PINNACLE WEST CAPITAL CORP, 10-Q filed on 8/8/2019
Quarterly Report
v3.19.2
Document and Entity Information - shares
 6 Months Ended
Jun. 30, 2019
Aug. 01, 2019
Entity Information [Line Items]    
Entity Shell Company false  
Entity Interactive Data Current Yes  
Security Exchange Name NYSE  
Trading Symbol PNW  
Title of 12(b) Security Common Stock  
Entity Tax Identification Number 86-0512431  
Entity Address, Address Line One 400 North Fifth Street, P.O. Box 53999  
Entity Address, City or Town Phoenix  
Entity Address, State or Province AZ  
Entity Address, Postal Zip Code 85072-3999  
City Area Code (602)  
Local Phone Number 250-1000  
Entity File Number 1-8962  
Document Transition Report false  
Document Quarterly Report true  
Entity Registrant Name PINNACLE WEST CAPITAL CORPORATION  
Entity Central Index Key 0000764622  
Document Type 10-Q  
Document Period End Date Jun. 30, 2019  
Amendment Flag false  
Current Fiscal Year End Date --12-31  
Entity Current Reporting Status Yes  
Entity Filer Category Large Accelerated Filer  
Entity Emerging Growth Company false  
Entity Small Business false  
Entity Common Stock, Shares Outstanding (in shares)   112,303,854
Document Fiscal Year Focus 2019  
Document Fiscal Period Focus Q2  
Entity Incorporation, State or Country Code AZ  
APS    
Entity Information [Line Items]    
Entity Shell Company false  
Entity Interactive Data Current Yes  
Entity Tax Identification Number 86-0011170  
Entity Address, Address Line One 400 North Fifth Street, P.O. Box 53999  
Entity Address, City or Town Phoenix  
Entity Address, State or Province AZ  
Entity Address, Postal Zip Code 85072-3999  
City Area Code (602)  
Local Phone Number 250-1000  
Entity File Number 1-4473  
Entity Registrant Name ARIZONA PUBLIC SERVICE COMPANY  
Entity Central Index Key 0000007286  
Document Type 10-Q  
Document Period End Date Jun. 30, 2019  
Amendment Flag false  
Current Fiscal Year End Date --12-31  
Entity Current Reporting Status Yes  
Entity Filer Category Non-accelerated Filer  
Entity Emerging Growth Company false  
Entity Small Business false  
Entity Common Stock, Shares Outstanding (in shares)   71,264,947
Document Fiscal Year Focus 2019  
Document Fiscal Period Focus Q2  
Entity Incorporation, State or Country Code AZ  
v3.19.2
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited) - USD ($)
shares in Thousands, $ in Thousands
 3 Months Ended 6 Months Ended
Jun. 30, 2019
Jun. 30, 2018
Jun. 30, 2019
Jun. 30, 2018
OPERATING REVENUES $ 869,501 $ 974,123 $ 1,610,031 $ 1,666,837
OPERATING EXPENSES        
Fuel and purchased power 242,222 257,087 472,810 454,197
Operations and maintenance 227,543 268,397 473,177 534,079
Depreciation and amortization 147,374 145,436 296,081 290,261
Taxes other than income taxes 55,090 53,607 110,180 107,207
Other expenses 683 7,434 1,110 7,597
Total 672,912 731,961 1,353,358 1,393,341
OPERATING INCOME 196,589 242,162 256,673 273,496
OTHER INCOME (DEDUCTIONS)        
Allowance for equity funds used during construction 7,572 13,073 18,760 27,152
Pension and other postretirement non-service credits - net 6,374 12,006 11,488 24,865
Other income (Note 9) 12,885 6,598 20,054 10,583
Other expense (Note 9) (4,350) (3,771) (8,708) (7,000)
Total 22,481 27,906 41,594 55,600
INTEREST EXPENSE        
Interest charges 57,465 60,708 118,118 119,662
Allowance for borrowed funds used during construction (4,494) (6,291) (11,159) (13,046)
Total 52,971 54,417 106,959 106,616
INCOME BEFORE INCOME TAXES 166,099 215,651 191,308 222,480
INCOME TAXES 17,080 44,039 19,498 42,774
NET INCOME 149,019 171,612 171,810 179,706
Less: Net income attributable to noncontrolling interests (Note 6) 4,874 4,874 9,747 9,747
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS $ 144,145 $ 166,738 $ 162,063 $ 169,959
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING        
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - BASIC (in shares) 112,337 112,115 112,381 112,067
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - DILUTED (in shares) 112,651 112,471 112,734 112,482
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING        
Net income attributable to common shareholders - basic (in dollars per share) $ 1.28 $ 1.49 $ 1.44 $ 1.52
Net income attributable to common shareholders - diluted (in dollars per share) $ 1.28 $ 1.48 $ 1.44 $ 1.51
APS        
OPERATING REVENUES $ 869,501 $ 971,963 $ 1,610,031 $ 1,663,969
OPERATING EXPENSES        
Fuel and purchased power 242,222 270,138 472,810 472,148
Operations and maintenance 224,143 251,999 464,518 506,600
Depreciation and amortization 147,354 144,533 296,039 288,645
Taxes other than income taxes 55,081 53,269 110,159 106,511
Other expenses 683 434 1,110 597
Total 669,483 720,373 1,344,636 1,374,501
OPERATING INCOME 200,018 251,590 265,395 289,468
OTHER INCOME (DEDUCTIONS)        
Allowance for equity funds used during construction 7,572 13,073 18,760 27,152
Pension and other postretirement non-service credits - net 6,757 12,389 12,256 25,586
Other income (Note 9) 11,691 6,235 18,107 10,007
Other expense (Note 9) (3,428) (3,372) (7,306) (6,318)
Total 22,592 28,325 41,817 56,427
INTEREST EXPENSE        
Interest charges 53,591 57,731 110,256 113,889
Allowance for borrowed funds used during construction (4,494) (6,291) (11,159) (13,046)
Total 49,097 51,440 99,097 100,843
INCOME BEFORE INCOME TAXES 173,513 228,475 208,115 245,052
INCOME TAXES 18,463 45,776 19,916 47,882
NET INCOME 155,050 182,699 188,199 197,170
Less: Net income attributable to noncontrolling interests (Note 6) 4,874 4,874 9,747 9,747
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS $ 150,176 $ 177,825 $ 178,452 $ 187,423
v3.19.2
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) - USD ($)
$ in Thousands
 3 Months Ended 6 Months Ended
Jun. 30, 2019
Jun. 30, 2018
Jun. 30, 2019
Jun. 30, 2018
NET INCOME $ 149,019 $ 171,612 $ 171,810 $ 179,706
Derivative instruments:        
Net unrealized gain (loss), net of tax expense 0 0 0 (96)
Reclassification of net realized loss, net of tax expense 404 456 732 865
Pension and other postretirement benefits activity, net of tax benefit (1,539) (4,739) (660) (3,839)
Total other comprehensive income (loss) (1,135) (4,283) 72 (3,070)
COMPREHENSIVE INCOME 147,884 167,329 171,882 176,636
Less: Comprehensive income attributable to noncontrolling interests 4,874 4,874 9,747 9,747
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS 143,010 162,455 162,135 166,889
APS        
NET INCOME 155,050 182,699 188,199 197,170
Derivative instruments:        
Net unrealized gain (loss), net of tax expense 0 0 0 (96)
Reclassification of net realized loss, net of tax expense 404 456 732 865
Pension and other postretirement benefits activity, net of tax benefit (1,653) (4,764) (901) (3,907)
Total other comprehensive income (loss) (1,249) (4,308) (169) (3,138)
COMPREHENSIVE INCOME 153,801 178,391 188,030 194,032
Less: Comprehensive income attributable to noncontrolling interests 4,874 4,874 9,747 9,747
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS $ 148,927 $ 173,517 $ 178,283 $ 184,285
v3.19.2
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) (Parenthetical) - USD ($)
$ in Thousands
 3 Months Ended 6 Months Ended
Jun. 30, 2019
Jun. 30, 2018
Jun. 30, 2019
Jun. 30, 2018
Net unrealized loss, tax expense $ 0 $ 0 $ 0 $ 96
Reclassification of net realized loss, tax expense (benefit) 134 150 242 232
Pension and other postretirement (benefits) activity, tax benefit (expense) 506 1,558 218 1,115
APS        
Net unrealized loss, tax expense 0 0 0 96
Reclassification of net realized loss, tax expense (benefit) 134 150 242 232
Pension and other postretirement (benefits) activity, tax benefit (expense) $ 544 $ 1,566 $ 297 $ 1,260
v3.19.2
CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($)
$ in Thousands
Jun. 30, 2019
Dec. 31, 2018
CURRENT ASSETS    
Cash and cash equivalents $ 1,648 $ 5,766
Customer and other receivables 263,836 267,887
Accrued unbilled revenues 193,657 137,170
Allowance for doubtful accounts (3,095) (4,069)
Materials and supplies (at average cost) 289,928 269,065
Fossil fuel (at average cost) 25,453 25,029
Assets from risk management activities (Note 7) 459 1,113
Deferred fuel and purchased power regulatory asset (Note 4) 30,559 37,164
Other regulatory assets (Note 4) 153,900 129,738
Other current assets 72,222 56,128
Total current assets 1,028,567 924,991
INVESTMENTS AND OTHER ASSETS    
Nuclear decommissioning trust (Notes 11 and 12) 950,448 851,134
Other special use funds (Notes 11 and 12) 241,558 236,101
Other assets 97,322 103,247
Total investments and other assets 1,289,328 1,190,482
PROPERTY, PLANT AND EQUIPMENT    
Plant in service and held for future use 19,630,407 18,736,628
Accumulated depreciation and amortization (6,470,935) (6,366,014)
Net 13,159,472 12,370,614
Construction work in progress 568,890 1,170,062
Palo Verde sale leaseback, net of accumulated depreciation (Note 6) 103,841 105,775
Intangible assets, net of accumulated amortization 261,584 262,902
Nuclear fuel, net of accumulated amortization 159,633 120,217
Total property, plant and equipment 14,253,420 14,029,570
DEFERRED DEBITS    
Regulatory assets (Note 4) 1,321,431 1,342,941
Operating lease right-of-use assets (Note 16) 176,219 0
Assets for other postretirement benefits (Note 5) 56,336 46,906
Other 40,365 129,312
Total deferred debits 1,594,351 1,519,159
TOTAL ASSETS 18,165,666 17,664,202
CURRENT LIABILITIES    
Accounts payable 327,969 277,336
Accrued taxes 158,921 154,819
Accrued interest 50,581 61,107
Common dividends payable 82,824 82,675
Short-term borrowings (Note 3) 432,373 76,400
Current maturities of long-term debt (Note 3) 250,000 500,000
Customer deposits 84,177 91,174
Liabilities from risk management activities (Note 7) 58,834 35,506
Liabilities for asset retirements 21,950 19,842
Operating lease liabilities (Note 16) 60,596 0
Regulatory liabilities (Note 4) 231,857 165,876
Other current liabilities 140,879 184,229
Total current liabilities 1,900,961 1,648,964
DEFERRED CREDITS AND OTHER    
Deferred income taxes 1,838,145 1,807,421
Regulatory liabilities (Note 4) 2,287,892 2,325,976
Liabilities for asset retirements 723,005 706,703
Liabilities for pension benefits (Note 5) 356,928 443,170
Liabilities from risk management activities (Note 7) 21,592 24,531
Customer advances 174,411 137,153
Coal mine reclamation 197,443 212,785
Deferred investment tax credit 197,749 200,405
Unrecognized tax benefits 26,271 22,517
Operating lease liabilities (Note 16) 53,005 0
Other 144,142 147,640
Total deferred credits and other 6,020,583 6,028,301
COMMITMENTS AND CONTINGENCIES (SEE NOTE 8)
EQUITY    
Common stock, no par value; authorized 150,000,000 shares, 112,361,595 and 112,159,896 issued at respective dates 2,648,234 2,634,265
Treasury stock at cost; 58,219 and 58,135 shares at respective dates (5,140) (4,825)
Total common stock 2,643,094 2,629,440
Retained earnings 2,637,620 2,641,183
Accumulated other comprehensive loss (47,636) (47,708)
Total shareholders’ equity 5,233,078 5,222,915
Noncontrolling interests (Note 6) 124,165 125,790
Total equity 5,357,243 5,348,705
Long-term debt less current maturities (Note 3) 4,886,879 4,638,232
TOTAL LIABILITIES AND EQUITY 18,165,666 17,664,202
APS    
CURRENT ASSETS    
Cash and cash equivalents 1,355 5,707
Customer and other receivables 253,501 257,654
Accrued unbilled revenues 193,657 137,170
Allowance for doubtful accounts (3,095) (4,069)
Materials and supplies (at average cost) 289,928 269,065
Fossil fuel (at average cost) 25,453 25,029
Assets from risk management activities (Note 7) 459 1,113
Deferred fuel and purchased power regulatory asset (Note 4) 30,559 37,164
Other regulatory assets (Note 4) 153,900 129,738
Other current assets 49,697 35,111
Total current assets 995,414 893,682
INVESTMENTS AND OTHER ASSETS    
Nuclear decommissioning trust (Notes 11 and 12) 950,448 851,134
Other special use funds (Notes 11 and 12) 241,558 236,101
Other assets 46,089 40,817
Total investments and other assets 1,238,095 1,128,052
PROPERTY, PLANT AND EQUIPMENT    
Plant in service and held for future use 19,626,920 18,733,142
Accumulated depreciation and amortization (6,467,684) (6,362,771)
Net 13,159,236 12,370,371
Construction work in progress 568,890 1,170,062
Palo Verde sale leaseback, net of accumulated depreciation (Note 6) 103,841 105,775
Intangible assets, net of accumulated amortization 261,429 262,746
Nuclear fuel, net of accumulated amortization 159,633 120,217
Total property, plant and equipment 14,253,029 14,029,171
DEFERRED DEBITS    
Regulatory assets (Note 4) 1,321,431 1,342,941
Operating lease right-of-use assets (Note 16) 174,320 0
Assets for other postretirement benefits (Note 5) 52,611 43,212
Other 39,523 128,265
Total deferred debits 1,587,885 1,514,418
TOTAL ASSETS 18,074,423 17,565,323
CURRENT LIABILITIES    
Accounts payable 319,435 266,277
Accrued taxes 175,922 176,357
Accrued interest 49,703 60,228
Common dividends payable 82,800 82,700
Short-term borrowings (Note 3) 376,873 0
Current maturities of long-term debt (Note 3) 250,000 500,000
Customer deposits 84,177 91,174
Liabilities from risk management activities (Note 7) 58,834 35,506
Liabilities for asset retirements 21,950 19,842
Operating lease liabilities (Note 16) 60,395 0
Regulatory liabilities (Note 4) 231,857 165,876
Other current liabilities 138,423 178,137
Total current liabilities 1,850,369 1,576,097
DEFERRED CREDITS AND OTHER    
Deferred income taxes 1,831,660 1,812,664
Regulatory liabilities (Note 4) 2,287,892 2,325,976
Liabilities for asset retirements 723,005 706,703
Liabilities for pension benefits (Note 5) 340,154 425,404
Liabilities from risk management activities (Note 7) 21,592 24,531
Customer advances 174,411 137,153
Coal mine reclamation 197,443 212,785
Deferred investment tax credit 197,749 200,405
Unrecognized tax benefits 42,313 41,861
Operating lease liabilities (Note 16) 51,158 0
Other 121,052 125,511
Total deferred credits and other 5,988,429 6,012,993
COMMITMENTS AND CONTINGENCIES (SEE NOTE 8)
EQUITY    
Total common stock 178,162 178,162
Additional paid-in capital 2,721,696 2,721,696
Retained earnings 2,801,110 2,788,256
Accumulated other comprehensive loss (27,276) (27,107)
Total shareholders’ equity 5,673,692 5,661,007
Noncontrolling interests (Note 6) 124,165 125,790
Total equity 5,797,857 5,786,797
Long-term debt less current maturities (Note 3) 4,437,768 4,189,436
Total capitalization 10,235,625 9,976,233
TOTAL LIABILITIES AND EQUITY $ 18,074,423 $ 17,565,323
v3.19.2
CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical) - $ / shares
Jun. 30, 2019
Dec. 31, 2018
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest [Abstract]    
Common stock, par value (in dollars per share)
Common stock, authorized shares (in shares) 150,000,000 150,000,000
Common stock, issued shares (in shares) 112,361,595 112,159,896
Treasury stock at cost, shares (in shares) 58,219 58,135
v3.19.2
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($)
$ in Thousands
 6 Months Ended
Jun. 30, 2019
Jun. 30, 2018
CASH FLOWS FROM OPERATING ACTIVITIES    
NET INCOME $ 171,810 $ 179,706
Adjustments to reconcile net income to net cash provided by operating activities:    
Depreciation and amortization including nuclear fuel 332,185 325,550
Deferred fuel and purchased power (16,702) (50,112)
Deferred fuel and purchased power amortization 23,307 50,851
Allowance for equity funds used during construction (18,760) (27,152)
Deferred income taxes 4,326 33,711
Deferred investment tax credit (2,656) (2,778)
Stock compensation 13,725 13,189
Changes in current assets and liabilities:    
Customer and other receivables 3,543 (18,672)
Accrued unbilled revenues (56,487) (95,453)
Materials, supplies and fossil fuel (21,287) (22,970)
Other current assets (16,121) 11,069
Accounts payable 65,874 36,614
Accrued taxes 4,102 8,140
Other current liabilities (61,270) 9,410
Change in other long-term assets (82,850) 23,927
Change in other long-term liabilities 3,195 (79,228)
Net cash flow provided by operating activities 345,934 395,802
CASH FLOWS FROM INVESTING ACTIVITIES    
Capital expenditures (541,401) (679,949)
Contributions in aid of construction 18,909 19,339
Allowance for borrowed funds used during construction (11,159) (13,046)
Proceeds from nuclear decommissioning trust sales and other special use funds 309,354 258,401
Investment in nuclear decommissioning trust and other special use funds (310,494) (259,542)
Other 7,153 (4,299)
Net cash flow used for investing activities (527,638) (679,096)
CASH FLOWS FROM FINANCING ACTIVITIES    
Issuance of long-term debt 497,324 0
Short-term borrowing and payments — net 363,973 500,849
Short-term debt borrowings 49,000 45,000
Short-term debt repayments (57,000) (25,000)
Dividends paid on common stock (161,979) (151,942)
Repayment of long-term debt (500,000) (82,000)
Common stock equity issuance - net of purchases (2,360) (2,294)
Distributions to noncontrolling interests (11,372) (11,372)
Net cash flow provided by financing activities 177,586 273,241
NET DECREASE IN CASH AND CASH EQUIVALENTS (4,118) (10,053)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 5,766 13,892
CASH AND CASH EQUIVALENTS AT END OF PERIOD 1,648 3,839
Supplemental disclosure of cash flow information    
Income taxes, net of refunds 10,788 10,032
Interest, net of amounts capitalized 114,717 104,249
Significant non-cash investing and financing activities:    
Accrued capital expenditures 108,056 65,995
APS    
CASH FLOWS FROM OPERATING ACTIVITIES    
NET INCOME 188,199 197,170
Adjustments to reconcile net income to net cash provided by operating activities:    
Depreciation and amortization including nuclear fuel 332,143 323,934
Deferred fuel and purchased power (16,702) (50,112)
Deferred fuel and purchased power amortization 23,307 50,851
Allowance for equity funds used during construction (18,760) (27,152)
Deferred income taxes (10,625) 10,372
Deferred investment tax credit (2,656) (2,778)
Changes in current assets and liabilities:    
Customer and other receivables 3,645 (9,254)
Accrued unbilled revenues (56,487) (95,453)
Materials, supplies and fossil fuel (21,287) (23,073)
Other current assets (14,613) 7,552
Accounts payable 68,399 39,573
Accrued taxes (435) 26,412
Other current liabilities (57,709) 7,395
Change in other long-term assets (84,946) 34,947
Change in other long-term liabilities 3,253 (84,643)
Net cash flow provided by operating activities 334,726 405,741
CASH FLOWS FROM INVESTING ACTIVITIES    
Capital expenditures (541,401) (670,841)
Contributions in aid of construction 18,909 19,339
Allowance for borrowed funds used during construction (11,159) (13,046)
Proceeds from nuclear decommissioning trust sales and other special use funds 309,354 258,227
Investment in nuclear decommissioning trust and other special use funds (310,494) (259,367)
Other (1,612) (1,221)
Net cash flow used for investing activities (536,403) (666,909)
CASH FLOWS FROM FINANCING ACTIVITIES    
Issuance of long-term debt 497,324 0
Short-term borrowing and payments — net 376,873 499,949
Short-term debt borrowings 0 25,000
Short-term debt repayments 0 (25,000)
Dividends paid on common stock (165,500) (155,500)
Repayment of long-term debt (500,000) (82,000)
Distributions to noncontrolling interests (11,372) (11,372)
Net cash flow provided by financing activities 197,325 251,077
NET DECREASE IN CASH AND CASH EQUIVALENTS (4,352) (10,091)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 5,707 13,851
CASH AND CASH EQUIVALENTS AT END OF PERIOD 1,355 3,760
Supplemental disclosure of cash flow information    
Income taxes, net of refunds 35,573 24,689
Interest, net of amounts capitalized 107,169 98,478
Significant non-cash investing and financing activities:    
Accrued capital expenditures $ 108,056 $ 65,995
v3.19.2
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Unaudited) - USD ($)
$ in Thousands
Total
Common Stock
Treasury Stock
Retained Earnings
Accumulated Other Comprehensive Income (Loss)
Noncontrolling Interests
APS
APS
Common Stock
APS
Additional Paid-In Capital
APS
Retained Earnings
APS
Accumulated Other Comprehensive Income (Loss)
APS
Noncontrolling Interests
Beginning balance (in shares) at Dec. 31, 2017   (111,816,170) (64,463)         (71,264,947)        
Balance at beginning of period 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
Increase (Decrease) in Shareholders' Equity                        
Net income 179,706     169,959   9,747 197,170     187,423   9,747
Other comprehensive loss (3,070)       (3,070)   (3,138)       (3,138)  
Dividends on common stock (155,620)     (155,620)     (155,599)     (155,599)    
Issuance of common stock (in shares)   174,052                    
Issuance of common stock 9,867 $ 9,867                    
Purchase of treasury stock (in shares) [1]     (81,177)                  
Purchase of treasury stock [1] (6,277)   $ (6,277)                  
Reissuance of treasury stock for stock-based compensation and other (in shares)     128,007                  
Reissuance of treasury stock for stock-based compensation and other 10,470   $ 10,470 0   0            
Reclassification of income tax effects related to new tax reform (8,552)     8,552 [2] (8,552) [2]         5,038 [3] (5,038) [3]  
Capital activities by noncontrolling interests (11,372)         (11,372) (11,372)         (11,372)
Ending balance (in shares) at Jun. 30, 2018   (111,990,222) (17,633)         (71,264,947)        
Balance at end of period at Jun. 30, 2018 5,159,434 $ 2,624,672 $ (1,431) 2,465,402 (56,624) 127,415 5,412,930 $ 178,162 2,571,696 2,570,816 (35,159) 127,415
Beginning balance (in shares) at Mar. 31, 2018   (111,961,963) (29,097)         (71,264,947)        
Balance at beginning of period at Mar. 31, 2018 5,153,671 $ 2,620,261 $ (2,431) 2,454,268 (52,341) 133,914 5,401,512 $ 178,162 2,571,696 2,548,591 (30,851) 133,914
Increase (Decrease) in Shareholders' Equity                        
Net income 171,612     166,738   4,874 182,699     177,825   4,874
Other comprehensive loss (4,283)       (4,283)   (4,308)       (4,308)  
Other             (1)         (1)
Dividends on common stock (155,604)     (155,604)     (155,600)     (155,600)    
Issuance of common stock (in shares)   28,259                    
Issuance of common stock 4,411 $ 4,411                    
Reissuance of treasury stock for stock-based compensation and other (in shares)     11,464                  
Reissuance of treasury stock for stock-based compensation and other 999   $ 1,000 0   (1)            
Capital activities by noncontrolling interests (11,372)         (11,372) (11,372)         (11,372)
Ending balance (in shares) at Jun. 30, 2018   (111,990,222) (17,633)         (71,264,947)        
Balance at end of period at Jun. 30, 2018 $ 5,159,434 $ 2,624,672 $ (1,431) 2,465,402 (56,624) 127,415 5,412,930 $ 178,162 2,571,696 2,570,816 (35,159) 127,415
Beginning balance (in shares) at Dec. 31, 2018 (112,159,896) (112,159,896) (58,135)         (71,264,947)        
Balance at beginning of period at Dec. 31, 2018 $ 5,348,705 $ 2,634,265 $ (4,825) 2,641,183 (47,708) 125,790 5,786,797 $ 178,162 2,721,696 2,788,256 (27,107) 125,790
Increase (Decrease) in Shareholders' Equity                        
Net income 171,810     162,063   9,747 188,199     178,452   9,747
Other comprehensive loss 72       72   (169)       (169)  
Dividends on common stock (165,626)     (165,626)     (165,598)     (165,598)    
Issuance of common stock (in shares)   201,699                    
Issuance of common stock 13,969 $ 13,969                    
Purchase of treasury stock (in shares) [1]     (75,791)                  
Purchase of treasury stock [1] (6,882)   $ (6,882)                  
Reissuance of treasury stock for stock-based compensation and other (in shares)     75,707                  
Reissuance of treasury stock for stock-based compensation and other 6,567   $ 6,567 0   0            
Capital activities by noncontrolling interests $ (11,372)         (11,372) (11,372)         (11,372)
Ending balance (in shares) at Jun. 30, 2019 (112,361,595) (112,361,595) (58,219)         (71,264,947)        
Balance at end of period at Jun. 30, 2019 $ 5,357,243 $ 2,648,234 $ (5,140) 2,637,620 (47,636) 124,165 5,797,857 $ 178,162 2,721,696 2,801,110 (27,276) 124,165
Beginning balance (in shares) at Mar. 31, 2019   (112,340,322) (63,271)         (71,264,947)        
Balance at beginning of period at Mar. 31, 2019 5,381,725 $ 2,644,063 $ (5,586) 2,659,086 (46,501) 130,663 5,821,026 $ 178,162 2,721,696 2,816,532 (26,027) 130,663
Increase (Decrease) in Shareholders' Equity                        
Net income 149,019     144,145   4,874 155,050     150,176   4,874
Other comprehensive loss (1,135)       (1,135)   (1,249)       (1,249)  
Dividends on common stock (165,611)     (165,611)     (165,598)     (165,598)    
Issuance of common stock (in shares)   21,273                    
Issuance of common stock 4,171 $ 4,171                    
Reissuance of treasury stock for stock-based compensation and other (in shares)     5,052                  
Reissuance of treasury stock for stock-based compensation and other 446   $ 446 0   0            
Capital activities by noncontrolling interests $ (11,372)         (11,372) (11,372)         (11,372)
Ending balance (in shares) at Jun. 30, 2019 (112,361,595) (112,361,595) (58,219)         (71,264,947)        
Balance at end of period at Jun. 30, 2019 $ 5,357,243 $ 2,648,234 $ (5,140) $ 2,637,620 $ (47,636) $ 124,165 $ 5,797,857 $ 178,162 $ 2,721,696 $ 2,801,110 $ (27,276) $ 124,165
[1]
Primarily represents shares of common stock withheld from certain stock awards for tax purposes.
[2]
In 2018, the Company adopted new accounting guidance and elected to reclassify income tax effects of the Tax Cuts and Jobs Act of 2017 (the “Tax Act”) on items within accumulated other comprehensive income to retained earnings.
[3]
In 2018, the Company adopted new accounting guidance and elected to reclassify income tax effects of the Tax Act on items within accumulated other comprehensive income to retained earnings.
v3.19.2
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Unaudited) Parenthetical - $ / shares
 3 Months Ended 6 Months Ended
Jun. 30, 2019
Jun. 30, 2018
Jun. 30, 2019
Jun. 30, 2018
Statement of Stockholders' Equity [Abstract]        
DIVIDENDS DECLARED PER SHARE (in dollars per share) $ 1.48 $ 1.39 $ 1.48 $ 1.39
v3.19.2
Consolidation and Nature of Operations
 6 Months Ended
Jun. 30, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]  
Consolidation and Nature of Operations
Consolidation and Nature of Operations
 
The unaudited condensed consolidated financial statements include the accounts of Pinnacle West and our subsidiaries:  APS, 4C Acquisition, LLC ("4CA"), Bright Canyon Energy Corporation ("BCE") and El Dorado Investment Company ("El Dorado").  See Note 8 for more information on 4CA matters. Intercompany accounts and transactions between the consolidated companies have been eliminated.  The unaudited condensed consolidated financial statements for APS include the accounts of APS and the Palo Verde Generating Station ("Palo Verde") sale leaseback variable interest entities ("VIEs") (see Note 6 for further discussion).  Our accounting records are maintained in accordance with accounting principles generally accepted in the United States of America ("GAAP").  The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period.  Actual results could differ from those estimates.
 
Amounts reported in our interim Condensed Consolidated Statements of Income are not necessarily indicative of amounts expected for the respective annual periods, due to the effects of seasonal temperature variations on energy consumption, timing of maintenance on electric generating units, and other factors.
 
Our condensed consolidated financial statements reflect all adjustments (consisting only of normal recurring adjustments except as otherwise disclosed in the notes) that we believe are necessary for the fair presentation of our financial position, results of operations, and cash flows for the periods presented. Certain information and footnote disclosures normally included in financial statements prepared in conformity with GAAP have been condensed or omitted pursuant to such regulations, although we believe that the disclosures provided are adequate to make the interim information presented not misleading. The accompanying condensed consolidated financial statements and these notes should be read in conjunction with the audited consolidated financial statements and notes included in our 2018 Form 10-K.
Supplemental Cash Flow Information

The following table summarizes supplemental Pinnacle West cash flow information (dollars in thousands):
 
Six Months Ended
June 30,
 
2019
 
2018
Cash paid during the period for:
 
 
 
Income taxes, net of refunds
$
10,788

 
$
10,032

Interest, net of amounts capitalized
114,717

 
104,249

Significant non-cash investing and financing activities:
 
 
 
Accrued capital expenditures
$
108,056

 
$
65,995

Right-of-use operating lease assets obtained in exchange for operating lease liabilities
4,562

 
—

Dividends accrued but not yet paid
82,824

 
77,821



The following table summarizes supplemental APS cash flow information (dollars in thousands):
 
Six Months Ended 
 June 30,
 
2019
 
2018
Cash paid during the period for:
 
 
 
Income taxes, net of refunds
$
35,573

 
$
24,689

Interest, net of amounts capitalized
107,169

 
98,478

Significant non-cash investing and financing activities:
 
 
 
Accrued capital expenditures
$
108,056

 
$
65,995

Right-of-use operating lease assets obtained in exchange for operating lease liabilities
4,562

 
—

Dividends accrued but not yet paid
82,800

 
77,800
v3.19.2
Revenue
 6 Months Ended
Jun. 30, 2019
Revenue from Contract with Customer [Abstract]  
Revenue Revenue

Sources of Revenue

We derive our revenues from contracts with customers primarily from sales of electricity to our regulated retail customers. Our retail electric services and tariff rates are regulated by the ACC. Revenues from wholesale energy sales and transmission services for others represent energy and transmission sales to wholesale customers. Our wholesale activities and tariff rates are regulated by the United States Federal Energy Regulatory Commission ("FERC").

    
The following table provides detail of Pinnacle West's consolidated revenue disaggregated by revenue sources (dollars in thousands):
 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
 
2019
2018
 
2019
2018
Retail residential electric service
 
$
432,568

$
500,247

 
$
784,134

$
816,922

Retail non-residential electric service
 
395,929

435,500

 
728,597

778,689

Wholesale energy sales
 
21,991

15,392

 
58,443

27,481

Transmission services for others
 
15,157

15,489

 
30,406

30,334

Other sources
 
3,856

7,495

 
8,451

13,411

Total operating revenues
 
$
869,501

$
974,123

 
$
1,610,031

$
1,666,837


    
Revenue Activities

Our revenues are primarily derived from activities that are classified as revenues from contracts with customers. This includes sales of electricity to our regulated retail customers and wholesale and transmission activities. Our revenues from contracts with customers for the three and six months ended June 30, 2019 were $858 million and $1,578 million, and for the three and six months ended June 30, 2018 were $954 million and $1,640 million, respectively.

We have certain revenues that do not meet the specific accounting criteria to be classified as revenues from contracts with customers. For the three and six months ended June 30, 2019, our revenues that do not qualify as revenue from contracts with customers were $12 million and $32 million, and for the three and six months ended June 30, 2018 were $20 million and $27 million, respectively. This relates primarily to certain regulatory cost recovery mechanisms that are considered alternative revenue programs. We recognize revenue associated with alternative revenue programs when specific events permitting recognition are completed. Certain amounts associated with alternative revenue programs will subsequently be billed to customers; however, we do not reclassify billed amounts into revenue from contracts with customers. See Note 4 for a discussion of our regulatory cost recovery mechanisms.

Contract Assets and Liabilities from Contracts with Customers

There were no material contract assets, contract liabilities, or deferred contract costs recorded on the Condensed Consolidated Balance Sheets as of June 30, 2019 or December 31, 2018.
v3.19.2
Long-Term Debt and Liquidity Matters
 6 Months Ended
Jun. 30, 2019
Debt Disclosure [Abstract]  
Long-Term Debt and Liquidity Matters
Long-Term Debt and Liquidity Matters

Pinnacle West and APS maintain committed revolving credit facilities in order to enhance liquidity and provide credit support for their commercial paper programs, to refinance indebtedness, and for other general corporate purposes.
 
Pinnacle West
 
On May 9, 2019, Pinnacle West entered into a $50 million term loan agreement that matures May 7, 2020. Pinnacle West used the proceeds to refinance indebtedness under and terminate a prior $150 million revolving credit facility. Borrowings under the agreement bear interest at London Inter-bank Offered Rate ("LIBOR') plus 0.55% per annum. At June 30, 2019, Pinnacle West had $46 million in outstanding borrowings under the agreement.

At June 30, 2019, Pinnacle West had a $200 million revolving credit facility that matures in July 2023. Pinnacle West has the option to increase the amount of the facility up to a maximum of $300 million upon the satisfaction of certain conditions and with the consent of the lenders. Interest rates are based on Pinnacle West's senior unsecured debt credit ratings. The facility is available to support Pinnacle West's $200 million commercial paper program, for bank borrowings or for issuances of letters of credits. At June 30, 2019, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding and $10 million of commercial paper borrowings.

APS

On February 26, 2019, APS entered into a $200 million term loan agreement that matures August 26, 2020. APS used the proceeds to repay existing indebtedness. Borrowings under the agreement bear interest at LIBOR plus 0.50% per annum.

On February 28, 2019, APS issued $300 million of 4.25% unsecured senior notes that mature on March 1, 2049. The net proceeds from the sale, together with funds made available from the term loan described above, were used to repay existing indebtedness.

On March 1, 2019, APS repaid at maturity $500 million aggregate principal amount of its 8.75% senior notes.

At June 30, 2019, APS had two revolving credit facilities totaling $1 billion, including a $500 million credit facility that matures in June 2022 and a $500 million facility that matures in July 2023.  APS may increase the amount of each facility up to a maximum of $700 million, for a total of $1.4 billion, upon the satisfaction of certain conditions and with the consent of the lenders.  Interest rates are based on APS’s senior unsecured debt credit ratings. These facilities are available to support APS’s $500 million commercial paper program, for bank borrowings or for issuances of letters of credit.  At June 30, 2019, APS had $377 million of commercial paper outstanding and no outstanding borrowings or letters of credit under its revolving credit facilities.
 
See "Financial Assurances" in Note 8 for a discussion of other outstanding letters of credit.
 
Debt Fair Value
 
Our long-term debt fair value estimates are classified within Level 2 of the fair value hierarchy. The following table presents the estimated fair value of our long-term debt, including current maturities (dollars in thousands):

 
As of June 30, 2019
 
As of December 31, 2018
 
Carrying
Amount
 
Fair Value
 
Carrying
Amount
 
Fair Value
Pinnacle West
$
449,111

 
$
449,124

 
$
448,796

 
$
443,955

APS
4,687,768

 
5,119,091

 
4,689,436

 
4,789,608

Total
$
5,136,879

 
$
5,568,215

 
$
5,138,232

 
$
5,233,563
v3.19.2
Regulatory Matters
 6 Months Ended
Jun. 30, 2019
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. On March 27, 2017, a majority of the stakeholders in the general retail rate case, including the ACC Staff, the Residential Utility Consumer Office, limited income advocates and private rooftop solar organizations signed a settlement agreement (the "2017 Settlement Agreement") and filed it with the ACC. The 2017 Settlement Agreement provides for a net retail base rate increase of $94.6 million, excluding the transfer of adjustor balances, consisting of: (1) a non-fuel, non-depreciation, base rate increase of $87.2 million per year; (2) a base rate decrease of $53.6 million attributable to reduced fuel and purchased power costs; and (3) a base rate increase of $61.0 million due to changes in depreciation schedules. The average annual customer bill impact under the 2017 Settlement Agreement was calculated as an increase of 3.28% (the average annual bill impact for a typical APS residential customer was calculated as an increase of 4.54%).

Other key provisions of the agreement include the following:

•
an agreement by APS not to file another general retail rate case application before June 1, 2019;
•
an authorized return on common equity of 10.0%;
•
a capital structure comprised of 44.2% debt and 55.8% common equity;
•
a cost deferral order for potential future recovery in APS’s next general retail rate case for the construction and operating costs APS incurs for its Ocotillo modernization project;
•
a cost deferral and procedure to allow APS to request rate adjustments prior to its next general retail rate case related to its share of the construction costs associated with installing selective catalytic reduction ("SCR") equipment at the Four Corners Power Plant ("Four Corners");
•
a deferral for future recovery (or credit to customers) of the Arizona property tax expense above or below a specified test year level caused by changes to the applicable Arizona property tax rate;
•
an expansion of the Power Supply Adjustor (“PSA”) to include certain environmental chemical costs and third-party battery storage costs;
•
a new AZ Sun II program (now known as "APS Solar Communities") for utility-owned solar distributed generation with the purpose of expanding access to rooftop solar for low and moderate income Arizonans, recoverable through the Arizona Renewable Energy Standard and Tariff ("RES"), to be no less than $10 million per year, 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 distributed generation ("DG") customers would be required to select a rate option that has time of use rates and either a new grid access charge or demand component;
▪
a Resource Comparison Proxy (“RCP”) for exported energy of 12.9 cents per kWh in year one; and
•
an agreement by APS not to pursue any new self-build generation (with certain exceptions) having an in-service date prior to January 1, 2022 (extended to December 31, 2027 for combined-cycle generating units), unless expressly authorized by the ACC.

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

On August 15, 2017, the ACC approved (by a vote of 4-1), the 2017 Settlement Agreement without material modifications.  On August 18, 2017, the ACC issued a final written Opinion and Order reflecting its decision in APS’s general retail rate case (the "2017 Rate Case Decision"), which is subject to requests for rehearing and potential appeal. The new rates went into effect on August 19, 2017.

On 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 were consolidated, and APS requested and was granted intervention. 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. The Arizona Supreme Court denied review.

On January 3, 2018, an APS customer filed a petition with the ACC that was determined by the ACC Staff to be a complaint filed pursuant to Arizona Revised Statute §40-246 (the “Complaint”) and not a request for rehearing. Arizona Revised Statute §40-246 requires the ACC to hold a hearing regarding any complaint alleging that a public service corporation is in violation of any commission order or that the rates being charged are not just and reasonable if the complaint is signed by at least twenty-five customers of the public service corporation. The Complaint alleged that APS is “in violation of commission order” [sic]. On February 13, 2018, the complainant filed an amended Complaint alleging that the rates and charges in the 2017 Rate Case Decision are not just and reasonable.  The complainant requested that the ACC hold a hearing on the amended Complaint to determine if the average bill impact on residential customers of the rates and charges approved in the 2017 Rate Case Decision is greater than 4.54% (the average annual bill impact for a typical APS residential customer estimated by APS) and, if so, what effect the alleged greater bill impact has on APS's revenues and the overall reasonableness and justness of APS's rates and charges, in order to determine if there is sufficient evidence to warrant a full-scale rate hearing.  The ACC held a hearing on this matter beginning in September 2018 and the hearing was concluded on October 1, 2018. On April 9, 2019, the Administrative Law Judge issued a Recommended Opinion and Order recommending that the Complaint be dismissed. The ACC considered the matter at its April and May 2019 open meetings, but no decision was issued. On July 3, 2019, the Administrative Law Judge issued an amendment to the Recommended Opinion and Order that incorporated the requirements of the rate review of the 2017 Rate Case Decision (see below discussion regarding the rate review). On July 10, 2019, the ACC reconsidered the matter and adopted the Administrative Law Judge's amended Recommended Opinion and Order along with several ACC Commissioner amendments and an amendment incorporating the results of the rate review and resolved the Complaint.

On December 24, 2018, certain ACC Commissioners filed a letter stating that because the ACC had received a substantial number of complaints that the rate increase authorized by the 2017 Rate Case Decision was much more than anticipated, they believe there is a possibility that APS is earning more than was authorized by the 2017 Rate Case Decision.  Accordingly, the ACC Commissioners requested the ACC Staff to perform a rate review of APS using calendar year 2018 as a test year and file a report by May 3, 2019. The ACC Commissioners also asked the ACC Staff to evaluate APS’s efforts to educate its customers regarding the new rates approved in the 2017 Rate Case Decision. On April 23, 2019, the ACC Staff indicated that they would need some additional time beyond May 3, 2019 to file the requested report.

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

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

APS cannot predict the outcome or impact of the future rate case to be filed no later than October 31, 2019. APS is assessing the impact to its financial statements of the implementation of the other key provisions of the amended order regarding the rate review and cannot predict at this time whether they will have a material impact on its financial position, results of operations or cash flows. 

Cost Recovery Mechanisms
 
APS has received regulatory decisions that allow for more timely recovery of certain costs outside of a general retail rate case through the following recovery mechanisms.
 
Renewable Energy Standard.  In 2006, the ACC approved the RES.  Under the RES, electric utilities that are regulated by the ACC must supply an increasing percentage of their retail electric energy sales from eligible renewable resources, including solar, wind, biomass, biogas and geothermal technologies.  In order to achieve these requirements, the ACC allows APS to include a RES surcharge as part of customer bills to recover the approved amounts for use on renewable energy projects.  Each year APS is required to file a five-year implementation plan with the ACC and seek approval for funding the upcoming year’s RES budget. In 2015, the ACC revised the RES rules to allow the ACC to consider all available information, including the number of rooftop solar arrays in a utility’s service territory, to determine compliance with the RES.

On June 30, 2017, APS filed its 2018 RES Implementation Plan and proposed a budget of approximately $90 million.  APS’s budget request supports existing approved projects and commitments and includes the anticipated transfer of specific revenue requirements into base rates in accordance with the 2017 Settlement Agreement and also requests a permanent waiver of the residential distributed energy requirement for 2018 contained in the RES rules. APS's 2018 RES budget request 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 including a waiver of the distributed energy requirements for the 2018 implementation year.

On June 29, 2018, APS filed its 2019 RES Implementation Plan and proposed a budget of approximately $89.9 million.  APS’s budget request supports existing approved projects and commitments and requests a permanent waiver of the residential distributed energy requirement for 2019 contained in the RES rules. The ACC has not yet ruled on the 2019 RES Implementation Plan.
    
On July 1, 2019, APS filed its 2020 RES Implementation Plan and proposed a budget of approximately $86.3 million. APS’s budget request supports existing approved projects and commitments and requests a permanent waiver of the residential distributed energy requirement for 2020 contained in the RES rules. The ACC has not yet ruled on the 2020 RES Implementation Plan.

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

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

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

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

On May 7, 2019, APS filed a request for an extension to file its 2020 DSM Plan no later than December 31, 2019. On July 10, 2019, the ACC approved this request.

 Power Supply Adjustor Mechanism and Balance.  The PSA provides for the adjustment of retail rates to reflect variations primarily in retail fuel and purchased power costs.  The following table shows the changes in the deferred fuel and purchased power regulatory asset for 2019 and 2018 (dollars in thousands):
 
 
Six Months Ended
June 30,
 
2019
 
2018
Beginning balance
$
37,164

 
$
75,637

Deferred fuel and purchased power costs — current period
16,702

 
50,112

Amounts charged to customers
(23,307
)
 
(50,851
)
Ending balance
$
30,559

 
$
74,898


 
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 into 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 ("TCA") 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 settlement agreement entered into in 2012 regarding APS's rate case (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.

On March 7, 2018, APS made a filing to make modifications to its annual transmission formula to provide transmission customers the benefit of the reduced federal corporate income tax rate resulting from the Tax Act beginning in its 2018 annual transmission formula rate update filing. These modifications were approved by FERC on May 22, 2018 and reduced APS’s transmission rates compared to the rate that would have gone into effect absent these changes.

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

Effective June 1, 2019, APS's annual wholesale transmission rates for all users of its transmission system increased by approximately $4.9 million for the twelve-month period beginning June 1, 2019 in accordance with the FERC-approved formula. An adjustment to APS’s retail rates to recover FERC approved transmission charges went into effect automatically on June 1, 2019.

 Lost Fixed Cost Recovery Mechanism.  The LFCR mechanism permits APS to recover on an after-the-fact basis a portion of its fixed costs that would otherwise have been collected by APS in the kWh sales lost due to APS energy efficiency programs and to DG such as rooftop solar arrays.  The fixed costs recoverable by the LFCR mechanism were first established in the 2012 Settlement Agreement and amount to approximately 3.1 cents per residential kWh lost and 2.3 cents per non-residential kWh lost. These amounts were revised in the 2017 Settlement Agreement to 2.5 cents for both lost residential and non-residential kWh.  The LFCR adjustment has a year-over-year cap of 1% of retail revenues.  Any amounts left unrecovered in a particular year because of this cap can be carried over for recovery in a future year.  The kWhs lost from energy efficiency are based on a third-party evaluation of APS’s energy efficiency programs.  DG sales losses are determined from the metered output from the DG units.
 
APS filed its 2017 LFCR adjustment on January 13, 2017 requesting an LFCR adjustment of $63.7 million. 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). On July 10, 2019, the ACC approved APS’s 2019 LFCR adjustment as filed, effective with the next billing cycle of July 2019. 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 ("TEAM").  As part of the 2017 Settlement Agreement, the parties agreed to a rate adjustment mechanism to address potential federal income tax reform and enable the pass-
through of certain income tax effects to customers. The TEAM expressly applies to APS's retail rates with the exception of a small subset of customers taking service under specially-approved tariffs. On December 22, 2017, the Tax Act was enacted.  This legislation made significant changes to the federal income tax laws including a reduction in the corporate tax rate from 35% to 21% effective January 1, 2018.

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

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

On August 13, 2018, APS filed a second request with the ACC that addressed the return of an additional $86.5 million in tax savings to customers related to the amortization of non-depreciation related excess deferred taxes previously collected from customers ("TEAM Phase II"). The ACC approved this request on March 13, 2019, effective the first billing cycle in April 2019. The impact of TEAM Phase II is expected to be earnings neutral as both the timing of the reduction in revenues refunded through TEAM Phase II and the offsetting income tax benefit are recognized based upon our seasonal kWh sales pattern.
    
On April 10, 2019, APS filed a third request with the ACC that addressed the amortization of depreciation related excess deferred taxes over a 28.5 year period (“TEAM Phase III”).  Over the first 36 months, TEAM Phase III is expected to return $34.5 million to customers annually, and APS proposed this refund begin July 1, 2019.  APS is currently in the process of seeking IRS guidance affirming the amortization method and period applicable to these depreciation related excess deferred taxes. The ACC has not yet approved TEAM Phase III.

Net Metering

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

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

In addition, the ACC made the following determinations:

•
Customers who have interconnected a DG system or submitted an application for interconnection for DG systems prior to September 1, 2017, based on APS's 2017 Rate Case Decision, will be grandfathered for a period of 20 years from the date the customer’s interconnection application was accepted by the utility;
•
Customers with DG solar systems are to be considered a separate class of customers for ratemaking purposes; and
•
Once an export price is set for APS, no netting or banking of retail credits will be available for new DG customers, and the then-applicable export price will be guaranteed for new customers for a period of 10 years.

This decision of the ACC addresses policy determinations only. The decision states that its principles will be applied in future general retail rate cases, and the policy determinations themselves may be subject to future change, as are all ACC policies. A first-year export energy price of 12.9 cents per kWh was included in the 2017 Settlement Agreement and became effective on September 1, 2017.

In accordance with the 2017 Rate Case Decision, APS filed its request for a second-year export energy price of 11.6 cents per kWh on May 1, 2018.  This price reflected the 10% annual reduction discussed above. The new tariff became effective on October 1, 2018. APS filed its request for a third-year export energy price of 10.45 cents per kWh on May 1, 2019, with a requested effective date of September 1, 2019.  This price also reflects the 10% annual reduction discussed above.  The ACC has not yet ruled on this request.

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

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

Subpoena from Arizona Corporation Commissioner Robert Burns

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

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

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

On August 4, 2017, Commissioner Burns amended his complaint to add all of the ACC Commissioners and the ACC itself as defendants. All defendants moved to dismiss the amended complaint. On February 15, 2018, the Superior Court dismissed Commissioner Burns’ amended complaint. On March 6, 2018, Commissioner Burns filed an objection to the proposed final order from the Superior Court and a motion to further amend his complaint. The Superior Court permitted Commissioner Burns to amend his complaint to add a claim regarding his attempted investigation into whether his fellow commissioners should have been disqualified from voting on APS’s 2017 rate case. Commissioner Burns filed his second amended complaint, and all defendants filed responses opposing the second amended complaint and requested that it be dismissed. Oral argument occurred in November 2018 regarding the motion to dismiss. On December 18, 2018, the trial court granted the defendants’ motions to dismiss and entered final judgment on January 18, 2019. On February 13, 2019, Commissioner Burns filed a notice of appeal. On July 12, 2019, Commissioner Burns filed his opening brief in the Arizona Court of Appeals and all answering briefs are due on August 21, 2019. APS and Pinnacle West cannot predict the outcome of this matter.

Information Requests from Arizona Corporation Commissioners

On January 14, 2019, ACC Commissioner Kennedy opened a docket to investigate campaign expenditures and political participation of APS and Pinnacle West. In addition, on February 27, 2019, ACC Commissioners Burns and Dunn opened a new docket and requested documents from APS and Pinnacle West related to ACC elections and charitable contributions related to the ACC. On March 1, 2019, ACC Commissioner Kennedy issued a subpoena to APS seeking several categories of information for both Pinnacle West and APS including political contributions, lobbying expenditures, marketing and advertising expenditures, and contributions made to 501(c)(3) and 501(c)(4) entities, for the years 2013-2018. Pinnacle West and APS voluntarily responded to both sets of requests on March 29, 2019. APS also received and responded to various follow-on requests from ACC Commissioners on these matters. Pinnacle West and APS cannot predict the outcome of these matters.

Renewable Energy Ballot Initiative
    
On February 20, 2018, a renewable energy advocacy organization filed with the Arizona Secretary of State a ballot initiative for an Arizona constitutional amendment requiring Arizona public service corporations to provide at least 50% of their annual retail sales of electricity from renewable sources by 2030. For purposes of the proposed amendment, eligible renewable sources would not include nuclear generating facilities. The initiative was placed on the November 2018 Arizona elections ballot. On November 6, 2018, the initiative failed to receive adequate voter support and was defeated.
    
Energy Modernization Plan

On January 30, 2018, former ACC Commissioner Tobin proposed the Energy Modernization Plan, which consisted of a series of energy policies tied to clean energy sources such as energy storage, biomass, energy efficiency, electric vehicles, and expanded energy planning through the integrated resource plans ("IRP") process. In August 2018, the ACC directed ACC Staff to open a new rulemaking docket which will address a wide range of energy issues, including the Energy Modernization Plan proposals. The rulemaking will consider possible modifications to existing ACC rules, such as the RES, Electric and Gas Energy Efficiency Standards, Net Metering, Resource Planning, and the Biennial Transmission Assessment, as well as the development of new rules regarding forest bioenergy, electric vehicles, interconnection of distributed generation, baseload security, blockchain technology and other technological developments, retail competition, and other energy-related topics. On April 25, 2019, the ACC Staff issued a set of draft rules in regards to the Energy Modernization Plan and workshops were held on April 29, 2019 regarding these draft rules. On July 2, 2019, the ACC Staff issued a revised set of draft rules, which propose a RES goal of 45% of retail energy served be renewable by 2035 and a goal of 20% of retail sales during peak demand to be from clean energy resources by 2035.  The draft rules also require a certain amount of the RES goal to be derived from Distributed Renewable Storage, for which utilities would be required to offer performance-based incentives.  Clean peak sales would include nuclear energy as a clean resource. The ACC held stakeholder meetings and workshops on ACC Staff’s draft energy rules on July 30 and July 31, 2019 and additional stakeholder workshops will be held in August 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. On February 25, 2019, APS filed a request to extend the deadline to file its Preliminary IRP from April 1, 2019 to August 1, 2019.  On April 24, 2019, the ACC approved this request. On August 1, 2019, APS filed its Preliminary IRP.

Public Utility Regulatory Policies Act

In August 2016, APS filed an application requesting that all of its contracts with qualifying facilities over 100 kW be set at a presumptive maximum 2 year term. A qualifying facility is an eligible energy-producing facility as defined by FERC regulations within a host electric utility’s service territory that has a right to sell to the host utility. Host utilities are required to purchase power from qualifying facilities at an avoided cost. A hearing is set to begin on August 27, 2019 regarding APS’s application. APS cannot predict the outcome of this matter.

Residential Electric Utility Customer Service Disconnections

On June 13, 2019, APS voluntarily suspended electric disconnections for residential customers who had not paid their bills.  On June 20, 2019, the ACC voted to enact emergency rule amendments to prevent residential electric utility customer service disconnections during the period from June 1 through October 15.  During the moratorium on disconnections, APS cannot charge late fees and interest on amounts that are past due from customers.  Customer deposits must also be used to pay delinquent amounts before disconnection can occur and customers will have four months to pay back their deposit and any remaining delinquent amounts.  The emergency rule changes will be effective for 180 days and may be renewed once.  During that time, the ACC will begin a formal regular rulemaking process to allow stakeholder input and time for consideration of permanent rules changes.  The ACC further ordered that each regulated electric utility serving retail customers in Arizona update its service conditions by incorporating the emergency rule amendments, restore power to any customers who were disconnected during the month of June 2019 and credit any fees that were charged for a reconnection. In July 2019, certain Arizona electric cooperatives filed a request for rehearing of the emergency rules for disconnections on several grounds, including that Attorney General certification is required for such rulemaking. APS currently estimates that the disconnection moratorium will result in an impact to its 2019 operating results of approximately $5 million to $10 million pre-tax depending on certain assumptions, including customer behaviors. APS is further assessing the impact to its financial statements beyond 2019, which will be affected by the results of final rulemaking related to disconnections.

Retail Electric Competition Rules

On November 17, 2018, the ACC voted to re-examine the facilitation of a deregulated retail electric market in Arizona. An ACC special open meeting workshop was held on December 3, 2018. No substantive action was taken, but interested parties were asked to submit written comments and respond to a list of questions from ACC Staff. On July 1 and July 2, 2019, ACC Staff issued a report and initial proposed draft rules regarding possible modifications to the ACC’s retail electric competition rules. Interested parties filed comments to the ACC Staff report and a stakeholder meeting and workshop to discuss the retail electric
competition rules was held on July 30, 2019. APS cannot predict whether these efforts will result in any changes and, if changes to the rules results, what impact these rules would have on APS.

Four Corners 

SCE-Related Matters. On December 30, 2013, APS purchased Southern California Edison Company's ("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 $44 million as of June 30, 2019 and is being amortized in rates over a total of 10 years.

 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. On June 14, 2019, the United States Court of Appeals for the Ninth Circuit issued an unpublished memorandum order denying APS’s petition for review of FERC’s orders that denied APS’s request to recover the regulatory asset through its FERC-jurisdictional rates and granting APS’s petition for review of FERC’s orders finding the agreement to be a jurisdictional contract. The United States Court of Appeals for the Ninth Circuit vacated FERC’s determination that the agreement was required to be filed with FERC and remanded the issue to FERC for additional proceedings. APS cannot predict the outcome of the remand 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 cannot predict the outcome or timing of the decision on this matter. APS may be required to record a charge to its results of operations if the ACC issues an unfavorable decision (see SCR deferral in the Regulatory Assets and Liabilities table below).
  
Cholla

On September 11, 2014, APS announced that it would close Unit 2 of the Cholla Power Plant ("Cholla") and cease burning coal at the other APS-owned units (Units 1 and 3) at the plant by the mid-2020s, if the United States Environmental Protection Agency ("EPA") 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 ($81 million as of June 30, 2019), in addition to a return on its investment. In accordance with GAAP, in the third quarter of 2014, Unit 2’s remaining net book value was reclassified from property, plant and equipment to a regulatory asset. The 2017 Settlement Agreement also shortened the depreciation lives of Cholla Units 1 and 3 to 2025.
On March 20, 2019, APS announced that it began evaluating the feasibility and cost of converting a unit at Cholla to burn biomass. Biomass is a fuel comprised of forest trimmings, and a converted unit at Cholla could assist in forest thinning, responsible forest management, an improved watershed, and a reduced wildfire risk. APS’s ability to operate a biomass power plant would depend on third-parties procuring forest biomass for fuel. APS reported the results of its evaluation on May 9, 2019 to the ACC. On July 10, 2019, the ACC voted to not require APS to file a request for proposal to convert the unit at Cholla to burn biomass.
Navajo Plant
The co-owners of the Navajo Generating Station (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.
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 ($83 million as of June 30, 2019) plus a return on the net book value as well as other costs related to retirement and closure, which are still being assessed and may be material. APS believes it will be allowed recovery of the net book value, in addition to a return on its investment. In accordance with GAAP, in the second quarter of 2017, APS's remaining net book value of its interest in the Navajo Plant was reclassified from property, plant and equipment to a regulatory asset. If the ACC does not allow full recovery of the remaining net book value of this interest, all or a portion of the regulatory asset will be written off and APS's net income, cash flows, and financial position will be negatively impacted.    
Regulatory Assets and Liabilities 
The detail of regulatory assets is as follows (dollars in thousands): 
 
Amortization Through
 
June 30, 2019
 
December 31, 2018
 
 
Current
 
Non-Current
 
Current
 
Non-Current
Pension
(a)
 
$
—

 
$
712,907

 
$
—

 
$
733,351

Retired power plant costs
2033
 
28,182

 
153,122

 
28,182

 
167,164

Income taxes — allowance for funds used during construction ("AFUDC") equity
2049
 
6,457

 
152,388

 
6,457

 
151,467

Deferred fuel and purchased power — mark-to-market (Note 7)
2023
 
55,729

 
21,516

 
31,728

 
23,768

Deferred fuel and purchased power (b) (c)
2020
 
30,559

 
—

 
37,164

 
—

Four Corners cost deferral
2024
 
8,077

 
36,190

 
8,077

 
40,228

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

 
25,170

 
1,079

 
25,522

Lost fixed cost recovery (b)
2020
 
25,746

 
—

 
32,435

 
—

Palo Verde VIEs (Note 6)
2046
 
—

 
20,325

 
—

 
20,015

Deferred compensation
2036
 
—

 
37,572

 
—

 
36,523

Deferred property taxes
2027
 
8,569

 
62,072

 
8,569

 
66,356

Loss on reacquired debt
2038
 
1,637

 
12,850

 
1,637

 
13,668

Tax expense of Medicare subsidy
2024
 
1,235

 
5,772

 
1,235

 
6,176

TCA balancing account (b)
2021
 
5,381

 
3,895

 
3,860

 
772

AG-1 deferral
2022
 
2,787

 
4,110

 
2,654

 
5,819

Mead-Phoenix transmission line CIAC
2050
 
332

 
9,878

 
332

 
10,044

Coal reclamation
2026
 
1,546

 
16,250

 
1,546

 
15,607

SCR deferral
N/A
 
—

 
37,919

 
—

 
23,276

Tax expense adjuster mechanism (b)
2019
 
3,149

 
—

 
—

 
—

Ocotillo deferral
N/A
 
—

 
9,495

 
—

 
—

Other
Various
 
3,994

 
—

 
1,947

 
3,185

Total regulatory assets (d)
 
 
$
184,459

 
$
1,321,431

 
$
166,902

 
$
1,342,941


(a)
This asset represents the future recovery of pension benefit obligations through retail rates.  If these costs are disallowed by the ACC, this regulatory asset would be charged to other comprehensive income ("OCI") and result in lower future revenues.
(b)
See "Cost Recovery Mechanisms" discussion above.
(c)
Subject to a carrying charge.
(d)
There are no regulatory assets for which the ACC has allowed recovery of costs, but not allowed a return by exclusion from rate base.  FERC rates are set using a formula rate as described in "Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters."


The detail of regulatory liabilities is as follows (dollars in thousands):
 
 
Amortization Through
 
June 30, 2019
 
December 31, 2018
 
 
Current
 
Non-Current
 
Current
 
Non-Current
Excess deferred income taxes - ACC - Tax Cuts and Jobs Act (a)
(b)
 
$
68,651

 
$
1,178,216

 
$
—

 
$
1,272,709

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

 
241,633

 
6,302

 
243,691

Asset retirement obligations
2057
 
—

 
359,912

 
—

 
278,585

Removal costs
(c)
 
50,701

 
153,847

 
39,866

 
177,533

Other postretirement benefits
(d)
 
37,821

 
105,214

 
37,864

 
125,903

Income taxes — deferred investment tax credit
2047
 
2,164

 
50,414

 
2,164

 
51,120

Income taxes — change in rates
2048
 
2,764

 
69,171

 
2,769

 
70,069

Spent nuclear fuel
2027
 
6,578

 
53,769

 
6,503

 
57,002

Renewable energy standard (b)
2021
 
40,639

 
4,950

 
44,966

 
20

Demand side management (b)
2021
 
7,191

 
24,146

 
14,604

 
4,123

Sundance maintenance
2030
 
1,641

 
15,495

 
1,278

 
17,228

Deferred gains on utility property
2022
 
3,423

 
5,372

 
4,423

 
6,581

Four Corners coal reclamation
2038
 
1,858

 
17,540

 
1,858

 
17,871

Tax expense adjustor mechanism (b)
2020
 
1,663

 
—

 
3,237

 
—

Other
Various
 
461

 
8,213

 
42

 
3,541

Total regulatory liabilities
 
 
$
231,857

 
$
2,287,892

 
$
165,876

 
$
2,325,976


(a)
For purposes of presentation on the Statement of Cash Flows, amortization of the regulatory liabilities for excess deferred income taxes are reflected as "Deferred income taxes" under Cash Flows From Operating Activities.
(b)
See “Cost Recovery Mechanisms” discussion above.
(c)
In accordance with regulatory accounting guidance, APS accrues removal costs for its regulated assets, even if there is no legal obligation for removal.
(d)
See Note 5.
v3.19.2
Retirement Plans and Other Postretirement Benefits
 6 Months Ended
Jun. 30, 2019
Retirement Benefits [Abstract]  
Retirement Plans and Other Postretirement Benefits
Retirement Plans and Other Postretirement Benefits
 
Pinnacle West sponsors a qualified defined benefit and account balance pension plan, a non-qualified supplemental excess benefit retirement plan, and an other postretirement benefit plan for the employees of Pinnacle West and our subsidiaries.  Pinnacle West uses a December 31 measurement date for its pension and other postretirement benefit plans.  The market-related value of our plan assets is their fair value at the measurement dates.

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

 
Pension Benefits
 
Other Benefits
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
2019
 
2018
 
2019
 
2018
 
2019
 
2018
 
2019
 
2018
Service cost — benefits earned during the period
$
12,408

 
$
14,121

 
$
24,951

 
$
28,334

 
$
4,470

 
$
5,445

 
$
9,184

 
$
10,550

Non-service costs (credits):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Interest cost on benefit obligation
34,069

 
31,338

 
68,421

 
62,345

 
7,421

 
6,973

 
14,947

 
14,074

Expected return on plan assets
(43,049
)
 
(45,759
)
 
(85,942
)
 
(91,426
)
 
(9,603
)
 
(10,520
)
 
(19,206
)
 
(21,041
)
  Amortization of:
 

 
 
 
 

 
 

 
 

 
 

 
 

 
 

  Prior service credit
—

 
—

 
—

 
—

 
(9,455
)
 
(9,461
)
 
(18,910
)
 
(18,921
)
  Net actuarial loss
10,053

 
8,259

 
21,292

 
16,041

 
—

 
—

 
—

 
—

Net periodic benefit
cost (credit)
$
13,481

 
$
7,959

 
$
28,722

 
$
15,294

 
$
(7,167
)
 
$
(7,563
)
 
$
(13,985
)
 
$
(15,338
)
Portion of cost (credit) charged to expense
$
7,000

 
$
2,769

 
$
15,244

 
$
5,011

 
$
(5,063
)
 
$
(5,119
)
 
$
(9,880
)
 
$
(10,724
)

 
Contributions
 
We have made voluntary contributions of $120 million to our pension plan year-to-date in 2019. The minimum required contributions for the pension plan are zero for the next three years. We expect to make voluntary contributions up to a total of $350 million during the 2019-2021 period. We do not expect to make any contributions over the next three years to our other postretirement benefit plans.
v3.19.2
Palo Verde Sale Leaseback Variable Interest Entities
 6 Months Ended
Jun. 30, 2019
Variable Interest Entities [Abstract]  
Palo Verde Sale Leaseback Variable Interest Entities
Palo Verde Sale Leaseback Variable Interest Entities
 
In 1986, APS entered into agreements with three separate VIE lessor trust entities in order to sell and lease back interests in Palo Verde Unit 2 and related common facilities. APS will retain the assets through 2023 under one lease and 2033 under the other two leases. APS will be required to make payments relating to these leases of approximately $23 million annually through 2023, and $16 million annually for the period 2024 through 2033. At the end of the lease period, APS will have the option to purchase the leased assets at their fair market value, extend the leases for up to two years, or return the assets to the lessors.

The leases' terms give APS the ability to utilize the assets for a significant portion of the assets’ economic life, and therefore provide APS with the power to direct activities of the VIEs that most significantly impact the VIEs’ economic performance.  Predominantly due to the lease terms, APS has been deemed the primary beneficiary of these VIEs and therefore consolidates the VIEs.
 
As a result of consolidation, we eliminate lease accounting and instead recognize depreciation expense, resulting in an increase in net income for the three and six months ended June 30, 2019 of $5 million and $10 million, respectively, and for the three and six months ended June 30, 2018 of $5 million and $10 million, respectively, entirely attributable to the noncontrolling interests. Income attributable to Pinnacle West shareholders is not impacted by the consolidation.

Our Condensed Consolidated Balance Sheets at June 30, 2019 and December 31, 2018 include the following amounts relating to the VIEs (dollars in thousands):
 
 
June 30, 2019
 
December 31, 2018
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation
$
103,841

 
$
105,775

Equity — Noncontrolling interests
124,165

 
125,790


 
Assets of the VIEs are restricted and may only be used for payment to the noncontrolling interest holders. These assets are reported on our condensed consolidated financial statements.
 
APS is exposed to losses relating to these VIEs upon the occurrence of certain events that APS does not consider to be reasonably likely to occur.  Under certain circumstances (for example, the Nuclear Regulatory Commission ("NRC") issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), APS would be required to make specified payments to the VIEs’ noncontrolling equity participants and take title to the leased Unit 2 interests, which, if appropriate, may be required to be written down in value.  If such an event were to occur during the lease periods, APS may be required to pay the noncontrolling equity participants approximately $299 million beginning in 2019, and up to $456 million over the lease extension terms.
 
For regulatory ratemaking purposes, the agreements continue to be treated as operating leases and, as a result, we have recorded a regulatory asset relating to the arrangements.
v3.19.2
Derivative Accounting
 6 Months Ended
Jun. 30, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]  
Derivative Accounting Derivative Accounting
 
Derivative financial instruments are used to manage exposure to commodity price and transportation costs of electricity, natural gas, emissions allowances, and in interest rates.  Risks associated with market volatility are managed by utilizing various physical and financial derivative instruments, including futures, forwards, options and swaps.  As part of our overall risk management program, we may use derivative instruments to hedge purchases and sales of electricity and fuels.  Derivative instruments that meet certain hedge accounting criteria may be designated as cash flow hedges and are used to limit our exposure to cash flow variability on forecasted transactions.  The changes in market value of such instruments have a high correlation to price changes in the hedged transactions.  Derivative instruments are also entered into for economic hedging purposes.  While economic hedges may mitigate exposure to fluctuations in commodity prices, these instruments have not been designated as accounting hedges.  Contracts that have the same terms (quantities, delivery points and delivery periods) and for which power does not flow are netted, which reduces both revenues and fuel and purchased power costs in our Condensed Consolidated Statements of Income, but does not impact our financial condition, net income or cash flows.
 
Our derivative instruments, excluding those qualifying for a scope exception, are recorded on the balance sheets as an asset or liability and are measured at fair value.  See Note 11 for a discussion of fair value measurements.  Derivative instruments may qualify for the normal purchases and normal sales scope exception if they require physical delivery and the quantities represent those transacted in the normal course of business.  Derivative instruments qualifying for the normal purchases and sales scope exception are accounted for under the accrual method of accounting and excluded from our derivative instrument discussion and disclosures below.
 
For its regulated operations, APS defers for future rate treatment 100% of the unrealized gains and losses on derivatives pursuant to the PSA mechanism that would otherwise be recognized in income.  Realized gains and losses on derivatives are deferred in accordance with the PSA to the extent the amounts are above or below the Base Fuel Rate (see Note 4).  Gains and losses from derivatives in the following tables represent the amounts reflected in income before the effect of PSA deferrals.
 
As of June 30, 2019 and December 31, 2018, we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position): 
 
 
 
Quantity
Commodity
 
Unit of Measure
June 30, 2019
 
December 31, 2018
Power
 
GWh
1,000

 
250

Gas
 
Billion cubic feet
218

 
218


 
Gains and Losses from Derivative Instruments
 
The following table provides information about gains and losses from derivative instruments in designated cash flow accounting hedging relationships during the three and six months ended June 30, 2019 and 2018 (dollars in thousands):
 
 
 
Financial Statement Location
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
Commodity Contracts
 
 
2019
 
2018
 
2019
 
2018
Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a)
 
Fuel and purchased power (b)
 
$
(538
)
 
$
(606
)
 
$
(974
)
 
$
(1,097
)

(a)
During the three and six months ended June 30, 2019 and 2018, we had no gains or losses reclassified from accumulated OCI to earnings related to discontinued cash flow hedges.
(b)
Amounts are before the effect of PSA deferrals.
 
During the next twelve months, we estimate that a net loss of approximately $1 million before income taxes will be reclassified from accumulated OCI as an offset to the effect of market price changes for the related hedged transactions.  In accordance with the PSA, most of these amounts will be recorded as either a regulatory asset or liability and have no immediate effect on earnings.

The following table provides information about gains and losses from derivative instruments not designated as accounting hedging instruments during the three and six months ended June 30, 2019 and 2018 (dollars in thousands):
 
 
 
Financial Statement Location
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
Commodity Contracts
 
 
2019
 
2018
 
2019
 
2018
Net Loss Recognized in Income
 
Operating revenues
 
$
—

 
$
(341
)
 
$
—

 
$
(1,560
)
Net Gain (Loss) Recognized in Income
 
Fuel and purchased power (a)
 
(49,686
)
 
3,384

 
(41,516
)
 
(30,705
)
Total
 
 
 
$
(49,686
)
 
$
3,043

 
$
(41,516
)
 
$
(32,265
)

(a)
Amounts are before the effect of PSA deferrals.
 
Derivative Instruments in the Condensed Consolidated Balance Sheets
 
Our derivative transactions are typically executed under standardized or customized agreements, which include collateral requirements and, in the event of a default, would allow for the netting of positive and negative exposures associated with a single counterparty.  Agreements that allow for the offsetting of positive and negative exposures associated with a single counterparty are considered master netting arrangements.  Transactions with counterparties that have master netting arrangements are offset and reported net on the Condensed Consolidated Balance Sheets.  Transactions that do not allow for offsetting of positive and negative positions are reported gross on the Condensed Consolidated Balance Sheets.
 
We do not offset a counterparty’s current derivative contracts with the counterparty’s non-current derivative contracts, although our master netting arrangements would allow current and non-current positions to be offset in the event of a default.  Additionally, in the event of a default, our master netting arrangements would allow for the offsetting of all transactions executed under the master netting arrangement.  These types of transactions may include non-derivative instruments, derivatives qualifying for scope exceptions, trade receivables and trade payables arising from settled positions, and other forms of non-cash collateral (such as letters of credit).  These types of transactions are excluded from the offsetting tables presented below.
 
The following tables provide information about the fair value of our risk management activities reported on a gross basis, and the impacts of offsetting as of June 30, 2019 and December 31, 2018.  These amounts relate to commodity contracts and are located in the assets and liabilities from risk management activities lines of our Condensed Consolidated Balance Sheets.

As of June 30, 2019:
(dollars in thousands)
 
Gross
 Recognized
 Derivatives
 (a)
 
Amounts
Offset
 (b)
 
Net
 Recognized
 Derivatives
 
Other
 (c)
 
Amount Reported on Balance Sheets
Current assets
 
$
3,558

 
$
(2,939
)
 
$
619

 
$
(160
)
 
$
459

Investments and other assets
 
76

 
—

 
76

 
—

 
76

Total assets
 
3,634

 
(2,939
)
 
695

 
(160
)
 
535

 
 
 
 
 
 
 
 
 
 
 
Current liabilities
 
(60,588
)
 
2,939

 
(57,649
)
 
(1,185
)
 
(58,834
)
Deferred credits and other
 
(21,592
)
 
—

 
(21,592
)
 
—

 
(21,592
)
Total liabilities
 
(82,180
)
 
2,939

 
(79,241
)
 
(1,185
)
 
(80,426
)
Total
 
$
(78,546
)
 
$
—

 
$
(78,546
)
 
$
(1,345
)
 
$
(79,891
)

(a)
All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)
No cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting.
(c)
Represents cash collateral and cash margin that is not subject to offsetting. Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument. Includes cash collateral received from counterparties of $1,185 and cash margin provided to counterparties of ($160).

As of December 31, 2018:
(dollars in thousands)
 
Gross
Recognized
Derivatives
 (a)
 
Amounts
Offset
(b)
 
Net
 Recognized
 Derivatives
 
Other
 (c)
 
Amount
Reported on
Balance Sheets
Current assets
 
$
3,106

 
$
(2,149
)
 
$
957

 
$
156

 
$
1,113

Investments and other assets
 
36

 
(36
)
 
—

 
—

 
—

Total assets
 
3,142

 
(2,185
)
 
957

 
156

 
1,113

 
 
 
 
 
 
 
 
 
 
 
Current liabilities
 
(36,345
)
 
2,149

 
(34,196
)
 
(1,310
)
 
(35,506
)
Deferred credits and other
 
(24,567
)
 
36

 
(24,531
)
 
—

 
(24,531
)
Total liabilities
 
(60,912
)
 
2,185

 
(58,727
)
 
(1,310
)
 
(60,037
)
Total
 
$
(57,770
)
 
$
—

 
$
(57,770
)
 
$
(1,154
)
 
$
(58,924
)

(a)
All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)
No cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting.
(c)
Represents cash collateral and cash margin that is not subject to offsetting. Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument.  Includes cash collateral received from counterparties of $1,310 and cash margin provided to counterparties of $156.

Credit Risk and Credit Related Contingent Features
 
We are exposed to losses in the event of nonperformance or nonpayment by counterparties and have risk management contracts with many counterparties. As of June 30, 2019, Pinnacle West has no counterparties with positive exposures of greater than 10% of risk management assets. Our risk management process assesses and monitors the financial exposure of all counterparties.  Despite the fact that the great majority of our trading counterparties' debt is rated as investment grade by the credit rating agencies, there is still a possibility that one or more of these counterparties could default, resulting in a material impact on consolidated earnings for a given period. Counterparties in the portfolio consist principally of financial institutions, major energy companies, municipalities and local distribution companies.  We maintain credit policies that we believe minimize overall credit risk to within acceptable limits.  Determination of the credit quality of our counterparties is based upon a number of factors, including credit ratings and our evaluation of their financial condition.  To manage credit risk, we employ collateral requirements and standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty.  Valuation adjustments are established representing our estimated credit losses on our overall exposure to counterparties.
 
Certain of our derivative instrument contracts contain credit-risk-related contingent features including, among other things, investment grade credit rating provisions, credit-related cross-default provisions, and adequate assurance provisions.  Adequate assurance provisions allow a counterparty with reasonable grounds for uncertainty to demand additional collateral based on subjective events and/or conditions.  For those derivative instruments in a net liability position, with investment grade credit contingencies, the counterparties could demand additional collateral if our debt credit rating were to fall below investment grade (below BBB- for Standard & Poor’s or Fitch or Baa3 for Moody’s).
 
The following table provides information about our derivative instruments that have credit-risk-related contingent features at June 30, 2019 (dollars in thousands):
 
June 30, 2019
Aggregate fair value of derivative instruments in a net liability position
$
82,064

Cash collateral posted
—

Additional cash collateral in the event credit-risk-related contingent features were fully triggered (a)
80,804


(a)
This amount is after counterparty netting and includes those contracts which qualify for scope exceptions, which are excluded from the derivative details above.
 
We also have energy-related non-derivative instrument contracts with investment grade credit-related contingent features, which could also require us to post additional collateral of approximately $95 million if our debt credit ratings were to fall below investment grade.
v3.19.2
Commitments and Contingencies
 6 Months Ended
Jun. 30, 2019
Commitments and Contingencies Disclosure [Abstract]  
Commitments and Contingencies
Commitments and Contingencies
 
Palo Verde Generating Station
 
Spent Nuclear Fuel and Waste Disposal
 
On December 19, 2012, APS, acting on behalf of itself and the participant owners of Palo Verde, filed a second breach of contract lawsuit against the United States Department of Energy ("DOE") in the United States Court of Federal Claims ("Court of Federal Claims").  The lawsuit sought to recover damages incurred due to DOE’s breach of the Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste ("Standard Contract") for failing to accept Palo Verde's spent nuclear fuel and high level waste from January 1, 2007 through June 30, 2011, as it was required to do pursuant to the terms of the Standard Contract and the Nuclear Waste Policy Act.  On August 18, 2014, APS and DOE entered into a settlement agreement, stipulating to a dismissal of the lawsuit and payment of $57.4 million by DOE to the Palo Verde owners for certain specified costs incurred by Palo Verde during the period January 1, 2007 through June 30, 2011. APS’s share of this amount is $16.7 million. Amounts recovered in the lawsuit and settlement were recorded as adjustments to a regulatory liability and had no impact on the amount of reported net income. In addition, the settlement agreement, as amended, provides APS with a method for submitting claims and getting recovery for costs incurred through December 31, 2019.

APS has submitted four claims pursuant to the terms of the August 18, 2014 settlement agreement, for four separate time periods during July 1, 2011 through June 30, 2018. The DOE has approved and paid $74.2 million for these claims (APS’s share is $21.6 million). The amounts recovered were primarily recorded as adjustments to a regulatory liability and had no impact on reported net income. In accordance with the 2017 Rate Case Decision, this regulatory liability is being refunded to customers (see Note 4). APS submitted its most recent claim pursuant to the terms of the August 18, 2014 settlement agreement to the DOE on October 31, 2018 in the amount of $10.2 million (APS's share is $3.0 million). On February 11, 2019 and April 10, 2019 (in response to APS's request for reconsideration), the DOE approved in total a payment of $10.2 million (APS’s share is $3.0 million). On June 7, 2019, APS received this payment.

Nuclear Insurance

Public liability for incidents at nuclear power plants is governed by the Price-Anderson Nuclear Industries Indemnity Act ("Price-Anderson Act"), which limits the liability of nuclear reactor owners to the amount of insurance available from both commercial sources and an industry-wide retrospective payment plan.  In accordance with the Price-Anderson Act, the Palo Verde participants are insured against public liability for a nuclear incident of up to approximately $13.9 billion per occurrence. Palo Verde maintains the maximum available nuclear liability insurance in the amount of $450 million, which is provided by American Nuclear Insurers ("ANI").  The remaining balance of approximately $13.5 billion of liability coverage is provided through a mandatory industry-wide retrospective premium program.  If losses at any nuclear power plant covered by the program exceed the accumulated funds, APS could be responsible for retrospective premiums.  The maximum retrospective premium per reactor under the program for each nuclear liability incident is approximately $137.6 million, subject to a maximum annual premium of approximately $20.5 million per incident.  Based on APS’s ownership interest in the three Palo Verde units, APS’s maximum retrospective premium per incident for all three units is approximately $120.1 million, with a maximum annual retrospective premium of approximately $17.9 million.    
    
The Palo Verde participants maintain insurance for property damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.8 billion.  APS has also secured accidental outage
insurance for a sudden and unforeseen accidental outage of any of the three units.  The property damage, decontamination, and accidental outage insurance are provided by Nuclear Electric Insurance Limited ("NEIL").  APS is subject to retrospective premium adjustments under all NEIL policies if NEIL’s losses in any policy year exceed accumulated funds. The maximum amount APS could incur under the current NEIL policies totals approximately $25.5 million for each retrospective premium assessment declared by NEIL’s Board of Directors due to losses.  In addition, NEIL policies contain rating triggers that would result in APS providing approximately $73.4 million of collateral assurance within 20 business days of a rating downgrade to non-investment grade.  The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions, sublimits and exclusions.

Contractual Obligations

As of June 30, 2019, our fuel and purchased power commitments have increased approximately $100 million from the information provided in our 2018 Form 10-K. This change primarily relates to new purchased power commitments. The majority of the changes relate to 2024 and thereafter.

Other than the item described above, there have been no material changes, as of June 30, 2019, outside the normal course of business in contractual obligations from the information provided in our 2018 Form 10-K. See Note 3 for discussion regarding changes in our long-term debt obligations.

Superfund-Related Matters
 
The Comprehensive Environmental Response Compensation and Liability Act ("Superfund" or "CERCLA") establishes liability for the cleanup of hazardous substances found contaminating the soil, water or air.  Those who released, generated, transported to or disposed of hazardous substances at a contaminated site are among the parties who are potentially responsible ("PRPs").  PRPs may be strictly, and often are jointly and severally, liable for clean-up.  On September 3, 2003, EPA advised APS that EPA considers APS to be a PRP in the Motorola 52nd Street Superfund Site, Operable Unit 3 ("OU3") in Phoenix, Arizona.  APS has facilities that are within this Superfund site.  APS and Pinnacle West have agreed with EPA to perform certain investigative activities of the APS facilities within OU3.  In addition, on September 23, 2009, APS agreed with EPA and one other PRP to voluntarily assist with the funding and management of the site-wide groundwater remedial investigation and feasibility study ("RI/FS").  Based upon discussions between the OU3 working group parties and EPA, along with the results of recent technical analyses prepared by the OU3 working group to supplement the RI/FS for OU3, APS anticipates finalizing the RI/FS in the fall or winter of 2019. We estimate that our costs related to this investigation and study will be approximately $2 million.  We anticipate incurring additional expenditures in the future, but because the overall investigation is not complete and ultimate remediation requirements are not yet finalized, at the present time expenditures related to this matter cannot be reasonably estimated.
 
On August 6, 2013, Roosevelt Irrigation District ("RID") filed a lawsuit in Arizona District Court against APS and 24 other defendants, alleging that RID’s groundwater wells were contaminated by the release of hazardous substances from facilities owned or operated by the defendants.  The lawsuit also alleges that, under Superfund laws, the defendants are jointly and severally liable to RID.  The allegations against APS arise out of APS’s current and former ownership of facilities in and around OU3.  As part of a state governmental investigation into groundwater contamination in this area, on January 25, 2015, the Arizona Department of Environmental Quality ("ADEQ") sent a letter to APS seeking information concerning the degree to which, if any, APS’s current and former ownership of these facilities may have contributed to groundwater contamination in this area.  APS responded to ADEQ on May 4, 2015. On December 16, 2016, two RID environmental and engineering contractors filed an ancillary lawsuit for recovery of costs against APS and the
other defendants in the RID litigation. That same day, another RID service provider filed an additional ancillary CERCLA lawsuit against certain of the defendants in the main RID litigation, but excluded APS and certain other parties as named defendants. Because the ancillary lawsuits concern past costs allegedly incurred by these RID vendors, which were ruled unrecoverable directly by RID in November of 2016, the additional lawsuits do not increase APS's exposure or risk related to these matters.

On April 5, 2018, RID and the defendants in that particular litigation executed a settlement agreement, fully resolving RID's CERCLA claims concerning both past and future cost recovery. APS's share of this settlement was immaterial. In addition, the two environmental and engineering vendors voluntarily dismissed their lawsuit against APS and the other named defendants without prejudice. An order to this effect was entered on April 17, 2018. With this disposition of the case, the vendors may file their lawsuit again in the future. In addition, APS and certain other parties not named in the remaining RID service provider lawsuit may be brought into the litigation via third-party complaints filed by the current direct defendants. We are unable to predict the outcome of these matters; however, we do not expect the outcome to have a material impact on our financial position, results of operations or cash flows.
  
Environmental Matters

APS is subject to numerous environmental laws and regulations affecting many aspects of its present and future operations, including air emissions of both conventional pollutants and greenhouse gases, water quality, wastewater discharges, solid waste, hazardous waste, and coal combustion residuals ("CCRs").  These laws and regulations can change from time to time, imposing new obligations on APS resulting in increased capital, operating, and other costs.  Associated capital expenditures or operating costs could be material.  APS intends to seek recovery of any such environmental compliance costs through our rates, but cannot predict whether it will obtain such recovery.  The following proposed and final rules involve material compliance costs to APS.
 
Regional Haze Rules.  APS has received the final rulemaking imposing new pollution control requirements on Four Corners and the Navajo Plant. EPA will require these plants to install pollution control equipment that constitutes best available retrofit technology ("BART") to lessen the impacts of emissions on visibility surrounding the plants. In addition, EPA issued a final rule for Regional Haze compliance at Cholla that does not involve the installation of new pollution controls and that will replace an earlier BART determination for this facility. See below for details of the Cholla BART approval.

Four Corners. Based on EPA’s final standards, APS's 63% share of the cost of required controls for Four Corners Units 4 and 5 is approximately $400 million, the majority of which has already been incurred.  In addition, APS and El Paso Electric Company ("El Paso") entered into an asset purchase agreement providing for the purchase by APS, or an affiliate of APS, of El Paso's 7% interest in Four Corners Units 4 and 5. 4CA purchased the El Paso interest on July 6, 2016. Navajo Transitional Energy Company, LLC ("NTEC") purchased the interest from 4CA on July 3, 2018. See "Four Corners - 4CA Matter" below for a discussion of the NTEC purchase. The cost of the pollution controls related to the 7% interest is approximately $45 million, which was assumed by NTEC through its purchase of the 7% interest.

Navajo Plant. APS estimates that its share of costs for upgrades at the Navajo Plant, based on EPA’s Federal Implementation Plan ("FIP"), could be up to approximately $200 million; however, given the future plans for the Navajo Plant, we do not expect to incur these costs.  See "Navajo Plant" in Note 4 for information regarding future plans for the Navajo Plant and details related to the resulting regulatory asset.

Cholla. APS believed that EPA’s original 2012 final rule establishing controls constituting BART for Cholla, which would require installation of SCR controls, was unsupported and that EPA had no basis for disapproving Arizona’s State Implementation Plan ("SIP") and promulgating a FIP that was inconsistent with the state’s considered BART determinations under the regional haze program.  In September 2014, APS met with EPA to propose a compromise BART strategy, whereby APS would permanently close Cholla Unit 2 and cease burning coal at Units 1 and 3 by the mid-2020s. (See "Cholla" in Note 4 for information regarding future plans for the Cholla plant and details related to the resulting regulatory asset.) APS made the proposal with the understanding that additional emission control equipment is unlikely to be required in the future because retiring and/or converting the units as contemplated in the proposal is more cost effective than, and will result in increased visibility improvement over, the BART requirements for oxides of nitrogen ("NOx") imposed through EPA's BART FIP. In early 2017, EPA approved a final rule incorporating APS's compromise proposal, which took effect for Cholla on April 26, 2017.
 
Coal Combustion Waste. On December 19, 2014, EPA issued its final regulations governing the handling and disposal of CCR, such as fly ash and bottom ash. The rule regulates CCR as a non-hazardous waste under Subtitle D of the Resource Conservation and Recovery Act ("RCRA") and establishes national minimum criteria for existing and new CCR landfills and surface impoundments and all lateral expansions consisting of location restrictions, design and operating criteria, groundwater monitoring and corrective action, closure requirements and post closure care, and recordkeeping, notification, and internet posting requirements. The rule generally requires any existing unlined CCR surface impoundment that is contaminating groundwater above a regulated constituent’s groundwater protection standard to stop receiving CCR and either retrofit or close, and further requires the closure of any CCR landfill or surface impoundment that cannot meet the applicable performance criteria for location restrictions or structural integrity. Such closure requirements are deemed "forced closure" or "closure for cause" of unlined surface impoundments, and are the subject of recent regulatory and judicial activities described below.
On December 16, 2016, President Obama signed the Water Infrastructure Improvements for the Nation ("WIIN") Act into law, which contains a number of provisions requiring EPA to modify the self-implementing provisions of the Agency's current CCR rules under Subtitle D. Such modifications include new EPA authority to directly enforce the CCR rules through the use of administrative orders and providing states, like Arizona, where the Cholla facility is located, the option of developing CCR disposal unit permitting programs, subject to EPA approval. For facilities in states that do not develop state-specific permitting programs, EPA is required to develop a federal permit program, pending the availability of congressional appropriations. By contrast, for facilities located within the boundaries of Native American tribal reservations, such as the Navajo Nation, where the Navajo Plant and Four Corners facilities are located, EPA is required to develop a federal permit program regardless of appropriated funds.

ADEQ has initiated a process to evaluate how to develop a state CCR permitting program that would cover electric generating units ("EGUs"), including Cholla. While APS has been working with ADEQ on the development of this program, we are unable to predict when Arizona will be able to finalize and secure EPA approval for a state-specific CCR permitting program. With respect to the Navajo Nation, APS has sought clarification as to when and how EPA would be initiating permit proceedings for facilities on the reservation, including Four Corners. We are unable to predict at this time when EPA will be issuing CCR management permits for the facilities on the Navajo Nation. At this time, it remains unclear how the CCR provisions of the WIIN Act will affect APS and its management of CCR.

Based upon utility industry petitions for EPA to reconsider the RCRA Subtitle D regulations for CCR, which were premised in part on the CCR provisions of the 2016 WIIN Act, on September 13, 2017 EPA agreed to evaluate whether to revise these federal CCR regulations. On July 17, 2018, EPA finalized a revision to its
RCRA Subtitle D regulations for CCR, the "Phase I, Part I" revision to its CCR regulations, deferring for future action a number of other proposed changes contemplated in a March 1, 2018 proposal. For the final rule issued on July 17, 2018, EPA established nationwide health-based standards for certain constituents of CCR subject to groundwater corrective action and delayed the closure deadlines for certain unlined CCR surface impoundments by 18 months (for example, those disposal units required to undergo forced closure). These changes to the federal regulations governing CCR disposal are unlikely to have a material impact on APS. As for those aspects of the March 2018 rulemaking proposal for which EPA has yet to take final action, it remains unclear which specific provisions of the federal CCR rules will ultimately be modified, how they will be modified, or when such modification will occur.

Pursuant to a June 24, 2016 order by the D.C. Circuit Court of Appeals in the litigation by industry- and environmental-groups challenging EPA’s CCR regulations, EPA is required to complete a rulemaking proceeding in the near future concerning whether or not boron must be included on the list of groundwater constituents that might trigger corrective action under EPA’s CCR rules.  Simultaneously with the issuance of EPA's proposed modifications to the federal CCR rules in response to industry petitions, on March 1, 2018, EPA issued a proposed rule seeking comment as to whether or not boron should be included on this list. EPA is not required to take final action approving the inclusion of boron.  Should EPA take final action adding boron to the list of groundwater constituents that might trigger corrective action, any resulting corrective action measures may increase APS's costs of compliance with the CCR rule at our coal-fired generating facilities.  At this time APS cannot predict the eventual results of this rulemaking proceeding concerning boron.

On August 21, 2018, the D.C. Circuit Court issued its decision on the merits in this litigation. The Court upheld the legality of EPA’s CCR regulations, though it vacated and remanded back to EPA a number of specific provisions, which are to be corrected in accordance with the Court’s order. Among the issues affecting APS’s management of CCR, the D.C. Circuit’s decision vacated and remanded those provisions of the EPA CCR regulations that allow for the operation of unlined CCR surface impoundments, even where those unlined impoundments have not otherwise violated a regulatory location restriction or groundwater protection standard (i.e., otherwise triggering forced closure). At this time, it remains unclear how this D.C. Circuit Court decision will affect APS’s operations or any financial impacts, as EPA has yet to take regulatory action on remand to revise its 2015 CCR regulations consistent with the Court’s order.

Based on this decision, on December 17, 2018, certain environmental groups filed an emergency motion with the D.C. Circuit to either stay or summarily vacate EPA's July 17, 2018 final rule extending the closure-initiation deadline for certain unlined CCR surface impoundments until October 2020. In response, EPA filed a motion to remand but not vacate that deadline extension regulation. On March 13, 2019, the Court issued its ruling on the pending motions concerning the October 2020 deadline for closure initiation and granted remand without vacatur. This ruling allows the current October 2020 deadline to remain in effect while EPA completes a rulemaking to revise or reaffirm this deadline in accordance with the August 2018 D.C. Circuit decision concerning the closure of unlined CCR surface impoundments. We cannot predict the outcome of EPA’s remand rulemaking concerning the October 2020 deadline for closure initiation.
    
APS currently disposes of CCR in ash ponds and dry storage areas at Cholla and Four Corners. APS estimates that its share of incremental costs to comply with the CCR rule for Four Corners is approximately $22 million and its share of incremental costs to comply with the CCR rule for Cholla is approximately $15 million. The Navajo Plant currently disposes of CCR in a dry landfill storage area. To comply with the CCR rule for the Navajo Plant, APS's share of incremental costs is approximately $1 million, which has been incurred. Additionally, the CCR rule requires ongoing, phased groundwater monitoring. By October 17, 2017, electric utility companies that own or operate CCR disposal units, such as APS, must have collected sufficient groundwater sampling data to initiate a detection monitoring program.  To the extent that certain threshold constituents are identified through this initial detection monitoring at levels above the CCR rule’s standards, the rule required the initiation of an assessment monitoring program by April 15, 2018. 

APS has completed the statistical analyses for its CCR disposal units that triggered assessment monitoring. APS determined that several of its CCR disposal units at Cholla and Four Corners will need to undergo corrective action. In addition, all such disposal units must cease operating and initiate closure by October of 2020. APS currently estimates that the additional incremental costs to complete this corrective action and closure work, along with the costs to develop replacement CCR disposal capacity, could be approximately $5 million for both Cholla and Four Corners. APS initiated an assessment of corrective measures on January 14, 2019, and anticipates completing this assessment during the summer of 2019. During this assessment, APS will gather additional groundwater data, solicit input from the public, host public hearings, and select remedies. As such, this $5 million cost estimate may change based upon APS’s performance of the CCR rule’s corrective action assessment process. Given uncertainties that may exist until we have fully completed the corrective action assessment process, we cannot predict any ultimate impacts to the Company; however, at this time we do not believe any potential change to the cost estimate would have a material impact on our financial position, results of operations or cash flows.

Clean Power Plan/Affordable Clean Energy Regulations. On June 19, 2019, EPA took final action on its proposals to repeal EPA's 2015 Clean Power Plan (“CPP”) and replace those regulations with a new rule, the Affordable Clean Energy (“ACE”) regulations. EPA originally finalized the CPP on August 3, 2015, and those regulations had been stayed pending judicial review.

The ACE are based upon measures that can be implemented to improve the heat rate of steam-electric power plants, specifically coal-fired EGUs. In contrast with the CPP, EPA's ACE regulations would not involve utility-level generation dispatch shifting away from coal-fired generation and toward renewable energy resources and natural gas-fired combined cycle power plants. EPA’s ACE regulations provide states and EPA regions (e.g., the Navajo Nation) with three years to develop plans establishing source-specific standards of performance based upon application of the ACE rule’s heat-rate improvement emission guidelines. While corresponding New Source Review (“NSR”) reform regulations were proposed as part of EPA’s initial ACE proposal, the finalized ACE regulations did not include such reform measures. EPA announced that it will be taking final action on EPA's NSR reform proposal for EGUs in the near future.

We cannot at this time predict the outcome of EPA's regulatory actions repealing and replacing the CPP. This action will likely be subject to judicial review and the outcome of those proceedings cannot be predicted. In addition, to the extent that the ACE regulations go into effect as finalized, it is not clear how the state of Arizona or EPA Region IX (i.e., as to the Navajo Nation) will implement these regulations as applied to the Cholla and Four Corners facilities, respectively.

Other environmental rules that could involve material compliance costs include those related to effluent limitations, the ozone national ambient air quality standard and other rules or matters involving the
Clean Air Act, Clean Water Act, Endangered Species Act, RCRA, Superfund, the Navajo Nation, and water supplies for our power plants.  The financial impact of complying with current and future environmental rules could jeopardize the economic viability of our coal plants or the willingness or ability of power plant participants to fund any required equipment upgrades or continue their participation in these plants.  The economics of continuing to own certain resources, particularly our coal plants, may deteriorate, warranting early retirement of those plants, which may result in asset impairments.  APS would seek recovery in rates for the book value of any remaining investments in the plants as well as other costs related to early retirement, but cannot predict whether it would obtain such recovery.
  
Federal Agency Environmental Lawsuit Related to Four Corners

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

On September 15, 2016, NTEC, the company that owns the adjacent mine, filed a motion to intervene for the purpose of dismissing the lawsuit based on NTEC's tribal sovereign immunity. On September 11, 2017, the Arizona District Court issued an order granting NTEC's motion, dismissing the litigation with prejudice, and terminating the proceedings. On November 9, 2017, the environmental group plaintiffs appealed the district court order dismissing their lawsuit. On July 29, 2019, the Ninth Circuit Court of Appeals affirmed the September 2017 dismissal of the lawsuit. We cannot predict the outcome of any further proceedings.

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

On July 16, 2018, several environmental groups filed a petition for review before the EPA Environmental Appeals Board ("EAB") concerning the NPDES wastewater discharge permit for Four Corners, which was reissued on June 12, 2018.  The environmental groups allege that the permit was reissued in contravention of several requirements under the Clean Water Act and did not contain required provisions concerning EPA’s 2015 revised effluent limitation guidelines for steam-electric EGUs, 2014 existing-source regulations governing cooling-water intake structures, and effluent limits for surface seepage and subsurface discharges from coal-ash disposal facilities.  To address certain of these issues through a reconsidered permit, EPA took action on December 19, 2018 to withdraw the NPDES permit reissued in June 2018. Withdrawal of the permit moots the EAB appeal, and EPA filed a motion to dismiss on that basis. The EAB thereafter dismissed the environmental group appeal on February 12, 2019. On April 30, 2019, EPA issued a proposed NPDES permit for Four Corners and took comment on this proposal through July 1, 2019. As part of this proposal, EPA is contemplating a December 31, 2023 compliance deadline governing Four Corners for the recently updated effluent guidelines for bottom-ash transport water. EPA currently projects that it will take final action on this permit proposal by September 30, 2019. At this time we cannot predict the outcome of EPA's reconsideration of the NPDES permit and whether reconsideration will have a material impact on our financial position, results of operations or cash flows.
    
Four Corners - 4CA Matter

On July 6, 2016, 4CA purchased El Paso’s 7% interest in Four Corners. NTEC had the option to purchase the 7% interest and ultimately purchased the interest on July 3, 2018. NTEC purchased the 7% interest at 4CA’s book value, approximately $70 million, and is paying 4CA the purchase price over a period of four years pursuant to a secured interest-bearing promissory note. In connection with the sale, Pinnacle West guaranteed certain obligations that NTEC will have to the other owners of Four Corners, such as NTEC's 7% share of capital expenditures and operating and maintenance expenses. Pinnacle West's guarantee is secured by a portion of APS's payments to be owed to NTEC under the 2016 Coal Supply Agreement.
The 2016 Coal Supply Agreement contained alternate pricing terms for the 7% interest in the event NTEC did not purchase the interest. Until the time that NTEC purchased the 7% interest, the alternate pricing provisions were applicable to 4CA as the holder of the 7% interest. These terms included a formula under which NTEC must make certain payments to 4CA for reimbursement of operations and maintenance costs and a specified rate of return, offset by revenue generated by 4CA’s power sales. Such payments are due to 4CA at the end of each calendar year. A $10 million payment was due to 4CA at December 31, 2017, which NTEC satisfied by directing to 4CA a prepayment from APS of a portion of a future mine reclamation obligation. The balance of the amount under this formula due December 31, 2018 for calendar year 2017 was approximately $20 million, which was paid to 4CA on December 14, 2018. The balance of the amount under this formula for calendar year 2018 (up to the date that NTEC purchased the 7% interest) is approximately $10 million, which is due to 4CA at December 31, 2019.
Financial Assurances

In the normal course of business, we obtain standby letters of credit and surety bonds from financial institutions and other third parties. These instruments guarantee our own future performance and provide third parties with financial and performance assurance in the event we do not perform. These instruments support commodity contract collateral obligations and other transactions. As of June 30, 2019, standby letters of credit totaled $1.7 million and will expire in 2020. As of June 30, 2019, surety bonds expiring through 2020 totaled $17 million. The underlying liabilities insured by these instruments are reflected on our balance sheets, where applicable. Therefore, no additional liability is reflected for the letters of credit and surety bonds themselves.
 
We enter into agreements that include indemnification provisions relating to liabilities arising from or related to certain of our agreements.  Most significantly, APS has agreed to indemnify the equity participants and other parties in the Palo Verde sale leaseback transactions with respect to certain tax matters.  Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnification provisions cannot be reasonably estimated.  Based on historical experience and evaluation of the specific indemnities, we do not believe that any material loss related to such indemnification provisions is likely.
 
Pinnacle West has issued parental guarantees and has provided indemnification under certain surety bonds for APS which were not material at June 30, 2019. In connection with the sale of 4CA's 7% interest to NTEC, Pinnacle West is guaranteeing certain obligations that NTEC will have to the other owners of Four Corners. (See "Four Corners - 4CA Matter" above for information related to this guarantee.) A maximum obligation is not explicitly stated in the guarantee and, therefore, the overall maximum amount of the obligation under such guarantee cannot be reasonably estimated; however, we consider the fair value of this guarantee to be immaterial.
v3.19.2
Other Income and Other Expense
 6 Months Ended
Jun. 30, 2019
Other Income and Expenses [Abstract]  
Other Income and Other Expense
Other Income and Other Expense
 
The following table provides detail of Pinnacle West's Consolidated other income and other expense for the three and six months ended June 30, 2019 and 2018 (dollars in thousands):

 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
2019
 
2018
 
2019
 
2018
Other income:
 

 
 

 
 

 
 

Interest income
$
2,699

 
$
2,408

 
$
5,001

 
$
4,299

Debt return on Four Corners SCR (Note 4)
4,887


4,188

 
9,731

 
6,280

Debt return on Ocotillo modernization project (Note 4)
5,294

 
—

 
5,294

 
—

Miscellaneous
5

 
2

 
28

 
4

Total other income
$
12,885

 
$
6,598

 
$
20,054

 
$
10,583

Other expense:
 

 
 

 
 

 
 

Non-operating costs
$
(3,481
)
 
$
(3,278
)
 
$
(6,185
)
 
$
(4,924
)
Investment losses — net
(491
)
 
(174
)
 
(729
)
 
(350
)
Miscellaneous
(378
)
 
(319
)
 
(1,794
)
 
(1,726
)
Total other expense
$
(4,350
)
 
$
(3,771
)
 
$
(8,708
)
 
$
(7,000
)

The following table provides detail of APS’s other income and other expense for the three and six months ended June 30, 2019 and 2018 (dollars in thousands):
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
2019
 
2018
 
2019
 
2018
Other income:
 

 
 

 
 

 
 

Interest income
$
1,504

 
$
2,046

 
$
3,054

 
$
3,724

Debt return on Four Corners SCR (Note 4)
4,887


4,188

 
9,731


6,280

Debt return on Ocotillo modernization project (Note 4)
5,294

 
—

 
5,294

 
—

Miscellaneous
6

 
1

 
28

 
3

Total other income
$
11,691

 
$
6,235

 
$
18,107

 
$
10,007

Other expense:
 

 
 

 
 

 
 

Non-operating costs
$
(3,049
)
 
$
(3,057
)
 
$
(5,517
)
 
$
(4,596
)
Miscellaneous
(379
)
 
(315
)
 
(1,789
)
 
(1,722
)
Total other expense
$
(3,428
)
 
$
(3,372
)
 
$
(7,306
)
 
$
(6,318
)
v3.19.2
Earnings Per Share
 6 Months Ended
Jun. 30, 2019
Earnings Per Share [Abstract]  
Earnings Per Share
Earnings Per Share
 
The following table presents the calculation of Pinnacle West’s basic and diluted earnings per share for the three and six months ended June 30, 2019 and 2018 (in thousands, except per share amounts):
 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
 
2019
 
2018
 
2019
 
2018
Net income attributable to common shareholders
$
144,145

 
$
166,738

 
$
162,063

 
$
169,959

Weighted average common shares outstanding — basic
112,337

 
112,115

 
112,381

 
112,067

Net effect of dilutive securities:
 
 
 
 
 
 
 
Contingently issuable performance shares and restricted stock units
314

 
356

 
353

 
415

Weighted average common shares outstanding — diluted
112,651

 
112,471

 
112,734

 
112,482

Earnings per weighted-average common share outstanding
 
 
 
 
 
 
 
Net income attributable to common shareholders — basic
$
1.28

 
$
1.49

 
$
1.44

 
$
1.52

Net income attributable to common shareholders — diluted
$
1.28

 
$
1.48

 
$
1.44

 
$
1.51
v3.19.2
Fair Value Measurements
 6 Months Ended
Jun. 30, 2019
Fair Value Disclosures [Abstract]  
Fair Value Measurements
Fair Value Measurements
 
We classify our assets and liabilities that are carried at fair value within the fair value hierarchy.  This hierarchy ranks the quality and reliability of the inputs used to determine fair values, which are then classified and disclosed in one of three categories.  The three levels of the fair value hierarchy are:
 
Level 1 — Unadjusted quoted prices in active markets for identical assets or liabilities.

Level 2 — Other significant observable inputs, including quoted prices in active markets for similar assets or liabilities; quoted prices in markets that are not active, and model-derived valuations whose inputs are observable (such as yield curves).
 
 Level 3 — Valuation models with significant unobservable inputs that are supported by little or no market activity.  Instruments in this category include long-dated derivative transactions where valuations are unobservable due to the length of the transaction, options, and transactions in locations where observable market data does not exist.  The valuation models we employ utilize spot prices, forward prices, historical market data and other factors to forecast future prices.
 
Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  Thus, a valuation may be classified in Level 3 even though the valuation may include significant inputs that are readily observable.  We maximize the use of observable inputs and minimize the use of unobservable inputs.  We rely primarily on the market approach of using prices and other market information for identical and/or comparable assets and liabilities.  If market data is not readily available, inputs may reflect our own assumptions about the inputs market participants would use.  Our assessment of the inputs and the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities as well as their placement within the fair value hierarchy levels. 
We assess whether a market is active by obtaining observable broker quotes, reviewing actual market activity, and assessing the volume of transactions.  We consider broker quotes observable inputs when the quote is binding on the broker, we can validate the quote with market activity, or we can determine that the inputs the broker used to arrive at the quoted price are observable.

Certain instruments have been valued using the concept of Net Asset Value ("NAV"), as a practical expedient. These instruments are typically structured as investment companies offering shares or units to multiple investors for the purpose of providing a return. These instruments are similar to mutual funds; however, their NAV is generally not published and publicly available, nor are these instruments traded on an exchange. Instruments valued using NAV, as a practical expedient are included in our fair value disclosures however, in accordance with GAAP are not classified within the fair value hierarchy levels.

Recurring Fair Value Measurements
 
We apply recurring fair value measurements to cash equivalents, derivative instruments, and investments held in the nuclear decommissioning trust and other special use funds. On an annual basis we apply fair value measurements to plan assets held in our retirement and other benefit plans.  See Note 7 in the 2018 Form 10-K for fair value discussion of plan assets held in our retirement and other benefit plans.
 
Cash Equivalents
 
Cash equivalents represent certain investments in money market funds that are valued using quoted prices in active markets.
   
Risk Management Activities — Derivative Instruments
 
Exchange traded commodity contracts are valued using unadjusted quoted prices.  For non-exchange traded commodity contracts, we calculate fair value based on the average of the bid and offer price, discounted to reflect net present value.  We maintain certain valuation adjustments for a number of risks associated with the valuation of future commitments.  These include valuation adjustments for liquidity and credit risks.  The liquidity valuation adjustment represents the cost that would be incurred if all unmatched positions were closed out or hedged.  The credit valuation adjustment represents estimated credit losses on our net exposure to counterparties, taking into account netting agreements, expected default experience for the credit rating of the counterparties and the overall diversification of the portfolio.  We maintain credit policies that management believes minimize overall credit risk.
 
Certain non-exchange traded commodity contracts are valued based on unobservable inputs due to the long-term nature of contracts, characteristics of the product, or the unique location of the transactions.  Our long-dated energy transactions consist of observable valuations for the near-term portion and unobservable valuations for the long-term portions of the transaction.  We rely primarily on broker quotes to value these instruments.  When our valuations utilize broker quotes, we perform various control procedures to ensure the quote has been developed consistent with fair value accounting guidance.  These controls include assessing the quote for reasonableness by comparison against other broker quotes, reviewing historical price relationships, and assessing market activity.  When broker quotes are not available, the primary valuation technique used to calculate the fair value is the extrapolation of forward pricing curves using observable market data for more liquid delivery points in the same region and actual transactions at more illiquid delivery points.
 
When the unobservable portion is significant to the overall valuation of the transaction, the entire transaction is classified as Level 3.  Our classification of instruments as Level 3 is primarily reflective of the long-term nature of our energy transactions.
 
Our energy risk management committee, consisting of officers and key management personnel, oversees our energy risk management activities to ensure compliance with our stated energy risk management policies.  We have a risk control function that is responsible for valuing our derivative commodity instruments in accordance with established policies and procedures.  The risk control function reports to the chief financial officer’s organization.
 
Investments Held in Nuclear Decommissioning Trust and Other Special Use Funds
 
The nuclear decommissioning trust and other special use funds invest in fixed income and equity securities. Other special use funds include the coal reclamation escrow account and the active union medical account. See Note 12 for additional discussion about our investment accounts.

We value investments in fixed income and equity securities using information provided by our trustees and escrow agent. Our trustees and escrow agent use pricing services that utilize the valuation methodologies described below to determine fair market value. We have internal control procedures designed to ensure this information is consistent with fair value accounting guidance. These procedures include assessing valuations using an independent pricing source, verifying that pricing can be supported by actual recent market transactions, assessing hierarchy classifications, comparing investment returns with benchmarks, and obtaining and reviewing independent audit reports on the trustees’ and escrow agent's internal operating controls and valuation processes.

Fixed Income Securities

Fixed income securities issued by the U.S. Treasury are valued using quoted active market prices and are typically classified as Level 1.  Fixed income securities issued by corporations, municipalities, and other agencies, including mortgage-backed instruments, are valued using quoted inactive market prices, quoted active market prices for similar securities, or by utilizing calculations which incorporate observable inputs such as yield curves and spreads relative to such yield curves.  These fixed income instruments are classified as Level 2.  Whenever possible, multiple market quotes are obtained which enables a cross-check validation.  A primary price source is identified based on asset type, class, or issue of securities.

Fixed income securities may also include short-term investments in certificates of deposit, variable rate notes, time deposit accounts, U.S. Treasury and Agency obligations, U.S. Treasury repurchase agreements, commercial paper, and other short-term instruments. These instruments are valued using active market prices or utilizing observable inputs described above.

Equity Securities

The nuclear decommissioning trust's equity security investments are held indirectly through commingled funds.  The commingled funds are valued using the funds' NAV as a practical expedient. The funds' NAV is primarily derived from the quoted active market prices of the underlying equity securities held by the funds. We may transact in these commingled funds on a semi-monthly basis at the NAV.  The commingled funds are maintained by a bank and hold investments in accordance with the stated objective of tracking the performance of the S&P 500 Index.  Because the commingled funds' shares are offered to a limited
group of investors, they are not considered to be traded in an active market. As these instruments are valued using NAV, as a practical expedient, they have not been classified within the fair value hierarchy.

The nuclear decommissioning trust and other special use funds may also hold equity securities that include exchange traded mutual funds and money market accounts for short-term liquidity purposes. These short-term, highly-liquid, investments are valued using active market prices.


Fair Value Tables
 
The following table presents the fair value at June 30, 2019 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):
 
 
Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 
Other
 
 
 
Balance at June 30, 2019
Assets
 

 
 

 
 

 
 

 
 
 
 

Risk management activities — derivative instruments:
 
 
 
 
 
 
 
 
 
 
 
Commodity contracts
$
—

 
$
3,198

 
$
436

 
$
(3,099
)
 
(a)
 
$
535

Nuclear decommissioning trust:
 
 
 
 
 
 
 
 
 
 
 
Equity securities
5,319

 
—

 
—

 
6,665

 
(b)
 
11,984

U.S. commingled equity funds
—

 
—

 
—

 
469,375

 
(c)
 
469,375

U.S. Treasury debt
162,044

 
—

 
—

 
—

 
 
 
162,044

Corporate debt
—

 
115,674

 
—

 
—

 
 
 
115,674

Mortgage-backed securities
—

 
113,179

 
—

 
—

 
 
 
113,179

Municipal bonds
—

 
67,158

 
—

 
—

 
 
 
67,158

Other fixed income
—

 
11,034

 
—

 
—

 
 
 
11,034

Subtotal nuclear decommissioning trust
167,363

 
307,045

 
—

 
476,040

 
 
 
950,448

 
 
 
 
 
 
 
 
 
 
 
 
Other special use funds:
 
 
 
 
 
 
 
 
 
 
 
Equity securities
13,200

 
—

 
—

 
997

 
(b)
 
14,197

U.S. Treasury debt
214,712

 
—

 
—

 
—

 

 
214,712

Municipal bonds
—

 
12,649

 
—

 
—

 
 
 
12,649

Subtotal other special use funds
227,912

 
12,649

 
—

 
997

 
 
 
241,558

 
 
 
 
 
 
 
 
 
 
 
 
Total assets
$
395,275

 
$
322,892

 
$
436

 
$
473,938

 
 
 
$
1,192,541

Liabilities
 

 
 

 
 

 
 

 
 
 
 

Risk management activities — derivative instruments:
 

 
 

 
 

 
 

 
 
 
 

Commodity contracts
$
—

 
$
(68,992
)
 
$
(13,189
)
 
$
1,755

 
(a)
 
$
(80,426
)

(a)
Represents counterparty netting, margin, and collateral. See Note 7.
(b)
Represents net pending securities sales and purchases.
(c)
Valued using NAV as a practical expedient and, therefore, are not classified in the fair value hierarchy.


The following table presents the fair value at December 31, 2018 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):
 
 
Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 
Other
 
 
 
Balance at December 31, 2018
Assets
 

 
 

 
 

 
 

 
 
 
 

Cash equivalents
$
1,200

 
$
—

 
$
—

 
$
—

 
 
 
$
1,200

Risk management activities — derivative instruments:
 
 
 
 
 
 
 
 
 
 
 
Commodity contracts
—

 
3,140

 
2

 
(2,029
)
 
(a)
 
1,113

Nuclear decommissioning trust:
 

 
 

 
 

 
 

 
 
 
 

Equity securities
5,203

 
—

 
—

 
2,148

 
(b)
 
7,351

U.S. commingled equity funds
—

 
—

 
—

 
396,805

 
(c)
 
396,805

U.S. Treasury debt
148,173

 
—

 
—

 
—

 
 
 
148,173

Corporate debt
—

 
96,656

 
—

 
—

 
 
 
96,656

Mortgage-backed securities
—

 
113,115

 
—

 
—

 
 
 
113,115

Municipal bonds
—

 
79,073

 
—

 
—

 
 
 
79,073

Other fixed income
—

 
9,961

 
—

 
—

 
 
 
9,961

Subtotal nuclear decommissioning trust
153,376

 
298,805

 
—

 
398,953

 
 
 
851,134

 
 
 
 
 
 
 
 
 
 
 
 
Other special use funds:
 
 
 
 
 
 
 
 
 
 
 
Equity securities
45,130

 
—

 
—

 
593

 
(b)
 
45,723

U.S. Treasury debt
173,310

 
—

 
—

 
—

 
 
 
173,310

Municipal bonds
—

 
17,068

 
—

 
—

 
 
 
17,068

Subtotal other special use funds
218,440

 
17,068

 
—

 
593

 
 
 
236,101

 
 
 
 
 
 
 
 
 
 
 
 
Total assets
$
373,016

 
$
319,013

 
$
2

 
$
397,517

 
 
 
$
1,089,548

Liabilities
 

 
 

 
 

 
 

 
 
 
 

Risk management activities — derivative instruments:
 

 
 

 
 

 
 

 
 
 
 

Commodity contracts
$
—

 
$
(52,696
)
 
$
(8,216
)
 
$
875

 
(a)
 
$
(60,037
)

(a)
Represents counterparty netting, margin, and collateral. See Note 7.
(b)
Represents net pending securities sales and purchases.
(c)
Valued using NAV as a practical expedient and, therefore, are not classified in the fair value hierarchy.


Fair Value Measurements Classified as Level 3
 
The significant unobservable inputs used in the fair value measurement of our energy derivative contracts include broker quotes that cannot be validated as an observable input primarily due to the long-term nature of the quote.  Significant changes in these inputs in isolation would result in significantly higher or lower fair value measurements.  Changes in our derivative contract fair values, including changes relating to unobservable inputs, typically will not impact net income due to regulatory accounting treatment (see Note 4).
 
Because our forward commodity contracts classified as Level 3 are currently in a net purchase position, we would expect price increases of the underlying commodity to result in increases in the net fair value of the related contracts.  Conversely, if the price of the underlying commodity decreases, the net fair value of the related contracts would likely decrease.
 
Other unobservable valuation inputs include credit and liquidity reserves which do not have a material impact on our valuations; however, significant changes in these inputs could also result in higher or lower fair value measurements.
 
The following tables provide information regarding our significant unobservable inputs used to value our risk management derivative Level 3 instruments at June 30, 2019 and December 31, 2018:
 
 
June 30, 2019
Fair Value (thousands)
 
Valuation Technique
 
Significant Unobservable Input
 
 
 
Weighted-Average
Commodity Contracts
Assets
 
Liabilities
 
 
 
Range
 
Electricity:
 

 
 

 
 
 
 
 
 
 
 

Forward Contracts (a)
$
294

 
$
11,675

 
Discounted cash flows
 
Electricity forward price (per MWh)
 
$18.27 - $30.11
 
$
26.78

Natural Gas:
 

 
 

 
 
 
 
 
 
 
 

Forward Contracts (a)
142

 
1,514

 
Discounted cash flows
 
Natural gas forward price (per MMBtu)
 
$0.05 - $2.88
 
$
2.41

Total
$
436

 
$
13,189

 
 
 
 
 
 
 
 


(a)
Includes swaps and physical and financial contracts.

 
December 31, 2018
Fair Value (thousands)
 
Valuation Technique
 
Significant Unobservable Input
 
 
 
Weighted-Average
Commodity Contracts
Assets
 
Liabilities
 
 
 
Range
 
Electricity:
 

 
 

 
 
 
 
 
 
 
 

Forward Contracts (a)
$
—

 
$
2,456

 
Discounted cash flows
 
Electricity forward price (per MWh)
 
$17.88 - $37.03
 
$
26.10

Natural Gas:
 

 
 

 
 
 
 
 
 
 
 

Forward Contracts (a)
2

 
5,760

 
Discounted cash flows
 
Natural gas forward price (per MMBtu)
 
$1.79 - $2.92
 
$
2.48

Total
$
2

 
$
8,216

 
 
 
 
 
 
 
 


(a)
Includes swaps and physical and financial contracts.
 
The following table shows the changes in fair value for our risk management activities assets and liabilities that are measured at fair value on a recurring basis using Level 3 inputs for the three and six months ended June 30, 2019 and 2018 (dollars in thousands):
 
 
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
Commodity Contracts
 
2019
 
2018
 
2019
 
2018
Net derivative balance at beginning of period
 
$
(5,612
)
 
$
(19,754
)
 
$
(8,214
)
 
$
(18,256
)
Total net gains (losses) realized/unrealized:
 
 

 
 

 
 
 
 
Deferred as a regulatory asset or liability
 
(8,731
)
 
(989
)
 
(10,310
)
 
(3,311
)
Settlements
 
2,431

 
494

 
2,949

 
1,276

Transfers into Level 3 from Level 2
 
(3,096
)
 
(2,534
)
 
(3,098
)
 
(4,979
)
Transfers from Level 3 into Level 2
 
2,255

 
13,425

 
5,920

 
15,912

Net derivative balance at end of period
 
$
(12,753
)
 
$
(9,358
)
 
$
(12,753
)
 
$
(9,358
)
 
 
 
 
 
 
 
 
 
Net unrealized gains included in earnings related to instruments still held at end of period
 
$
—

 
$
—

 
$
—

 
$
—



Transfers between levels in the fair value hierarchy shown in the table above reflect the fair market value at the beginning of the period and are triggered by a change in the lowest significant input as of the end of the period.  We had no significant Level 1 transfers to or from any other hierarchy level.  Transfers in or out of Level 3 are typically related to our long-dated energy transactions that extend beyond available quoted periods.
 
Financial Instruments Not Carried at Fair Value
 
The carrying value of our short-term borrowings approximate fair value and are classified within Level 2 of the fair value hierarchy. See Note 3 for our long-term debt fair values. The NTEC note receivable related to the sale of 4CA’s interest in Four Corners bears interest at 3.9% per annum and has a book value of $53 million as of June 30, 2019 and $61 million as of December 31, 2018 as presented on the Condensed Consolidated Balance Sheets.  The carrying amount is not materially different from the fair value of the note receivable and is classified within Level 3 of the fair value hierarchy.  See Note 8 for more information on 4CA matters.
v3.19.2
Investments in Nuclear Decommissioning Trusts and Other Special Use Funds
 6 Months Ended
Jun. 30, 2019
Investments, Debt and Equity Securities [Abstract]  
Investments in Nuclear Decommissioning Trusts and Other Special Use Funds
Investments in Nuclear Decommissioning Trust and Other Special Use Funds
 
We have investments in debt and equity securities held in nuclear decommissioning trust, coal reclamation escrow account, and an active union employee medical account. Investments in debt securities are classified as available-for-sale securities. We record both debt and equity security investments at their fair value on our Condensed Consolidated Balance Sheets. See Note 11 for a discussion of how fair value is determined and the classification of the investments within the fair value hierarchy. The investments in each trust or account are restricted for use and are intended to fund specified costs and activities as further described for each fund below.

Nuclear Decommissioning Trust - To fund the future costs APS expects to incur to decommission Palo Verde, APS established an external decommissioning trust in accordance with NRC regulations.  Third-party investment managers are authorized to buy and sell securities per stated investment guidelines.  The trust funds are invested in fixed income securities and equity securities. Earnings and proceeds from sales and maturities of securities are reinvested in the trust. Because of the ability of APS to recover decommissioning
costs in rates, and in accordance with the regulatory treatment, APS has deferred realized and unrealized gains and losses (including other-than-temporary impairments) in other regulatory liabilities.
 
Coal Reclamation Escrow Account - APS has investments restricted for the future coal mine reclamation funding related to Four Corners. This escrow account is primarily invested in fixed income securities. Earnings and proceeds from sales of securities are reinvested in the escrow account. Because of the ability of APS to recover coal reclamation costs in rates, and in accordance with the regulatory treatment, APS has deferred realized and unrealized gains and losses (including other-than-temporary impairments) in other regulatory liabilities. Activities relating to APS coal reclamation escrow account investments are included within the other special use funds in the table below.

Active Union Employee Medical Account - APS has investments restricted for paying active union employee medical costs. These investments were transferred from APS other postretirement benefit trust assets into the active union employee medical trust in January 2018 (see Note 7 in the 2018 Form 10-K). These investments may be used to pay active union employee medical costs incurred in the current and future periods. The account is invested primarily in fixed income securities. In accordance with the ratemaking treatment, APS has deferred the unrealized gains and losses (including other-than-temporary impairments) in other regulatory assets. Activities relating to active union employee medical account investments are included within the other special use funds in the table below.

APS

The following tables present the unrealized gains and losses based on the original cost of the investment and summarizes the fair value of APS's nuclear decommissioning trust and other special use fund assets at June 30, 2019 and December 31, 2018 (dollars in thousands):  
 
June 30, 2019
 
Fair Value
 
Total
Unrealized
Gains
 
Total
Unrealized
Losses
Investment Type:
Nuclear Decommissioning Trust
 
Other Special Use Funds
 
Total
 
 
Equity securities
$
474,694

 
$
13,200

 
$
487,894

 
$
291,295

 
$
—

Available for sale-fixed income securities
469,089

 
227,361

 
696,450

(a)
24,638

 
(696
)
Other
6,665

 
997

 
7,662

(b)
—

 
—

Total
$
950,448

 
$
241,558

 
$
1,192,006

 
$
315,933

 
$
(696
)

(a)
As of June 30, 2019, the amortized cost basis of these available-for-sale investments is $672 million.
(b)
Represents net pending securities sales and purchases.

 
December 31, 2018
 
Fair Value
 
Total
Unrealized
Gains
 
Total
Unrealized
Losses
Investment Type:
Nuclear Decommissioning Trust
 
Other Special Use Funds
 
Total
 
 
Equity securities
$
402,008

 
$
45,130

 
$
447,138

 
$
222,147

 
$
(459
)
Available for sale-fixed income securities
446,978

 
190,378

 
637,356

(a)
8,634

 
(6,778
)
Other
2,148

 
593

 
2,741

(b)
—

 
—

Total
$
851,134

 
$
236,101

 
$
1,087,235

 
$
230,781

 
$
(7,237
)

(a)
As of December 31, 2018, the amortized cost basis of these available-for-sale investments is $635 million.
(b)
Represents net pending securities sales and purchases.
    
The following table sets forth APS's realized gains and losses relating to the sale and maturity of available-for-sale debt securities and equity securities, and the proceeds from the sale and maturity of these investment securities for the three and six months ended June 30, 2019 and 2018 (dollars in thousands):
 
Three Months Ended June 30,
 
Nuclear Decommissioning Trust
 
Other Special Use Funds
 
Total
2019
 
 
 
 
 
Realized gains
$
2,643

 
$
—

 
$
2,643

Realized losses
(1,700
)
 
—

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

 
36,747

 
130,306

2018
 
 
 
 
 
Realized gains
$
1,484

 
$
—

 
$
1,484

Realized losses
(2,978
)
 
—

 
(2,978
)
Proceeds from the sale of securities (a)
122,790

 
2,426

 
125,216


(a)
Proceeds are reinvested in the nuclear decommissioning trust and coal reclamation escrow account.

 
Six Months Ended June 30,
 
Nuclear Decommissioning Trust
 
Other Special Use Funds
 
Total
2019
 
 
 
 
 
Realized gains
$
3,746

 
$
—

 
$
3,746

Realized losses
(3,105
)
 
—

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

 
93,202

 
309,354

2018
 
 
 
 
 
Realized gains
$
2,298

 
$
1

 
$
2,299

Realized losses
(5,025
)
 
—

 
(5,025
)
Proceeds from the sale of securities (a)
253,246

 
4,981

 
258,227



(a)
Proceeds are reinvested in the nuclear decommissioning trust and coal reclamation escrow account.

     The fair value of APS's fixed income securities, summarized by contractual maturities, at June 30, 2019, is as follows (dollars in thousands):
 
Nuclear Decommissioning Trust (a)
 
Coal Reclamation Escrow Account
 
Active Union Medical Trust
 
Total
Less than one year
$
37,373

 
$
22,253

 
$
40,219

 
$
99,845

1 year – 5 years
126,745

 
17,449

 
140,569

 
284,763

5 years – 10 years
113,989

 
1,807

 
—

 
115,796

Greater than 10 years
190,982

 
5,064

 
—

 
196,046

Total
$
469,089

 
$
46,573

 
$
180,788

 
$
696,450


(a)
Includes certain fixed income investments that are not due at a single maturity date. These investments have been allocated within the table based on the final payment date of the instrument.
v3.19.2
New Accounting Standards
 6 Months Ended
Jun. 30, 2019
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]  
New Accounting Standards New Accounting Standards
    
Standards Adopted in 2019

ASU 2016-02, Leases

In February 2016, a new lease accounting standard was issued. This new standard supersedes the existing lease accounting model, and modifies both lessee and lessor accounting. The new standard requires a lessee to reflect most operating lease arrangements on the balance sheet by recording a right-of-use asset and a lease liability that is initially measured at the present value of lease payments. Among other changes, the new standard also modifies the definition of a lease, and requires expanded lease disclosures. Since the issuance of the new lease standard, additional lease related guidance has been issued relating to land easements and how entities may elect to account for these arrangements at transition, among other items. The new lease standard and related amendments were effective for us on January 1, 2019, with early application permitted. The standard must be adopted using a modified retrospective approach with a cumulative-effect adjustment to the opening balance of retained earnings determined at either the date of adoption, or the earliest period presented in the financial statements. The standard includes various optional practical expedients provided to facilitate transition. We adopted this standard, and related amendments, on January 1, 2019. See Note 16.

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. On July 1, 2019, we early adopted this new accounting standard using the prospective approach. The adoption did not have a material impact on our financial statements.

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. Since the issuance of the new standard, various guidance has been issued that amends the new standard, including clarifications of certain aspects of the standard and targeted transition relief, among other changes. The new standard and related amendments are 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.
v3.19.2
Changes in Accumulated Other Comprehensive Loss
 6 Months Ended
Jun. 30, 2019
Comprehensive Income (Loss), Net of Tax, Attributable to Parent [Abstract]  
Changes in Accumulated Other Comprehensive Loss Changes in Accumulated Other Comprehensive Loss
 
The following table shows the changes in Pinnacle West's consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the three and six months ended June 30, 2019 and 2018 (dollars in thousands):
 
 Pension and Other Postretirement Benefits
 
 
 
 Derivative Instruments
 
 
 
 Total
Three Months Ended June 30
 
 
 
 
 
 
 
 
 
Balance March 31, 2019
$
(45,118
)
 
 
 
$
(1,383
)
 
 
 
$
(46,501
)
OCI (loss) before reclassifications
(2,422
)
 
 
 
—

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

 
 (a)
 
404

 
(b)
 
1,287

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


 
 
 

 
 
 

Balance March 31, 2018
$
(49,494
)
 
 
 
$
(2,847
)
 
 
 
$
(52,341
)
OCI (loss) before reclassifications
(5,928
)
 
 
 
—

 
 
 
(5,928
)
Amounts reclassified from accumulated other comprehensive loss
1,189

 
 (a)
 
456

 
(b)
 
1,645

Balance June 30, 2018
$
(54,233
)
 
 
 
$
(2,391
)
 
 
 
$
(56,624
)

 
 Pension and Other Postretirement Benefits
 
 
 
 Derivative Instruments
 
 
 
 Total
Six Months Ended June 30
 
 
 
 
 
 
 
 
 
Balance December 31, 2018
$
(45,997
)
 
 
 
$
(1,711
)
 
 
 
$
(47,708
)
OCI (loss) before reclassifications
(2,422
)
 
 
 
—

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

 
 (a)
 
732

 
(b)
 
2,494

Balance June 30, 2019
$
(46,657
)
 
 
 
$
(979
)
 
 
 
$
(47,636
)
 
 
 
 
 
 
 
 
 
 
Balance December 31, 2017
$
(42,440
)
 
 
 
$
(2,562
)
 
 
 
$
(45,002
)
OCI (loss) before reclassifications
(5,928
)
 
 
 
(96
)
 
 
 
(6,024
)
Amounts reclassified from accumulated other comprehensive loss
2,089

 
 (a)
 
865

 
(b)
 
2,954

Reclassification of income tax effect related to tax reform
(7,954
)
 
 (c)
 
(598
)
 
 (c)
 
(8,552
)
Balance June 30, 2018
$
(54,233
)
 
 
 
$
(2,391
)
 
 
 
$
(56,624
)

(a)
These amounts primarily represent amortization of actuarial loss and are included in the computation of net periodic pension cost.  See Note 5.
(b)
These amounts represent realized gains and losses and are included in the computation of fuel and purchased power costs and are subject to the PSA.  See Note 7.
(c)
In 2018, the company adopted new accounting guidance and elected to reclassify income tax effects of the Tax Act on items within accumulated other comprehensive income to retained earnings.
The following table shows the changes in APS's consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the three and six months ended June 30, 2019 and 2018 (dollars in thousands): 
 
 Pension and Other Postretirement Benefits
 
 
 
 Derivative Instruments
 
 
 
 Total
Three Months Ended June 30
 
 
 
 
 
 
 
 
 
Balance March 31, 2019
$
(24,644
)
 
 
 
$
(1,383
)
 
 
 
$
(26,027
)
OCI (loss) before reclassifications
(2,414
)
 
 
 
—

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

 
 (a)
 
404

 
 (b)
 
1,165

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


 
 
 

 
 
 

Balance March 31, 2018
$
(28,004
)
 
 
 
$
(2,847
)
 
 
 
$
(30,851
)
OCI (loss) before reclassifications
(5,790
)
 
 
 
—

 
 
 
(5,790
)
Amounts reclassified from accumulated other comprehensive loss
1,026

 
 (a)
 
456

 
 (b)
 
1,482

Balance June 30, 2018
$
(32,768
)
 
 
 
$
(2,391
)
 
 
 
$
(35,159
)

 
 Pension and Other Postretirement Benefits
 
 
 
 Derivative Instruments
 
 
 
 Total
Six Months Ended June 30
 
 
 
 
 
 
 
 
 
Balance December 31, 2018
$
(25,396
)
 
 
 
$
(1,711
)
 
 
 
$
(27,107
)
OCI (loss) before reclassifications
(2,414
)
 
 
 
—

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

 
 (a)
 
732

 
 (b)
 
2,245

Balance June 30, 2019
$
(26,297
)
 
 
 
$
(979
)
 
 
 
$
(27,276
)
 
 
 
 
 
 
 
 
 
 
Balance December 31, 2017
$
(24,421
)
 
 
 
$
(2,562
)
 
 
 
$
(26,983
)
OCI (loss) before reclassifications
(5,790
)
 
 
 
(96
)
 
 
 
(5,886
)
Amounts reclassified from accumulated other comprehensive loss
1,883

 
 (a)
 
865

 
 (b)
 
2,748

Reclassification of income tax effect related to tax reform
(4,440
)
 
 (c)
 
(598
)
 
 (c)
 
(5,038
)
Balance June 30, 2018
$
(32,768
)
 
 
 
$
(2,391
)
 
 
 
$
(35,159
)




(a)
These amounts primarily represent amortization of actuarial loss and are included in the computation of net periodic pension cost.  See Note 5.
(b)
These amounts represent realized gains and losses and are included in the computation of fuel and purchased power costs and are subject to the PSA.  See Note 7.
(c)
In 2018, the company adopted new accounting guidance and elected to reclassify income tax effects of the Tax Act on items within accumulated other comprehensive income to retained earnings.
v3.19.2
Income Taxes
 6 Months Ended
Jun. 30, 2019
Income Tax Disclosure [Abstract]  
Income Taxes
Income Taxes
 
The Tax Cuts and Jobs Act reduced the corporate tax rate to 21% effective January 1, 2018. As a result of this rate reduction, the Company recognized a $1.14 billion reduction in its net deferred income tax liabilities as of December 31, 2017. In accordance with accounting for regulated companies, the effect of this rate reduction was substantially offset by a net regulatory liability.

Federal income tax laws require the amortization of a majority of the balance over the remaining regulatory life of the related property. As a result of the modifications made to the annual transmission formula rate during the second quarter of 2018, the Company began amortization of FERC jurisdictional net excess deferred tax liabilities in 2018. On March 13, 2019, the ACC approved the Company's proposal to amortize non-depreciation related net excess deferred tax liabilities subject to its jurisdiction over a twelve month period. As a result, the Company began amortization in March 2019. As of June 30, 2019, the Company has recorded $19.4 million of income tax benefit related to the amortization of these non-depreciation related net excess deferred tax liabilities. On April 10, 2019, the Company filed a request with the ACC which addresses the amortization of depreciation related excess deferred taxes. See Note 4 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.  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.
    
Net income associated with the Palo Verde sale leaseback VIEs is not subject to tax.  As a result, there is no income tax expense associated with the VIEs recorded on the Pinnacle West Consolidated and APS Consolidated Statements of Income. See Note 6 for additional details related to the Palo Verde sale leaseback VIEs.

As of the balance sheet date, the tax year ended December 31, 2015 and all subsequent tax years remain subject to examination by the IRS.  With a few exceptions, the Company is no longer subject to state income tax examinations by tax authorities for years before 2014.
v3.19.2
Leases
 6 Months Ended
Jun. 30, 2019
Leases [Abstract]  
Leases
Leases
 
We lease certain land, buildings, vehicles, equipment and other property through operating rental agreements with varying terms, provisions, and expiration dates. APS also has certain purchased power agreements that qualify as lease arrangements. Our leases have remaining terms that expire in 2019 through 2050. Substantially all of our leasing activities relate to APS.

In 1986, APS entered into agreements with three separate lessor trust entities in order to sell and lease back interests in Palo Verde Unit 2 and related common facilities.  These lessor trust entities have been deemed VIEs for which APS is the primary beneficiary.  As the primary beneficiary, APS consolidated these lessor trust entities.  The impacts of these sale leaseback transactions are excluded from our lease disclosures as lease accounting is eliminated upon consolidation.  See Note 6 for a discussion of VIEs.
On January 1, 2019 we adopted new lease accounting guidance (see Note 13). We elected the transition method that allows us to apply the new lease 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 Condensed 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 resulted in expanded lease disclosures, which are included below.
The following tables provide information related to our lease costs for the three and six months ended June 30, 2019 (dollars in thousands):

 
 
Three Months Ended
June 30, 2019
 
 
Purchased Power Lease Contracts
 
Land, Property & Equipment Leases
 
Total
Operating lease cost
 
$
14,063

 
$
4,414

 
$
18,477

Variable lease cost
 
41,529

 
360

 
41,889

Short-term lease cost
 
—

 
1,812

 
1,812

Total lease cost
 
$
55,592

 
$
6,586

 
$
62,178




 
 
Six Months Ended
June 30, 2019
 
 
Purchased Power Lease Contracts
 
Land, Property & Equipment Leases
 
Total
Operating lease cost
 
$
14,063

 
$
8,762

 
$
22,825

Variable lease cost
 
58,820

 
360

 
59,180

Short-term lease cost
 
—

 
2,665

 
2,665

Total lease cost
 
$
72,883

 
$
11,787

 
$
84,670



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

The following table provides information related to the maturity of our operating lease liabilities at June 30, 2019 (dollars in thousands):
 
 
June 30, 2019
Year
 
Purchased Power Lease Contracts
 
Land, Property & Equipment Leases
 
Total
2019 (remaining six months of 2019)
 
$
49,051

 
$
7,335

 
$
56,386

2020
 
—

 
12,868

 
12,868

2021
 
—

 
10,029

 
10,029

2022
 
—

 
6,988

 
6,988

2023
 
—

 
5,838

 
5,838

2024
 
—

 
3,691

 
3,691

Thereafter
 
—

 
38,506

 
38,506

Total lease commitments
 
49,051

 
85,255

 
134,306

Less imputed interest
 
294

 
20,411

 
20,705

Total lease liabilities
 
$
48,757

 
$
64,844

 
$
113,601

 
We recognize lease assets and liabilities upon lease commencement. At June 30, 2019, we have additional lease arrangements that have been executed, but have not yet commenced. These arrangements primarily relate to purchased power lease contracts. These leases have commencement dates beginning in June 2020 with terms ending through October 2027. We expect the total fixed consideration paid for these arrangements, which includes both lease and nonlease payments, will approximate $705 million over the term of the arrangements.

The following table provides information related to estimated future minimum operating lease payments at December 31, 2018 (dollars in thousands):
 
 
December 31, 2018
Year
 
Purchased Power Lease Contracts
 
Land, Property & Equipment Leases
 
Total
2019
 
$
54,499

 
$
13,747

 
$
68,246

2020
 
—

 
12,428

 
12,428

2021
 
—

 
9,478

 
9,478

2022
 
—

 
6,513

 
6,513

2023
 
—

 
5,359

 
5,359

Thereafter
 
—

 
42,236

 
42,236

Total future lease commitments
 
$
54,499

 
$
89,761

 
$
144,260



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

Weighted average discount rate (a)
3.84
%


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

 
Six Months Ended
June 30, 2019
Cash paid for amounts included in the measurement of lease liabilities - operating cash flows (dollars in thousands):
$
11,987
v3.19.2
New Accounting Standards (Policies)
 6 Months Ended
Jun. 30, 2019
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]  
New Accounting Standards
Standards Adopted in 2019

ASU 2016-02, Leases

In February 2016, a new lease accounting standard was issued. This new standard supersedes the existing lease accounting model, and modifies both lessee and lessor accounting. The new standard requires a lessee to reflect most operating lease arrangements on the balance sheet by recording a right-of-use asset and a lease liability that is initially measured at the present value of lease payments. Among other changes, the new standard also modifies the definition of a lease, and requires expanded lease disclosures. Since the issuance of the new lease standard, additional lease related guidance has been issued relating to land easements and how entities may elect to account for these arrangements at transition, among other items. The new lease standard and related amendments were effective for us on January 1, 2019, with early application permitted. The standard must be adopted using a modified retrospective approach with a cumulative-effect adjustment to the opening balance of retained earnings determined at either the date of adoption, or the earliest period presented in the financial statements. The standard includes various optional practical expedients provided to facilitate transition. We adopted this standard, and related amendments, on January 1, 2019. See Note 16.

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. On July 1, 2019, we early adopted this new accounting standard using the prospective approach. The adoption did not have a material impact on our financial statements.

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. Since the issuance of the new standard, various guidance has been issued that amends the new standard, including clarifications of certain aspects of the standard and targeted transition relief, among other changes. The new standard and related amendments are 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.
v3.19.2
Consolidation and Nature of Operations (Tables)
 6 Months Ended
Jun. 30, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]  
Summary of supplemental cash flow information
The following table summarizes supplemental Pinnacle West cash flow information (dollars in thousands):
 
Six Months Ended
June 30,
 
2019
 
2018
Cash paid during the period for:
 
 
 
Income taxes, net of refunds
$
10,788

 
$
10,032

Interest, net of amounts capitalized
114,717

 
104,249

Significant non-cash investing and financing activities:
 
 
 
Accrued capital expenditures
$
108,056

 
$
65,995

Right-of-use operating lease assets obtained in exchange for operating lease liabilities
4,562

 
—

Dividends accrued but not yet paid
82,824

 
77,821



The following table summarizes supplemental APS cash flow information (dollars in thousands):
 
Six Months Ended 
 June 30,
 
2019
 
2018
Cash paid during the period for:
 
 
 
Income taxes, net of refunds
$
35,573

 
$
24,689

Interest, net of amounts capitalized
107,169

 
98,478

Significant non-cash investing and financing activities:
 
 
 
Accrued capital expenditures
$
108,056

 
$
65,995

Right-of-use operating lease assets obtained in exchange for operating lease liabilities
4,562

 
—

Dividends accrued but not yet paid
82,800

 
77,800
v3.19.2
Revenue (Tables)
 6 Months Ended
Jun. 30, 2019
Revenue from Contract with Customer [Abstract]  
Disaggregation of Revenue
The following table provides detail of Pinnacle West's consolidated revenue disaggregated by revenue sources (dollars in thousands):
 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
 
2019
2018
 
2019
2018
Retail residential electric service
 
$
432,568

$
500,247

 
$
784,134

$
816,922

Retail non-residential electric service
 
395,929

435,500

 
728,597

778,689

Wholesale energy sales
 
21,991

15,392

 
58,443

27,481

Transmission services for others
 
15,157

15,489

 
30,406

30,334

Other sources
 
3,856

7,495

 
8,451

13,411

Total operating revenues
 
$
869,501

$
974,123

 
$
1,610,031

$
1,666,837
v3.19.2
Long-Term Debt and Liquidity Matters (Tables)
 6 Months Ended
Jun. 30, 2019
Debt Disclosure [Abstract]  
Schedule of estimated fair value of long-term debt, including current maturities The following table presents the estimated fair value of our long-term debt, including current maturities (dollars in thousands):

 
As of June 30, 2019
 
As of December 31, 2018
 
Carrying
Amount
 
Fair Value
 
Carrying
Amount
 
Fair Value
Pinnacle West
$
449,111

 
$
449,124

 
$
448,796

 
$
443,955

APS
4,687,768

 
5,119,091

 
4,689,436

 
4,789,608

Total
$
5,136,879

 
$
5,568,215

 
$
5,138,232

 
$
5,233,563
v3.19.2
Regulatory Matters (Tables)
 6 Months Ended
Jun. 30, 2019
Regulated Operations [Abstract]  
Schedule of changes in the deferred fuel and purchased power regulatory asset The following table shows the changes in the deferred fuel and purchased power regulatory asset for 2019 and 2018 (dollars in thousands):
 
 
Six Months Ended
June 30,
 
2019
 
2018
Beginning balance
$
37,164

 
$
75,637

Deferred fuel and purchased power costs — current period
16,702

 
50,112

Amounts charged to customers
(23,307
)
 
(50,851
)
Ending balance
$
30,559

 
$
74,898
Schedule of regulatory assets
The detail of regulatory assets is as follows (dollars in thousands): 
 
Amortization Through
 
June 30, 2019
 
December 31, 2018
 
 
Current
 
Non-Current
 
Current
 
Non-Current
Pension
(a)
 
$
—

 
$
712,907

 
$
—

 
$
733,351

Retired power plant costs
2033
 
28,182

 
153,122

 
28,182

 
167,164

Income taxes — allowance for funds used during construction ("AFUDC") equity
2049
 
6,457

 
152,388

 
6,457

 
151,467

Deferred fuel and purchased power — mark-to-market (Note 7)
2023
 
55,729

 
21,516

 
31,728

 
23,768

Deferred fuel and purchased power (b) (c)
2020
 
30,559

 
—

 
37,164

 
—

Four Corners cost deferral
2024
 
8,077

 
36,190

 
8,077

 
40,228

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

 
25,170

 
1,079

 
25,522

Lost fixed cost recovery (b)
2020
 
25,746

 
—

 
32,435

 
—

Palo Verde VIEs (Note 6)
2046
 
—

 
20,325

 
—

 
20,015

Deferred compensation
2036
 
—

 
37,572

 
—

 
36,523

Deferred property taxes
2027
 
8,569

 
62,072

 
8,569

 
66,356

Loss on reacquired debt
2038
 
1,637

 
12,850

 
1,637

 
13,668

Tax expense of Medicare subsidy
2024
 
1,235

 
5,772

 
1,235

 
6,176

TCA balancing account (b)
2021
 
5,381

 
3,895

 
3,860

 
772

AG-1 deferral
2022
 
2,787

 
4,110

 
2,654

 
5,819

Mead-Phoenix transmission line CIAC
2050
 
332

 
9,878

 
332

 
10,044

Coal reclamation
2026
 
1,546

 
16,250

 
1,546

 
15,607

SCR deferral
N/A
 
—

 
37,919

 
—

 
23,276

Tax expense adjuster mechanism (b)
2019
 
3,149

 
—

 
—

 
—

Ocotillo deferral
N/A
 
—

 
9,495

 
—

 
—

Other
Various
 
3,994

 
—

 
1,947

 
3,185

Total regulatory assets (d)
 
 
$
184,459

 
$
1,321,431

 
$
166,902

 
$
1,342,941


(a)
This asset represents the future recovery of pension benefit obligations through retail rates.  If these costs are disallowed by the ACC, this regulatory asset would be charged to other comprehensive income ("OCI") and result in lower future revenues.
(b)
See "Cost Recovery Mechanisms" discussion above.
(c)
Subject to a carrying charge.
(d)
There are no regulatory assets for which the ACC has allowed recovery of costs, but not allowed a return by exclusion from rate base.  FERC rates are set using a formula rate as described in "Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters."
Schedule of regulatory liabilities
The detail of regulatory liabilities is as follows (dollars in thousands):
 
 
Amortization Through
 
June 30, 2019
 
December 31, 2018
 
 
Current
 
Non-Current
 
Current
 
Non-Current
Excess deferred income taxes - ACC - Tax Cuts and Jobs Act (a)
(b)
 
$
68,651

 
$
1,178,216

 
$
—

 
$
1,272,709

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

 
241,633

 
6,302

 
243,691

Asset retirement obligations
2057
 
—

 
359,912

 
—

 
278,585

Removal costs
(c)
 
50,701

 
153,847

 
39,866

 
177,533

Other postretirement benefits
(d)
 
37,821

 
105,214

 
37,864

 
125,903

Income taxes — deferred investment tax credit
2047
 
2,164

 
50,414

 
2,164

 
51,120

Income taxes — change in rates
2048
 
2,764

 
69,171

 
2,769

 
70,069

Spent nuclear fuel
2027
 
6,578

 
53,769

 
6,503

 
57,002

Renewable energy standard (b)
2021
 
40,639

 
4,950

 
44,966

 
20

Demand side management (b)
2021
 
7,191

 
24,146

 
14,604

 
4,123

Sundance maintenance
2030
 
1,641

 
15,495

 
1,278

 
17,228

Deferred gains on utility property
2022
 
3,423

 
5,372

 
4,423

 
6,581

Four Corners coal reclamation
2038
 
1,858

 
17,540

 
1,858

 
17,871

Tax expense adjustor mechanism (b)
2020
 
1,663

 
—

 
3,237

 
—

Other
Various
 
461

 
8,213

 
42

 
3,541

Total regulatory liabilities
 
 
$
231,857

 
$
2,287,892

 
$
165,876

 
$
2,325,976


(a)
For purposes of presentation on the Statement of Cash Flows, amortization of the regulatory liabilities for excess deferred income taxes are reflected as "Deferred income taxes" under Cash Flows From Operating Activities.
(b)
See “Cost Recovery Mechanisms” discussion above.
(c)
In accordance with regulatory accounting guidance, APS accrues removal costs for its regulated assets, even if there is no legal obligation for removal.
(d)
See Note 5.
v3.19.2
Retirement Plans and Other Postretirement Benefits (Tables)
 6 Months Ended
Jun. 30, 2019
Retirement Benefits [Abstract]  
Schedule of net periodic benefit costs and the portion of these costs charged to expense (including administrative costs and excluding amounts capitalized as overhead construction, billed to electric plant participants or charged or amortized to the regulatory asset)
The following table provides details of the plans’ net periodic benefit costs and the portion of these costs charged to expense (including administrative costs and excluding amounts capitalized as overhead construction or billed to electric plant participants) (dollars in thousands):

 
Pension Benefits
 
Other Benefits
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
2019
 
2018
 
2019
 
2018
 
2019
 
2018
 
2019
 
2018
Service cost — benefits earned during the period
$
12,408

 
$
14,121

 
$
24,951

 
$
28,334

 
$
4,470

 
$
5,445

 
$
9,184

 
$
10,550

Non-service costs (credits):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Interest cost on benefit obligation
34,069

 
31,338

 
68,421

 
62,345

 
7,421

 
6,973

 
14,947

 
14,074

Expected return on plan assets
(43,049
)
 
(45,759
)
 
(85,942
)
 
(91,426
)
 
(9,603
)
 
(10,520
)
 
(19,206
)
 
(21,041
)
  Amortization of:
 

 
 
 
 

 
 

 
 

 
 

 
 

 
 

  Prior service credit
—

 
—

 
—

 
—

 
(9,455
)
 
(9,461
)
 
(18,910
)
 
(18,921
)
  Net actuarial loss
10,053

 
8,259

 
21,292

 
16,041

 
—

 
—

 
—

 
—

Net periodic benefit
cost (credit)
$
13,481

 
$
7,959

 
$
28,722

 
$
15,294

 
$
(7,167
)
 
$
(7,563
)
 
$
(13,985
)
 
$
(15,338
)
Portion of cost (credit) charged to expense
$
7,000

 
$
2,769

 
$
15,244

 
$
5,011

 
$
(5,063
)
 
$
(5,119
)
 
$
(9,880
)
 
$
(10,724
)
v3.19.2
Palo Verde Sale Leaseback Variable Interest Entities (Tables)
 6 Months Ended
Jun. 30, 2019
Variable Interest Entities [Abstract]  
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets

Our Condensed Consolidated Balance Sheets at June 30, 2019 and December 31, 2018 include the following amounts relating to the VIEs (dollars in thousands):
 
 
June 30, 2019
 
December 31, 2018
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation
$
103,841

 
$
105,775

Equity — Noncontrolling interests
124,165

 
125,790
v3.19.2
Derivative Accounting (Tables)
 6 Months Ended
Jun. 30, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]  
Outstanding gross notional amount of derivatives, which represents both purchases and sales (does not reflect net position)
As of June 30, 2019 and December 31, 2018, we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position): 
 
 
 
Quantity
Commodity
 
Unit of Measure
June 30, 2019
 
December 31, 2018
Power
 
GWh
1,000

 
250

Gas
 
Billion cubic feet
218

 
218
Gains and losses from derivative instruments in designated cash flow accounting hedges relationships
The following table provides information about gains and losses from derivative instruments in designated cash flow accounting hedging relationships during the three and six months ended June 30, 2019 and 2018 (dollars in thousands):
 
 
 
Financial Statement Location
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
Commodity Contracts
 
 
2019
 
2018
 
2019
 
2018
Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a)
 
Fuel and purchased power (b)
 
$
(538
)
 
$
(606
)
 
$
(974
)
 
$
(1,097
)

(a)
During the three and six months ended June 30, 2019 and 2018, we had no gains or losses reclassified from accumulated OCI to earnings related to discontinued cash flow hedges.
(b)
Amounts are before the effect of PSA deferrals.
Gains and losses from derivative instruments not designated as accounting hedges instruments
The following table provides information about gains and losses from derivative instruments not designated as accounting hedging instruments during the three and six months ended June 30, 2019 and 2018 (dollars in thousands):
 
 
 
Financial Statement Location
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
Commodity Contracts
 
 
2019
 
2018
 
2019
 
2018
Net Loss Recognized in Income
 
Operating revenues
 
$
—

 
$
(341
)
 
$
—

 
$
(1,560
)
Net Gain (Loss) Recognized in Income
 
Fuel and purchased power (a)
 
(49,686
)
 
3,384

 
(41,516
)
 
(30,705
)
Total
 
 
 
$
(49,686
)
 
$
3,043

 
$
(41,516
)
 
$
(32,265
)

(a)
Amounts are before the effect of PSA deferrals.
Schedule of offsetting assets
The following tables provide information about the fair value of our risk management activities reported on a gross basis, and the impacts of offsetting as of June 30, 2019 and December 31, 2018.  These amounts relate to commodity contracts and are located in the assets and liabilities from risk management activities lines of our Condensed Consolidated Balance Sheets.

As of June 30, 2019:
(dollars in thousands)
 
Gross
 Recognized
 Derivatives
 (a)
 
Amounts
Offset
 (b)
 
Net
 Recognized
 Derivatives
 
Other
 (c)
 
Amount Reported on Balance Sheets
Current assets
 
$
3,558

 
$
(2,939
)
 
$
619

 
$
(160
)
 
$
459

Investments and other assets
 
76

 
—

 
76

 
—

 
76

Total assets
 
3,634

 
(2,939
)
 
695

 
(160
)
 
535

 
 
 
 
 
 
 
 
 
 
 
Current liabilities
 
(60,588
)
 
2,939

 
(57,649
)
 
(1,185
)
 
(58,834
)
Deferred credits and other
 
(21,592
)
 
—

 
(21,592
)
 
—

 
(21,592
)
Total liabilities
 
(82,180
)
 
2,939

 
(79,241
)
 
(1,185
)
 
(80,426
)
Total
 
$
(78,546
)
 
$
—

 
$
(78,546
)
 
$
(1,345
)
 
$
(79,891
)

(a)
All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)
No cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting.
(c)
Represents cash collateral and cash margin that is not subject to offsetting. Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument. Includes cash collateral received from counterparties of $1,185 and cash margin provided to counterparties of ($160).

As of December 31, 2018:
(dollars in thousands)
 
Gross
Recognized
Derivatives
 (a)
 
Amounts
Offset
(b)
 
Net
 Recognized
 Derivatives
 
Other
 (c)
 
Amount
Reported on
Balance Sheets
Current assets
 
$
3,106

 
$
(2,149
)
 
$
957

 
$
156

 
$
1,113

Investments and other assets
 
36

 
(36
)
 
—

 
—

 
—

Total assets
 
3,142

 
(2,185
)
 
957

 
156

 
1,113

 
 
 
 
 
 
 
 
 
 
 
Current liabilities
 
(36,345
)
 
2,149

 
(34,196
)
 
(1,310
)
 
(35,506
)
Deferred credits and other
 
(24,567
)
 
36

 
(24,531
)
 
—

 
(24,531
)
Total liabilities
 
(60,912
)
 
2,185

 
(58,727
)
 
(1,310
)
 
(60,037
)
Total
 
$
(57,770
)
 
$
—

 
$
(57,770
)
 
$
(1,154
)
 
$
(58,924
)

(a)
All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)
No cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting.
(c)
Represents cash collateral and cash margin that is not subject to offsetting. Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument.  Includes cash collateral received from counterparties of $1,310 and cash margin provided to counterparties of $156.
Schedule of offsetting liabilities
The following tables provide information about the fair value of our risk management activities reported on a gross basis, and the impacts of offsetting as of June 30, 2019 and December 31, 2018.  These amounts relate to commodity contracts and are located in the assets and liabilities from risk management activities lines of our Condensed Consolidated Balance Sheets.

As of June 30, 2019:
(dollars in thousands)
 
Gross
 Recognized
 Derivatives
 (a)
 
Amounts
Offset
 (b)
 
Net
 Recognized
 Derivatives
 
Other
 (c)
 
Amount Reported on Balance Sheets
Current assets
 
$
3,558

 
$
(2,939
)
 
$
619

 
$
(160
)
 
$
459

Investments and other assets
 
76

 
—

 
76

 
—

 
76

Total assets
 
3,634

 
(2,939
)
 
695

 
(160
)
 
535

 
 
 
 
 
 
 
 
 
 
 
Current liabilities
 
(60,588
)
 
2,939

 
(57,649
)
 
(1,185
)
 
(58,834
)
Deferred credits and other
 
(21,592
)
 
—

 
(21,592
)
 
—

 
(21,592
)
Total liabilities
 
(82,180
)
 
2,939

 
(79,241
)
 
(1,185
)
 
(80,426
)
Total
 
$
(78,546
)
 
$
—

 
$
(78,546
)
 
$
(1,345
)
 
$
(79,891
)

(a)
All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)
No cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting.
(c)
Represents cash collateral and cash margin that is not subject to offsetting. Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument. Includes cash collateral received from counterparties of $1,185 and cash margin provided to counterparties of ($160).

As of December 31, 2018:
(dollars in thousands)
 
Gross
Recognized
Derivatives
 (a)
 
Amounts
Offset
(b)
 
Net
 Recognized
 Derivatives
 
Other
 (c)
 
Amount
Reported on
Balance Sheets
Current assets
 
$
3,106

 
$
(2,149
)
 
$
957

 
$
156

 
$
1,113

Investments and other assets
 
36

 
(36
)
 
—

 
—

 
—

Total assets
 
3,142

 
(2,185
)
 
957

 
156

 
1,113

 
 
 
 
 
 
 
 
 
 
 
Current liabilities
 
(36,345
)
 
2,149

 
(34,196
)
 
(1,310
)
 
(35,506
)
Deferred credits and other
 
(24,567
)
 
36

 
(24,531
)
 
—

 
(24,531
)
Total liabilities
 
(60,912
)
 
2,185

 
(58,727
)
 
(1,310
)
 
(60,037
)
Total
 
$
(57,770
)
 
$
—

 
$
(57,770
)
 
$
(1,154
)
 
$
(58,924
)

(a)
All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)
No cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting.
(c)
Represents cash collateral and cash margin that is not subject to offsetting. Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument.  Includes cash collateral received from counterparties of $1,310 and cash margin provided to counterparties of $156.
Information about derivative instruments that have credit-risk-related contingent features
The following table provides information about our derivative instruments that have credit-risk-related contingent features at June 30, 2019 (dollars in thousands):
 
June 30, 2019
Aggregate fair value of derivative instruments in a net liability position
$
82,064

Cash collateral posted
—

Additional cash collateral in the event credit-risk-related contingent features were fully triggered (a)
80,804


(a)
This amount is after counterparty netting and includes those contracts which qualify for scope exceptions, which are excluded from the derivative details above.
v3.19.2
Other Income and Other Expense (Tables)
 6 Months Ended
Jun. 30, 2019
Other Income and Expenses [Abstract]  
Detail of other income and other expense
The following table provides detail of Pinnacle West's Consolidated other income and other expense for the three and six months ended June 30, 2019 and 2018 (dollars in thousands):

 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
2019
 
2018
 
2019
 
2018
Other income:
 

 
 

 
 

 
 

Interest income
$
2,699

 
$
2,408

 
$
5,001

 
$
4,299

Debt return on Four Corners SCR (Note 4)
4,887


4,188

 
9,731

 
6,280

Debt return on Ocotillo modernization project (Note 4)
5,294

 
—

 
5,294

 
—

Miscellaneous
5

 
2

 
28

 
4

Total other income
$
12,885

 
$
6,598

 
$
20,054

 
$
10,583

Other expense:
 

 
 

 
 

 
 

Non-operating costs
$
(3,481
)
 
$
(3,278
)
 
$
(6,185
)
 
$
(4,924
)
Investment losses — net
(491
)
 
(174
)
 
(729
)
 
(350
)
Miscellaneous
(378
)
 
(319
)
 
(1,794
)
 
(1,726
)
Total other expense
$
(4,350
)
 
$
(3,771
)
 
$
(8,708
)
 
$
(7,000
)

The following table provides detail of APS’s other income and other expense for the three and six months ended June 30, 2019 and 2018 (dollars in thousands):
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
2019
 
2018
 
2019
 
2018
Other income:
 

 
 

 
 

 
 

Interest income
$
1,504

 
$
2,046

 
$
3,054

 
$
3,724

Debt return on Four Corners SCR (Note 4)
4,887


4,188

 
9,731


6,280

Debt return on Ocotillo modernization project (Note 4)
5,294

 
—

 
5,294

 
—

Miscellaneous
6

 
1

 
28

 
3

Total other income
$
11,691

 
$
6,235

 
$
18,107

 
$
10,007

Other expense:
 

 
 

 
 

 
 

Non-operating costs
$
(3,049
)
 
$
(3,057
)
 
$
(5,517
)
 
$
(4,596
)
Miscellaneous
(379
)
 
(315
)
 
(1,789
)
 
(1,722
)
Total other expense
$
(3,428
)
 
$
(3,372
)
 
$
(7,306
)
 
$
(6,318
)
v3.19.2
Earnings Per Share (Tables)
 6 Months Ended
Jun. 30, 2019
Earnings Per Share [Abstract]  
Schedule of earnings per weighted average common share outstanding
The following table presents the calculation of Pinnacle West’s basic and diluted earnings per share for the three and six months ended June 30, 2019 and 2018 (in thousands, except per share amounts):
 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
 
2019
 
2018
 
2019
 
2018
Net income attributable to common shareholders
$
144,145

 
$
166,738

 
$
162,063

 
$
169,959

Weighted average common shares outstanding — basic
112,337

 
112,115

 
112,381

 
112,067

Net effect of dilutive securities:
 
 
 
 
 
 
 
Contingently issuable performance shares and restricted stock units
314

 
356

 
353

 
415

Weighted average common shares outstanding — diluted
112,651

 
112,471

 
112,734

 
112,482

Earnings per weighted-average common share outstanding
 
 
 
 
 
 
 
Net income attributable to common shareholders — basic
$
1.28

 
$
1.49

 
$
1.44

 
$
1.52

Net income attributable to common shareholders — diluted
$
1.28

 
$
1.48

 
$
1.44

 
$
1.51
v3.19.2
Fair Value Measurements (Tables)
 6 Months Ended
Jun. 30, 2019
Fair Value Disclosures [Abstract]  
Fair value of assets and liabilities that are measured at fair value on a recurring basis
The following table presents the fair value at June 30, 2019 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):
 
 
Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 
Other
 
 
 
Balance at June 30, 2019
Assets
 

 
 

 
 

 
 

 
 
 
 

Risk management activities — derivative instruments:
 
 
 
 
 
 
 
 
 
 
 
Commodity contracts
$
—

 
$
3,198

 
$
436

 
$
(3,099
)
 
(a)
 
$
535

Nuclear decommissioning trust:
 
 
 
 
 
 
 
 
 
 
 
Equity securities
5,319

 
—

 
—

 
6,665

 
(b)
 
11,984

U.S. commingled equity funds
—

 
—

 
—

 
469,375

 
(c)
 
469,375

U.S. Treasury debt
162,044

 
—

 
—

 
—

 
 
 
162,044

Corporate debt
—

 
115,674

 
—

 
—

 
 
 
115,674

Mortgage-backed securities
—

 
113,179

 
—

 
—

 
 
 
113,179

Municipal bonds
—

 
67,158

 
—

 
—

 
 
 
67,158

Other fixed income
—

 
11,034

 
—

 
—

 
 
 
11,034

Subtotal nuclear decommissioning trust
167,363

 
307,045

 
—

 
476,040

 
 
 
950,448

 
 
 
 
 
 
 
 
 
 
 
 
Other special use funds:
 
 
 
 
 
 
 
 
 
 
 
Equity securities
13,200

 
—

 
—

 
997

 
(b)
 
14,197

U.S. Treasury debt
214,712

 
—

 
—

 
—

 

 
214,712

Municipal bonds
—

 
12,649

 
—

 
—

 
 
 
12,649

Subtotal other special use funds
227,912

 
12,649

 
—

 
997

 
 
 
241,558

 
 
 
 
 
 
 
 
 
 
 
 
Total assets
$
395,275

 
$
322,892

 
$
436

 
$
473,938

 
 
 
$
1,192,541

Liabilities
 

 
 

 
 

 
 

 
 
 
 

Risk management activities — derivative instruments:
 

 
 

 
 

 
 

 
 
 
 

Commodity contracts
$
—

 
$
(68,992
)
 
$
(13,189
)
 
$
1,755

 
(a)
 
$
(80,426
)

(a)
Represents counterparty netting, margin, and collateral. See Note 7.
(b)
Represents net pending securities sales and purchases.
(c)
Valued using NAV as a practical expedient and, therefore, are not classified in the fair value hierarchy.


The following table presents the fair value at December 31, 2018 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):
 
 
Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 
Other
 
 
 
Balance at December 31, 2018
Assets
 

 
 

 
 

 
 

 
 
 
 

Cash equivalents
$
1,200

 
$
—

 
$
—

 
$
—

 
 
 
$
1,200

Risk management activities — derivative instruments:
 
 
 
 
 
 
 
 
 
 
 
Commodity contracts
—

 
3,140

 
2

 
(2,029
)
 
(a)
 
1,113

Nuclear decommissioning trust:
 

 
 

 
 

 
 

 
 
 
 

Equity securities
5,203

 
—

 
—

 
2,148

 
(b)
 
7,351

U.S. commingled equity funds
—

 
—

 
—

 
396,805

 
(c)
 
396,805

U.S. Treasury debt
148,173

 
—

 
—

 
—

 
 
 
148,173

Corporate debt
—

 
96,656

 
—

 
—

 
 
 
96,656

Mortgage-backed securities
—

 
113,115

 
—

 
—

 
 
 
113,115

Municipal bonds
—

 
79,073

 
—

 
—

 
 
 
79,073

Other fixed income
—

 
9,961

 
—

 
—

 
 
 
9,961

Subtotal nuclear decommissioning trust
153,376

 
298,805

 
—

 
398,953

 
 
 
851,134

 
 
 
 
 
 
 
 
 
 
 
 
Other special use funds:
 
 
 
 
 
 
 
 
 
 
 
Equity securities
45,130

 
—

 
—

 
593

 
(b)
 
45,723

U.S. Treasury debt
173,310

 
—

 
—

 
—

 
 
 
173,310

Municipal bonds
—

 
17,068

 
—

 
—

 
 
 
17,068

Subtotal other special use funds
218,440

 
17,068

 
—

 
593

 
 
 
236,101

 
 
 
 
 
 
 
 
 
 
 
 
Total assets
$
373,016

 
$
319,013

 
$
2

 
$
397,517

 
 
 
$
1,089,548

Liabilities
 

 
 

 
 

 
 

 
 
 
 

Risk management activities — derivative instruments:
 

 
 

 
 

 
 

 
 
 
 

Commodity contracts
$
—

 
$
(52,696
)
 
$
(8,216
)
 
$
875

 
(a)
 
$
(60,037
)

(a)
Represents counterparty netting, margin, and collateral. See Note 7.
(b)
Represents net pending securities sales and purchases.
(c)
Valued using NAV as a practical expedient and, therefore, are not classified in the fair value hierarchy.
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
The following tables provide information regarding our significant unobservable inputs used to value our risk management derivative Level 3 instruments at June 30, 2019 and December 31, 2018:
 
 
June 30, 2019
Fair Value (thousands)
 
Valuation Technique
 
Significant Unobservable Input
 
 
 
Weighted-Average
Commodity Contracts
Assets
 
Liabilities
 
 
 
Range
 
Electricity:
 

 
 

 
 
 
 
 
 
 
 

Forward Contracts (a)
$
294

 
$
11,675

 
Discounted cash flows
 
Electricity forward price (per MWh)
 
$18.27 - $30.11
 
$
26.78

Natural Gas:
 

 
 

 
 
 
 
 
 
 
 

Forward Contracts (a)
142

 
1,514

 
Discounted cash flows
 
Natural gas forward price (per MMBtu)
 
$0.05 - $2.88
 
$
2.41

Total
$
436

 
$
13,189

 
 
 
 
 
 
 
 


(a)
Includes swaps and physical and financial contracts.

 
December 31, 2018
Fair Value (thousands)
 
Valuation Technique
 
Significant Unobservable Input
 
 
 
Weighted-Average
Commodity Contracts
Assets
 
Liabilities
 
 
 
Range
 
Electricity:
 

 
 

 
 
 
 
 
 
 
 

Forward Contracts (a)
$
—

 
$
2,456

 
Discounted cash flows
 
Electricity forward price (per MWh)
 
$17.88 - $37.03
 
$
26.10

Natural Gas:
 

 
 

 
 
 
 
 
 
 
 

Forward Contracts (a)
2

 
5,760

 
Discounted cash flows
 
Natural gas forward price (per MMBtu)
 
$1.79 - $2.92
 
$
2.48

Total
$
2

 
$
8,216

 
 
 
 
 
 
 
 


(a)
Includes swaps and physical and financial contracts.
Changes in fair value for assets and liabilities that are measured at fair value on a recurring basis using Level 3 inputs
 
The following table shows the changes in fair value for our risk management activities assets and liabilities that are measured at fair value on a recurring basis using Level 3 inputs for the three and six months ended June 30, 2019 and 2018 (dollars in thousands):
 
 
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
Commodity Contracts
 
2019
 
2018
 
2019
 
2018
Net derivative balance at beginning of period
 
$
(5,612
)
 
$
(19,754
)
 
$
(8,214
)
 
$
(18,256
)
Total net gains (losses) realized/unrealized:
 
 

 
 

 
 
 
 
Deferred as a regulatory asset or liability
 
(8,731
)
 
(989
)
 
(10,310
)
 
(3,311
)
Settlements
 
2,431

 
494

 
2,949

 
1,276

Transfers into Level 3 from Level 2
 
(3,096
)
 
(2,534
)
 
(3,098
)
 
(4,979
)
Transfers from Level 3 into Level 2
 
2,255

 
13,425

 
5,920

 
15,912

Net derivative balance at end of period
 
$
(12,753
)
 
$
(9,358
)
 
$
(12,753
)
 
$
(9,358
)
 
 
 
 
 
 
 
 
 
Net unrealized gains included in earnings related to instruments still held at end of period
 
$
—

 
$
—

 
$
—

 
$
—
v3.19.2
Investments in Nuclear Decommissioning Trusts and Other Special Use Funds (Tables)
 6 Months Ended
Jun. 30, 2019
Investments, Debt and Equity Securities [Abstract]  
Fair value of APS's nuclear decommissioning trust fund assets
The following tables present the unrealized gains and losses based on the original cost of the investment and summarizes the fair value of APS's nuclear decommissioning trust and other special use fund assets at June 30, 2019 and December 31, 2018 (dollars in thousands):  
 
June 30, 2019
 
Fair Value
 
Total
Unrealized
Gains
 
Total
Unrealized
Losses
Investment Type:
Nuclear Decommissioning Trust
 
Other Special Use Funds
 
Total
 
 
Equity securities
$
474,694

 
$
13,200

 
$
487,894

 
$
291,295

 
$
—

Available for sale-fixed income securities
469,089

 
227,361

 
696,450

(a)
24,638

 
(696
)
Other
6,665

 
997

 
7,662

(b)
—

 
—

Total
$
950,448

 
$
241,558

 
$
1,192,006

 
$
315,933

 
$
(696
)

(a)
As of June 30, 2019, the amortized cost basis of these available-for-sale investments is $672 million.
(b)
Represents net pending securities sales and purchases.

 
December 31, 2018
 
Fair Value
 
Total
Unrealized
Gains
 
Total
Unrealized
Losses
Investment Type:
Nuclear Decommissioning Trust
 
Other Special Use Funds
 
Total
 
 
Equity securities
$
402,008

 
$
45,130

 
$
447,138

 
$
222,147

 
$
(459
)
Available for sale-fixed income securities
446,978

 
190,378

 
637,356

(a)
8,634

 
(6,778
)
Other
2,148

 
593

 
2,741

(b)
—

 
—

Total
$
851,134

 
$
236,101

 
$
1,087,235

 
$
230,781

 
$
(7,237
)

(a)
As of December 31, 2018, the amortized cost basis of these available-for-sale investments is $635 million.
(b)
Represents net pending securities sales and purchases.
    
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds
The following table sets forth APS's realized gains and losses relating to the sale and maturity of available-for-sale debt securities and equity securities, and the proceeds from the sale and maturity of these investment securities for the three and six months ended June 30, 2019 and 2018 (dollars in thousands):
 
Three Months Ended June 30,
 
Nuclear Decommissioning Trust
 
Other Special Use Funds
 
Total
2019
 
 
 
 
 
Realized gains
$
2,643

 
$
—

 
$
2,643

Realized losses
(1,700
)
 
—

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

 
36,747

 
130,306

2018
 
 
 
 
 
Realized gains
$
1,484

 
$
—

 
$
1,484

Realized losses
(2,978
)
 
—

 
(2,978
)
Proceeds from the sale of securities (a)
122,790

 
2,426

 
125,216


(a)
Proceeds are reinvested in the nuclear decommissioning trust and coal reclamation escrow account.

 
Six Months Ended June 30,
 
Nuclear Decommissioning Trust
 
Other Special Use Funds
 
Total
2019
 
 
 
 
 
Realized gains
$
3,746

 
$
—

 
$
3,746

Realized losses
(3,105
)
 
—

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

 
93,202

 
309,354

2018
 
 
 
 
 
Realized gains
$
2,298

 
$
1

 
$
2,299

Realized losses
(5,025
)
 
—

 
(5,025
)
Proceeds from the sale of securities (a)
253,246

 
4,981

 
258,227



(a)
Proceeds are reinvested in the nuclear decommissioning trust and coal reclamation escrow account.

     The fair value of APS's fixed income securities, summarized by contractual maturities, at June 30, 2019, is as follows (dollars in thousands):
 
Nuclear Decommissioning Trust (a)
 
Coal Reclamation Escrow Account
 
Active Union Medical Trust
 
Total
Less than one year
$
37,373

 
$
22,253

 
$
40,219

 
$
99,845

1 year – 5 years
126,745

 
17,449

 
140,569

 
284,763

5 years – 10 years
113,989

 
1,807

 
—

 
115,796

Greater than 10 years
190,982

 
5,064

 
—

 
196,046

Total
$
469,089

 
$
46,573

 
$
180,788

 
$
696,450


(a)
Includes certain fixed income investments that are not due at a single maturity date. These investments have been allocated within the table based on the final payment date of the instrument.
Fair value of fixed income securities, summarized by contractual maturities
     The fair value of APS's fixed income securities, summarized by contractual maturities, at June 30, 2019, is as follows (dollars in thousands):
 
Nuclear Decommissioning Trust (a)
 
Coal Reclamation Escrow Account
 
Active Union Medical Trust
 
Total
Less than one year
$
37,373

 
$
22,253

 
$
40,219

 
$
99,845

1 year – 5 years
126,745

 
17,449

 
140,569

 
284,763

5 years – 10 years
113,989

 
1,807

 
—

 
115,796

Greater than 10 years
190,982

 
5,064

 
—

 
196,046

Total
$
469,089

 
$
46,573

 
$
180,788

 
$
696,450


(a)
Includes certain fixed income investments that are not due at a single maturity date. These investments have been allocated within the table based on the final payment date of the instrument.
v3.19.2
Changes in Accumulated Other Comprehensive Loss (Tables)
 6 Months Ended
Jun. 30, 2019
Comprehensive Income (Loss), Net of Tax, Attributable to Parent [Abstract]  
Schedule of changes in accumulated other comprehensive loss including reclassification adjustments, net of tax, by component
The following table shows the changes in Pinnacle West's consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the three and six months ended June 30, 2019 and 2018 (dollars in thousands):
 
 Pension and Other Postretirement Benefits
 
 
 
 Derivative Instruments
 
 
 
 Total
Three Months Ended June 30
 
 
 
 
 
 
 
 
 
Balance March 31, 2019
$
(45,118
)
 
 
 
$
(1,383
)
 
 
 
$
(46,501
)
OCI (loss) before reclassifications
(2,422
)
 
 
 
—

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

 
 (a)
 
404

 
(b)
 
1,287

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


 
 
 

 
 
 

Balance March 31, 2018
$
(49,494
)
 
 
 
$
(2,847
)
 
 
 
$
(52,341
)
OCI (loss) before reclassifications
(5,928
)
 
 
 
—

 
 
 
(5,928
)
Amounts reclassified from accumulated other comprehensive loss
1,189

 
 (a)
 
456

 
(b)
 
1,645

Balance June 30, 2018
$
(54,233
)
 
 
 
$
(2,391
)
 
 
 
$
(56,624
)

 
 Pension and Other Postretirement Benefits
 
 
 
 Derivative Instruments
 
 
 
 Total
Six Months Ended June 30
 
 
 
 
 
 
 
 
 
Balance December 31, 2018
$
(45,997
)
 
 
 
$
(1,711
)
 
 
 
$
(47,708
)
OCI (loss) before reclassifications
(2,422
)
 
 
 
—

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

 
 (a)
 
732

 
(b)
 
2,494

Balance June 30, 2019
$
(46,657
)
 
 
 
$
(979
)
 
 
 
$
(47,636
)
 
 
 
 
 
 
 
 
 
 
Balance December 31, 2017
$
(42,440
)
 
 
 
$
(2,562
)
 
 
 
$
(45,002
)
OCI (loss) before reclassifications
(5,928
)
 
 
 
(96
)
 
 
 
(6,024
)
Amounts reclassified from accumulated other comprehensive loss
2,089

 
 (a)
 
865

 
(b)
 
2,954

Reclassification of income tax effect related to tax reform
(7,954
)
 
 (c)
 
(598
)
 
 (c)
 
(8,552
)
Balance June 30, 2018
$
(54,233
)
 
 
 
$
(2,391
)
 
 
 
$
(56,624
)

(a)
These amounts primarily represent amortization of actuarial loss and are included in the computation of net periodic pension cost.  See Note 5.
(b)
These amounts represent realized gains and losses and are included in the computation of fuel and purchased power costs and are subject to the PSA.  See Note 7.
(c)
In 2018, the company adopted new accounting guidance and elected to reclassify income tax effects of the Tax Act on items within accumulated other comprehensive income to retained earnings.
The following table shows the changes in APS's consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the three and six months ended June 30, 2019 and 2018 (dollars in thousands): 
 
 Pension and Other Postretirement Benefits
 
 
 
 Derivative Instruments
 
 
 
 Total
Three Months Ended June 30
 
 
 
 
 
 
 
 
 
Balance March 31, 2019
$
(24,644
)
 
 
 
$
(1,383
)
 
 
 
$
(26,027
)
OCI (loss) before reclassifications
(2,414
)
 
 
 
—

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

 
 (a)
 
404

 
 (b)
 
1,165

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


 
 
 

 
 
 

Balance March 31, 2018
$
(28,004
)
 
 
 
$
(2,847
)
 
 
 
$
(30,851
)
OCI (loss) before reclassifications
(5,790
)
 
 
 
—

 
 
 
(5,790
)
Amounts reclassified from accumulated other comprehensive loss
1,026

 
 (a)
 
456

 
 (b)
 
1,482

Balance June 30, 2018
$
(32,768
)
 
 
 
$
(2,391
)
 
 
 
$
(35,159
)

 
 Pension and Other Postretirement Benefits
 
 
 
 Derivative Instruments
 
 
 
 Total
Six Months Ended June 30
 
 
 
 
 
 
 
 
 
Balance December 31, 2018
$
(25,396
)
 
 
 
$
(1,711
)
 
 
 
$
(27,107
)
OCI (loss) before reclassifications
(2,414
)
 
 
 
—

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

 
 (a)
 
732

 
 (b)
 
2,245

Balance June 30, 2019
$
(26,297
)
 
 
 
$
(979
)
 
 
 
$
(27,276
)
 
 
 
 
 
 
 
 
 
 
Balance December 31, 2017
$
(24,421
)
 
 
 
$
(2,562
)
 
 
 
$
(26,983
)
OCI (loss) before reclassifications
(5,790
)
 
 
 
(96
)
 
 
 
(5,886
)
Amounts reclassified from accumulated other comprehensive loss
1,883

 
 (a)
 
865

 
 (b)
 
2,748

Reclassification of income tax effect related to tax reform
(4,440
)
 
 (c)
 
(598
)
 
 (c)
 
(5,038
)
Balance June 30, 2018
$
(32,768
)
 
 
 
$
(2,391
)
 
 
 
$
(35,159
)




(a)
These amounts primarily represent amortization of actuarial loss and are included in the computation of net periodic pension cost.  See Note 5.
(b)
These amounts represent realized gains and losses and are included in the computation of fuel and purchased power costs and are subject to the PSA.  See Note 7.
(c)
In 2018, the company adopted new accounting guidance and elected to reclassify income tax effects of the Tax Act on items within accumulated other comprehensive income to retained earnings.
v3.19.2
Leases (Tables)
 6 Months Ended
Jun. 30, 2019
Leases [Abstract]  
Lease cost

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

Weighted average discount rate (a)
3.84
%


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

 
Six Months Ended
June 30, 2019
Cash paid for amounts included in the measurement of lease liabilities - operating cash flows (dollars in thousands):
$
11,987


The following tables provide information related to our lease costs for the three and six months ended June 30, 2019 (dollars in thousands):

 
 
Three Months Ended
June 30, 2019
 
 
Purchased Power Lease Contracts
 
Land, Property & Equipment Leases
 
Total
Operating lease cost
 
$
14,063

 
$
4,414

 
$
18,477

Variable lease cost
 
41,529

 
360

 
41,889

Short-term lease cost
 
—

 
1,812

 
1,812

Total lease cost
 
$
55,592

 
$
6,586

 
$
62,178




 
 
Six Months Ended
June 30, 2019
 
 
Purchased Power Lease Contracts
 
Land, Property & Equipment Leases
 
Total
Operating lease cost
 
$
14,063

 
$
8,762

 
$
22,825

Variable lease cost
 
58,820

 
360

 
59,180

Short-term lease cost
 
—

 
2,665

 
2,665

Total lease cost
 
$
72,883

 
$
11,787

 
$
84,670
Schedule of future minimum payments
The following table provides information related to the maturity of our operating lease liabilities at June 30, 2019 (dollars in thousands):
 
 
June 30, 2019
Year
 
Purchased Power Lease Contracts
 
Land, Property & Equipment Leases
 
Total
2019 (remaining six months of 2019)
 
$
49,051

 
$
7,335

 
$
56,386

2020
 
—

 
12,868

 
12,868

2021
 
—

 
10,029

 
10,029

2022
 
—

 
6,988

 
6,988

2023
 
—

 
5,838

 
5,838

2024
 
—

 
3,691

 
3,691

Thereafter
 
—

 
38,506

 
38,506

Total lease commitments
 
49,051

 
85,255

 
134,306

Less imputed interest
 
294

 
20,411

 
20,705

Total lease liabilities
 
$
48,757

 
$
64,844

 
$
113,601

 
We recognize lease assets and liabilities upon lease commencement. At June 30, 2019, we have additional lease arrangements that have been executed, but have not yet commenced. These arrangements primarily relate to purchased power lease contracts. These leases have commencement dates beginning in June 2020 with terms ending through October 2027. We expect the total fixed consideration paid for these arrangements, which includes both lease and nonlease payments, will approximate $705 million over the term of the arrangements.

The following table provides information related to estimated future minimum operating lease payments at December 31, 2018 (dollars in thousands):
 
 
December 31, 2018
Year
 
Purchased Power Lease Contracts
 
Land, Property & Equipment Leases
 
Total
2019
 
$
54,499

 
$
13,747

 
$
68,246

2020
 
—

 
12,428

 
12,428

2021
 
—

 
9,478

 
9,478

2022
 
—

 
6,513

 
6,513

2023
 
—

 
5,359

 
5,359

Thereafter
 
—

 
42,236

 
42,236

Total future lease commitments
 
$
54,499

 
$
89,761

 
$
144,260
v3.19.2
Consolidation and Nature of Operations (Details) - USD ($)
$ in Thousands
 6 Months Ended
Jun. 30, 2019
Jun. 30, 2018
Cash paid during the period for:    
Income taxes, net of refunds $ 10,788 $ 10,032
Interest, net of amounts capitalized 114,717 104,249
Significant non-cash investing and financing activities:    
Accrued capital expenditures 108,056 65,995
Right-of-use operating lease assets obtained in exchange for operating lease liabilities 4,562 0
Dividends accrued but not yet paid 82,824 77,821
APS    
Cash paid during the period for:    
Income taxes, net of refunds 35,573 24,689
Interest, net of amounts capitalized 107,169 98,478
Significant non-cash investing and financing activities:    
Accrued capital expenditures 108,056 65,995
Right-of-use operating lease assets obtained in exchange for operating lease liabilities 4,562 0
Dividends accrued but not yet paid $ 82,800 $ 77,800
v3.19.2
Revenue (Details) - USD ($)
$ in Thousands
 3 Months Ended 6 Months Ended
Jun. 30, 2019
Jun. 30, 2018
Jun. 30, 2019
Jun. 30, 2018
Disaggregation of Revenue [Line Items]        
Operating revenues $ 869,501 $ 974,123 $ 1,610,031 $ 1,666,837
Regulatory cost recovery revenue 12,000 20,000 32,000 27,000
Electric Service | Retail residential electric service        
Disaggregation of Revenue [Line Items]        
Operating revenues 432,568 500,247 784,134 816,922
Electric Service | Retail non-residential electric service        
Disaggregation of Revenue [Line Items]        
Operating revenues 395,929 435,500 728,597 778,689
Electric Service | Wholesale energy sales        
Disaggregation of Revenue [Line Items]        
Operating revenues 21,991 15,392 58,443 27,481
Transmission Services For Others        
Disaggregation of Revenue [Line Items]        
Operating revenues 15,157 15,489 30,406 30,334
Other sources        
Disaggregation of Revenue [Line Items]        
Operating revenues 3,856 7,495 8,451 13,411
Electric and Transmission Service        
Disaggregation of Revenue [Line Items]        
Operating revenues $ 858,000 $ 954,000 $ 1,578,000 $ 1,640,000
v3.19.2
Long-Term Debt and Liquidity Matters - Narrative (Details)
May 09, 2019
USD ($)
Mar. 01, 2019
USD ($)
Feb. 26, 2019
USD ($)
Jun. 30, 2019
USD ($)
Facility
May 08, 2019
USD ($)
Feb. 28, 2019
USD ($)
Pinnacle West | Revolving Credit Facility | Revolving credit facility maturing June 2019            
Long-Term Debt and Liquidity Matters            
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders (up to)         $ 150,000,000  
Pinnacle West | Revolving Credit Facility | Revolving credit Facility maturing July 2023            
Long-Term Debt and Liquidity Matters            
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders (up to)       $ 300,000,000    
Current borrowing capacity on credit facility       200,000,000    
Long-term line of credit       0    
Pinnacle West | Term Loan            
Long-Term Debt and Liquidity Matters            
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders (up to) $ 50,000,000          
Long-term line of credit       46,000,000    
Pinnacle West | Letter of Credit | Revolving credit Facility maturing July 2023            
Long-Term Debt and Liquidity Matters            
Outstanding letters of credit       0    
Pinnacle West | Commercial paper | Revolving credit Facility maturing July 2023            
Long-Term Debt and Liquidity Matters            
Commercial paper       10,000,000    
APS | Term Loan            
Long-Term Debt and Liquidity Matters            
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders (up to)     $ 200,000,000      
APS | Senior notes            
Long-Term Debt and Liquidity Matters            
Debt instrument, face amount           $ 300,000,000
Debt instrument, interest rate   8.75%       4.25%
APS | Revolving Credit Facility | Revolving credit Facility maturing July 2023            
Long-Term Debt and Liquidity Matters            
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders (up to)       700,000,000    
Current borrowing capacity on credit facility       500,000,000    
APS | Revolving Credit Facility | Term Loan Facility            
Long-Term Debt and Liquidity Matters            
Extinguishment of debt   $ 500,000,000        
APS | Revolving Credit Facility | Revolving Credit Facility Maturing in 2022 and 2023            
Long-Term Debt and Liquidity Matters            
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders (up to)       1,400,000,000    
Current borrowing capacity on credit facility       1,000,000,000    
Long-term line of credit       $ 0    
Number of line of credit facilities | Facility       2    
APS | Revolving Credit Facility | Revolving credit facility maturing June 2022            
Long-Term Debt and Liquidity Matters            
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders (up to)       $ 700,000,000    
Current borrowing capacity on credit facility       500,000,000    
APS | Commercial paper            
Long-Term Debt and Liquidity Matters            
Maximum commercial paper support available under credit facility       500,000,000    
APS | Commercial paper | Revolving Credit Facility Maturing in 2022 and 2023            
Long-Term Debt and Liquidity Matters            
Commercial paper       $ 377,000,000    
LIBOR | Pinnacle West | Term Loan            
Long-Term Debt and Liquidity Matters            
Debt instrument, basis spread on variable rate 0.55%          
LIBOR | APS | Term Loan            
Long-Term Debt and Liquidity Matters            
Debt instrument, basis spread on variable rate     0.50%      
v3.19.2
Long-Term Debt and Liquidity Matters - Estimated Fair Value of Long-Term Debt (Details) - USD ($)
$ in Thousands
Jun. 30, 2019
Dec. 31, 2018
Estimated fair value of long-term debt, including current maturities    
Carrying Amount $ 5,136,879 $ 5,138,232
Fair Value 5,568,215 5,233,563
Pinnacle West    
Estimated fair value of long-term debt, including current maturities    
Carrying Amount 449,111 448,796
Fair Value 449,124 443,955
APS    
Estimated fair value of long-term debt, including current maturities    
Carrying Amount 4,687,768 4,689,436
Fair Value $ 5,119,091 $ 4,789,608
v3.19.2
Regulatory Matters - Retail Rate Case Filing (Details) - Retail Rate Case Filing with Arizona Corporation Commission - ACC - APS
Jan. 03, 2018
Customer
Nov. 13, 2017
USD ($)
Mar. 27, 2017
USD ($)
$ / kWh
Jun. 30, 2019
appeal
Public Utilities, General Disclosures [Line Items]        
Approximate percentage of increase in average customer bill     3.28%  
Approximate percentage of increase in average residential customer bill 4.54%   4.54%  
Net retail base rate, increase     $ 94,600,000  
Non-fuel and non-depreciation base rate, increase     87,200,000  
Fuel-related base rate decrease     53,600,000  
Base rate increase, changes in depreciation schedules     $ 61,000,000.0  
Authorized return on common equity (as a percent)     10.00%  
Percentage of debt in capital structure     44.20%  
Percentage of common equity in capital structure     55.80%  
Rate matter, resource comparison proxy for exported energy (in dollars per kWh) | $ / kWh     0.129  
Periodic metering infrastructure opt-out fee   $ 5    
Number of appeals | appeal       2
Number of customers named in complaint | Customer 25      
AZ Sun Program Phase 2        
Public Utilities, General Disclosures [Line Items]        
Public utilities, minimum annual renewable energy standard and tariff     $ 10,000,000  
Public utilities, maximum annual renewable energy standard and tariff     $ 15,000,000  
Minimum        
Public Utilities, General Disclosures [Line Items]        
Rate matter, environmental surcharge cap rate (in dollars per kWh) | $ / kWh     0.00016  
Maximum        
Public Utilities, General Disclosures [Line Items]        
Rate matter, environmental surcharge cap rate (in dollars per kWh) | $ / kWh     0.00050  
v3.19.2
Regulatory Matters - Cost Recovery Mechanism and Net Metering (Details)
 1 Months Ended 6 Months Ended 12 Months Ended
Jun. 01, 2019
USD ($)
Apr. 10, 2019
USD ($)
Feb. 15, 2019
USD ($)
Feb. 01, 2019
$ / kWh
Aug. 13, 2018
USD ($)
Jun. 01, 2018
USD ($)
May 01, 2018
$ / kWh
Feb. 20, 2018
Feb. 15, 2018
USD ($)
Feb. 01, 2018
$ / kWh
Jan. 08, 2018
USD ($)
Nov. 20, 2017
USD ($)
Aug. 19, 2017
$ / kWh
Jun. 01, 2017
USD ($)
Feb. 01, 2017
$ / kWh
Jan. 13, 2017
USD ($)
Dec. 20, 2016
$ / kWh
Feb. 01, 2016
$ / kWh
Aug. 31, 2016
Jun. 30, 2019
USD ($)
Jun. 30, 2018
USD ($)
Dec. 31, 2019
USD ($)
Dec. 31, 2017
USD ($)
$ / kWh
Dec. 31, 2012
$ / kWh
Jul. 01, 2019
USD ($)
Dec. 31, 2018
USD ($)
Jun. 29, 2018
USD ($)
Nov. 14, 2017
USD ($)
Sep. 01, 2017
USD ($)
Jun. 30, 2017
USD ($)
Change in regulatory asset                                                            
Deferred fuel and purchased power costs — current period                                       $ 16,702,000 $ 50,112,000                  
Amounts charged to customers                                       (23,307,000) (50,851,000)                  
Ballot Initiative, proposed required energy supply from renewable sources (as a percent)               50.00%                                            
APS                                                            
Change in regulatory asset                                                            
Deferred fuel and purchased power costs — current period                                       16,702,000 50,112,000                  
Amounts charged to customers                                       $ (23,307,000) (50,851,000)                  
Lost Fixed Cost Recovery Mechanisms | APS                                                            
Change in regulatory asset                                                            
Fixed costs recoverable per residential power lost (in dollars per kWh) | $ / kWh                                               0.031            
Fixed costs recoverable per non-residential power lost (in dollars per kWh) | $ / kWh                                               0.023            
Fixed cost recoverable per power lost (in dollars per kWh) | $ / kWh                                             0.025              
Percentage of retail revenues                                       1.00%                    
Amount of adjustment representing prorated sales losses approval                               $ 63,700,000                            
Increase (decrease) in amount of adjustment representing prorated sales losses     $ (24,500,000)           $ (3,000,000)                                          
Amount of adjustment representing prorated sales losses pending approval     $ 36,200,000           $ 60,700,000                                          
ACC | APS                                                            
Change in regulatory asset                                                            
Program term                                     2 years                      
Gross-up for revenue requirement of rate regulation   $ 34,500,000     $ 86,500,000           $ 119,100,000                                      
Deferred taxes amortization, period   28 years 6 months                                                        
ACC | RES | APS                                                            
Settlement Agreement                                                            
Plan term                                       5 years                    
ACC | RES 2018 | APS                                                            
Settlement Agreement                                                            
Amount of proposed budget                                                     $ 89,900,000     $ 90,000,000
ACC | RES 2018 | APS | Solar Communities                                                            
Change in regulatory asset                                                            
Program term                       3 years                                    
ACC | Demand Side Management Adjustor Charge 2018 | APS                                                            
Settlement Agreement                                                            
Amount of proposed budget                                                   $ 34,100,000   $ 52,600,000 $ 52,600,000  
ACC | Power Supply Adjustor (PSA) | APS                                                            
Change in regulatory asset                                                            
Beginning balance                                       $ 37,164,000 75,637,000 $ 37,164,000                
Deferred fuel and purchased power costs — current period                                       16,702,000 50,112,000                  
Amounts charged to customers                                       (23,307,000) (50,851,000)                  
Ending balance                                       30,559,000 $ 74,898,000   $ 75,637,000              
PSA rate (in dollars per kWh) | $ / kWh       0.001658           0.004555     0.000555   (0.001348)                              
PSA rate for prior year (in dollars per kWh) | $ / kWh       0.000536           0.002009     0.000876   (0.001027)                              
Forward component of increase in PSA (in dollars per kWh) | $ / kWh       0.001122           0.002546     (0.000321)   (0.000321)                              
Maximum increase (decrease) in PSA rate | $ / kWh                   0.004                                        
Fuel and purchased power costs, excess annual limit                                       $ 16,400,000                    
ACC | Net Metering | APS                                                            
Change in regulatory asset                                                            
Cost of service, resource comparison proxy method, maximum annual percentage decrease                                 10.00%                          
Cost of service for interconnected DG system customers, grandfathered period                                 20 years                          
Cost of service for new customers, guaranteed export price period                                 10 years                          
First-year export energy price (in dollars per kWh) | $ / kWh                                 0.129                          
Second-year export energy price (in dollars per kWh) | $ / kWh             0.116                                              
United States Federal Energy Regulatory Commission | Open Access Transmission Tariff | APS                                                            
Change in regulatory asset                                                            
Increase (decrease) in annual wholesale transmission rates $ (4,900,000)         $ (22,700,000)               $ (35,100,000)                                
Cost Recovery Mechanisms | ACC | Power Supply Adjustor (PSA) | APS                                                            
Change in regulatory asset                                                            
Historical component of increase in PSA (in dollars per kWh) | $ / kWh       (0.002897)                           0.001678                        
Minimum | ACC | RES 2018 | APS | Solar Communities                                                            
Change in regulatory asset                                                            
Required annual capital investment                       $ 10,000,000                                    
Maximum | ACC | RES 2018 | APS | Solar Communities                                                            
Change in regulatory asset                                                            
Required annual capital investment                       $ 15,000,000                                    
Subsequent Event | ACC | RES 2018 | APS                                                            
Settlement Agreement                                                            
Amount of proposed budget                                                 $ 86,300,000          
Forecast | Minimum | ACC | APS                                                            
Change in regulatory asset                                                            
Operating Results                                           5,000,000                
Forecast | Maximum | ACC | APS                                                            
Change in regulatory asset                                                            
Operating Results                                           $ 10,000,000                
v3.19.2
Regulatory Matters - Four Corners and Cholla (Details) - APS - USD ($)
$ in Millions
 1 Months Ended 3 Months Ended 6 Months Ended
Dec. 23, 2014
Dec. 30, 2013
Sep. 30, 2018
Apr. 30, 2018
Jun. 30, 2016
Jun. 30, 2019
Dec. 31, 2015
SCE | Four Corners Units 4 and 5              
Business Acquisition [Line Items]              
Ownership interest acquired   48.00%          
Settlement agreement, ACC approved rate adjustment, annualized customer impact $ 57.1   $ 58.5 $ 67.5      
Net receipt due to negotiation of alternate arrangement   $ 40.0          
Four Corners cost deferral | SCE | Four Corners Units 4 and 5              
Business Acquisition [Line Items]              
Regulatory assets, non-current           $ 44.0  
Regulatory noncurrent asset amortization period           10 years  
Retired power plant costs              
Business Acquisition [Line Items]              
Net book value           $ 81.0  
Navajo Plant              
Business Acquisition [Line Items]              
Net book value           $ 83.0  
Four Corners | SCE              
Business Acquisition [Line Items]              
Regulatory assets, non-current             $ 12.0
Regulatory asset, write off amount         $ 12.0    
v3.19.2
Regulatory Matters - Schedule of Regulatory Assets (Details) - USD ($)
$ in Thousands
Jun. 30, 2019
Dec. 31, 2018
Detail of regulatory assets    
Current $ 184,459 $ 166,902
Non-Current 1,321,431 1,342,941
Pension    
Detail of regulatory assets    
Current 0 0
Non-Current 712,907 733,351
Retired power plant costs    
Detail of regulatory assets    
Current 28,182 28,182
Non-Current 153,122 167,164
Income taxes — allowance for funds used during construction (AFUDC) equity    
Detail of regulatory assets    
Current 6,457 6,457
Non-Current 152,388 151,467
Deferred fuel and purchased power — mark-to-market (Note 7)    
Detail of regulatory assets    
Current 55,729 31,728
Non-Current 21,516 23,768
Deferred fuel and purchased power    
Detail of regulatory assets    
Current 30,559 37,164
Non-Current 0 0
Four Corners cost deferral    
Detail of regulatory assets    
Current 8,077 8,077
Non-Current 36,190 40,228
Income taxes — investment tax credit basis adjustment    
Detail of regulatory assets    
Current 1,079 1,079
Non-Current 25,170 25,522
Lost fixed cost recovery    
Detail of regulatory assets    
Current 25,746 32,435
Non-Current 0 0
Palo Verde VIEs (Note 6)    
Detail of regulatory assets    
Current 0 0
Non-Current 20,325 20,015
Deferred compensation    
Detail of regulatory assets    
Current 0 0
Non-Current 37,572 36,523
Deferred property taxes    
Detail of regulatory assets    
Current 8,569 8,569
Non-Current 62,072 66,356
Loss on reacquired debt    
Detail of regulatory assets    
Current 1,637 1,637
Non-Current 12,850 13,668
Tax expense of Medicare subsidy    
Detail of regulatory assets    
Current 1,235 1,235
Non-Current 5,772 6,176
TCA balancing account    
Detail of regulatory assets    
Current 5,381 3,860
Non-Current 3,895 772
AG-1 deferral    
Detail of regulatory assets    
Current 2,787 2,654
Non-Current 4,110 5,819
Mead-Phoenix transmission line CIAC    
Detail of regulatory assets    
Current 332 332
Non-Current 9,878 10,044
Coal reclamation    
Detail of regulatory assets    
Current 1,546 1,546
Non-Current 16,250 15,607
SCR deferral    
Detail of regulatory assets    
Current 0 0
Non-Current 37,919 23,276
Tax expense adjustor mechanism    
Detail of regulatory assets    
Current 3,149 0
Non-Current 0 0
Ocotillo deferral    
Detail of regulatory assets    
Current 0 0
Non-Current 9,495 0
Other    
Detail of regulatory assets    
Current 3,994 1,947
Non-Current $ 0 $ 3,185
v3.19.2
Regulatory Matters - Schedule of Regulatory Liabilities (Details) - USD ($)
$ in Thousands
Jun. 30, 2019
Dec. 31, 2018
Detail of regulatory liabilities    
Current $ 231,857 $ 165,876
Non-Current 2,287,892 2,325,976
Asset retirement obligations    
Detail of regulatory liabilities    
Current 0 0
Non-Current 359,912 278,585
Removal costs    
Detail of regulatory liabilities    
Current 50,701 39,866
Non-Current 153,847 177,533
Other postretirement benefits    
Detail of regulatory liabilities    
Current 37,821 37,864
Non-Current 105,214 125,903
Income taxes — deferred investment tax credit    
Detail of regulatory liabilities    
Current 2,164 2,164
Non-Current 50,414 51,120
Income taxes — change in rates    
Detail of regulatory liabilities    
Current 2,764 2,769
Non-Current 69,171 70,069
Spent nuclear fuel    
Detail of regulatory liabilities    
Current 6,578 6,503
Non-Current 53,769 57,002
Renewable energy standard    
Detail of regulatory liabilities    
Current 40,639 44,966
Non-Current 4,950 20
Demand side management    
Detail of regulatory liabilities    
Current 7,191 14,604
Non-Current 24,146 4,123
Sundance maintenance    
Detail of regulatory liabilities    
Current 1,641 1,278
Non-Current 15,495 17,228
Deferred gains on utility property    
Detail of regulatory liabilities    
Current 3,423 4,423
Non-Current 5,372 6,581
Four Corners coal reclamation    
Detail of regulatory liabilities    
Current 1,858 1,858
Non-Current 17,540 17,871
Tax expense adjustor mechanism    
Detail of regulatory liabilities    
Current 1,663 3,237
Non-Current 0 0
Other    
Detail of regulatory liabilities    
Current 461 42
Non-Current 8,213 3,541
ACC | Excess deferred income taxes - ACC - Tax Cuts and Jobs Act (a)    
Detail of regulatory liabilities    
Current 68,651 0
Non-Current 1,178,216 1,272,709
United States Federal Energy Regulatory Commission | Excess deferred income taxes - ACC - Tax Cuts and Jobs Act (a)    
Detail of regulatory liabilities    
Current 6,302 6,302
Non-Current $ 241,633 $ 243,691
v3.19.2
Retirement Plans and Other Postretirement Benefits - Narrative (Details)
 6 Months Ended
Jun. 30, 2019
USD ($)
Pension Benefits  
Contributions  
Voluntary employer contributions to pension plan $ 120,000,000
Minimum employer contributions for the next three years 0
Maximum employer contributions for the next two years (up to) 350,000,000
Other Benefits  
Contributions  
Estimated future employer contributions in next three years $ 0
v3.19.2
Retirement Plans and Other Postretirement Benefits - Schedule of Net Benefit Cost (Details) - USD ($)
$ in Thousands
 3 Months Ended 6 Months Ended
Jun. 30, 2019
Jun. 30, 2018
Jun. 30, 2019
Jun. 30, 2018
Amortization of:        
Portion of cost (credit) charged to expense $ (6,374) $ (12,006) $ (11,488) $ (24,865)
Pension Benefits        
Retirement Plans and Other Benefits        
Service cost — benefits earned during the period 12,408 14,121 24,951 28,334
Interest cost on benefit obligation 34,069 31,338 68,421 62,345
Expected return on plan assets (43,049) (45,759) (85,942) (91,426)
Amortization of:        
Prior service credit 0 0 0 0
Net actuarial loss 10,053 8,259 21,292 16,041
Net periodic benefit cost (credit) 13,481 7,959 28,722 15,294
Portion of cost (credit) charged to expense 7,000 2,769 15,244 5,011
Other Benefits        
Retirement Plans and Other Benefits        
Service cost — benefits earned during the period 4,470 5,445 9,184 10,550
Interest cost on benefit obligation 7,421 6,973 14,947 14,074
Expected return on plan assets (9,603) (10,520) (19,206) (21,041)
Amortization of:        
Prior service credit (9,455) (9,461) (18,910) (18,921)
Net actuarial loss 0 0 0 0
Net periodic benefit cost (credit) (7,167) (7,563) (13,985) (15,338)
Portion of cost (credit) charged to expense $ (5,063) $ (5,119) $ (9,880) $ (10,724)
v3.19.2
Palo Verde Sale Leaseback Variable Interest Entities - Narrative (Details)
 3 Months Ended 6 Months Ended
Jun. 30, 2019
USD ($)
power_plant
Jun. 30, 2018
USD ($)
Jun. 30, 2019
USD ($)
power_plant
Lease
Jun. 30, 2018
USD ($)
Dec. 31, 1986
Trust
Palo Verde Sale Leaseback Variable Interest Entities          
Increase in net income due to consolidation of Palo Verde Sale Leaseback Trusts $ 4,874,000 $ 4,874,000 $ 9,747,000 $ 9,747,000  
APS          
Palo Verde Sale Leaseback Variable Interest Entities          
Number of VIE lessor trusts 3   3   3
Increase in net income due to consolidation of Palo Verde Sale Leaseback Trusts $ 4,874,000 4,874,000 $ 9,747,000 9,747,000  
APS | Consolidation of VIEs          
Palo Verde Sale Leaseback Variable Interest Entities          
Increase in net income due to consolidation of Palo Verde Sale Leaseback Trusts $ 5,000,000 $ 5,000,000 10,000,000 $ 10,000,000  
Initial loss exposure to the VIE's noncontrolling equity participants during lease extension period     299,000,000    
Maximum loss exposure to the VIE's noncontrolling equity participants during lease extension period     $ 456,000,000    
APS | Consolidation of VIEs | Through 2023          
Palo Verde Sale Leaseback Variable Interest Entities          
Number of leases under which assets are retained | Lease     1    
APS | Consolidation of VIEs | Through 2033          
Palo Verde Sale Leaseback Variable Interest Entities          
Number of leases under which assets are retained | Lease     2    
APS | Consolidation of VIEs | Period 2017 through 2023          
Palo Verde Sale Leaseback Variable Interest Entities          
Annual lease payments     $ 23,000,000    
APS | Consolidation of VIEs | Period 2024 through 2033          
Palo Verde Sale Leaseback Variable Interest Entities          
Annual lease payments     $ 16,000,000    
APS | Consolidation of VIEs | Period 2024 through 2033 | Maximum          
Palo Verde Sale Leaseback Variable Interest Entities          
Lease period (up to)     2 years    
v3.19.2
Palo Verde Sale Leaseback Variable Interest Entities - Schedule of VIEs (Details) - USD ($)
$ in Thousands
Jun. 30, 2019
Dec. 31, 2018
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets    
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation $ 103,841 $ 105,775
Equity — Noncontrolling interests 124,165 125,790
APS    
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets    
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation 103,841 105,775
Equity — Noncontrolling interests 124,165 125,790
APS | Consolidation of VIEs    
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets    
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation 103,841 105,775
Equity — Noncontrolling interests $ 124,165 $ 125,790
v3.19.2
Derivative Accounting - Narrative (Details) - USD ($)
 3 Months Ended 6 Months Ended
Jun. 30, 2019
Jun. 30, 2018
Jun. 30, 2019
Jun. 30, 2018
Commodity Contracts        
Derivative Accounting        
Additional collateral to counterparties for energy related non-derivative instrument contracts $ 95,000,000   $ 95,000,000  
Commodity Contracts | Designated as Hedging Instruments        
Derivative Accounting        
Amount reclassified from accumulated other comprehensive income to earnings related to discontinued cash flow hedges $ 0 $ 0 0 $ 0
Estimated loss before income taxes to be reclassified from accumulated other comprehensive income     $ 1,000,000  
APS        
Derivative Accounting        
Percentage of unrealized gains and losses on certain derivatives deferred for future rate treatment 100.00%   100.00%  
v3.19.2
Derivative Accounting - Schedule of Gross Notional Amounts Outstanding (Details) - Commodity Contracts
GWh in Thousands, Bcf in Thousands
Jun. 30, 2019
GWh
Bcf
Dec. 31, 2018
GWh
Bcf
Outstanding gross notional amount of derivatives    
Power | GWh 1,000 250
Gas | Bcf 218 218
v3.19.2
Derivative Accounting - Gains and Losses from Derivative Instruments (Details) - Commodity Contracts - USD ($)
 3 Months Ended 6 Months Ended
Jun. 30, 2019
Jun. 30, 2018
Jun. 30, 2019
Jun. 30, 2018
Designated as Hedging Instruments        
Gains and losses from derivative instruments        
Amount reclassified from accumulated other comprehensive income to earnings related to discontinued cash flow hedges $ 0 $ 0 $ 0 $ 0
Designated as Hedging Instruments | Fuel and purchased power        
Gains and losses from derivative instruments        
Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (538,000) (606,000) (974,000) (1,097,000)
Not Designated as Hedging Instruments        
Gains and losses from derivative instruments        
Net Gain (Loss) Recognized in Income (49,686,000) 3,043,000 (41,516,000) (32,265,000)
Not Designated as Hedging Instruments | Operating revenues        
Gains and losses from derivative instruments        
Net Gain (Loss) Recognized in Income 0 (341,000) 0 (1,560,000)
Not Designated as Hedging Instruments | Fuel and purchased power        
Gains and losses from derivative instruments        
Net Gain (Loss) Recognized in Income $ (49,686,000) $ 3,384,000 $ (41,516,000) $ (30,705,000)
v3.19.2
Derivative Accounting - Derivative Instruments in the Balance Sheets (Details) - USD ($)
Jun. 30, 2019
Dec. 31, 2018
Assets    
Gross Recognized Derivatives $ 535,000 $ 1,113,000
Liabilities    
Amount Reported on Balance Sheets (80,426,000) (60,037,000)
Commodity Contracts    
Assets    
Gross Recognized Derivatives 3,634,000 3,142,000
Amounts Offset (2,939,000) (2,185,000)
Net Recognized Derivatives 695,000 957,000
Other 160,000 (156,000)
Amount Reported on Balance Sheets 535,000 1,113,000
Liabilities    
Gross Recognized Derivatives (82,180,000) (60,912,000)
Amounts Offset 2,939,000 2,185,000
Net Recognized Derivatives (79,241,000) (58,727,000)
Other (1,185,000) (1,310,000)
Amount Reported on Balance Sheets (80,426,000) (60,037,000)
Assets and Liabilities    
Gross Recognized Derivatives (78,546,000) (57,770,000)
Amounts Offset 0 0
Net Recognized Derivatives (78,546,000) (57,770,000)
Other (1,345,000) (1,154,000)
Amount Reported on Balance Sheets (79,891,000) (58,924,000)
Commodity Contracts | Current assets    
Assets    
Gross Recognized Derivatives 3,558,000 3,106,000
Amounts Offset (2,939,000) (2,149,000)
Net Recognized Derivatives 619,000 957,000
Other 160,000 (156,000)
Amount Reported on Balance Sheets 459,000 1,113,000
Commodity Contracts | Investments and other assets    
Assets    
Gross Recognized Derivatives 76,000 36,000
Amounts Offset 0 (36,000)
Net Recognized Derivatives 76,000 0
Other 0 0
Amount Reported on Balance Sheets 76,000 0
Commodity Contracts | Current liabilities    
Liabilities    
Gross Recognized Derivatives (60,588,000) (36,345,000)
Amounts Offset 2,939,000 2,149,000
Net Recognized Derivatives (57,649,000) (34,196,000)
Other (1,185,000) (1,310,000)
Amount Reported on Balance Sheets (58,834,000) (35,506,000)
Commodity Contracts | Deferred credits and other    
Liabilities    
Gross Recognized Derivatives (21,592,000) (24,567,000)
Amounts Offset 0 36,000
Net Recognized Derivatives (21,592,000) (24,531,000)
Other 0 0
Amount Reported on Balance Sheets $ (21,592,000) $ (24,531,000)
v3.19.2
Derivative Accounting - Credit Risk and Credit Related Contingent Features (Details) - Commodity Contracts
$ in Thousands
Jun. 30, 2019
USD ($)
Credit Risk and Credit-Related Contingent Features  
Aggregate fair value of derivative instruments in a net liability position $ 82,064
Cash collateral posted 0
Additional cash collateral in the event credit-risk-related contingent features were fully triggered $ 80,804
v3.19.2
Commitments and Contingencies - Palo Verde Nuclear Generating Station and Contractual Obligations (Details)
 2 Months Ended 6 Months Ended 84 Months Ended
Oct. 31, 2018
USD ($)
Aug. 18, 2014
USD ($)
Apr. 10, 2019
USD ($)
Jun. 30, 2019
USD ($)
power_plant
Jun. 30, 2018
USD ($)
time_period
claim
Dec. 31, 1986
Trust
Commitments and Contingencies            
Purchase obligation, increase       $ 100,000,000    
Breach of Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste            
Commitments and Contingencies            
Litigation settlement amount $ 10,200,000 $ 57,400,000 $ 10,200,000   $ 74,200,000  
APS            
Commitments and Contingencies            
Maximum insurance against public liability per occurrence for a nuclear incident (up to)       13,900,000,000    
Maximum available nuclear liability insurance (up to)       450,000,000    
Remaining nuclear liability insurance through mandatory industry wide retrospective assessment program       13,500,000,000    
Maximum retrospective premium assessment per reactor for each nuclear liability incident       137,600,000    
Annual limit per incident with respect to maximum retrospective premium assessment       $ 20,500,000    
Number of VIE lessor trusts       3   3
Maximum potential retrospective assessment per incident of APS       $ 120,100,000    
Annual payment limitation with respect to maximum potential retrospective premium assessment       17,900,000    
Amount of "all risk" (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde       2,800,000,000    
Maximum amount that APS could incur under the current NEIL policies for each retrospective assessment       25,500,000    
Collateral assurance provided based on rating triggers       $ 73,400,000    
Period to provide collateral assurance based on rating triggers       20 days    
APS | Breach of Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste            
Commitments and Contingencies            
Litigation settlement amount $ 3,000,000.0 $ 16,700,000 $ 3,000,000.0   $ 21,600,000  
Number of claims submitted | claim         4  
Number of settlement agreement time periods | time_period         4  
v3.19.2
Commitments and Contingencies - Superfund-Related Matters, Southwest Power Outage and Clean Air Act (Details) - APS - Contaminated groundwater wells
$ in Millions
 6 Months Ended
Apr. 05, 2018
plaintiff
Dec. 16, 2016
plaintiff
Aug. 06, 2013
Defendant
Jun. 30, 2019
USD ($)
Loss Contingencies [Line Items]        
Costs related to investigation and study under Superfund site | $       $ 2
Number of defendants against whom Roosevelt Irrigation District (RID) filed lawsuit | Defendant     24  
Number of plaintiffs   2    
Settled Litigation        
Loss Contingencies [Line Items]        
Number of plaintiffs 2      
v3.19.2
Commitments and Contingencies - Environmental Matters and Financial Assurances (Details) - USD ($)
$ in Millions
 6 Months Ended 12 Months Ended
Jul. 03, 2018
Jul. 06, 2016
Jun. 30, 2019
Dec. 31, 2017
Dec. 31, 2018
APS | Letters of Credit Expiring in 2020          
Financial Assurances          
Outstanding letters of credit     $ 1.7    
APS | Surety Bonds Expiring in 2020          
Financial Assurances          
Surety bonds expiring, amount     17.0    
4C Acquisition, LLC | Four Corners          
Environmental Matters          
Percentage of share of cost of control   7.00%      
4C Acquisition, LLC | Coal Supply Agreement Arbitration | Four Corners          
Four Corners Coal Supply Agreement          
Proceeds from operating and maintenance cost reimbursement       $ 10.0  
Reimbursement payments due to 4CA     $ 10.0   $ 20.0
NTEC | Four Corners          
Four Corners Coal Supply Agreement          
Option to purchase ownership interest (as a percent) 7.00% 7.00%      
Proceeds from operating and maintenance cost reimbursement $ 70.0        
NTEC | Coal Supply Agreement Arbitration | Four Corners          
Four Corners Coal Supply Agreement          
Option to purchase ownership interest (as a percent)   7.00%      
Regional Haze Rules | APS | Four Corners Units 4 and 5          
Environmental Matters          
Percentage of share of cost of control     63.00%    
Expected environmental cost     $ 400.0    
Regional Haze Rules | APS | Natural gas tolling contract obligations | Four Corners Units 4 and 5          
Environmental Matters          
Additional percentage share of cost of control     7.00%    
Regional Haze Rules | APS | Four Corners | Four Corners Units 4 and 5          
Environmental Matters          
Site contingency increase in loss exposure not accrued, best estimate     $ 45.0    
Regional Haze Rules | APS | Navajo Plant          
Environmental Matters          
Expected environmental cost     200.0    
Coal combustion waste | APS | Four Corners          
Environmental Matters          
Site contingency increase in loss exposure not accrued, best estimate     22.0    
Coal combustion waste | APS | Navajo Plant          
Environmental Matters          
Site contingency increase in loss exposure not accrued, best estimate     1.0    
Coal combustion waste | APS | Cholla and Four Corners          
Environmental Matters          
Site contingency increase in loss exposure not accrued, best estimate     5.0    
Minimum | Coal combustion waste | APS | Cholla          
Environmental Matters          
Site contingency increase in loss exposure not accrued, best estimate     $ 15.0    
v3.19.2
Other Income and Other Expense (Details) - USD ($)
$ in Thousands
 3 Months Ended 6 Months Ended
Jun. 30, 2019
Jun. 30, 2018
Jun. 30, 2019
Jun. 30, 2018
Other income:        
Interest income $ 2,699 $ 2,408 $ 5,001 $ 4,299
Miscellaneous 5 2 28 4
Total other income 12,885 6,598 20,054 10,583
Other expense:        
Non-operating costs (3,481) (3,278) (6,185) (4,924)
Investment losses — net (491) (174) (729) (350)
Miscellaneous (378) (319) (1,794) (1,726)
Total other expense (4,350) (3,771) (8,708) (7,000)
APS        
Other income:        
Interest income 1,504 2,046 3,054 3,724
Miscellaneous 6 1 28 3
Total other income 11,691 6,235 18,107 10,007
Other expense:        
Non-operating costs (3,049) (3,057) (5,517) (4,596)
Miscellaneous (379) (315) (1,789) (1,722)
Total other expense (3,428) (3,372) (7,306) (6,318)
SCR deferral        
Other income:        
Debt return on Four Corners SCR (Note 4) 4,887 4,188 9,731 6,280
SCR deferral | APS        
Other income:        
Debt return on Four Corners SCR (Note 4) 4,887 4,188 9,731 6,280
Ocotillo deferral        
Other income:        
Debt return on Four Corners SCR (Note 4) 5,294 0 5,294 0
Ocotillo deferral | APS        
Other income:        
Debt return on Four Corners SCR (Note 4) $ 5,294 $ 0 $ 5,294 $ 0
v3.19.2
Earnings Per Share (Details) - USD ($)
$ / shares in Units, shares in Thousands, $ in Thousands
 3 Months Ended 6 Months Ended
Jun. 30, 2019
Jun. 30, 2018
Jun. 30, 2019
Jun. 30, 2018
Earnings Per Share [Abstract]        
Net income attributable to common shareholders $ 144,145 $ 166,738 $ 162,063 $ 169,959
Weighted average common shares outstanding - basic (in shares) 112,337 112,115 112,381 112,067
Net effect of dilutive securities:        
Contingently issuable performance shares and restricted stock units (in shares) 314 356 353 415
Weighted average common shares outstanding — diluted (in shares) 112,651 112,471 112,734 112,482
Earnings per weighted-average common share outstanding        
Net income attributable to common shareholders - basic (in dollars per share) $ 1.28 $ 1.49 $ 1.44 $ 1.52
Net income attributable to common shareholders - diluted (in dollars per share) $ 1.28 $ 1.48 $ 1.44 $ 1.51
v3.19.2
Fair Value Measurements - Assets and Liabilities Measured on a Recurring Basis (Details) - USD ($)
$ in Thousands
Jun. 30, 2019
Dec. 31, 2018
Assets    
Cash equivalents   $ 1,200
Commodity contracts, assets $ 535 1,113
Commodity contracts, liabilities (3,099) (2,029)
Nuclear decommissioning trust 950,448 851,134
Nuclear decommissioning trust, other 476,040 398,953
Other special use funds 241,558 236,101
Other special use funds, other 997 593
Total assets 1,192,541 1,089,548
Total assets, other 473,938 397,517
Liabilities    
Total, other 1,755 875
Amount reported on balance sheet (80,426) (60,037)
Equity securities    
Assets    
Nuclear decommissioning trust 11,984 7,351
Nuclear decommissioning trust, other 6,665 2,148
Other special use funds 14,197 45,723
Other special use funds, other 997 593
U.S. commingled equity funds    
Assets    
Nuclear decommissioning trust 469,375 396,805
U.S. Treasury debt    
Assets    
Nuclear decommissioning trust 162,044 148,173
Other special use funds 214,712 173,310
Corporate debt    
Assets    
Nuclear decommissioning trust 115,674 96,656
Mortgage-backed securities    
Assets    
Nuclear decommissioning trust 113,179 113,115
Municipal bonds    
Assets    
Nuclear decommissioning trust 67,158 79,073
Other special use funds 12,649 17,068
Other fixed income    
Assets    
Nuclear decommissioning trust 11,034 9,961
Quoted Prices in Active Markets for Identical Assets (Level 1)    
Assets    
Cash equivalents   1,200
Commodity contracts, assets 0 0
Nuclear decommissioning trust 167,363 153,376
Other special use funds 227,912 218,440
Total assets 395,275 373,016
Liabilities    
Gross derivative liability 0 0
Quoted Prices in Active Markets for Identical Assets (Level 1) | Equity securities    
Assets    
Nuclear decommissioning trust 5,319 5,203
Other special use funds 13,200 45,130
Quoted Prices in Active Markets for Identical Assets (Level 1) | U.S. commingled equity funds    
Assets    
Nuclear decommissioning trust 0 0
Quoted Prices in Active Markets for Identical Assets (Level 1) | U.S. Treasury debt    
Assets    
Nuclear decommissioning trust 162,044 148,173
Other special use funds 214,712 173,310
Quoted Prices in Active Markets for Identical Assets (Level 1) | Corporate debt    
Assets    
Nuclear decommissioning trust 0 0
Quoted Prices in Active Markets for Identical Assets (Level 1) | Mortgage-backed securities    
Assets    
Nuclear decommissioning trust 0 0
Quoted Prices in Active Markets for Identical Assets (Level 1) | Municipal bonds    
Assets    
Nuclear decommissioning trust 0 0
Other special use funds 0 0
Quoted Prices in Active Markets for Identical Assets (Level 1) | Other fixed income    
Assets    
Nuclear decommissioning trust 0 0
Significant Other Observable Inputs (Level 2)    
Assets    
Cash equivalents   0
Commodity contracts, assets 3,198 3,140
Nuclear decommissioning trust 307,045 298,805
Other special use funds 12,649 17,068
Total assets 322,892 319,013
Liabilities    
Gross derivative liability (68,992) (52,696)
Significant Other Observable Inputs (Level 2) | Equity securities    
Assets    
Nuclear decommissioning trust 0 0
Other special use funds 0 0
Significant Other Observable Inputs (Level 2) | U.S. commingled equity funds    
Assets    
Nuclear decommissioning trust 0 0
Significant Other Observable Inputs (Level 2) | U.S. Treasury debt    
Assets    
Nuclear decommissioning trust 0 0
Other special use funds 0 0
Significant Other Observable Inputs (Level 2) | Corporate debt    
Assets    
Nuclear decommissioning trust 115,674 96,656
Significant Other Observable Inputs (Level 2) | Mortgage-backed securities    
Assets    
Nuclear decommissioning trust 113,179 113,115
Significant Other Observable Inputs (Level 2) | Municipal bonds    
Assets    
Nuclear decommissioning trust 67,158 79,073
Other special use funds 12,649 17,068
Significant Other Observable Inputs (Level 2) | Other fixed income    
Assets    
Nuclear decommissioning trust 11,034 9,961
Significant Unobservable Inputs (Level 3)    
Assets    
Cash equivalents   0
Commodity contracts, assets 436 2
Nuclear decommissioning trust 0 0
Other special use funds 0 0
Total assets 436 2
Liabilities    
Gross derivative liability (13,189) (8,216)
Significant Unobservable Inputs (Level 3) | Equity securities    
Assets    
Nuclear decommissioning trust 0 0
Other special use funds 0 0
Significant Unobservable Inputs (Level 3) | U.S. commingled equity funds    
Assets    
Nuclear decommissioning trust 0 0
Significant Unobservable Inputs (Level 3) | U.S. Treasury debt    
Assets    
Nuclear decommissioning trust 0 0
Other special use funds 0 0
Significant Unobservable Inputs (Level 3) | Corporate debt    
Assets    
Nuclear decommissioning trust 0 0
Significant Unobservable Inputs (Level 3) | Mortgage-backed securities    
Assets    
Nuclear decommissioning trust 0 0
Significant Unobservable Inputs (Level 3) | Municipal bonds    
Assets    
Nuclear decommissioning trust 0 0
Other special use funds 0 0
Significant Unobservable Inputs (Level 3) | Other fixed income    
Assets    
Nuclear decommissioning trust 0 0
Fair Value Measured at Net Asset Value Per Share | U.S. commingled equity funds    
Assets    
Nuclear decommissioning trust $ 469,375 $ 396,805
v3.19.2
Fair Value Measurements - Significant Unobservable Inputs Used to Value Level 3 Instruments (Details 2) - Forward Price
$ in Thousands
Jun. 30, 2019
USD ($)
$ / MWh
Dec. 31, 2018
USD ($)
$ / MWh
Significant Unobservable Inputs (Level 3)    
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments    
Assets | $ $ 436 $ 2
Financial and Nonfinancial Liabilities, Fair Value Disclosure | $ 13,189 $ 8,216
Electricity forward contracts | Minimum    
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments    
Significant Unobservable Input   17.88
Electricity forward contracts | Maximum    
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments    
Significant Unobservable Input   37.03
Electricity forward contracts | Significant Unobservable Inputs (Level 3)    
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments    
Assets | $ 294 $ 0
Financial and Nonfinancial Liabilities, Fair Value Disclosure | $ $ 11,675 $ 2,456
Electricity forward contracts | Significant Unobservable Inputs (Level 3) | Weighted-Average    
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments    
Significant Unobservable Input 26.78 26.10
Electricity forward contracts | Significant Unobservable Inputs (Level 3) | Minimum    
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments    
Significant Unobservable Input 18.27  
Electricity forward contracts | Significant Unobservable Inputs (Level 3) | Maximum    
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments    
Significant Unobservable Input 30.11  
Natural gas contracts | Minimum    
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments    
Significant Unobservable Input   1.79
Natural gas contracts | Maximum    
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments    
Significant Unobservable Input   2.92
Natural gas contracts | Significant Unobservable Inputs (Level 3)    
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments    
Assets | $ $ 142 $ 2
Financial and Nonfinancial Liabilities, Fair Value Disclosure | $ $ 1,514 $ 5,760
Natural gas contracts | Significant Unobservable Inputs (Level 3) | Weighted-Average    
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments    
Significant Unobservable Input 2.41 2.48
Natural gas contracts | Significant Unobservable Inputs (Level 3) | Minimum    
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments    
Significant Unobservable Input (0.23)  
Natural gas contracts | Significant Unobservable Inputs (Level 3) | Maximum    
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments    
Significant Unobservable Input 2.88  
v3.19.2
Fair Value Measurements - Level 3 Rollforward Derivatives (Details) - USD ($)
$ in Thousands
 3 Months Ended 6 Months Ended
Jun. 30, 2019
Jun. 30, 2018
Jun. 30, 2019
Jun. 30, 2018
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]        
Net derivative balance at beginning of period $ (5,612) $ (19,754) $ (8,214) $ (18,256)
Deferred as a regulatory asset or liability (8,731) (989) (10,310) (3,311)
Settlements 2,431 494 2,949 1,276
Transfers into Level 3 from Level 2 (3,096) (2,534) (3,098) (4,979)
Transfers from Level 3 into Level 2 2,255 13,425 5,920 15,912
Net derivative balance at end of period (12,753) (9,358) (12,753) (9,358)
Net unrealized gains included in earnings related to instruments still held at end of period $ 0 $ 0 $ 0 $ 0
v3.19.2
Fair Value Measurements - Financial Instruments Not Carried at Fair Value (Details) - USD ($)
$ in Millions
Jun. 30, 2019
Dec. 31, 2018
Fair Value Disclosures [Abstract]    
Stated interest rate for notes receivable 3.90%  
Note receivable, net book value $ 53 $ 61
v3.19.2
Investments in Nuclear Decommissioning Trusts and Other Special Use Funds (Details) - APS - USD ($)
$ in Thousands
 3 Months Ended 6 Months Ended
Jun. 30, 2019
Jun. 30, 2018
Jun. 30, 2019
Jun. 30, 2018
Dec. 31, 2018
Nuclear decommissioning trust fund assets          
Fair Value $ 1,192,006   $ 1,192,006   $ 1,087,235
Total Unrealized Gains 315,933   315,933   230,781
Total Unrealized Losses (696)   (696)   (7,237)
Amortized cost 672,000   672,000   635,000
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds          
Realized gains 2,643 $ 1,484 3,746 $ 2,299  
Realized losses (1,700) (2,978) (3,105) (5,025)  
Proceeds from the sale of securities 130,306 125,216 309,354 258,227  
Equity securities          
Nuclear decommissioning trust fund assets          
Equity securities 487,894   487,894   447,138
Total Unrealized Gains 291,295   291,295   222,147
Total Unrealized Losses 0   0   459
Available for sale-fixed income securities          
Nuclear decommissioning trust fund assets          
Fair Value 696,450   696,450   637,356
Total Unrealized Gains 24,638   24,638   8,634
Total Unrealized Losses (696)   (696)   (6,778)
Fair value of fixed income securities, summarized by contractual maturities          
Less than one year 99,845   99,845    
1 year – 5 years 284,763   284,763    
5 years – 10 years 115,796   115,796    
Greater than 10 years 196,046   196,046    
Total 696,450   696,450    
Other          
Nuclear decommissioning trust fund assets          
Fair Value 7,662   7,662   2,741
Total Unrealized Gains 0   0   0
Total Unrealized Losses 0   0   0
Nuclear Decommissioning Trust          
Nuclear decommissioning trust fund assets          
Fair Value 950,448   950,448   851,134
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds          
Realized gains 2,643 1,484 3,746 2,298  
Realized losses (1,700) (2,978) (3,105) (5,025)  
Proceeds from the sale of securities 93,559 122,790 216,152 253,246  
Nuclear Decommissioning Trust | Equity securities          
Nuclear decommissioning trust fund assets          
Equity securities 474,694   474,694   402,008
Nuclear Decommissioning Trust | Available for sale-fixed income securities          
Nuclear decommissioning trust fund assets          
Fair Value 469,089   469,089   446,978
Fair value of fixed income securities, summarized by contractual maturities          
Less than one year 37,373   37,373    
1 year – 5 years 126,745   126,745    
5 years – 10 years 113,989   113,989    
Greater than 10 years 190,982   190,982    
Total 469,089   469,089    
Nuclear Decommissioning Trust | Other          
Nuclear decommissioning trust fund assets          
Fair Value 6,665   6,665   2,148
Other Special Use Funds          
Nuclear decommissioning trust fund assets          
Fair Value 241,558   241,558   236,101
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds          
Realized gains 0 0 0 1  
Realized losses 0 0 0 0  
Proceeds from the sale of securities 36,747 $ 2,426 93,202 $ 4,981  
Other Special Use Funds | Equity securities          
Nuclear decommissioning trust fund assets          
Equity securities 13,200   13,200   45,130
Other Special Use Funds | Available for sale-fixed income securities          
Nuclear decommissioning trust fund assets          
Fair Value 227,361   227,361   190,378
Other Special Use Funds | Other          
Nuclear decommissioning trust fund assets          
Fair Value 997   997   $ 593
Coal Reclamation Escrow Account | Available for sale-fixed income securities          
Fair value of fixed income securities, summarized by contractual maturities          
Less than one year 22,253   22,253    
1 year – 5 years 17,449   17,449    
5 years – 10 years 1,807   1,807    
Greater than 10 years 5,064   5,064    
Total 46,573   46,573    
Active Union Medical Trust | Available for sale-fixed income securities          
Fair value of fixed income securities, summarized by contractual maturities          
Less than one year 40,219   40,219    
1 year – 5 years 140,569   140,569    
5 years – 10 years 0   0    
Greater than 10 years 0   0    
Total $ 180,788   $ 180,788    
v3.19.2
Changes in Accumulated Other Comprehensive Loss (Details) - USD ($)
$ in Thousands
 3 Months Ended 6 Months Ended
Jun. 30, 2019
Jun. 30, 2018
Jun. 30, 2019
Jun. 30, 2018
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]        
Balance at beginning of period $ 5,381,725 $ 5,153,671 $ 5,348,705 $ 5,135,730
OCI (loss) before reclassifications (2,422) (5,928) (2,422) (6,024)
Amounts reclassified from accumulated other comprehensive loss 1,287 1,645 2,494 2,954
Reclassification of income tax effect related to tax reform       (8,552)
Balance at end of period 5,357,243 5,159,434 5,357,243 5,159,434
Pension and Other Postretirement Benefits        
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]        
Balance at beginning of period (45,118) (49,494) (45,997) (42,440)
OCI (loss) before reclassifications (2,422) (5,928) (2,422) (5,928)
Amounts reclassified from accumulated other comprehensive loss 883 1,189 1,762 2,089
Reclassification of income tax effect related to tax reform       (7,954)
Balance at end of period (46,657) (54,233) (46,657) (54,233)
Derivative Instruments        
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]        
Balance at beginning of period (1,383) (2,847) (1,711) (2,562)
OCI (loss) before reclassifications 0 0 0 (96)
Amounts reclassified from accumulated other comprehensive loss 404 456 732 865
Reclassification of income tax effect related to tax reform       (598)
Balance at end of period (979) (2,391) (979) (2,391)
Accumulated Other Comprehensive Income (Loss)        
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]        
Balance at beginning of period (46,501) (52,341) (47,708) (45,002)
Reclassification of income tax effect related to tax reform [1]       (8,552)
Balance at end of period (47,636) (56,624) (47,636) (56,624)
APS        
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]        
Balance at beginning of period 5,821,026 5,401,512 5,786,797 5,385,869
OCI (loss) before reclassifications (2,414) (5,790)    
Amounts reclassified from accumulated other comprehensive loss 1,165 1,482    
Balance at end of period 5,797,857 5,412,930 5,797,857 5,412,930
APS | Pension and Other Postretirement Benefits        
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]        
Balance at beginning of period (24,644) (28,004) (25,396) (24,421)
OCI (loss) before reclassifications (2,414) (5,790) (2,414) (5,790)
Amounts reclassified from accumulated other comprehensive loss 761 1,026 1,513 1,883
Reclassification of income tax effect related to tax reform       (4,440)
Balance at end of period (26,297) (32,768) (26,297) (32,768)
APS | Derivative Instruments        
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]        
Balance at beginning of period (1,383) (2,847) (1,711) (2,562)
OCI (loss) before reclassifications 0 0 0 (96)
Amounts reclassified from accumulated other comprehensive loss 404 456 732 865
Reclassification of income tax effect related to tax reform       (598)
Balance at end of period (979) (2,391) (979) (2,391)
APS | Accumulated Other Comprehensive Income (Loss)        
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]        
Balance at beginning of period (26,027) (30,851) (27,107) (26,983)
OCI (loss) before reclassifications     (2,414) (5,886)
Amounts reclassified from accumulated other comprehensive loss     2,245 2,748
Reclassification of income tax effect related to tax reform [2]       (5,038)
Balance at end of period $ (27,276) $ (35,159) $ (27,276) $ (35,159)
[1]
In 2018, the Company adopted new accounting guidance and elected to reclassify income tax effects of the Tax Cuts and Jobs Act of 2017 (the “Tax Act”) on items within accumulated other comprehensive income to retained earnings.
[2]
In 2018, the Company adopted new accounting guidance and elected to reclassify income tax effects of the Tax Act on items within accumulated other comprehensive income to retained earnings.
v3.19.2
Income Taxes (Details) - USD ($)
$ in Millions
 6 Months Ended 12 Months Ended
Jun. 30, 2019
Dec. 31, 2017
Income Tax Disclosure [Abstract]    
Reduction in net deferred income tax liabilities   $ 1,140.0
Non-depreciation and amortization $ 19.4  
v3.19.2
Leases - Additional information (Details) - USD ($)
$ in Thousands
Jun. 30, 2019
Jan. 01, 2019
Dec. 31, 2018
Operating Leased Assets [Line Items]      
Operating lease right-of-use assets (Note 16) $ 176,219 $ 194,000 $ 0
Operating lease, liability 113,601 119,000  
Other (40,365)   (129,312)
Other current liabilities (140,879)   $ (184,229)
Lease not yet commenced $ 705,000    
Accounting Standards Update 2016-02      
Operating Leased Assets [Line Items]      
Other   85,000  
Other current liabilities   $ 10,000  
v3.19.2
Leases - Lease costs (Details) - USD ($)
$ in Thousands
 3 Months Ended 6 Months Ended
Jun. 30, 2019
Jun. 30, 2019
Operating Leased Assets [Line Items]    
Operating lease cost $ 18,477 $ 22,825
Variable lease cost 41,889 59,180
Short-term lease cost 1,812 2,665
Total lease cost 62,178 84,670
Purchased Power Lease Contracts    
Operating Leased Assets [Line Items]    
Operating lease cost 14,063 14,063
Variable lease cost 41,529 58,820
Short-term lease cost 0 0
Total lease cost 55,592 72,883
Land, Property & Equipment Leases    
Operating Leased Assets [Line Items]    
Operating lease cost 4,414 8,762
Variable lease cost 360 360
Short-term lease cost 1,812 2,665
Total lease cost $ 6,586 $ 11,787
v3.19.2
Leases - Maturity of our operating lease liabilities (Details) - USD ($)
$ in Thousands
Jun. 30, 2019
Jan. 01, 2019
Dec. 31, 2018
Lessee, Lease, Description [Line Items]      
2019 (remaining six months of 2019) $ 56,386    
2019     $ 68,246
2020 12,868   12,428
2021 10,029   9,478
2022 6,988   6,513
2023 5,838   5,359
2024 3,691    
Thereafter 38,506    
Thereafter     42,236
Total lease commitments 134,306   144,260
Less imputed interest 20,705    
Total lease liabilities 113,601 $ 119,000  
Purchased Power Lease Contracts      
Lessee, Lease, Description [Line Items]      
2019 (remaining six months of 2019) 49,051    
2019     54,499
2020 0   0
2021 0   0
2022 0   0
2023 0   0
2024 0    
Thereafter 0    
Thereafter     0
Total lease commitments 49,051   54,499
Less imputed interest 294    
Total lease liabilities 48,757    
Land, Property & Equipment Leases      
Lessee, Lease, Description [Line Items]      
2019 (remaining six months of 2019) 7,335    
2019     13,747
2020 12,868   12,428
2021 10,029   9,478
2022 6,988   6,513
2023 5,838   5,359
2024 3,691    
Thereafter 38,506    
Thereafter     42,236
Total lease commitments 85,255   $ 89,761
Less imputed interest 20,411    
Total lease liabilities $ 64,844    
v3.19.2
Leases - Other additional information related to operating lease liabilities (Details)
$ in Thousands
 6 Months Ended
Jun. 30, 2019
USD ($)
Leases [Abstract]  
Weighted average remaining lease term 8 years
Weighted average discount rate (a) 3.84%
Cash paid for amounts included in the measurement of lease liabilities - operating cash flows $ 11,987