Implementation Plan and proposed a budget of approximately $150 million. APS’s budget request included additional funding to process the high volume of residential rooftop solar interconnection requests and also requested a permanent waiver of the residential distributed energy requirement for 2017 contained in the RES rules. On April 7, 2017, APS filed an amended 2017 RES Implementation Plan and updated budget request which included the revenue neutral transfer of specific revenue requirements into base rates in accordance with the 2017 Settlement Agreement.  On August 15, 2017, the ACC approved the 2017 RES Implementation Plan.

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 is 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, buildings of 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.

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. The ACC has not yet ruled on the 2019 RES Implementation Plan.

In September 2016, the ACC initiated a proceeding which will examine the possible modernization and expansion of the RES. On January 30, 2018, ACC Commissioner Tobin proposed a plan in this proceeding which would broaden the RES to include a series of energy policies tied to clean energy sources (the "Energy Modernization Plan"). The Energy Modernization Plan includes replacing the current RES standard with a new standard called the Clean Resource Energy Standard and Tariff ("CREST"), which incorporates the
proposals in the Energy Modernization Plan.  A set of draft CREST rules for the ACC’s consideration was issued by Commissioner Tobin’s office on July 5, 2018. See "Energy Modernization Plan" below for more information on CREST.

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. On March 20, 2015, APS filed an application with the ACC requesting a budget of $68.9 million for 2015 and minor modifications to its DSM portfolio going forward, including for the first time three resource savings projects which reflect energy savings on APS's system. The ACC approved APS’s 2015 DSM budget on November 25, 2015. In its decision, the ACC also ruled that verified energy savings from APS's resource savings projects could be counted toward compliance with the EES; however, the ACC ruled that APS was not allowed to count savings from systems savings projects toward determination of the achievement of performance incentives, nor may APS include savings from conservation voltage reduction in the calculation of its LFCR mechanism.

On June 1, 2016, APS filed its 2017 DSM Plan, in which APS proposed programs and measures that specifically focus on reducing peak demand, shifting load to off-peak periods and educating customers about strategies to manage their energy and demand.  The requested budget in the 2017 DSM Plan was $62.6 million. On January 27, 2017, APS filed an updated and modified 2017 DSM Plan that incorporated the proposed Residential Demand Response, Energy Storage and Load Management Program and requested that the budget be increased to $66.6 million. On August 15, 2017, the ACC approved the amended 2017 DSM Plan.

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 reduced requested budget of $52.6 million and requests a waiver of the EES 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.    
     
Power Supply Adjustor Mechanism and Balance.  The PSA provides for the adjustment of retail rates to reflect variations 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 (liability) for 2018 and 2017 (dollars in thousands):
 
Twelve Months Ended
December 31,
 
2018
 
2017
Beginning balance
$
75,637

 
$
12,465

Deferred fuel and purchased power costs — current period
78,277

 
48,405

Amounts refunded/(charged) to customers
(116,750
)
 
14,767

Ending balance
$
37,164

 
$
75,637


 
The PSA rate for the PSA year beginning February 1, 2017 was $(0.001348) per kWh, as compared to $0.001678 per kWh for the prior year.  This rate was comprised of a forward component of $(0.001027) per kWh and a historical component of $(0.000321) per kWh. On August 19, 2017, the PSA rate was revised to $0.000555 per kWh as part of the 2017 Rate Case Decision. This new rate was comprised of a forward component of $0.000876 per kWh and a historical component of $(0.000321) per kWh.

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 until the following year and were reflected in the 2019 reset of the PSA.

On November 30, 2018, APS filed its PSA rate for the PSA year beginning February 1, 2019. That rate was $0.001658 per kWh and consisted of a forward component of $0.000536 per kWh and a historical component of $0.001122 per kWh. The 2019 PSA rate is a $0.002897 per kWh decrease compared to 2018. These rates went into effect as filed on February 1, 2019.
 
Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters In July 2008, FERC approved an Open Access Transmission Tariff for 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 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.

Effective June 1, 2017, APS's annual wholesale transmission rates for all users of its transmission system increased by approximately $35.1 million for the twelve-month period beginning June 1, 2017 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, 2017. 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.

On January 31, 2017, APS made a filing with FERC to reduce the Post-Employment Benefits Other than Pension expense reflected in its FERC transmission formula rate calculation to recognize certain savings resulting from plan design changes to the other postretirement benefit plans.  A transmission customer intervened and protested certain aspects of APS’s filing.  FERC initiated a proceeding under Section 206 of the Federal Power Act to evaluate the justness and reasonableness of the revised formula rate filing APS proposed.  APS entered into a settlement agreement with the intervening transmission customer, which was filed with FERC for approval on September 26, 2017. FERC approved the settlement agreement without modification or condition on December 21, 2017.

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.
 
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 kWh’s 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.
 
APS filed its 2016 annual LFCR adjustment on January 15, 2016, requesting an LFCR adjustment of $46.4 million (a $7.9 million annual increase). The ACC approved the 2016 annual LFCR effective beginning in May 2016. APS filed its 2017 LFCR adjustment on January 13, 2017 requesting an LFCR adjustment of
$63.7 million (a $17.3 million per year increase over 2016 levels). On April 5, 2017, the ACC approved the 2017 annual LFCR adjustment as filed, effective with the first billing cycle of April 2017. 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 (a $3 million per year decrease from 2017 levels). 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). 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 and FERC Tax Filing.  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. 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 requesting that the TEAM be implemented in two steps.  The first addresses the change in the marginal federal tax rate from 35% to 21% resulting from the Tax Act and, if approved, would reduce rates by $119.1 million annually through an equal cents per kWh credit.  APS asked that this decrease become effective February 1, 2018. On February 22, 2018, the ACC approved the reduction of rates by $119.1 million for the remainder of 2018 through an equal cents per kWh credit applied to all but a small subset of customers who are taking service under specially-approved tariffs. The rate reduction was effective for the first billing cycle in March 2018.

The impact of the TEAM, 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 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 from the prior year due to lower customer rates through the TEAM 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 to return an additional $86.5 million in tax savings to customers. This second request addresses amortization of non-depreciation related excess deferred taxes previously collected from customers. The ACC has not yet approved this request.

Additionally, as part of this second request, APS informed the ACC of its intent to file a third future request to address the amortization of depreciation related excess deferred taxes, as the Company is currently in the process of seeking IRS guidance regarding the amortization method and period applicable to these depreciation related excess deferred taxes.

The TEAM expressly applies to APS's retail rates with the exception of a small subset of customers taking service under specially-approved tariffs noted above. As discussed under "Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters" above, FERC issued an order on May 22, 2018 authorizing APS to provide for the cost reductions resulting from the income tax changes in its wholesale transmission rates.

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, the date new rates were effective 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 is 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 reflects the 10% annual reduction discussed above. The new tariff became effective on October 1, 2018.

On January 23, 2017, 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.

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. APS and Pinnacle West cannot predict the outcome of this matter.

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, ACC Commissioner Tobin proposed the Energy Modernization Plan, which consists 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 IRP process. The Energy Modernization Plan includes replacing the current RES standard with a new standard called the CREST, which incorporates the proposals in the Energy Modernization Plan. On February 22, 2018, the ACC Staff filed a Notice of Inquiry to further examine the matter. As a part of this proposal, the ACC voted in March 2018 to direct utilities to develop a comprehensive biomass generation plan to be included in each utility’s RES Implementation Plan. On July 5, 2018, Commissioner Tobin’s office issued a set of draft CREST rules for the ACC’s consideration.
    
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 Renewable Energy Standard, 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.  Workshops on these energy issues are scheduled to be held throughout 2019. 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 is required to file a Preliminary Resource Plan by April 1, 2019 and its final IRP by April 1, 2020.

Four Corners
 
SCE-Related Matters. On December 30, 2013, APS purchased SCE’s 48% ownership interest in each of Units 4 and 5 of Four Corners.  The 2012 Settlement Agreement includes a procedure to allow APS to request rate adjustments prior to its next general retail rate case related to APS’s acquisition of the additional interests in Units 4 and 5 and the related closure of Units 1-3 of Four Corners.  APS made its filing under this provision on December 30, 2013. On December 23, 2014, the ACC approved rate adjustments resulting in a revenue increase of $57.1 million on an annual basis.  This included the deferral for future recovery of all non-fuel operating costs for the acquired SCE interest in Four Corners, net of the non-fuel operating costs savings
resulting from the closure of Units 1-3 from the date of closing of the purchase through its inclusion in rates.  The 2012 Settlement Agreement also provided for deferral for future recovery of all unrecovered costs incurred in connection with the closure of Units 1-3.  The deferral balance related to the acquisition of SCE’s interest in Units 4 and 5 and the closure of Units 1-3 was $48 million as of December 31, 2018 and is being amortized in rates over a total of 10 years. The ACC's rate adjustment decision was appealed and on September 26, 2017, the Court of Appeals affirmed the ACC's decision on the Four Corners rate adjustment.
 
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 provides 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 cannot predict whether or if the enforcement division will take any action. 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. That proceeding is pending, and APS cannot predict the outcome of the proceeding.

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 anticipates a decision later in 2019.

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 approves 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.

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 ($89 million as of December 31, 2018), 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 2026.
Navajo Plant
The co-owners of the Navajo Plant and the Navajo Nation agreed that the Navajo Plant will 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 will allow for decommissioning activities to begin after the plant ceases operations in December 2019. Various stakeholders including regulators, tribal representatives, the plant's coal supplier and the U.S. Department of the Interior have been meeting to determine if an alternate solution can be reached that would permit continued operation of the plant beyond 2019. Although we cannot predict whether any alternate plans will be found that would be acceptable to all of the stakeholders and feasible to implement, we believe it is probable that the current owners of the Navajo Plant will cease operations in December 2019.
  
On February 14, 2017, the ACC opened a docket titled "ACC Investigation Concerning the Future of the Navajo Generating Station" with the stated goal of engaging stakeholders and negotiating a sustainable pathway for the Navajo Plant to continue operating in some form after December 2019. APS cannot predict the outcome of this proceeding.

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 ($88 million as of December 31, 2018) 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, 2018
 
December 31, 2017
 
Amortization Through
 
Current
 
Non-Current
 
Current
 
Non-Current
Pension
(a)
 
$

 
$
733,351

 
$

 
$
576,188

Retired power plant costs
2033
 
28,182

 
167,164

 
27,402

 
188,843

Income taxes - AFUDC equity
2048
 
6,457

 
151,467

 
3,828

 
142,852

Deferred fuel and purchased power — mark-to-market (Note 16)
2023
 
31,728

 
23,768

 
52,100

 
34,845

Deferred fuel and purchased power (b) (c)
2019
 
37,164

 

 
75,637

 

Four Corners cost deferral
2024
 
8,077

 
40,228

 
8,077

 
48,305

Income taxes — investment tax credit basis adjustment
2047
 
1,079

 
25,522

 
1,066

 
26,218

Lost fixed cost recovery (b)
2019
 
32,435

 

 
59,844

 

Palo Verde VIEs (Note 18)
2046
 

 
20,015

 

 
19,395

Deferred compensation
2036
 

 
36,523

 

 
36,413

Deferred property taxes
2027
 
8,569

 
66,356

 
8,569

 
74,926

Loss on reacquired debt
2038
 
1,637

 
13,668

 
1,637

 
15,305

Tax expense of Medicare subsidy
2024
 
1,235

 
6,176

 
1,236

 
7,415

TCA balancing account (b)
2020
 
3,860

 
772

 
1,220

 

AG-1 deferral
2022
 
2,654

 
5,819

 
2,654

 
8,472

Mead-Phoenix transmission line CIAC
2050
 
332

 
10,044

 
332

 
10,376

Coal reclamation
2026
 
1,546

 
15,607

 
1,068

 
12,396

SCR deferral
N/A
 

 
23,276

 

 
353

Other
Various
 
1,947

 
3,185

 
3,418

 

Total regulatory assets (d)
 
 
$
166,902

 
$
1,342,941

 
$
248,088

 
$
1,202,302

(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 7 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, 2018
 
December 31, 2017
 
Amortization Through
 
Current
 
Non-Current
 
Current
 
Non-Current
Excess deferred income taxes - ACC - Tax Cuts and Jobs Act
(a)
 
$

 
$
1,272,709

 
$

 
$
1,266,104

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

 
243,691

 

 
254,170

Asset retirement obligations
2057
 

 
278,585

 

 
332,171

Removal costs
(b)
 
39,866

 
177,533

 
18,238

 
209,191

Other post retirement benefits
(c)
 
37,864

 
125,903

 
37,642

 
151,985

Income taxes - deferred investment tax credit
2047
 
2,164

 
51,120

 
2,164

 
52,497

Income taxes - change in rates
2048
 
2,769

 
70,069

 
2,573

 
70,537

Spent nuclear fuel
2027
 
6,503

 
57,002

 
6,924

 
62,132

Renewable energy standard (d)
2020
 
44,966

 
20

 
23,155

 

Demand side management (d)
2020
 
14,604

 
4,123

 
3,066

 
4,921

Sundance maintenance
2030
 
1,278

 
17,228

 

 
16,897

Deferred gains on utility property
2022
 
4,423

 
6,581

 
4,423

 
10,988

Four Corners coal reclamation
2038
 
1,858

 
17,871

 
1,858

 
18,921

Tax expense adjustor mechanism (d)
2019
 
3,237

 

 

 

Other
Various
 
42

 
3,541

 
43

 
2,022

Total regulatory liabilities
 
 
$
165,876

 
$
2,325,976

 
$
100,086

 
$
2,452,536


(a)
While the majority of the excess deferred tax balance shown is subject to special amortization rules under federal income tax laws, which require amortization of the balance over the remaining regulatory life of the related property, treatment of a portion of the liability, and the month in which pass-through of the excess deferred tax balance will begin is subject to regulatory approval. This approval will be sought through the Company's TEAM adjustor mechanism. As a result, the Company cannot estimate the amount of this regulatory liability which is expected to reverse within the next 12 months. See Note 4.
(b)
In accordance with regulatory accounting guidance, APS accrues for removal costs for its regulated assets, even if there is no legal obligation for removal.
(c)
See Note 7.
(d)
See “Cost Recovery Mechanisms” discussion above.
v3.10.0.1
Income Taxes
12 Months Ended
Dec. 31, 2018
Income Tax Disclosure [Abstract]  
Income Taxes Income Taxes
 
Certain assets and liabilities are reported differently for income tax purposes than they are for financial statement purposes.  The tax effect of these differences is recorded as deferred taxes.  We calculate deferred taxes using currently enacted income tax rates.    

APS has recorded regulatory assets and regulatory liabilities related to income taxes on its Balance Sheets in accordance with accounting guidance for regulated operations.  The regulatory assets are for certain temporary differences, primarily the allowance for equity funds used during construction, investment tax credit (“ITC”) basis adjustment and tax expense of Medicare subsidy.  The regulatory liabilities primarily relate to the change in income tax rates and deferred taxes resulting from ITCs.
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 to 21% effective January 1, 2018. As a result of this rate reduction, the Company recognized a $1.14 billion reduction in its net deferred income tax liabilities as of December 31, 2017.

In accordance with accounting for regulated companies, the effect of this rate reduction is substantially offset by a net regulatory liability. As of December 31, 2017, to reflect the $1.14 billion reduction in its net deferred income tax liabilities caused by the rate reduction, APS has recorded a net regulatory liability of $1.52 billion and a new $377 million net deferred tax asset. The Company will amortize the net regulatory liability in accordance with applicable federal income tax laws, which require the amortization of a majority of the balance over the remaining regulatory life of the related property. As a result of the modifications made to the annual transmission formula rate during the second quarter, the Company has recorded amortization of FERC jurisdictional net excess deferred tax liabilities, retroactive to January 1, 2018. The Company continues to work with the ACC on a plan to amortize the remaining net excess deferred tax liabilities subject to its jurisdiction. See Note 3 for more details.

In August 2018, Treasury proposed regulations that clarify bonus depreciation transition rules under the Tax Act for regulated public utility property placed in service after September 27, 2017 and before January 1, 2018. During the third quarter the Company recorded deferred tax liabilities of approximately $11 million and an increase in its net regulatory liability for excess deferred taxes of approximately $9 million, primarily related to bonus depreciation benefits claimed on the Company’s 2017 tax return as a result of this clarifying guidance. However, the proposed regulations are ambiguous with respect to regulated public utility property placed in service on or after January 1, 2018. On December 20, 2018, the Joint Committee on Taxation (“JCT”) released the general explanation of the Tax Act. The document - commonly referred to as the "Blue Book" - provides a comprehensive technical description of the Tax Act and includes the legislative intent of Congress with respect to the changes made by provisions of the Tax Act. The “Blue Book” provides clarification that the intent of the Tax Act was to exclude from the definition of bonus depreciation qualified property any property placed in service by a regulated public utility after December 31, 2017. In a footnote, the JCT indicated that a technical correction bill may be necessary to reflect this intent.

Management recognizes tax positions which it believes are "more likely than not" to be sustained upon examination. In applying this "more likely than not" assessment, the Company is required to consider the technical merits of a position, including legislative intent. As a result, while no legislation has been passed which clarifies the ambiguities related to bonus depreciation for property placed in service on or after January 1, 2018, the Company currently believes the continued availability of bonus depreciation is not "more likely than not" to be sustained upon examination. As a result, the Company has not recognized any current or deferred tax benefits related to bonus depreciation for property placed in service on or after January 1, 2018.

For the quarter ending March 31, 2018, the Company early adopted  ASU 2018-02, Income Statement-Reporting Comprehensive Income: Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income and elected to reclassify the income tax effects of the Tax Act on items within accumulated other comprehensive income to retained earnings. See Note 2 for additional information.

In accordance with regulatory requirements, APS ITCs are deferred and are amortized over the life of the related property with such amortization applied as a credit to reduce current income tax expense in the statement of income.
 
Net income associated with the Palo Verde sale leaseback VIEs is not subject to tax (see Note 18).  As a result, there is no income tax expense associated with the VIEs recorded on the Pinnacle West Consolidated and APS Consolidated Statements of Income.
 The following is a tabular reconciliation of the total amounts of unrecognized tax benefits, excluding interest and penalties, at the beginning and end of the year that are included in accrued taxes and unrecognized tax benefits (dollars in thousands):

 
Pinnacle West Consolidated
 
APS Consolidated
 
2018
 
2017
 
2016
 
2018
 
2017
 
2016
Total unrecognized tax benefits, January 1
$
41,966

 
$
36,075

 
$
34,447

 
$
41,966

 
$
36,075

 
$
34,447

Additions for tax positions of the current year
3,436

 
2,937

 
2,695

 
3,436

 
2,937

 
2,695

Additions for tax positions of prior years
2,696

 
4,783

 
886

 
2,696

 
4,783

 
886

Reductions for tax positions of prior years for:
 

 
 

 
 

 
 

 
 

 
 

Changes in judgment
(1,764
)
 
(1,829
)
 
(1,953
)
 
(1,764
)
 
(1,829
)
 
(1,953
)
Settlements with taxing authorities

 

 

 

 

 

Lapses of applicable statute of limitations
(5,603
)
 

 

 
(5,603
)
 

 

Total unrecognized tax benefits, December 31
$
40,731

 
$
41,966

 
$
36,075

 
$
40,731

 
$
41,966

 
$
36,075



Included in the balances of unrecognized tax benefits are the following tax positions that, if recognized, would decrease our effective tax rate (dollars in thousands):

 
Pinnacle West Consolidated
 
APS Consolidated
 
2018
 
2017
 
2016
 
2018
 
2017
 
2016
Tax positions, that if recognized, would decrease our effective tax rate
$
19,504

 
$
16,373