Document and Entity Information
Document and Entity Information - shares | 9 Months Ended | |
Sep. 30, 2019 | Oct. 31, 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 | Sep. 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) | 112,410,824 | |
Document Fiscal Year Focus | 2019 | |
Document Fiscal Period Focus | Q3 | |
Entity Incorporation, State or Country Code | AZ | |
APS | ||
Entity Information [Line Items] | ||
Entity Shell Company | false | |
Entity Interactive Data Current | Yes | |
Entity Tax Identification Number | 86-0011170 | |
Entity Address, Address Line One | 400 North Fifth Street, P.O. Box 53999 | |
Entity Address, City or Town | Phoenix | |
Entity Address, State or Province | AZ | |
Entity Address, Postal Zip Code | 85072-3999 | |
City Area Code | (602) | |
Local Phone Number | 250-1000 | |
Entity File Number | 1-4473 | |
Entity Registrant Name | ARIZONA PUBLIC SERVICE COMPANY | |
Entity Central Index Key | 0000007286 | |
Document Type | 10-Q | |
Document Period End Date | Sep. 30, 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 | Q3 | |
Entity Incorporation, State or Country Code | AZ |
CONDENSED CONSOLIDATED STATEMEN
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited) - USD ($) shares in Thousands, $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2019 | Sep. 30, 2018 | Sep. 30, 2019 | Sep. 30, 2018 | |
OPERATING REVENUES | $ 1,190,787 | $ 1,268,034 | $ 2,800,818 | $ 2,934,871 |
OPERATING EXPENSES | ||||
Fuel and purchased power | 344,862 | 389,936 | 817,672 | 844,133 |
Operations and maintenance | 238,582 | 246,545 | 711,759 | 780,624 |
Depreciation and amortization | 149,450 | 145,971 | 445,531 | 436,232 |
Taxes other than income taxes | 53,809 | 51,375 | 163,989 | 158,582 |
Other expenses | 794 | 900 | 1,904 | 8,497 |
Total | 787,497 | 834,727 | 2,140,855 | 2,228,068 |
OPERATING INCOME | 403,290 | 433,307 | 659,963 | 706,803 |
OTHER INCOME (DEDUCTIONS) | ||||
Allowance for equity funds used during construction | 5,917 | 12,259 | 24,677 | 39,411 |
Pension and other postretirement non-service credits - net | 5,752 | 12,449 | 17,240 | 37,314 |
Other income (Note 9) | 15,191 | 6,958 | 35,245 | 17,541 |
Other expense (Note 9) | (5,740) | (5,063) | (14,448) | (12,063) |
Total | 21,120 | 26,603 | 62,714 | 82,203 |
INTEREST EXPENSE | ||||
Interest charges | 57,481 | 61,605 | 175,599 | 181,267 |
Allowance for borrowed funds used during construction | (3,486) | (5,913) | (14,645) | (18,959) |
Total | 53,995 | 55,692 | 160,954 | 162,308 |
INCOME BEFORE INCOME TAXES | 370,415 | 404,218 | 561,723 | 626,698 |
INCOME TAXES | 53,266 | 84,333 | 72,764 | 127,107 |
NET INCOME | 317,149 | 319,885 | 488,959 | 499,591 |
Less: Net income attributable to noncontrolling interests (Note 6) | 4,873 | 4,873 | 14,620 | 14,620 |
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS | $ 312,276 | $ 315,012 | $ 474,339 | $ 484,971 |
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING | ||||
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - BASIC (in shares) | 112,463 | 112,148 | 112,408 | 112,094 |
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - DILUTED (in shares) | 112,746 | 112,533 | 112,739 | 112,499 |
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING | ||||
Net income attributable to common shareholders - basic (in dollars per share) | $ 2.78 | $ 2.81 | $ 4.22 | $ 4.33 |
Net income attributable to common shareholders - diluted (in dollars per share) | $ 2.77 | $ 2.80 | $ 4.21 | $ 4.31 |
APS | ||||
OPERATING REVENUES | $ 1,190,787 | $ 1,267,997 | $ 2,800,818 | $ 2,931,966 |
OPERATING EXPENSES | ||||
Fuel and purchased power | 344,862 | 389,889 | 817,672 | 862,037 |
Operations and maintenance | 235,440 | 226,346 | 699,958 | 732,946 |
Depreciation and amortization | 149,428 | 145,949 | 445,467 | 434,594 |
Taxes other than income taxes | 53,798 | 51,366 | 163,957 | 157,877 |
Other expenses | 794 | 900 | 1,904 | 1,497 |
Total | 784,322 | 814,450 | 2,128,958 | 2,188,951 |
OPERATING INCOME | 406,465 | 453,547 | 671,860 | 743,015 |
OTHER INCOME (DEDUCTIONS) | ||||
Allowance for equity funds used during construction | 5,917 | 12,259 | 24,677 | 39,411 |
Pension and other postretirement non-service credits - net | 6,133 | 12,812 | 18,389 | 38,398 |
Other income (Note 9) | 14,534 | 6,153 | 32,641 | 16,160 |
Other expense (Note 9) | (2,826) | (3,361) | (10,132) | (9,679) |
Total | 23,758 | 27,863 | 65,575 | 84,290 |
INTEREST EXPENSE | ||||
Interest charges | 53,812 | 58,551 | 164,068 | 172,440 |
Allowance for borrowed funds used during construction | (3,486) | (5,913) | (14,645) | (18,959) |
Total | 50,326 | 52,638 | 149,423 | 153,481 |
INCOME BEFORE INCOME TAXES | 379,897 | 428,772 | 588,012 | 673,824 |
INCOME TAXES | 56,154 | 85,533 | 76,070 | 133,415 |
NET INCOME | 323,743 | 343,239 | 511,942 | 540,409 |
Less: Net income attributable to noncontrolling interests (Note 6) | 4,873 | 4,873 | 14,620 | 14,620 |
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS | $ 318,870 | $ 338,366 | $ 497,322 | $ 525,789 |
CONDENSED CONSOLIDATED STATEM_2
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2019 | Sep. 30, 2018 | Sep. 30, 2019 | Sep. 30, 2018 | |
NET INCOME | $ 317,149 | $ 319,885 | $ 488,959 | $ 499,591 |
Derivative instruments: | ||||
Net unrealized loss, net of tax expense | 0 | 0 | 0 | (96) |
Reclassification of net realized loss, net of tax benefit | 218 | 451 | 950 | 1,316 |
Pension and other postretirement benefits activity, net of tax expense (benefit) | 880 | 1,099 | 220 | (2,740) |
Total other comprehensive income (loss) | 1,098 | 1,550 | 1,170 | (1,520) |
COMPREHENSIVE INCOME | 318,247 | 321,435 | 490,129 | 498,071 |
Less: Comprehensive income attributable to noncontrolling interests | 4,873 | 4,873 | 14,620 | 14,620 |
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS | 313,374 | 316,562 | 475,509 | 483,451 |
APS | ||||
NET INCOME | 323,743 | 343,239 | 511,942 | 540,409 |
Derivative instruments: | ||||
Net unrealized loss, net of tax expense | 0 | 0 | 0 | (96) |
Reclassification of net realized loss, net of tax benefit | 218 | 451 | 950 | 1,316 |
Pension and other postretirement benefits activity, net of tax expense (benefit) | 755 | 952 | (146) | (2,955) |
Total other comprehensive income (loss) | 973 | 1,403 | 804 | (1,735) |
COMPREHENSIVE INCOME | 324,716 | 344,642 | 512,746 | 538,674 |
Less: Comprehensive income attributable to noncontrolling interests | 4,873 | 4,873 | 14,620 | 14,620 |
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS | $ 319,843 | $ 339,769 | $ 498,126 | $ 524,054 |
CONDENSED CONSOLIDATED STATEM_3
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) (Parenthetical) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2019 | Sep. 30, 2018 | Sep. 30, 2019 | Sep. 30, 2018 | |
Net unrealized loss, tax expense | $ 0 | $ 0 | $ 0 | $ 96 |
Reclassification of net realized loss, net of tax benefit | (71) | (149) | (313) | (381) |
Pension and other postretirement benefits activity, net of tax expense (benefit) | 290 | 361 | 72 | (754) |
APS | ||||
Net unrealized loss, tax expense | 0 | 0 | 0 | 96 |
Reclassification of net realized loss, net of tax benefit | (71) | (149) | (313) | (381) |
Pension and other postretirement benefits activity, net of tax expense (benefit) | $ 249 | $ 313 | $ (48) | $ (947) |
CONDENSED CONSOLIDATED BALANCE
CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($) $ in Thousands | Sep. 30, 2019 | Dec. 31, 2018 | Dec. 31, 2017 |
CURRENT ASSETS | |||
Cash and cash equivalents | $ 29,852 | $ 5,766 | |
Customer and other receivables | 361,951 | 267,887 | |
Accrued unbilled revenues | 155,836 | 137,170 | |
Allowance for doubtful accounts | (7,282) | (4,069) | |
Materials and supplies (at average cost) | 293,899 | 269,065 | |
Fossil fuel (at average cost) | 18,527 | 25,029 | |
Income tax receivable | 14,063 | $ 0 | |
Assets from risk management activities (Note 7) | 817 | 1,113 | |
Deferred fuel and purchased power regulatory asset (Note 4) | 59,474 | 37,164 | |
Other regulatory assets (Note 4) | 138,033 | 129,738 | |
Other current assets | 67,985 | 56,128 | |
Total current assets | 1,133,155 | 924,991 | |
INVESTMENTS AND OTHER ASSETS | |||
Nuclear decommissioning trust (Notes 11 and 12) | 967,673 | 851,134 | |
Other special use funds (Notes 11 and 12) | 243,982 | 236,101 | |
Other assets | 102,116 | 103,247 | |
Total investments and other assets | 1,313,771 | 1,190,482 | |
PROPERTY, PLANT AND EQUIPMENT | |||
Plant in service and held for future use | 19,677,773 | 18,736,628 | |
Accumulated depreciation and amortization | (6,552,177) | (6,366,014) | |
Net | 13,125,596 | 12,370,614 | |
Construction work in progress | 738,492 | 1,170,062 | |
Palo Verde sale leaseback, net of accumulated depreciation (Note 6) | 102,873 | 105,775 | |
Intangible assets, net of accumulated amortization | 266,587 | 262,902 | |
Nuclear fuel, net of accumulated amortization | 141,903 | 120,217 | |
Total property, plant and equipment | 14,375,451 | 14,029,570 | |
DEFERRED DEBITS | |||
Regulatory assets (Note 4) | 1,329,446 | 1,342,941 | |
Operating lease right-of-use assets (Note 16) | 156,050 | 0 | |
Assets for other postretirement benefits (Note 5) | 31,717 | 46,906 | |
Other | 37,976 | 129,312 | |
Total deferred debits | 1,555,189 | 1,519,159 | |
TOTAL ASSETS | 18,377,566 | 17,664,202 | |
CURRENT LIABILITIES | |||
Accounts payable | 276,117 | 277,336 | |
Accrued taxes | 220,930 | 154,819 | |
Accrued interest | 50,993 | 61,107 | |
Common dividends payable | 0 | 82,675 | |
Short-term borrowings (Note 3) | 57,375 | 76,400 | |
Current maturities of long-term debt (Note 3) | 450,000 | 500,000 | |
Customer deposits | 78,173 | 91,174 | |
Liabilities from risk management activities (Note 7) | 44,349 | 35,506 | |
Liabilities for asset retirements | 12,850 | 19,842 | |
Operating lease liabilities (Note 16) | 26,221 | 0 | |
Regulatory liabilities (Note 4) | 208,022 | 165,876 | |
Other current liabilities | 161,716 | 184,229 | |
Total current liabilities | 1,586,746 | 1,648,964 | |
Long-term debt less current maturities (Note 3) | 4,984,996 | 4,638,232 | |
DEFERRED CREDITS AND OTHER | |||
Deferred income taxes | 1,975,989 | 1,807,421 | |
Regulatory liabilities (Note 4) | 2,310,131 | 2,325,976 | |
Liabilities for asset retirements | 736,079 | 706,703 | |
Liabilities for pension benefits (Note 5) | 297,843 | 443,170 | |
Liabilities from risk management activities (Note 7) | 27,305 | 24,531 | |
Customer advances | 192,374 | 137,153 | |
Coal mine reclamation | 165,695 | 212,785 | |
Deferred investment tax credit | 193,118 | 200,405 | |
Unrecognized tax benefits | 6,341 | 22,517 | |
Operating lease liabilities (Note 16) | 52,472 | 0 | |
Other | 166,772 | 147,640 | |
Total deferred credits and other | 6,124,119 | 6,028,301 | |
COMMITMENTS AND CONTINGENCIES (SEE NOTE 8) | |||
EQUITY | |||
Common stock, no par value; authorized 150,000,000 shares, 112,403,751 and 112,159,896 issued at respective dates | 2,654,430 | 2,634,265 | |
Treasury stock at cost; 57,947 and 58,135 shares at respective dates | (5,117) | (4,825) | |
Total common stock | 2,649,313 | 2,629,440 | |
Retained earnings | 2,949,891 | 2,641,183 | |
Accumulated other comprehensive loss | (46,538) | (47,708) | |
Total shareholders’ equity | 5,552,666 | 5,222,915 | |
Noncontrolling interests (Note 6) | 129,039 | 125,790 | |
Total equity | 5,681,705 | 5,348,705 | 5,135,730 |
TOTAL LIABILITIES AND EQUITY | 18,377,566 | 17,664,202 | |
APS | |||
CURRENT ASSETS | |||
Cash and cash equivalents | 29,542 | 5,707 | |
Customer and other receivables | 351,029 | 257,654 | |
Accrued unbilled revenues | 155,836 | 137,170 | |
Allowance for doubtful accounts | (7,282) | (4,069) | |
Materials and supplies (at average cost) | 293,899 | 269,065 | |
Fossil fuel (at average cost) | 18,527 | 25,029 | |
Income tax receivable | 15,982 | 0 | |
Assets from risk management activities (Note 7) | 817 | 1,113 | |
Deferred fuel and purchased power regulatory asset (Note 4) | 59,474 | 37,164 | |
Other regulatory assets (Note 4) | 138,033 | 129,738 | |
Other current assets | 45,506 | 35,111 | |
Total current assets | 1,101,363 | 893,682 | |
INVESTMENTS AND OTHER ASSETS | |||
Nuclear decommissioning trust (Notes 11 and 12) | 967,673 | 851,134 | |
Other special use funds (Notes 11 and 12) | 243,982 | 236,101 | |
Other assets | 55,846 | 40,817 | |
Total investments and other assets | 1,267,501 | 1,128,052 | |
PROPERTY, PLANT AND EQUIPMENT | |||
Plant in service and held for future use | 19,674,286 | 18,733,142 | |
Accumulated depreciation and amortization | (6,548,921) | (6,362,771) | |
Net | 13,125,365 | 12,370,371 | |
Construction work in progress | 738,493 | 1,170,062 | |
Palo Verde sale leaseback, net of accumulated depreciation (Note 6) | 102,873 | 105,775 | |
Intangible assets, net of accumulated amortization | 266,432 | 262,746 | |
Nuclear fuel, net of accumulated amortization | 141,903 | 120,217 | |
Total property, plant and equipment | 14,375,066 | 14,029,171 | |
DEFERRED DEBITS | |||
Regulatory assets (Note 4) | 1,329,446 | 1,342,941 | |
Operating lease right-of-use assets (Note 16) | 154,205 | 0 | |
Assets for other postretirement benefits (Note 5) | 28,071 | 43,212 | |
Other | 37,080 | 128,265 | |
Total deferred debits | 1,548,802 | 1,514,418 | |
TOTAL ASSETS | 18,292,732 | 17,565,323 | |
CURRENT LIABILITIES | |||
Accounts payable | 268,163 | 266,277 | |
Accrued taxes | 215,320 | 176,357 | |
Accrued interest | 48,374 | 60,228 | |
Common dividends payable | 0 | 82,700 | |
Short-term borrowings (Note 3) | 2,900 | 0 | |
Current maturities of long-term debt (Note 3) | 450,000 | 500,000 | |
Customer deposits | 78,173 | 91,174 | |
Liabilities from risk management activities (Note 7) | 44,349 | 35,506 | |
Liabilities for asset retirements | 12,850 | 19,842 | |
Operating lease liabilities (Note 16) | 26,028 | 0 | |
Regulatory liabilities (Note 4) | 208,022 | 165,876 | |
Other current liabilities | 159,992 | 178,137 | |
Total current liabilities | 1,514,171 | 1,576,097 | |
Long-term debt less current maturities (Note 3) | 4,535,728 | 4,189,436 | |
DEFERRED CREDITS AND OTHER | |||
Deferred income taxes | 1,976,662 | 1,812,664 | |
Regulatory liabilities (Note 4) | 2,310,131 | 2,325,976 | |
Liabilities for asset retirements | 736,079 | 706,703 | |
Liabilities for pension benefits (Note 5) | 281,605 | 425,404 | |
Liabilities from risk management activities (Note 7) | 27,305 | 24,531 | |
Customer advances | 192,374 | 137,153 | |
Coal mine reclamation | 165,695 | 212,785 | |
Deferred investment tax credit | 193,118 | 200,405 | |
Unrecognized tax benefits | 43,434 | 41,861 | |
Operating lease liabilities (Note 16) | 50,669 | 0 | |
Other | 143,190 | 125,511 | |
Total deferred credits and other | 6,120,262 | 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 | 3,119,977 | 2,788,256 | |
Accumulated other comprehensive loss | (26,303) | (27,107) | |
Total shareholders’ equity | 5,993,532 | 5,661,007 | |
Noncontrolling interests (Note 6) | 129,039 | 125,790 | |
Total equity | 6,122,571 | 5,786,797 | $ 5,385,869 |
Total capitalization | 10,658,299 | 9,976,233 | |
TOTAL LIABILITIES AND EQUITY | $ 18,292,732 | $ 17,565,323 |
CONDENSED CONSOLIDATED BALANC_2
CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical) - $ / shares | Sep. 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) | 112,403,751 | 112,159,896 |
Treasury stock at cost, shares (in shares) | 57,947 | 58,135 |
CONDENSED CONSOLIDATED STATEM_4
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($) $ in Thousands | 9 Months Ended | |
Sep. 30, 2019 | Sep. 30, 2018 | |
CASH FLOWS FROM OPERATING ACTIVITIES | ||
NET INCOME | $ 488,959 | $ 499,591 |
Adjustments to reconcile net income to net cash provided by operating activities: | ||
Depreciation and amortization including nuclear fuel | 500,801 | 489,861 |
Deferred fuel and purchased power | (60,911) | (82,486) |
Deferred fuel and purchased power amortization | 38,601 | 92,397 |
Allowance for equity funds used during construction | (24,677) | (39,411) |
Deferred income taxes | 83,703 | 117,571 |
Deferred investment tax credit | (7,288) | (7,397) |
Stock compensation | 16,486 | 16,140 |
Changes in current assets and liabilities: | ||
Customer and other receivables | (91,506) | (65,203) |
Accrued unbilled revenues | (18,666) | (83,939) |
Materials, supplies and fossil fuel | (18,332) | (20,591) |
Income tax receivable | (14,063) | 0 |
Other current assets | (10,104) | 23,661 |
Accounts payable | 33,899 | (11,399) |
Accrued taxes | 66,111 | 78,624 |
Other current liabilities | (68,927) | 12,852 |
Change in other long-term assets | (52,276) | 14,120 |
Change in other long-term liabilities | (27,049) | (74,628) |
Net cash flow provided by operating activities | 834,761 | 959,763 |
CASH FLOWS FROM INVESTING ACTIVITIES | ||
Capital expenditures | (857,883) | (898,455) |
Contributions in aid of construction | 34,121 | 22,611 |
Allowance for borrowed funds used during construction | (14,645) | (18,959) |
Proceeds from nuclear decommissioning trust sales and other special use funds | 520,996 | 443,215 |
Investment in nuclear decommissioning trust and other special use funds | (523,573) | (461,777) |
Other | 8,971 | 49 |
Net cash flow used for investing activities | (832,013) | (913,316) |
CASH FLOWS FROM FINANCING ACTIVITIES | ||
Issuance of long-term debt | 794,981 | 295,245 |
Short-term borrowing and payments — net | (6,025) | 19,800 |
Short-term debt borrowings | 49,000 | 45,000 |
Short-term debt repayments | (62,000) | (32,000) |
Repayment of long-term debt | (500,000) | (82,000) |
Dividends paid on common stock | (243,116) | (228,037) |
Common stock equity issuance - net of purchases | (130) | (1,984) |
Distributions to noncontrolling interests | (11,372) | (11,372) |
Net cash flow provided by financing activities | 21,338 | 4,652 |
NET INCREASE IN CASH AND CASH EQUIVALENTS | 24,086 | 51,099 |
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD | 5,766 | 13,892 |
CASH AND CASH EQUIVALENTS AT END OF PERIOD | 29,852 | 64,991 |
APS | ||
CASH FLOWS FROM OPERATING ACTIVITIES | ||
NET INCOME | 511,942 | 540,409 |
Adjustments to reconcile net income to net cash provided by operating activities: | ||
Depreciation and amortization including nuclear fuel | 500,737 | 488,223 |
Deferred fuel and purchased power | (60,911) | (82,486) |
Deferred fuel and purchased power amortization | 38,601 | 92,397 |
Allowance for equity funds used during construction | (24,677) | (39,411) |
Deferred income taxes | 97,002 | 86,319 |
Deferred investment tax credit | (7,288) | (7,397) |
Changes in current assets and liabilities: | ||
Customer and other receivables | (90,817) | (56,874) |
Accrued unbilled revenues | (18,666) | (83,939) |
Materials, supplies and fossil fuel | (18,332) | (20,694) |
Income tax receivable | (15,982) | 0 |
Other current assets | (8,642) | 20,258 |
Accounts payable | 37,004 | (8,857) |
Accrued taxes | 38,963 | 106,172 |
Other current liabilities | (66,368) | 9,289 |
Change in other long-term assets | (54,872) | 25,405 |
Change in other long-term liabilities | (27,521) | (80,895) |
Net cash flow provided by operating activities | 830,173 | 987,919 |
CASH FLOWS FROM INVESTING ACTIVITIES | ||
Capital expenditures | (857,883) | (889,347) |
Contributions in aid of construction | 34,121 | 22,611 |
Allowance for borrowed funds used during construction | (14,645) | (18,959) |
Proceeds from nuclear decommissioning trust sales and other special use funds | 520,996 | 443,040 |
Investment in nuclear decommissioning trust and other special use funds | (523,573) | (461,602) |
Other | (3,563) | (1,261) |
Net cash flow used for investing activities | (844,547) | (905,518) |
CASH FLOWS FROM FINANCING ACTIVITIES | ||
Issuance of long-term debt | 794,981 | 295,245 |
Short-term borrowing and payments — net | 2,900 | 0 |
Short-term debt borrowings | 0 | 25,000 |
Short-term debt repayments | 0 | (25,000) |
Repayment of long-term debt | (500,000) | (82,000) |
Dividends paid on common stock | (248,300) | (233,300) |
Distributions to noncontrolling interests | (11,372) | (11,372) |
Net cash flow provided by financing activities | 38,209 | (31,427) |
NET INCREASE IN CASH AND CASH EQUIVALENTS | 23,835 | 50,974 |
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD | 5,707 | 13,851 |
CASH AND CASH EQUIVALENTS AT END OF PERIOD | $ 29,542 | $ 64,825 |
CONDENSED CONSOLIDATED STATEM_5
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 | APSCommon Stock | APSAdditional Paid-In Capital | APSRetained Earnings | APSAccumulated Other Comprehensive Income (Loss) | APSNoncontrolling 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 | 499,591 | 484,971 | 14,620 | 540,409 | 525,789 | 14,620 | |||||||||||
Other comprehensive income (loss) | (1,520) | (1,520) | (1,735) | (1,735) | |||||||||||||
Dividends on common stock | (155,607) | (155,607) | (155,601) | (155,601) | |||||||||||||
Issuance of common stock (in shares) | 199,779 | ||||||||||||||||
Issuance of common stock | 14,822 | $ 14,822 | |||||||||||||||
Purchase of treasury stock (in shares) | [1] | (81,278) | |||||||||||||||
Purchase of treasury stock | [1] | (6,285) | $ (6,285) | ||||||||||||||
Reissuance of treasury stock for stock-based compensation and other (in shares) | 128,373 | ||||||||||||||||
Reissuance of treasury stock for stock-based compensation and other | 10,501 | $ 10,500 | 1 | ||||||||||||||
Capital activities by noncontrolling interests | 11,372 | 11,372 | 11,372 | 11,372 | |||||||||||||
Reclassification of income tax effects related to new tax reform | (8,552) | 8,552 | [2] | (8,552) | [2] | 5,038 | [3] | (5,038) | [3] | ||||||||
Other | 1 | 1 | 1 | 1 | |||||||||||||
Ending balance (in shares) at Sep. 30, 2018 | 112,015,949 | 17,368 | 71,264,947 | ||||||||||||||
Balance at end of period at Sep. 30, 2018 | 5,485,861 | $ 2,629,627 | $ (1,409) | 2,780,428 | (55,074) | 132,289 | 5,757,571 | $ 178,162 | 2,571,696 | 2,909,180 | (33,756) | 132,289 | |||||
Beginning balance (in shares) at Jun. 30, 2018 | 111,990,222 | 17,633 | 71,264,947 | ||||||||||||||
Balance at beginning 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 | |||||
Increase (Decrease) in Shareholders' Equity | |||||||||||||||||
Net Income | 319,885 | 315,012 | 4,873 | 343,239 | 338,366 | 4,873 | |||||||||||
Other comprehensive income (loss) | 1,550 | 1,550 | 1,403 | 1,403 | |||||||||||||
Dividends on common stock | 14 | 14 | |||||||||||||||
Issuance of common stock (in shares) | 25,727 | ||||||||||||||||
Issuance of common stock | 4,955 | $ 4,955 | |||||||||||||||
Purchase of treasury stock (in shares) | [4] | (101) | |||||||||||||||
Purchase of treasury stock | [4] | (8) | $ (8) | ||||||||||||||
Reissuance of treasury stock for stock-based compensation and other (in shares) | 366 | ||||||||||||||||
Reissuance of treasury stock for stock-based compensation and other | 30 | $ 30 | 0 | ||||||||||||||
Other | 1 | 1 | (1) | (2) | 1 | ||||||||||||
Ending balance (in shares) at Sep. 30, 2018 | 112,015,949 | 17,368 | 71,264,947 | ||||||||||||||
Balance at end of period at Sep. 30, 2018 | $ 5,485,861 | $ 2,629,627 | $ (1,409) | 2,780,428 | (55,074) | 132,289 | 5,757,571 | $ 178,162 | 2,571,696 | 2,909,180 | (33,756) | 132,289 | |||||
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 | 488,959 | 474,339 | 14,620 | 511,942 | 497,322 | 14,620 | |||||||||||
Other comprehensive income (loss) | 1,170 | 1,170 | 804 | 804 | |||||||||||||
Dividends on common stock | (165,631) | (165,631) | (165,600) | (165,600) | |||||||||||||
Issuance of common stock (in shares) | 243,855 | ||||||||||||||||
Issuance of common stock | 20,165 | $ 20,165 | |||||||||||||||
Purchase of treasury stock (in shares) | [1] | (75,894) | |||||||||||||||
Purchase of treasury stock | [1] | (6,892) | $ (6,892) | ||||||||||||||
Reissuance of treasury stock for stock-based compensation and other (in shares) | 76,082 | ||||||||||||||||
Reissuance of treasury stock for stock-based compensation and other | 6,600 | $ 6,600 | 0 | ||||||||||||||
Capital activities by noncontrolling interests | 11,372 | 11,372 | 11,372 | 11,372 | |||||||||||||
Other | $ 1 | 1 | 0 | (1) | 1 | ||||||||||||
Ending balance (in shares) at Sep. 30, 2019 | 112,403,751 | 112,403,751 | 57,947 | 71,264,947 | |||||||||||||
Balance at end of period at Sep. 30, 2019 | $ 5,681,705 | $ 2,654,430 | $ (5,117) | 2,949,891 | (46,538) | 129,039 | 6,122,571 | $ 178,162 | 2,721,696 | 3,119,977 | (26,303) | 129,039 | |||||
Beginning balance (in shares) at Jun. 30, 2019 | 112,361,595 | 58,219 | 71,264,947 | ||||||||||||||
Balance at beginning of period at Jun. 30, 2019 | 5,357,243 | $ 2,648,234 | $ (5,140) | 2,637,620 | (47,636) | 124,165 | 5,797,857 | $ 178,162 | 2,721,696 | 2,801,110 | (27,276) | 124,165 | |||||
Increase (Decrease) in Shareholders' Equity | |||||||||||||||||
Net Income | 317,149 | 312,276 | 4,873 | 323,743 | 318,870 | 4,873 | |||||||||||
Other comprehensive income (loss) | 1,098 | 1,098 | 973 | 973 | |||||||||||||
Dividends on common stock | (5) | (5) | |||||||||||||||
Issuance of common stock (in shares) | 42,156 | ||||||||||||||||
Issuance of common stock | 6,196 | $ 6,196 | |||||||||||||||
Purchase of treasury stock (in shares) | [4] | (103) | |||||||||||||||
Purchase of treasury stock | [4] | (10) | $ (10) | ||||||||||||||
Reissuance of treasury stock for stock-based compensation and other (in shares) | 375 | ||||||||||||||||
Reissuance of treasury stock for stock-based compensation and other | 33 | $ 33 | 0 | ||||||||||||||
Other | $ 1 | 1 | (2) | (3) | 1 | ||||||||||||
Ending balance (in shares) at Sep. 30, 2019 | 112,403,751 | 112,403,751 | 57,947 | 71,264,947 | |||||||||||||
Balance at end of period at Sep. 30, 2019 | $ 5,681,705 | $ 2,654,430 | $ (5,117) | $ 2,949,891 | $ (46,538) | $ 129,039 | $ 6,122,571 | $ 178,162 | $ 2,721,696 | $ 3,119,977 | $ (26,303) | $ 129,039 | |||||
[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. | ||||||||||||||||
[4] | Primarily represents shares of common stock withheld from certain stock awards for tax purposes. |
CONDENSED CONSOLIDATED STATEM_6
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Unaudited) Parenthetical - $ / shares | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2019 | Sep. 30, 2018 | Sep. 30, 2019 | Sep. 30, 2018 | |
Statement of Stockholders' Equity [Abstract] | ||||
DIVIDENDS DECLARED PER SHARE (in dollars per share) | $ 0 | $ 0 | $ 1.48 | $ 1.39 |
Consolidation and Nature of Ope
Consolidation and Nature of Operations | 9 Months Ended |
Sep. 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): Nine Months Ended 2019 2018 Cash paid during the period for: Income taxes, net of refunds $ 12,488 $ 10,091 Interest, net of amounts capitalized 166,907 161,875 Significant non-cash investing and financing activities: Accrued capital expenditures $ 85,099 $ 99,405 Right-of-use operating lease assets obtained in exchange for operating lease liabilities 8,759 — Sale of 4CA's 7% interest in Four Corners — 68,907 The following table summarizes supplemental APS cash flow information (dollars in thousands): Nine Months Ended 2019 2018 Cash paid during the period for: Income taxes, net of refunds $ 35,573 $ 24,746 Interest, net of amounts capitalized 157,593 154,788 Significant non-cash investing and financing activities: Accrued capital expenditures $ 85,099 $ 99,405 Right-of-use operating lease assets obtained in exchange for operating lease liabilities 8,759 — |
Revenue
Revenue | 9 Months Ended |
Sep. 30, 2019 | |
Revenue from Contract with Customer [Abstract] | |
Revenue | Revenue Sources of Revenue The following table provides detail of Pinnacle West's consolidated revenue disaggregated by revenue sources (dollars in thousands): Three Months Ended September 30, Nine Months Ended September 30, 2019 2018 2019 2018 Retail Electric Revenue Residential $ 668,467 $ 695,480 $ 1,452,601 $ 1,512,402 Non-Residential 465,602 496,809 1,194,199 1,275,498 Wholesale energy sales 36,775 53,501 95,218 80,982 Transmission services for others 15,841 15,902 46,247 46,235 Other sources 4,102 6,342 12,553 19,754 Total operating revenues $ 1,190,787 $ 1,268,034 $ 2,800,818 $ 2,934,871 Retail Electric Revenue. Pinnacle West's retail electric revenue is generated by wholly owned regulated subsidiary APS's sale of electricity to our regulated customers within the authorized service territory at tariff rates approved by the ACC and based on customer k ilowatt-hour (" KWh") usage. Revenues related to the sale of electricity are generally recognized when service is rendered or electricity is delivered to customers. The billing of electricity sales to individual customers is based on the reading of their meters. We obtain customers' meter data on a systematic basis throughout the month, and generally bill customers within a month from when service was provided. Customers are generally required to pay for services within 15 days of when the services are billed. Wholesale Energy Sales and Transmission Services for Others. Revenues from wholesale energy sales and transmission services for others represent energy and transmission sales to wholesale customers. These activities primarily consist of managing fuel and purchased power risks in connection with the cost of serving our retail customers' energy requirements. We may also sell into the wholesale markets generation that is not needed for APS’s retail load. Our wholesale activities and tariff rates are regulated by the United States Federal Energy Regulatory Commission ("FERC"). In the electricity business, some contracts to purchase energy are settled by netting against other contracts to sell electricity. This is referred to as a book-out, and usually occurs in contracts that have the same terms (product type, quantities, and delivery points) and for which power does not flow. We net these book-outs, which reduces both wholesale revenues and fuel and purchased power costs. Revenue Activities Our revenues primarily consist of activities that are classified as revenues from contracts with customers. We derive our revenues from contracts with customers primarily from sales of electricity to our regulated retail customers. Revenues from contracts with customers also include wholesale and transmission activities. Our revenues from contracts with customers for the three and nine months ended September 30, 2019 were $1,178 million and $2,756 million, respectively, and for the three and nine months ended September 30, 2018 were $1,257 million and $2,897 million, respectively. We have certain revenues that do not meet the specific accounting criteria to be classified as revenues from contracts with customers. For the three and nine months ended September 30, 2019 , our revenues that do not qualify as revenue from contracts with customers were $13 million and $45 million , respectively, and for the three and nine months ended September 30, 2018 were $11 million and $38 million , respectively. This relates primarily to certain regulatory cost recovery mechanisms that are considered alternative revenue programs. We recognize revenue associated with alternative revenue programs when specific events permitting recognition are completed. Certain amounts associated with alternative revenue programs will subsequently be billed to customers; however, we do not reclassify billed amounts into revenue from contracts with customers. See Note 4 for a discussion of our regulatory cost recovery mechanisms. Contract Assets and Liabilities from Contracts with Customers There were no material contract assets, contract liabilities, or deferred contract costs recorded on the Condensed Consolidated Balance Sheets as of September 30, 2019 or December 31, 2018 |
Long-Term Debt and Liquidity Ma
Long-Term Debt and Liquidity Matters | 9 Months Ended |
Sep. 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 September 30, 2019 , Pinnacle West had $41 million in outstanding borrowings under the agreement. At September 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 September 30, 2019 , Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding and $13 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. On August 19, 2019, APS issued $300 million of 2.6% unsecured senior notes that mature on August 15, 2029. The net proceeds from the sale were used to repay short-term indebtedness, consisting of commercial paper borrowings, and to replenish cash used to fund capital expenditures. At September 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 September 30, 2019 , APS had $3 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 September 30, 2019 As of December 31, 2018 Carrying Amount Fair Value Carrying Amount Fair Value Pinnacle West $ 449,268 $ 449,670 $ 448,796 $ 443,955 APS 4,985,728 5,617,727 4,689,436 4,789,608 Total $ 5,434,996 $ 6,067,397 $ 5,138,232 $ 5,233,563 |
Regulatory Matters
Regulatory Matters | 9 Months Ended |
Sep. 30, 2019 | |
Regulated Operations [Abstract] | |
Regulatory Matters | Regulatory Matters 2019 Retail Rate Case Filing with the Arizona Corporation Commission On October 31, 2019, APS filed an application with the ACC for an annual increase in retail base rates of $69 million . This amount includes recovery of the deferral and rate base effects of the Four Corners selective catalytic reduction ("SCR") project that is currently the subject of a separate proceeding (see “SCR Cost Recovery” below). It also reflects a net credit to base rates of approximately $115 million primarily due to the prospective inclusion of rate refunds currently provided through the Tax Expense Adjustment Mechanism ("TEAM"). The proposed total revenue increase in APS's application is $184 million . The average annual customer bill impact of APS’s request is an increase of 5.6% (the average annual bill impact for a typical APS residential customer is 5.4% ). The principal provisions of APS's application are: • a test year comprised of twelve months ended June 30, 2019, adjusted as described below; • an original cost rate base of $8.87 billion , which approximates the ACC-jurisdictional portion of the book value of utility assets, net of accumulated depreciation and other credits; • the following proposed capital structure and costs of capital: Capital Structure Cost of Capital Long-term debt 45.3 % 4.10 % Common stock equity 54.7 % 10.15 % Weighted-average cost of capital 7.41 % • a 1% return on the increment of fair value rate base above APS’s original cost rate base, as provided for by Arizona law; • authorization to defer until APS's next general rate case the increase or decrease in its Arizona property taxes attributable to tax rate changes after the date the rate application is adjudicated; • a number of proposed rate and program changes for residential customers, including: ▪ a super off-peak period during the winter months for APS’s time-of-use with demand rates; ▪ additional $1.25 million in funding for limited-income crisis bill program; and ▪ a flat bill/subscription rate pilot program; • proposed rate design changes for commercial customers, including an experimental program designed to provide access to market pricing for up to 200 MW of medium and large commercial customers; • recovery of the deferral and rate base effects of the construction and operating costs of the Ocotillo modernization project (see below discussion of the 2017 Settlement Agreement); and • continued recovery of the remaining investment and other costs related to the retirement and closure of the Navajo Generating Station (the "Navajo Plant") (see "Navajo Plant" below). APS requested that the increase become effective December 1, 2020. APS cannot predict the outcome of its request. 2016 Retail Rate Case Filing with the Arizona Corporation Commission On June 1, 2016, APS filed an application with the ACC for an annual increase in retail base rates. On March 27, 2017, a majority of the stakeholders in the general retail rate case, including the ACC Staff, the Residential Utility Consumer Office, limited income advocates and private rooftop solar organizations signed a settlement agreement (the "2017 Settlement Agreement") and filed it with the ACC. The 2017 Settlement Agreement provides for a net retail base rate increase of $94.6 million , excluding the transfer of adjustor balances, consisting of: (1) a non-fuel, non-depreciation, base rate increase of $87.2 million per year; (2) a base rate decrease of $53.6 million attributable to reduced fuel and purchased power costs; and (3) a base rate increase of $61.0 million due to changes in depreciation schedules. The average annual customer bill impact under the 2017 Settlement Agreement was calculated as an increase of 3.28% (the average annual bill impact for a typical APS residential customer was calculated as an increase of 4.54% ). Other key provisions of the agreement include the following: • an agreement by APS not to file another general retail rate case application before June 1, 2019; • an authorized return on common equity of 10.0% ; • a capital structure comprised of 44.2% debt and 55.8% common equity; • a cost deferral order for potential future recovery in APS’s next general retail rate case for the construction and operating costs APS incurs for its Ocotillo modernization project; • a cost deferral and procedure to allow APS to request rate adjustments prior to its next general retail rate case related to its share of the construction costs associated with installing SCR equipment at the Four Corners Power Plant ("Four Corners"); • a deferral for future recovery (or credit to customers) of the Arizona property tax expense above or below a specified test year level caused by changes to the applicable Arizona property tax rate; • an expansion of the Power Supply Adjustor (“PSA”) to include certain environmental chemical costs and third-party energy storage costs; • a new AZ Sun II program (now known as "APS Solar Communities") for utility-owned solar distributed generation with the purpose of expanding access to rooftop solar for low and moderate income Arizonans, recoverable through the Arizona Renewable Energy Standard and Tariff ("RES"), to be no less than $10 million per year, 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 additional time beyond May 3, 2019 to file the requested report. On June 4, 2019, the ACC Staff filed a proposed order regarding the rate review of the 2017 Rate Case Decision. On June 11, 2019, the ACC Commissioners approved the proposed ACC Staff order with amendments. The key provisions of the amended order include the following: • APS must file a rate case no later than October 31, 2019, using a June 30, 2019 test-year; • until the conclusion of the rate case being filed no later than October 31, 2019, APS must provide information on customer bills that shows how much a customer would pay on their most economical rate given their actual usage during each month; • APS customers can switch rate plans during an open enrollment period of six months; • APS must identify customers whose bills have increased by more than 9% and that are not on the most economical rate and provide such customers with targeted education materials and an opportunity to switch rate plans; • APS must provide grandfathered net metering customers on legacy demand rates an opportunity to switch to another legacy rate to enable such customers to fully benefit from legacy net metering rates; • APS must fund and implement a supplemental customer education and outreach program to be developed with and administered by ACC Staff and a third-party consultant; and • APS must fund and organize, along with the third-party consultant, a stakeholder group to suggest better ways to communicate the impact of changes to adjustor cost recovery mechanisms (see below for discussion on cost recovery mechanisms), including more effective ways to educate customers on rate plans and to reduce energy usage. APS cannot predict the outcome or impact of the rate case filed on October 31, 2019. APS is assessing the impact to its financial statements of the implementation of the other key provisions of the amended order regarding the rate review and cannot predict at this time whether they will have a material impact on its financial position, results of operations or cash flows. Cost Recovery Mechanisms APS has received regulatory decisions that allow for more timely recovery of certain costs outside of a general retail rate case through the following recovery mechanisms. Renewable Energy Standard . In 2006, the ACC approved the RES. Under the RES, electric utilities that are regulated by the ACC must supply an increasing percentage of their retail electric energy sales from eligible renewable resources, including solar, wind, biomass, biogas and geothermal technologies. In order to achieve these requirements, the ACC allows APS to include a RES surcharge as part of customer bills to recover the approved amounts for use on renewable energy projects. Each year APS is required to file a five -year implementation plan with the ACC and seek approval for funding the upcoming year’s RES budget. In 2015, the ACC revised the R ES 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. On October 29, 2019, the ACC approved 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. Nuclear energy would be considered a clean resource under the draft rules. 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 of the LFCR). On September 1, 2017, APS filed its 2018 DSM Plan, which proposes modifications to the demand side management portfolio to better meet system and customer needs by focusing on peak demand reductions, storage, load shifting and demand response programs in addition to traditional energy savings measures. The 2018 DSM Plan seeks a requested budget of $52.6 million and requests a waiver of the Electric Energy Efficiency Standard for 2018. On November 14, 2017, APS filed an amended 2018 DSM Plan, which revised the allocations between budget items to address customer participation levels, but kept the overall budget at $52.6 million . The ACC has not yet ruled on the APS 2018 amended DSM Plan. On December 31, 2018, APS filed its 2019 DSM Plan, which requests a budget of $34.1 million and continues APS's focus on DSM strategies such as peak demand reduction, load shifting, storage and electrification strategies. The ACC has not yet ruled on the APS 2019 DSM Plan. On 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): Nine Months Ended 2019 2018 Beginning balance $ 37,164 $ 75,637 Deferred fuel and purchased power costs — current period 60,911 82,486 Amounts charged to customers (38,601 ) (92,397 ) Ending balance $ 59,474 $ 65,726 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 . 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. 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”). On October 29, 2019, the ACC approved TEAM Phase III providing both (i) a one-time bill credit of $64 million to be credited to customers on their December 2019 bills, and (ii) a monthly bill credit effective the first billing cycle in December 2019 which will provide an additional benefit of $39.5 million to customers through December 31, 2020. It is currently anticipated that benefits related to the amortization of depreciation related excess deferred taxes for periods beginning after December 31, 2020 will be fully incorporated into the 2019 rate case filing. Net Metering In 2015, the ACC voted to conduct a generic evidentiary hearing on the value and cost of DG to gather information that will inform the ACC on net metering issues and cost of service studies in upcoming utility rate cases. A hearing was held in April 2016. On October 7, 2016, the Administrative Law Judge issued a recommendation in the docket concerning the value and cost of DG solar installations. On December 20, 2016, the ACC completed its open meeting to consider the recommended opinion and order by the Administrative Law Judge. After making several amendments, the ACC approved the recommended decision by a 4-1 vote. As a result of the ACC’s action, effective with APS’s 2017 Rate Case Decision, the net metering tariff that governs payments for energy exported to the grid from residential rooftop solar systems was replaced by a more formula-driven approach that utilizes inputs from historical wholesale solar power until an avoided cost methodology is developed by the ACC. As amended, the decision provides that payments by utilities for energy exported to the grid from DG solar facilities will be determined using a RCP methodology, a method that is based on the most recent five-year rolling average price that APS pays for utility-scale solar projects, while a forecasted avoided cost methodology is being developed. The price established by this RCP method will be updated annually (between general retail rate cases) but will not be decreased by more than 10% per year. Once the avoided cost methodology is developed, the ACC will determine in APS's subsequent rate cases which method (or a combination of methods) is appropriate to determine the actual price to be paid by APS for exported distributed energy. In addition, the ACC made the following determinations: • Customers who have interconnected a DG system or submitted an application for interconnection for DG systems prior to September 1, 2017, based on APS's 2017 Rate Case Decision, will be grandfathered for a period of 20 years from the date the customer’s interconnection application was accepted by the utility; • Customers with DG solar systems are to be considered a separate class of customers for ratemaking purposes; and • Once an export price is set for APS, no netting or banking of retail credits will be available for new DG customers, and the then-applicable export price will be guaranteed for new customers for a period of 10 years. This decision of the ACC addresses policy determinations only. The decision states that its principles will be applied in future general retail rate cases, and the policy determinations themselves may be subject to future change, as are all ACC policies. A first-year export energy price of 12.9 cents per kWh was included in the 2017 Settlement Agreement and became effective on September 1, 2017. In accordance with the 2017 Rate Case Decision, APS filed its request for a second-year export energy price of 11.6 cents per kWh on May 1, 2018. This price reflected the 10% annual reduction discussed above. The new rate rider became effective on October 1, 2018. APS filed its request for a third-year export energy price of 10.45 cents per kWh on May 1, 2019. This price also reflects the 10% annual reduction discussed above. The new rate rider became effective on October 1, 2019. 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 "2016 Retail Rate Case Filing with the Arizona Corporation Commission" above for information regarding an ACC order in connecti |
Retirement Plans and Other Post
Retirement Plans and Other Postretirement Benefits | 9 Months Ended |
Sep. 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 Nine Months Ended Three Months Ended Nine Months Ended 2019 2018 2019 2018 2019 2018 2019 2018 Service cost — benefits earned during the period $ 12,476 $ 14,167 $ 37,427 $ 42,501 $ 4,593 $ 5,275 $ 13,777 $ 15,825 Non-service costs (credits): Interest cost on benefit obligation 34,211 31,172 102,632 93,517 7,473 7,037 22,420 21,111 Expected return on plan assets (42,971 ) (45,713 ) (128,913 ) (137,140 ) (9,603 ) (10,520 ) (28,809 ) (31,561 ) Amortization of: Prior service credit — — — — (9,456 ) (9,461 ) (28,366 ) (28,382 ) Net actuarial loss 10,646 8,021 31,938 24,062 — — — — Net periodic benefit cost (credit) $ 14,362 $ 7,647 $ 43,084 $ 22,940 $ (6,993 ) $ (7,669 ) $ (20,978 ) $ (23,007 ) Portion of cost (credit) charged to expense $ 7,593 $ 2,524 $ 22,837 $ 7,535 $ (4,966 ) $ (5,359 ) $ (14,846 ) $ (16,083 ) Contributions We have made voluntary contributions of $150 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. In 2019, the Company was reimbursed $30 million for prior year retiree medical claims from the other postretirement benefit plan trust assets. |
Palo Verde Sale Leaseback Varia
Palo Verde Sale Leaseback Variable Interest Entities | 9 Months Ended |
Sep. 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 nine months ended September 30, 2019 of $ 5 million and $15 million, respectively, and for the three and nine months ended September 30, 2018 of $5 million and $15 million, respectively, entirely attributable to the noncontrolling interests. Income attributable to Pinnacle West shareholders is not impacted by the consolidation. Our Condensed Consolidated Balance Sheets at September 30, 2019 and December 31, 2018 include the following amounts relating to the VIEs (dollars in thousands): September 30, 2019 December 31, 2018 Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation $ 102,873 $ 105,775 Equity — Noncontrolling interests 129,039 125,790 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. |
Derivative Accounting
Derivative Accounting | 9 Months Ended |
Sep. 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 September 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 September 30, 2019 December 31, 2018 Power GWh 232 250 Gas Billion cubic feet 187 218 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 nine months ended September 30, 2019 and 2018 (dollars in thousands): Financial Statement Location Three Months Ended Nine Months Ended Commodity Contracts 2019 2018 2019 2018 Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a) Fuel and purchased power (b) $ (289 ) $ (600 ) $ (1,263 ) $ (1,697 ) (a) During the three and nine months ended September 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 nine months ended September 30, 2019 and 2018 (dollars in thousands): Financial Statement Location Three Months Ended Nine Months Ended Commodity Contracts 2019 2018 2019 2018 Net Loss Recognized in Income Operating revenues $ — $ (1,029 ) $ — $ (2,590 ) Net Gain (Loss) Recognized in Income Fuel and purchased power (a) (28,249 ) 4,263 (69,765 ) (26,442 ) Total $ (28,249 ) $ 3,234 $ (69,765 ) $ (29,032 ) (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 September 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 September 30, 2019: Gross Recognized Derivatives (a) Amounts Offset (b) Net Recognized Derivatives Other (c) Amount Reported on Balance Sheets Current assets $ 1,776 $ (1,266 ) $ 510 $ 307 $ 817 Total assets 1,776 (1,266 ) 510 307 817 Current liabilities (44,429 ) 1,266 (43,163 ) (1,186 ) (44,349 ) Deferred credits and other (27,305 ) — (27,305 ) — (27,305 ) Total liabilities (71,734 ) 1,266 (70,468 ) (1,186 ) (71,654 ) Total $ (69,958 ) $ — $ (69,958 ) $ (879 ) $ (70,837 ) (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 $1,186 and cash margin provided to counterparties of $307 . As of December 31, 2018: 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 September 30, 2019, we have one counterparty for which our exposure represents approximately 62% of Pinnacle West’s $0.8 million of risk management assets. This exposure relates to a master agreement with a counterparty that has a very high credit rating. 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 September 30, 2019 (dollars in thousands): September 30, 2019 Aggregate fair value of derivative instruments in a net liability position $ 71,503 Cash collateral posted — Additional cash collateral in the event credit-risk-related contingent features were fully triggered (a) 70,230 (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. |
Commitments and Contingencies
Commitments and Contingencies | 9 Months Ended |
Sep. 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 five claims pursuant to the terms of the August 18, 2014 settlement agreement, for five separate time periods during July 1, 2011 through June 30, 2018. The DOE has approved and paid $84.3 million for these claims (APS’s share is $24.5 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). On October 31, 2019, APS filed its next claim pursuant to the terms of the August 18, 2014 settlement agreement in the amount of $16 million (APS’s share is $4.7 million ). 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 During 2019 our fuel and purchased power commitments have increased from the information provided in our 2018 10-K. The increase is primarily due to new purchased power commitments of approximately $260 million . The majority of the changes relate to 2024 and thereafter. During 2019 our coal reclamation commitments have decreased from the information provided in our 2018 10-K by approximately $100 million . The decrease is primarily due to a new coal reclamation cost study for Four Corners. The majority of the changes relate to 2024 and thereafter. Other than the items described above, there have been no material changes, as of September 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 52 nd 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. On August 16, 2019, Maricopa County, one of the three direct defendants in the service provider lawsuit, filed a third-party complaint seeking contribution for its liability, if any, from APS and 28 other third-party 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 , which has 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. On August 14, 2019, EPA modified its boron proposal to include a specific, health-based groundwater protection standard for boron. These proposals remain pending, and EPA is not required to take final action including boron among the list of constituents that will determine CCR corrective actions. 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 of the industry- and environmental-group litigation challenging the federal CCR regulations. 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). 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. On November 4, 2019, EPA issued a proposed rule responding to this litigation that contemplates an August 2020 closure initiation deadline with an optional three-month extension as needed for the completion of alternative disposal capacity. 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 APS predicts such assessment will continue through early 2020. 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 regulations 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 such as 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. Various state governments, industry organizations, and environmental and public-health public interest groups have filed lawsuits in the D.C. Circuit challenging the legality of EPA’s action, both in repealing the CPP and issuing the ACE regulations. In addition, to the extent that the ACE regulations go into effect as finalized, it is not yet clear how the state of Arizona or EPA will implement these regulations as applied to APS’s coal-fired EGUs. In light of these uncertainties, APS is still evaluating the impact of the ACE regulations on its coal-fired generation fleet. 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, after which the environmental group plaintiffs petitioned the Ninth Circuit for rehearing on September 12, 2019. 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. EPA issued the final NPDES permit for Four Corners on September 30, 2019. This permit is now subject to a petition for review before the EPA Environmental Appeals Board, based upon a November 1, 2019 filing by several environmental groups. We cannot predict the outcome of this review and whether the review 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 September 30, 2019 , standby letters of credit totaled $1.7 million and will expire in 2020. As of September 30, 2019 , surety bonds expiring through 2020 totaled $14 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 September 30, 2019 . In connection with the sale of 4CA's 7% interest to NTEC, Pinnacle West is guaranteeing |
Other Income and Other Expense
Other Income and Other Expense | 9 Months Ended |
Sep. 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 nine months ended September 30, 2019 and 2018 (dollars in thousands): Three Months Ended Nine Months Ended 2019 2018 2019 2018 Other income: Interest income $ 2,694 $ 1,957 $ 7,695 $ 6,256 Debt return on Four Corners SCR (Note 4) 4,920 4,910 14,651 11,190 Debt return on Ocotillo modernization project (Note 4) 7,555 — 12,849 — Miscellaneous 22 91 50 95 Total other income $ 15,191 $ 6,958 $ 35,245 $ 17,541 Other expense: Non-operating costs $ (2,647 ) $ (2,480 ) $ (8,832 ) $ (7,404 ) Investment losses — net (716 ) — (1,445 ) (268 ) Miscellaneous (2,377 ) (2,583 ) (4,171 ) (4,391 ) Total other expense $ (5,740 ) $ (5,063 ) $ (14,448 ) $ (12,063 ) The following table provides detail of APS’s other income and other expense for the three and nine months ended September 30, 2019 and 2018 (dollars in thousands): Three Months Ended Nine Months Ended 2019 2018 2019 2018 Other income: Interest income $ 2,037 $ 1,151 $ 5,091 $ 4,874 Debt return on Four Corners SCR (Note 4) 4,920 4,910 14,651 11,190 Debt return on Ocotillo modernization project (Note 4) 7,555 — 12,849 — Miscellaneous 22 92 50 96 Total other income $ 14,534 $ 6,153 $ 32,641 $ 16,160 Other expense: Non-operating costs $ (2,448 ) $ (2,334 ) $ (7,965 ) $ (6,931 ) Miscellaneous (378 ) (1,027 ) (2,167 ) (2,748 ) Total other expense $ (2,826 ) $ (3,361 ) $ (10,132 ) $ (9,679 ) |
Earnings Per Share
Earnings Per Share | 9 Months Ended |
Sep. 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 nine months ended September 30, 2019 and 2018 (in thousands, except per share amounts): Three Months Ended Nine Months Ended 2019 2018 2019 2018 Net income attributable to common shareholders $ 312,276 $ 315,012 $ 474,339 $ 484,971 Weighted average common shares outstanding — basic 112,463 112,148 112,408 112,094 Net effect of dilutive securities: Contingently issuable performance shares and restricted stock units 283 385 331 405 Weighted average common shares outstanding — diluted 112,746 112,533 112,739 112,499 Earnings per weighted-average common share outstanding Net income attributable to common shareholders — basic $ 2.78 $ 2.81 $ 4.22 $ 4.33 Net income attributable to common shareholders — diluted $ 2.77 $ 2.80 $ 4.21 $ 4.31 |
Fair Value Measurements
Fair Value Measurements | 9 Months Ended |
Sep. 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 at the measurement date. 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. 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 September 30, 2019 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands): Level 1 Level 2 Level 3 Other Total Assets Risk management activities — derivative instruments: Commodity contracts $ — $ 1,388 $ 388 $ (959 ) (a) $ 817 Nuclear decommissioning trust: Equity securities 8,774 — — (1,322 ) (b) 7,452 U.S. commingled equity funds — — — 476,693 (c) 476,693 U.S. Treasury debt 162,092 — — — 162,092 Corporate debt — 124,026 — — 124,026 Mortgage-backed securities — 112,704 — — 112,704 Municipal bonds — 74,202 — — 74,202 Other fixed income — 10,504 — — 10,504 Subtotal nuclear decommissioning trust 170,866 321,436 — 475,371 967,673 Other special use funds: Equity securities 1,982 — — 1,418 (b) 3,400 U.S. Treasury debt 232,165 — — — 232,165 Municipal bonds — 8,417 — — 8,417 Subtotal other special use funds 234,147 8,417 — 1,418 243,982 Total assets $ 405,013 $ 331,241 $ 388 $ 475,830 $ 1,212,472 Liabilities Risk management activities — derivative instruments: Commodity contracts $ — $ (69,752 ) $ (1,982 ) $ 80 (a) $ (71,654 ) (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): Level 1 Level 2 Level 3 Other Total 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 September 30, 2019 and December 31, 2018 : September 30, 2019 Valuation Technique Significant Unobservable Input Weighted-Average Commodity Contracts Assets Liabilities Range Electricity: Forward Contracts (a) $ 388 $ 489 Discounted cash flows Electricity forward price (per MWh) $17.79 - $17.79 $ 17.79 Natural Gas: Forward Contracts (a) — 1,493 Discounted cash flows Natural gas forward price (per MMBtu) $2.53 - $2.79 $ 2.64 Total $ 388 $ 1,982 (a) Includes swaps and physical and financial contracts. December 31, 2018 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 nine months ended September 30, 2019 and 2018 (dollars in thousands): Three Months Ended Nine Months Ended Commodity Contracts 2019 2018 2019 2018 Net derivative balance at beginning of period $ (12,753 ) $ (9,358 ) $ (8,214 ) $ (18,256 ) Total net gains (losses) realized/unrealized: Deferred as a regulatory asset or liability (2,324 ) 1,244 (12,634 ) (2,067 ) Settlements 8,980 (2,332 ) 11,929 (1,056 ) Transfers into Level 3 from Level 2 (613 ) (2,246 ) (3,711 ) (7,225 ) Transfers from Level 3 into Level 2 5,116 2,829 11,036 18,741 Net derivative balance at end of period $ (1,594 ) $ (9,863 ) $ (1,594 ) $ (9,863 ) 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 $49 million as of September 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. |
Investments in Nuclear Decommis
Investments in Nuclear Decommissioning Trusts and Other Special Use Funds | 9 Months Ended |
Sep. 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. In August 2019, the Company was reimbursed $15 million for prior year active union employee medical claims from the active union employee medical account. 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 September 30, 2019 and December 31, 2018 (dollars in thousands): September 30, 2019 Fair Value Total Unrealized Gains Total Unrealized Losses Investment Type: Nuclear Decommissioning Trust Other Special Use Funds Total Equity securities $ 485,467 $ 1,982 $ 487,449 $ 297,032 $ — Available for sale-fixed income securities 483,528 240,582 724,110 (a) 28,750 (476 ) Other (1,322 ) 1,418 96 (b) — — Total $ 967,673 $ 243,982 $ 1,211,655 $ 325,782 $ (476 ) (a) As of September 30, 2019 , the amortized cost basis of these available-for-sale investments is $696 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 nine months ended September 30, 2019 and 2018 (dollars in thousands): Three Months Ended September 30, Nuclear Decommissioning Trust Other Special Use Funds Total 2019 Realized gains $ 4,732 $ 4 $ 4,736 Realized losses (2,360 ) — (2,360 ) Proceeds from the sale of securities (a) 155,386 56,255 211,641 2018 Realized gains $ 653 $ — $ 653 Realized losses (1,965 ) — (1,965 ) Proceeds from the sale of securities (a) 148,150 25,127 173,277 (a) Proceeds are reinvested in the nuclear decommissioning trust and coal reclamation escrow account. Nine Months Ended September 30, Nuclear Decommissioning Trust Other Special Use Funds Total 2019 Realized gains $ 8,478 $ 4 $ 8,482 Realized losses (5,465 ) — (5,465 ) Proceeds from the sale of securities (a) 371,538 149,458 520,996 2018 Realized gains $ 2,951 $ 1 $ 2,952 Realized losses (6,990 ) — (6,990 ) Proceeds from the sale of securities (a) 401,396 41,644 443,040 (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 September 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 $ 40,309 $ 32,628 $ 37,013 $ 109,950 1 year – 5 years 133,488 25,928 140,895 300,311 5 years – 10 years 103,973 720 — 104,693 Greater than 10 years 205,758 3,398 — 209,156 Total $ 483,528 $ 62,674 $ 177,908 $ 724,110 (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. |
New Accounting Standards
New Accounting Standards | 9 Months Ended |
Sep. 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. Standard 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. |
Changes in Accumulated Other Co
Changes in Accumulated Other Comprehensive Loss | 9 Months Ended |
Sep. 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 nine months ended September 30, 2019 and 2018 (dollars in thousands): Pension and Other Postretirement Benefits Derivative Instruments Total Three Months Ended September 30 Balance June 30, 2019 $ (46,657 ) $ (979 ) $ (47,636 ) Amounts reclassified from accumulated other comprehensive loss 880 (a) 218 (b) 1,098 Balance September 30, 2019 $ (45,777 ) $ (761 ) $ (46,538 ) Balance June 30, 2018 $ (54,233 ) $ (2,391 ) $ (56,624 ) Amounts reclassified from accumulated other comprehensive loss 1,099 (a) 451 (b) 1,550 Balance September 30, 2018 $ (53,134 ) $ (1,940 ) $ (55,074 ) Pension and Other Postretirement Benefits Derivative Instruments Total Nine Months Ended September 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 2,642 (a) 950 (b) 3,592 Balance September 30, 2019 $ (45,777 ) $ (761 ) $ (46,538 ) 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 3,188 (a) 1,316 (b) 4,504 Reclassification of income tax effect related to tax reform (7,954 ) (c) (598 ) (c) (8,552 ) Balance September 30, 2018 $ (53,134 ) $ (1,940 ) $ (55,074 ) (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 nine months ended September 30, 2019 and 2018 (dollars in thousands): Pension and Other Postretirement Benefits Derivative Instruments Total Three Months Ended September 30 Balance June 30, 2019 $ (26,297 ) $ (979 ) $ (27,276 ) Amounts reclassified from accumulated other comprehensive loss 755 (a) 218 (b) 973 Balance September 30, 2019 $ (25,542 ) $ (761 ) $ (26,303 ) Balance June 30, 2018 $ (32,768 ) $ (2,391 ) $ (35,159 ) Amounts reclassified from accumulated other comprehensive loss 952 (a) 451 (b) 1,403 Balance September 30, 2018 $ (31,816 ) $ (1,940 ) $ (33,756 ) Pension and Other Postretirement Benefits Derivative Instruments Total Nine Months Ended September 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 2,268 (a) 950 (b) 3,218 Balance September 30, 2019 $ (25,542 ) $ (761 ) $ (26,303 ) Balance December 31, 2017 $ (24,421 ) $ (2,562 ) $ (26,983 ) OCI (loss) before reclassifications (5,791 ) (96 ) (5,887 ) Amounts reclassified from accumulated other comprehensive loss 2,836 (a) 1,316 (b) 4,152 Reclassification of income tax effect related to tax reform (4,440 ) (c) (598 ) (c) (5,038 ) Balance September 30, 2018 $ (31,816 ) $ (1,940 ) $ (33,756 ) (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. |
Income Taxes
Income Taxes | 9 Months Ended |
Sep. 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 September 30, 2019, the Company has recorded $42 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, U.S. Treasury proposed regulations that clarified 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, these proposed regulations were ambiguous with respect to regulated public utility property placed in service on or after January 1, 2018. In September 2019, U.S. Treasury issued final regulations, which replaced the August 2018 proposed regulations. These final regulations did not materially impact any tax position taken by the Company for property placed in service after September 27, 2017 and before January 1, 2018. Along with the September 2019 final regulations, U.S. Treasury also issued new proposed regulations which clarify bonus depreciation transition rules under the Tax Act for property placed in service by regulated public utilities after December 31, 2017. The proposed regulations provide that certain regulated public utility property which was under construction prior to September 28, 2017 and placed in service between January 1, 2018 and December 31, 2020 would continue to be eligible for bonus depreciation under the rules and bonus depreciation phase-downs in effect prior to enactment of the Tax Act. During the third quarter, as a result of the clarification provided by these proposed regulations, the Company recorded deferred tax liabilities of approximately $56 million related to bonus depreciation benefits claimed on the Company’s 2018 tax return. 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, 2016 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. |
Leases
Leases | 9 Months Ended |
Sep. 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 nine months ended September 30, 2019 (dollars in thousands): Three Months Ended Purchased Power Lease Contracts Land, Property & Equipment Leases Total Operating lease cost $ 21,095 $ 4,581 $ 25,676 Variable lease cost 36,917 183 37,100 Short-term lease cost — 812 812 Total lease cost $ 58,012 $ 5,576 $ 63,588 Nine Months Ended Purchased Power Lease Contracts Land, Property & Equipment Leases Total Operating lease cost $ 35,159 $ 13,343 $ 48,502 Variable lease cost 95,736 543 96,279 Short-term lease cost — 3,477 3,477 Total lease cost $ 130,895 $ 17,363 $ 148,258 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 September 30, 2019 (dollars in thousands): September 30, 2019 Year Purchased Power Lease Contracts Land, Property & Equipment Leases Total 2019 (remaining three months of 2019) $ 13,625 $ 3,352 $ 16,977 2020 — 14,083 14,083 2021 — 11,244 11,244 2022 — 7,727 7,727 2023 — 6,101 6,101 2024 — 3,915 3,915 Thereafter — 38,697 38,697 Total lease commitments 13,625 85,119 98,744 Less imputed interest 19 20,032 20,051 Total lease liabilities $ 13,606 $ 65,087 $ 78,693 We recognize lease assets and liabilities upon lease commencement. At September 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: September 30, 2019 Weighted average remaining lease term 12 years Weighted average discount rate (a) 3.73 % (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. Nine Months Ended Cash paid for amounts included in the measurement of lease liabilities - operating cash flows (dollars in thousands): $ 51,980 |
New Accounting Standards (Polic
New Accounting Standards (Policies) | 9 Months Ended |
Sep. 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. Standard 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. |
Consolidation and Nature of O_2
Consolidation and Nature of Operations (Tables) | 9 Months Ended |
Sep. 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): Nine Months Ended 2019 2018 Cash paid during the period for: Income taxes, net of refunds $ 12,488 $ 10,091 Interest, net of amounts capitalized 166,907 161,875 Significant non-cash investing and financing activities: Accrued capital expenditures $ 85,099 $ 99,405 Right-of-use operating lease assets obtained in exchange for operating lease liabilities 8,759 — Sale of 4CA's 7% interest in Four Corners — 68,907 The following table summarizes supplemental APS cash flow information (dollars in thousands): Nine Months Ended 2019 2018 Cash paid during the period for: Income taxes, net of refunds $ 35,573 $ 24,746 Interest, net of amounts capitalized 157,593 154,788 Significant non-cash investing and financing activities: Accrued capital expenditures $ 85,099 $ 99,405 Right-of-use operating lease assets obtained in exchange for operating lease liabilities 8,759 — |
Revenue (Tables)
Revenue (Tables) | 9 Months Ended |
Sep. 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 September 30, Nine Months Ended September 30, 2019 2018 2019 2018 Retail Electric Revenue Residential $ 668,467 $ 695,480 $ 1,452,601 $ 1,512,402 Non-Residential 465,602 496,809 1,194,199 1,275,498 Wholesale energy sales 36,775 53,501 95,218 80,982 Transmission services for others 15,841 15,902 46,247 46,235 Other sources 4,102 6,342 12,553 19,754 Total operating revenues $ 1,190,787 $ 1,268,034 $ 2,800,818 $ 2,934,871 |
Long-Term Debt and Liquidity _2
Long-Term Debt and Liquidity Matters (Tables) | 9 Months Ended |
Sep. 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 September 30, 2019 As of December 31, 2018 Carrying Amount Fair Value Carrying Amount Fair Value Pinnacle West $ 449,268 $ 449,670 $ 448,796 $ 443,955 APS 4,985,728 5,617,727 4,689,436 4,789,608 Total $ 5,434,996 $ 6,067,397 $ 5,138,232 $ 5,233,563 |
Regulatory Matters (Tables)
Regulatory Matters (Tables) | 9 Months Ended |
Sep. 30, 2019 | |
Regulated Operations [Abstract] | |
Schedule of capital structure and cost of capital | the following proposed capital structure and costs of capital: Capital Structure Cost of Capital Long-term debt 45.3 % 4.10 % Common stock equity 54.7 % 10.15 % Weighted-average cost of capital 7.41 % |
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): Nine Months Ended 2019 2018 Beginning balance $ 37,164 $ 75,637 Deferred fuel and purchased power costs — current period 60,911 82,486 Amounts charged to customers (38,601 ) (92,397 ) Ending balance $ 59,474 $ 65,726 |
Schedule of regulatory assets | The detail of regulatory assets is as follows (dollars in thousands): Amortization Through September 30, 2019 December 31, 2018 Current Non-Current Current Non-Current Pension (a) $ — $ 703,460 $ — $ 733,351 Retired power plant costs 2033 28,182 146,076 28,182 167,164 Income taxes — allowance for funds used during construction ("AFUDC") equity 2049 6,457 154,269 6,457 151,467 Deferred fuel and purchased power — mark-to-market (Note 7) 2023 41,643 27,305 31,728 23,768 Deferred property taxes 2027 8,569 60,338 8,569 66,356 Deferred fuel and purchased power (b) (c) 2020 59,474 — 37,164 — SCR deferral N/A — 45,296 — 23,276 Four Corners cost deferral 2024 8,077 34,171 8,077 40,228 Deferred compensation 2036 — 37,589 — 36,523 Lost fixed cost recovery (b) 2020 25,775 — 32,435 — Income taxes — investment tax credit basis adjustment 2047 1,079 24,555 1,079 25,522 Ocotillo deferral N/A — 23,643 — — Palo Verde VIEs (Note 6) 2046 — 20,480 — 20,015 Coal reclamation 2026 1,546 18,821 1,546 15,607 Loss on reacquired debt 2038 1,637 12,441 1,637 13,668 Mead-Phoenix transmission line CIAC 2050 332 9,795 332 10,044 TCA balancing account (b) 2021 5,016 2,721 3,860 772 Tax expense of Medicare subsidy 2024 1,235 5,073 1,235 6,176 AG-1 deferral 2022 2,787 3,413 2,654 5,819 Tax expense adjuster mechanism (b) 2019 2,916 — — — Other Various 2,782 — 1,947 3,185 Total regulatory assets (d) $ 197,507 $ 1,329,446 $ 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 September 30, 2019 December 31, 2018 Current Non-Current Current Non-Current Excess deferred income taxes - ACC - Tax Cuts and Jobs Act (a) (b) $ 38,529 $ 1,178,216 $ — $ 1,272,709 Excess deferred income taxes - FERC - Tax Cuts and Jobs Act (a) 2058 6,302 238,064 6,302 243,691 Asset retirement obligations 2057 — 367,930 — 278,585 Removal costs (c) 47,459 151,535 39,866 177,533 Other postretirement benefits (d) 37,821 95,789 37,864 125,903 Income taxes — change in rates 2048 2,764 67,605 2,769 70,069 Spent nuclear fuel 2027 5,746 53,229 6,503 57,002 Income taxes — deferred investment tax credit 2047 2,164 49,182 2,164 51,120 Four Corners coal reclamation 2038 1,858 49,194 1,858 17,871 Renewable energy standard (b) 2021 42,146 5,675 44,966 20 Demand side management (b) 2021 14,300 24,146 14,604 4,123 Sundance maintenance 2031 4,640 13,393 1,278 17,228 Deferred gains on utility property 2022 2,923 4,766 4,423 6,581 Property tax deferral N/A — 6,288 — 2,611 FERC transmission true up 2021 — 2,586 — — Other Various 1,370 2,533 3,279 930 Total regulatory liabilities $ 208,022 $ 2,310,131 $ 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. |
Retirement Plans and Other Po_2
Retirement Plans and Other Postretirement Benefits (Tables) | 9 Months Ended |
Sep. 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 Nine Months Ended Three Months Ended Nine Months Ended 2019 2018 2019 2018 2019 2018 2019 2018 Service cost — benefits earned during the period $ 12,476 $ 14,167 $ 37,427 $ 42,501 $ 4,593 $ 5,275 $ 13,777 $ 15,825 Non-service costs (credits): Interest cost on benefit obligation 34,211 31,172 102,632 93,517 7,473 7,037 22,420 21,111 Expected return on plan assets (42,971 ) (45,713 ) (128,913 ) (137,140 ) (9,603 ) (10,520 ) (28,809 ) (31,561 ) Amortization of: Prior service credit — — — — (9,456 ) (9,461 ) (28,366 ) (28,382 ) Net actuarial loss 10,646 8,021 31,938 24,062 — — — — Net periodic benefit cost (credit) $ 14,362 $ 7,647 $ 43,084 $ 22,940 $ (6,993 ) $ (7,669 ) $ (20,978 ) $ (23,007 ) Portion of cost (credit) charged to expense $ 7,593 $ 2,524 $ 22,837 $ 7,535 $ (4,966 ) $ (5,359 ) $ (14,846 ) $ (16,083 ) |
Palo Verde Sale Leaseback Var_2
Palo Verde Sale Leaseback Variable Interest Entities (Tables) | 9 Months Ended |
Sep. 30, 2019 | |
Variable Interest Entities [Abstract] | |
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets | Our Condensed Consolidated Balance Sheets at September 30, 2019 and December 31, 2018 include the following amounts relating to the VIEs (dollars in thousands): September 30, 2019 December 31, 2018 Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation $ 102,873 $ 105,775 Equity — Noncontrolling interests 129,039 125,790 |
Derivative Accounting (Tables)
Derivative Accounting (Tables) | 9 Months Ended |
Sep. 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 September 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 September 30, 2019 December 31, 2018 Power GWh 232 250 Gas Billion cubic feet 187 218 |
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 nine months ended September 30, 2019 and 2018 (dollars in thousands): Financial Statement Location Three Months Ended Nine Months Ended Commodity Contracts 2019 2018 2019 2018 Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a) Fuel and purchased power (b) $ (289 ) $ (600 ) $ (1,263 ) $ (1,697 ) (a) During the three and nine months ended September 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 nine months ended September 30, 2019 and 2018 (dollars in thousands): Financial Statement Location Three Months Ended Nine Months Ended Commodity Contracts 2019 2018 2019 2018 Net Loss Recognized in Income Operating revenues $ — $ (1,029 ) $ — $ (2,590 ) Net Gain (Loss) Recognized in Income Fuel and purchased power (a) (28,249 ) 4,263 (69,765 ) (26,442 ) Total $ (28,249 ) $ 3,234 $ (69,765 ) $ (29,032 ) (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 September 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 September 30, 2019: Gross Recognized Derivatives (a) Amounts Offset (b) Net Recognized Derivatives Other (c) Amount Reported on Balance Sheets Current assets $ 1,776 $ (1,266 ) $ 510 $ 307 $ 817 Total assets 1,776 (1,266 ) 510 307 817 Current liabilities (44,429 ) 1,266 (43,163 ) (1,186 ) (44,349 ) Deferred credits and other (27,305 ) — (27,305 ) — (27,305 ) Total liabilities (71,734 ) 1,266 (70,468 ) (1,186 ) (71,654 ) Total $ (69,958 ) $ — $ (69,958 ) $ (879 ) $ (70,837 ) (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 $1,186 and cash margin provided to counterparties of $307 . As of December 31, 2018: 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 September 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 September 30, 2019: Gross Recognized Derivatives (a) Amounts Offset (b) Net Recognized Derivatives Other (c) Amount Reported on Balance Sheets Current assets $ 1,776 $ (1,266 ) $ 510 $ 307 $ 817 Total assets 1,776 (1,266 ) 510 307 817 Current liabilities (44,429 ) 1,266 (43,163 ) (1,186 ) (44,349 ) Deferred credits and other (27,305 ) — (27,305 ) — (27,305 ) Total liabilities (71,734 ) 1,266 (70,468 ) (1,186 ) (71,654 ) Total $ (69,958 ) $ — $ (69,958 ) $ (879 ) $ (70,837 ) (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 $1,186 and cash margin provided to counterparties of $307 . As of December 31, 2018: 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 September 30, 2019 (dollars in thousands): September 30, 2019 Aggregate fair value of derivative instruments in a net liability position $ 71,503 Cash collateral posted — Additional cash collateral in the event credit-risk-related contingent features were fully triggered (a) 70,230 (a) This amount is after counterparty netting and includes those contracts which qualify for scope exceptions, which are excluded from the derivative details above. |
Other Income and Other Expense
Other Income and Other Expense (Tables) | 9 Months Ended |
Sep. 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 nine months ended September 30, 2019 and 2018 (dollars in thousands): Three Months Ended Nine Months Ended 2019 2018 2019 2018 Other income: Interest income $ 2,694 $ 1,957 $ 7,695 $ 6,256 Debt return on Four Corners SCR (Note 4) 4,920 4,910 14,651 11,190 Debt return on Ocotillo modernization project (Note 4) 7,555 — 12,849 — Miscellaneous 22 91 50 95 Total other income $ 15,191 $ 6,958 $ 35,245 $ 17,541 Other expense: Non-operating costs $ (2,647 ) $ (2,480 ) $ (8,832 ) $ (7,404 ) Investment losses — net (716 ) — (1,445 ) (268 ) Miscellaneous (2,377 ) (2,583 ) (4,171 ) (4,391 ) Total other expense $ (5,740 ) $ (5,063 ) $ (14,448 ) $ (12,063 ) The following table provides detail of APS’s other income and other expense for the three and nine months ended September 30, 2019 and 2018 (dollars in thousands): Three Months Ended Nine Months Ended 2019 2018 2019 2018 Other income: Interest income $ 2,037 $ 1,151 $ 5,091 $ 4,874 Debt return on Four Corners SCR (Note 4) 4,920 4,910 14,651 11,190 Debt return on Ocotillo modernization project (Note 4) 7,555 — 12,849 — Miscellaneous 22 92 50 96 Total other income $ 14,534 $ 6,153 $ 32,641 $ 16,160 Other expense: Non-operating costs $ (2,448 ) $ (2,334 ) $ (7,965 ) $ (6,931 ) Miscellaneous (378 ) (1,027 ) (2,167 ) (2,748 ) Total other expense $ (2,826 ) $ (3,361 ) $ (10,132 ) $ (9,679 ) |
Earnings Per Share (Tables)
Earnings Per Share (Tables) | 9 Months Ended |
Sep. 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 nine months ended September 30, 2019 and 2018 (in thousands, except per share amounts): Three Months Ended Nine Months Ended 2019 2018 2019 2018 Net income attributable to common shareholders $ 312,276 $ 315,012 $ 474,339 $ 484,971 Weighted average common shares outstanding — basic 112,463 112,148 112,408 112,094 Net effect of dilutive securities: Contingently issuable performance shares and restricted stock units 283 385 331 405 Weighted average common shares outstanding — diluted 112,746 112,533 112,739 112,499 Earnings per weighted-average common share outstanding Net income attributable to common shareholders — basic $ 2.78 $ 2.81 $ 4.22 $ 4.33 Net income attributable to common shareholders — diluted $ 2.77 $ 2.80 $ 4.21 $ 4.31 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 9 Months Ended |
Sep. 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 September 30, 2019 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands): Level 1 Level 2 Level 3 Other Total Assets Risk management activities — derivative instruments: Commodity contracts $ — $ 1,388 $ 388 $ (959 ) (a) $ 817 Nuclear decommissioning trust: Equity securities 8,774 — — (1,322 ) (b) 7,452 U.S. commingled equity funds — — — 476,693 (c) 476,693 U.S. Treasury debt 162,092 — — — 162,092 Corporate debt — 124,026 — — 124,026 Mortgage-backed securities — 112,704 — — 112,704 Municipal bonds — 74,202 — — 74,202 Other fixed income — 10,504 — — 10,504 Subtotal nuclear decommissioning trust 170,866 321,436 — 475,371 967,673 Other special use funds: Equity securities 1,982 — — 1,418 (b) 3,400 U.S. Treasury debt 232,165 — — — 232,165 Municipal bonds — 8,417 — — 8,417 Subtotal other special use funds 234,147 8,417 — 1,418 243,982 Total assets $ 405,013 $ 331,241 $ 388 $ 475,830 $ 1,212,472 Liabilities Risk management activities — derivative instruments: Commodity contracts $ — $ (69,752 ) $ (1,982 ) $ 80 (a) $ (71,654 ) (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): Level 1 Level 2 Level 3 Other Total 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 September 30, 2019 and December 31, 2018 : September 30, 2019 Valuation Technique Significant Unobservable Input Weighted-Average Commodity Contracts Assets Liabilities Range Electricity: Forward Contracts (a) $ 388 $ 489 Discounted cash flows Electricity forward price (per MWh) $17.79 - $17.79 $ 17.79 Natural Gas: Forward Contracts (a) — 1,493 Discounted cash flows Natural gas forward price (per MMBtu) $2.53 - $2.79 $ 2.64 Total $ 388 $ 1,982 (a) Includes swaps and physical and financial contracts. December 31, 2018 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 nine months ended September 30, 2019 and 2018 (dollars in thousands): Three Months Ended Nine Months Ended Commodity Contracts 2019 2018 2019 2018 Net derivative balance at beginning of period $ (12,753 ) $ (9,358 ) $ (8,214 ) $ (18,256 ) Total net gains (losses) realized/unrealized: Deferred as a regulatory asset or liability (2,324 ) 1,244 (12,634 ) (2,067 ) Settlements 8,980 (2,332 ) 11,929 (1,056 ) Transfers into Level 3 from Level 2 (613 ) (2,246 ) (3,711 ) (7,225 ) Transfers from Level 3 into Level 2 5,116 2,829 11,036 18,741 Net derivative balance at end of period $ (1,594 ) $ (9,863 ) $ (1,594 ) $ (9,863 ) Net unrealized gains included in earnings related to instruments still held at end of period $ — $ — $ — $ — |
Investments in Nuclear Decomm_2
Investments in Nuclear Decommissioning Trusts and Other Special Use Funds (Tables) | 9 Months Ended |
Sep. 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 September 30, 2019 and December 31, 2018 (dollars in thousands): September 30, 2019 Fair Value Total Unrealized Gains Total Unrealized Losses Investment Type: Nuclear Decommissioning Trust Other Special Use Funds Total Equity securities $ 485,467 $ 1,982 $ 487,449 $ 297,032 $ — Available for sale-fixed income securities 483,528 240,582 724,110 (a) 28,750 (476 ) Other (1,322 ) 1,418 96 (b) — — Total $ 967,673 $ 243,982 $ 1,211,655 $ 325,782 $ (476 ) (a) As of September 30, 2019 , the amortized cost basis of these available-for-sale investments is $696 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 nine months ended September 30, 2019 and 2018 (dollars in thousands): Three Months Ended September 30, Nuclear Decommissioning Trust Other Special Use Funds Total 2019 Realized gains $ 4,732 $ 4 $ 4,736 Realized losses (2,360 ) — (2,360 ) Proceeds from the sale of securities (a) 155,386 56,255 211,641 2018 Realized gains $ 653 $ — $ 653 Realized losses (1,965 ) — (1,965 ) Proceeds from the sale of securities (a) 148,150 25,127 173,277 (a) Proceeds are reinvested in the nuclear decommissioning trust and coal reclamation escrow account. Nine Months Ended September 30, Nuclear Decommissioning Trust Other Special Use Funds Total 2019 Realized gains $ 8,478 $ 4 $ 8,482 Realized losses (5,465 ) — (5,465 ) Proceeds from the sale of securities (a) 371,538 149,458 520,996 2018 Realized gains $ 2,951 $ 1 $ 2,952 Realized losses (6,990 ) — (6,990 ) Proceeds from the sale of securities (a) 401,396 41,644 443,040 (a) Proceeds are reinvested in the nuclear decommissioning trust and coal reclamation escrow account. |
Fair value of fixed income securities, summarized by contractual maturities | The fair value of APS's fixed income securities, summarized by contractual maturities, at September 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 $ 40,309 $ 32,628 $ 37,013 $ 109,950 1 year – 5 years 133,488 25,928 140,895 300,311 5 years – 10 years 103,973 720 — 104,693 Greater than 10 years 205,758 3,398 — 209,156 Total $ 483,528 $ 62,674 $ 177,908 $ 724,110 (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. |
Changes in Accumulated Other _2
Changes in Accumulated Other Comprehensive Loss (Tables) | 9 Months Ended |
Sep. 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 nine months ended September 30, 2019 and 2018 (dollars in thousands): Pension and Other Postretirement Benefits Derivative Instruments Total Three Months Ended September 30 Balance June 30, 2019 $ (46,657 ) $ (979 ) $ (47,636 ) Amounts reclassified from accumulated other comprehensive loss 880 (a) 218 (b) 1,098 Balance September 30, 2019 $ (45,777 ) $ (761 ) $ (46,538 ) Balance June 30, 2018 $ (54,233 ) $ (2,391 ) $ (56,624 ) Amounts reclassified from accumulated other comprehensive loss 1,099 (a) 451 (b) 1,550 Balance September 30, 2018 $ (53,134 ) $ (1,940 ) $ (55,074 ) Pension and Other Postretirement Benefits Derivative Instruments Total Nine Months Ended September 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 2,642 (a) 950 (b) 3,592 Balance September 30, 2019 $ (45,777 ) $ (761 ) $ (46,538 ) 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 3,188 (a) 1,316 (b) 4,504 Reclassification of income tax effect related to tax reform (7,954 ) (c) (598 ) (c) (8,552 ) Balance September 30, 2018 $ (53,134 ) $ (1,940 ) $ (55,074 ) (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 nine months ended September 30, 2019 and 2018 (dollars in thousands): Pension and Other Postretirement Benefits Derivative Instruments Total Three Months Ended September 30 Balance June 30, 2019 $ (26,297 ) $ (979 ) $ (27,276 ) Amounts reclassified from accumulated other comprehensive loss 755 (a) 218 (b) 973 Balance September 30, 2019 $ (25,542 ) $ (761 ) $ (26,303 ) Balance June 30, 2018 $ (32,768 ) $ (2,391 ) $ (35,159 ) Amounts reclassified from accumulated other comprehensive loss 952 (a) 451 (b) 1,403 Balance September 30, 2018 $ (31,816 ) $ (1,940 ) $ (33,756 ) Pension and Other Postretirement Benefits Derivative Instruments Total Nine Months Ended September 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 2,268 (a) 950 (b) 3,218 Balance September 30, 2019 $ (25,542 ) $ (761 ) $ (26,303 ) Balance December 31, 2017 $ (24,421 ) $ (2,562 ) $ (26,983 ) OCI (loss) before reclassifications (5,791 ) (96 ) (5,887 ) Amounts reclassified from accumulated other comprehensive loss 2,836 (a) 1,316 (b) 4,152 Reclassification of income tax effect related to tax reform (4,440 ) (c) (598 ) (c) (5,038 ) Balance September 30, 2018 $ (31,816 ) $ (1,940 ) $ (33,756 ) (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. |
Leases (Tables)
Leases (Tables) | 9 Months Ended |
Sep. 30, 2019 | |
Leases [Abstract] | |
Lease cost | The following tables provide information related to our lease costs for the three and nine months ended September 30, 2019 (dollars in thousands): Three Months Ended Purchased Power Lease Contracts Land, Property & Equipment Leases Total Operating lease cost $ 21,095 $ 4,581 $ 25,676 Variable lease cost 36,917 183 37,100 Short-term lease cost — 812 812 Total lease cost $ 58,012 $ 5,576 $ 63,588 Nine Months Ended Purchased Power Lease Contracts Land, Property & Equipment Leases Total Operating lease cost $ 35,159 $ 13,343 $ 48,502 Variable lease cost 95,736 543 96,279 Short-term lease cost — 3,477 3,477 Total lease cost $ 130,895 $ 17,363 $ 148,258 The following tables provide other additional information related to operating lease liabilities: September 30, 2019 Weighted average remaining lease term 12 years Weighted average discount rate (a) 3.73 % (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. Nine Months Ended Cash paid for amounts included in the measurement of lease liabilities - operating cash flows (dollars in thousands): $ 51,980 |
Schedule of future minimum payments | The following table provides information related to the maturity of our operating lease liabilities at September 30, 2019 (dollars in thousands): September 30, 2019 Year Purchased Power Lease Contracts Land, Property & Equipment Leases Total 2019 (remaining three months of 2019) $ 13,625 $ 3,352 $ 16,977 2020 — 14,083 14,083 2021 — 11,244 11,244 2022 — 7,727 7,727 2023 — 6,101 6,101 2024 — 3,915 3,915 Thereafter — 38,697 38,697 Total lease commitments 13,625 85,119 98,744 Less imputed interest 19 20,032 20,051 Total lease liabilities $ 13,606 $ 65,087 $ 78,693 We recognize lease assets and liabilities upon lease commencement. At September 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 |
Consolidation and Nature of O_3
Consolidation and Nature of Operations (Details) - USD ($) $ in Thousands | 9 Months Ended | |
Sep. 30, 2019 | Sep. 30, 2018 | |
Cash paid during the period for: | ||
Income taxes, net of refunds | $ 12,488 | $ 10,091 |
Interest, net of amounts capitalized | 166,907 | 161,875 |
Significant non-cash investing and financing activities: | ||
Accrued capital expenditures | 85,099 | 99,405 |
Right-of-use operating lease assets obtained in exchange for operating lease liabilities | 8,759 | 0 |
Sale of 4CA's 7% interest in Four Corners | 0 | 68,907 |
APS | ||
Cash paid during the period for: | ||
Income taxes, net of refunds | 35,573 | 24,746 |
Interest, net of amounts capitalized | 157,593 | 154,788 |
Significant non-cash investing and financing activities: | ||
Accrued capital expenditures | 85,099 | 99,405 |
Right-of-use operating lease assets obtained in exchange for operating lease liabilities | $ 8,759 | $ 0 |
APS | Four Corners | ||
Significant non-cash investing and financing activities: | ||
Ownership percentage | 7.00% |
Revenue (Details)
Revenue (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2019 | Sep. 30, 2018 | Sep. 30, 2019 | Sep. 30, 2018 | |
Disaggregation of Revenue [Line Items] | ||||
Operating revenues | $ 1,190,787 | $ 1,268,034 | $ 2,800,818 | $ 2,934,871 |
Regulatory cost recovery revenue | 13,000 | 11,000 | 45,000 | 38,000 |
Electric Service | Residential | ||||
Disaggregation of Revenue [Line Items] | ||||
Operating revenues | 668,467 | 695,480 | 1,452,601 | 1,512,402 |
Electric Service | Non-Residential | ||||
Disaggregation of Revenue [Line Items] | ||||
Operating revenues | 465,602 | 496,809 | 1,194,199 | 1,275,498 |
Electric Service | Wholesale energy sales | ||||
Disaggregation of Revenue [Line Items] | ||||
Operating revenues | 36,775 | 53,501 | 95,218 | 80,982 |
Transmission services for others | ||||
Disaggregation of Revenue [Line Items] | ||||
Operating revenues | 15,841 | 15,902 | 46,247 | 46,235 |
Other sources | ||||
Disaggregation of Revenue [Line Items] | ||||
Operating revenues | 4,102 | 6,342 | 12,553 | 19,754 |
Electric and Transmission Service | ||||
Disaggregation of Revenue [Line Items] | ||||
Operating revenues | $ 1,178,000 | $ 1,257,000 | $ 2,756,000 | $ 2,897,000 |
Long-Term Debt and Liquidity _3
Long-Term Debt and Liquidity Matters - Narrative (Details) | May 09, 2019USD ($) | Mar. 01, 2019USD ($) | Feb. 26, 2019USD ($) | Sep. 30, 2019USD ($)Facility | Aug. 19, 2019USD ($) | Feb. 28, 2019USD ($) |
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 | |||||
Long-term line of credit | 0 | |||||
Current borrowing capacity on credit facility | 200,000,000 | |||||
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 | 41,000,000 | |||||
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 | 13,000,000 | |||||
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 | $ 300,000,000 | ||||
Debt instrument, interest rate | 8.75% | 2.60% | 4.25% | |||
Extinguishment of debt | $ 500,000,000 | |||||
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 | 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 | |||||
Long-term line of credit | 0 | |||||
Current borrowing capacity on credit facility | $ 1,000,000,000 | |||||
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 | $ 3,000,000 | |||||
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% |
Long-Term Debt and Liquidity _4
Long-Term Debt and Liquidity Matters - Estimated Fair Value of Long-Term Debt (Details) - USD ($) $ in Thousands | Sep. 30, 2019 | Dec. 31, 2018 |
Estimated fair value of long-term debt, including current maturities | ||
Carrying Amount | $ 5,434,996 | $ 5,138,232 |
Fair Value | 6,067,397 | 5,233,563 |
Pinnacle West | ||
Estimated fair value of long-term debt, including current maturities | ||
Carrying Amount | 449,268 | 448,796 |
Fair Value | 449,670 | 443,955 |
APS | ||
Estimated fair value of long-term debt, including current maturities | ||
Carrying Amount | 4,985,728 | 4,689,436 |
Fair Value | $ 5,617,727 | $ 4,789,608 |
Regulatory Matters - Retail Rat
Regulatory Matters - Retail Rate Case Filing (Details) - ACC - APS | Oct. 31, 2019USD ($)GW | Jun. 30, 2019USD ($) | Apr. 10, 2019USD ($) | Aug. 13, 2018USD ($) | Feb. 13, 2018 | Jan. 08, 2018USD ($) | Jan. 03, 2018Customer | Nov. 13, 2017USD ($)appeal | Mar. 27, 2017USD ($)$ / kWh | Dec. 31, 2019USD ($) |
Public Utilities, General Disclosures [Line Items] | ||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amount, Tax Cuts and Jobs Act of 2017, Incomplete Accounting, Provisional Income Tax Expense (Benefit) | $ 184,000,000 | $ (86,500,000) | $ (119,100,000) | |||||||
Retail Rate Case Filing with Arizona Corporation Commission | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Approximate percentage of increase in average customer bill | 3.28% | |||||||||
Rate matter, cost base rate | $ 8,870,000,000 | |||||||||
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 | |||||||||
Approximate percentage of increase in average residential customer bill | 4.54% | 4.54% | ||||||||
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 | Retail Rate Case Filing with Arizona Corporation Commission | ||||||||||
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 | Retail Rate Case Filing with Arizona Corporation Commission | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Rate matter, environmental surcharge cap rate (in dollars per kWh) | $ / kWh | 0.00016 | |||||||||
Maximum | Retail Rate Case Filing with Arizona Corporation Commission | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Rate matter, environmental surcharge cap rate (in dollars per kWh) | $ / kWh | 0.00050 | |||||||||
Subsequent Event | Retail Rate Case Filing with Arizona Corporation Commission | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Retail base rate, increase | $ 0.054 | |||||||||
Base rate decrease, elimination of tax expense adjustment mechanism | $ 115,000,000 | |||||||||
Approximate percentage of increase in average customer bill | 5.60% | |||||||||
Funding limited income crisis bill program | $ 1,250,000 | |||||||||
Commercial customers, market pricing, threshold | GW | 0.2 | |||||||||
Forecast | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Operating Results | $ (10,000,000) | |||||||||
Forecast | Minimum | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Operating Results | $ 69,000,000 |
Regulatory Matters Regulatory M
Regulatory Matters Regulatory Matters - Capital Structure and Costs of Capital (Details) - Subsequent Event | Oct. 31, 2019 |
Cost of Capital | |
Long-term debt | 4.10% |
Common stock equity | 10.15% |
Weighted-average cost of capital | 7.41% |
Retail Rate Case Filing with Arizona Corporation Commission | APS | |
Capital Structure | |
Common stock equity | 54.70% |
Retail Rate Case Filing with Arizona Corporation Commission | ACC | APS | |
Capital Structure | |
Long-term debt | 45.30% |
Regulatory Matters - Cost Recov
Regulatory Matters - Cost Recovery Mechanism and Net Metering (Details) | Oct. 31, 2019USD ($) | Oct. 29, 2019USD ($) | Jun. 01, 2019USD ($) | Apr. 10, 2019USD ($) | Feb. 15, 2019USD ($) | Feb. 01, 2019$ / kWh | Aug. 13, 2018USD ($) | Jun. 01, 2018USD ($) | May 01, 2018$ / kWh | Feb. 20, 2018 | Feb. 15, 2018USD ($) | Feb. 01, 2018$ / kWh | Jan. 08, 2018USD ($) | Nov. 20, 2017USD ($) | Aug. 19, 2017$ / kWh | Jun. 01, 2017USD ($) | Feb. 01, 2017$ / kWh | Jan. 13, 2017USD ($) | Dec. 20, 2016$ / kWh | Feb. 01, 2016$ / kWh | Aug. 31, 2016 | Sep. 30, 2019USD ($) | Sep. 30, 2018USD ($) | Dec. 31, 2019USD ($) | Dec. 31, 2017USD ($)$ / kWh | Dec. 31, 2012$ / kWh | Jul. 01, 2019USD ($) | Dec. 31, 2018USD ($) | Jun. 29, 2018USD ($) | Nov. 14, 2017USD ($) | Sep. 01, 2017USD ($) | Jun. 30, 2017USD ($) |
Change in regulatory asset | ||||||||||||||||||||||||||||||||
Deferred fuel and purchased power costs — current period | $ 60,911,000 | $ 82,486,000 | ||||||||||||||||||||||||||||||
Amounts charged to customers | (38,601,000) | (92,397,000) | ||||||||||||||||||||||||||||||
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 | 60,911,000 | 82,486,000 | ||||||||||||||||||||||||||||||
Amounts charged to customers | $ (38,601,000) | (92,397,000) | ||||||||||||||||||||||||||||||
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 | |||||||||||||||||||||||||||||||
Amount of adjustment representing prorated sales losses pending approval | $ 36,200,000 | $ 60,700,000 | ||||||||||||||||||||||||||||||
Increase (decrease) in amount of adjustment representing prorated sales losses | $ (24,500,000) | $ (3,000,000) | ||||||||||||||||||||||||||||||
ACC | APS | ||||||||||||||||||||||||||||||||
Settlement Agreement | ||||||||||||||||||||||||||||||||
Program term | 2 years | |||||||||||||||||||||||||||||||
Change in regulatory asset | ||||||||||||||||||||||||||||||||
Gross-up for revenue requirement of rate regulation | $ (184,000,000) | $ 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 | $ 86,300,000 | $ 89,900,000 | $ 90,000,000 | |||||||||||||||||||||||||||||
ACC | RES 2018 | APS | Solar Communities | ||||||||||||||||||||||||||||||||
Settlement Agreement | ||||||||||||||||||||||||||||||||
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 | 60,911,000 | 82,486,000 | ||||||||||||||||||||||||||||||
Amounts charged to customers | (38,601,000) | (92,397,000) | ||||||||||||||||||||||||||||||
Ending balance | 59,474,000 | $ 65,726,000 | $ 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 | ||||||||||||||||||||||||||||||
Forecast | ACC | APS | ||||||||||||||||||||||||||||||||
Change in regulatory asset | ||||||||||||||||||||||||||||||||
Operating Results | $ 10,000,000 | |||||||||||||||||||||||||||||||
Minimum | ACC | RES 2018 | APS | Solar Communities | ||||||||||||||||||||||||||||||||
Settlement Agreement | ||||||||||||||||||||||||||||||||
Required annual capital investment | $ 10,000,000 | |||||||||||||||||||||||||||||||
Minimum | Forecast | ACC | APS | ||||||||||||||||||||||||||||||||
Change in regulatory asset | ||||||||||||||||||||||||||||||||
Operating Results | $ (69,000,000) | |||||||||||||||||||||||||||||||
Maximum | ACC | RES 2018 | APS | Solar Communities | ||||||||||||||||||||||||||||||||
Settlement Agreement | ||||||||||||||||||||||||||||||||
Required annual capital investment | $ 15,000,000 | |||||||||||||||||||||||||||||||
Subsequent Event | ACC | APS | ||||||||||||||||||||||||||||||||
Change in regulatory asset | ||||||||||||||||||||||||||||||||
Public Utilities, one-time bill credit | $ 64,000,000 | |||||||||||||||||||||||||||||||
Public Utilities, one-time bill credit, additional benefit | $ 39,500,000 |
Regulatory Matters - Four Corne
Regulatory Matters - Four Corners and Cholla (Details) - APS - USD ($) $ in Millions | Dec. 23, 2014 | Dec. 30, 2013 | Sep. 30, 2018 | Apr. 30, 2018 | Jun. 30, 2016 | Sep. 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 | ||||||
Four Corners cost deferral | SCE | Four Corners Units 4 and 5 | |||||||
Business Acquisition [Line Items] | |||||||
Regulatory assets, non-current | $ 42 | ||||||
Regulatory noncurrent asset amortization period | 10 years | ||||||
Retired power plant costs | |||||||
Business Acquisition [Line Items] | |||||||
Net book value | $ 77 | ||||||
Navajo Plant | |||||||
Business Acquisition [Line Items] | |||||||
Net book value | $ 80 | ||||||
Four Corners | SCE | |||||||
Business Acquisition [Line Items] | |||||||
Regulatory assets, non-current | $ 12 | ||||||
Regulatory asset, write off amount | $ 12 |
Regulatory Matters - Schedule o
Regulatory Matters - Schedule of Regulatory Assets (Details) - USD ($) $ in Thousands | Sep. 30, 2019 | Dec. 31, 2018 |
Detail of regulatory assets | ||
Current | $ 197,507 | $ 166,902 |
Non-Current | 1,329,446 | 1,342,941 |
Pension | ||
Detail of regulatory assets | ||
Current | 0 | 0 |
Non-Current | 703,460 | 733,351 |
Retired power plant costs | ||
Detail of regulatory assets | ||
Current | 28,182 | 28,182 |
Non-Current | 146,076 | 167,164 |
Income taxes — allowance for funds used during construction (AFUDC) equity | ||
Detail of regulatory assets | ||
Current | 6,457 | 6,457 |
Non-Current | 154,269 | 151,467 |
Deferred fuel and purchased power — mark-to-market (Note 7) | ||
Detail of regulatory assets | ||
Current | 41,643 | 31,728 |
Non-Current | 27,305 | 23,768 |
Deferred property taxes | ||
Detail of regulatory assets | ||
Current | 8,569 | 8,569 |
Non-Current | 60,338 | 66,356 |
Deferred fuel and purchased power | ||
Detail of regulatory assets | ||
Current | 59,474 | 37,164 |
Non-Current | 0 | 0 |
SCR deferral | ||
Detail of regulatory assets | ||
Current | 0 | 0 |
Non-Current | 45,296 | 23,276 |
Four Corners cost deferral | ||
Detail of regulatory assets | ||
Current | 8,077 | 8,077 |
Non-Current | 34,171 | 40,228 |
Deferred compensation | ||
Detail of regulatory assets | ||
Current | 0 | 0 |
Non-Current | 37,589 | 36,523 |
Lost fixed cost recovery | ||
Detail of regulatory assets | ||
Current | 25,775 | 32,435 |
Non-Current | 0 | 0 |
Income taxes — investment tax credit basis adjustment | ||
Detail of regulatory assets | ||
Current | 1,079 | 1,079 |
Non-Current | 24,555 | 25,522 |
Ocotillo deferral | ||
Detail of regulatory assets | ||
Current | 0 | 0 |
Non-Current | 23,643 | 0 |
Palo Verde VIEs (Note 6) | ||
Detail of regulatory assets | ||
Current | 0 | 0 |
Non-Current | 20,480 | 20,015 |
Coal reclamation | ||
Detail of regulatory assets | ||
Current | 1,546 | 1,546 |
Non-Current | 18,821 | 15,607 |
Loss on reacquired debt | ||
Detail of regulatory assets | ||
Current | 1,637 | 1,637 |
Non-Current | 12,441 | 13,668 |
Mead-Phoenix transmission line CIAC | ||
Detail of regulatory assets | ||
Current | 332 | 332 |
Non-Current | 9,795 | 10,044 |
TCA balancing account | ||
Detail of regulatory assets | ||
Current | 5,016 | 3,860 |
Non-Current | 2,721 | 772 |
Tax expense of Medicare subsidy | ||
Detail of regulatory assets | ||
Current | 1,235 | 1,235 |
Non-Current | 5,073 | 6,176 |
AG-1 deferral | ||
Detail of regulatory assets | ||
Current | 2,787 | 2,654 |
Non-Current | 3,413 | 5,819 |
Tax expense adjustor mechanism | ||
Detail of regulatory assets | ||
Current | 2,916 | 0 |
Non-Current | 0 | 0 |
Other | ||
Detail of regulatory assets | ||
Current | 2,782 | 1,947 |
Non-Current | $ 0 | $ 3,185 |
Regulatory Matters - Schedule_2
Regulatory Matters - Schedule of Regulatory Liabilities (Details) - USD ($) $ in Thousands | Sep. 30, 2019 | Dec. 31, 2018 |
Detail of regulatory liabilities | ||
Current | $ 208,022 | $ 165,876 |
Non-Current | 2,310,131 | 2,325,976 |
Asset retirement obligations | ||
Detail of regulatory liabilities | ||
Current | 0 | 0 |
Non-Current | 367,930 | 278,585 |
Removal costs | ||
Detail of regulatory liabilities | ||
Current | 47,459 | 39,866 |
Non-Current | 151,535 | 177,533 |
Other postretirement benefits | ||
Detail of regulatory liabilities | ||
Current | 37,821 | 37,864 |
Non-Current | 95,789 | 125,903 |
Income taxes — change in rates | ||
Detail of regulatory liabilities | ||
Current | 2,764 | 2,769 |
Non-Current | 67,605 | 70,069 |
Spent nuclear fuel | ||
Detail of regulatory liabilities | ||
Current | 5,746 | 6,503 |
Non-Current | 53,229 | 57,002 |
Income taxes — deferred investment tax credit | ||
Detail of regulatory liabilities | ||
Current | 2,164 | 2,164 |
Non-Current | 49,182 | 51,120 |
Four Corners coal reclamation | ||
Detail of regulatory liabilities | ||
Current | 1,858 | 1,858 |
Non-Current | 49,194 | 17,871 |
Renewable energy standard | ||
Detail of regulatory liabilities | ||
Current | 42,146 | 44,966 |
Non-Current | 5,675 | 20 |
Demand side management | ||
Detail of regulatory liabilities | ||
Current | 14,300 | 14,604 |
Non-Current | 24,146 | 4,123 |
Sundance maintenance | ||
Detail of regulatory liabilities | ||
Current | 4,640 | 1,278 |
Non-Current | 13,393 | 17,228 |
Deferred gains on utility property | ||
Detail of regulatory liabilities | ||
Current | 2,923 | 4,423 |
Non-Current | 4,766 | 6,581 |
Deferred property taxes | ||
Detail of regulatory liabilities | ||
Current | 0 | 0 |
Non-Current | 6,288 | 2,611 |
FERC transmission true up | ||
Detail of regulatory liabilities | ||
Current | 0 | 0 |
Non-Current | 2,586 | 0 |
Other | ||
Detail of regulatory liabilities | ||
Current | 1,370 | 3,279 |
Non-Current | 2,533 | 930 |
ACC | Excess deferred income taxes - ACC - Tax Cuts and Jobs Act | ||
Detail of regulatory liabilities | ||
Current | 38,529 | 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 | ||
Detail of regulatory liabilities | ||
Current | 6,302 | 6,302 |
Non-Current | $ 238,064 | $ 243,691 |
Retirement Plans and Other Po_3
Retirement Plans and Other Postretirement Benefits - Schedule of Net Benefit Cost (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2019 | Sep. 30, 2018 | Sep. 30, 2019 | Sep. 30, 2018 | |
Amortization of: | ||||
Portion of cost (credit) charged to expense | $ (5,752) | $ (12,449) | $ (17,240) | $ (37,314) |
Pension Benefits | ||||
Retirement Plans and Other Benefits | ||||
Service cost — benefits earned during the period | 12,476 | 14,167 | 37,427 | 42,501 |
Interest cost on benefit obligation | 34,211 | 31,172 | 102,632 | 93,517 |
Expected return on plan assets | (42,971) | (45,713) | (128,913) | (137,140) |
Amortization of: | ||||
Prior service credit | 0 | 0 | 0 | 0 |
Net actuarial loss | 10,646 | 8,021 | 31,938 | 24,062 |
Net periodic benefit cost (credit) | 14,362 | 7,647 | 43,084 | 22,940 |
Portion of cost (credit) charged to expense | 7,593 | 2,524 | 22,837 | 7,535 |
Other Benefits | ||||
Retirement Plans and Other Benefits | ||||
Service cost — benefits earned during the period | 4,593 | 5,275 | 13,777 | 15,825 |
Interest cost on benefit obligation | 7,473 | 7,037 | 22,420 | 21,111 |
Expected return on plan assets | (9,603) | (10,520) | (28,809) | (31,561) |
Amortization of: | ||||
Prior service credit | (9,456) | (9,461) | (28,366) | (28,382) |
Net actuarial loss | 0 | 0 | 0 | 0 |
Net periodic benefit cost (credit) | (6,993) | (7,669) | (20,978) | (23,007) |
Portion of cost (credit) charged to expense | $ (4,966) | $ (5,359) | $ (14,846) | $ (16,083) |
Retirement Plans and Other Po_4
Retirement Plans and Other Postretirement Benefits - Narrative (Details) | 9 Months Ended |
Sep. 30, 2019USD ($) | |
Pension Benefits | |
Contributions | |
Voluntary employer contributions to pension plan | $ 150,000,000 |
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 |
Retiree medical cost reimbursement | $ 30,000,000 |
Palo Verde Sale Leaseback Var_3
Palo Verde Sale Leaseback Variable Interest Entities - Narrative (Details) | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2019USD ($)power_plant | Sep. 30, 2018USD ($) | Sep. 30, 2019USD ($)Leasepower_plant | Sep. 30, 2018USD ($) | Dec. 31, 1986Trust | |
Palo Verde Sale Leaseback Variable Interest Entities | |||||
Increase in net income due to consolidation of Palo Verde Sale Leaseback Trusts | $ 4,873,000 | $ 4,873,000 | $ 14,620,000 | $ 14,620,000 | |
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 | $ 4,873,000 | 4,873,000 | $ 14,620,000 | 14,620,000 | |
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 | 15,000,000 | $ 15,000,000 | |
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 |
Palo Verde Sale Leaseback Var_4
Palo Verde Sale Leaseback Variable Interest Entities - Schedule of VIEs (Details) - USD ($) $ in Thousands | Sep. 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 | $ 102,873 | $ 105,775 |
Equity — Noncontrolling interests | 129,039 | 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 | 102,873 | 105,775 |
Equity — Noncontrolling interests | 129,039 | 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 | 102,873 | 105,775 |
Equity — Noncontrolling interests | $ 129,039 | $ 125,790 |
Derivative Accounting - Narrati
Derivative Accounting - Narrative (Details) - USD ($) | Sep. 30, 2019 | Sep. 30, 2019 | Sep. 30, 2018 | Sep. 30, 2019 | Sep. 30, 2018 | Dec. 31, 2018 |
Derivative Accounting | ||||||
Derivative liability | $ 71,654,000 | $ 71,654,000 | $ 71,654,000 | $ 60,037,000 | ||
Commodity Contracts | ||||||
Derivative Accounting | ||||||
Derivative liability | 71,654,000 | 71,654,000 | 71,654,000 | $ 60,037,000 | ||
Additional collateral to counterparties for energy related non-derivative instrument contracts | $ 95,000,000 | 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% | 100.00% | |||
Risk Management Assets | Credit Concentration Risk | ||||||
Derivative Accounting | ||||||
Concentration risk | 62.00% | |||||
Derivative liability | $ 800,000 | $ 800,000 | $ 800,000 |
Derivative Accounting - Schedul
Derivative Accounting - Schedule of Gross Notional Amounts Outstanding (Details) - Commodity Contracts GWh in Thousands, Bcf in Thousands | Sep. 30, 2019GWhBcf | Dec. 31, 2018GWhBcf |
Outstanding gross notional amount of derivatives | ||
Power | GWh | 232 | 250 |
Gas | Bcf | 187 | 218 |
Derivative Accounting - Gains a
Derivative Accounting - Gains and Losses from Derivative Instruments (Details) - Commodity Contracts - USD ($) | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2019 | Sep. 30, 2018 | Sep. 30, 2019 | Sep. 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) | (289,000) | (600,000) | (1,263,000) | (1,697,000) |
Not Designated as Hedging Instruments | ||||
Gains and losses from derivative instruments | ||||
Net Gain (Loss) Recognized in Income | (28,249,000) | 3,234,000 | (69,765,000) | (29,032,000) |
Not Designated as Hedging Instruments | Operating revenues | ||||
Gains and losses from derivative instruments | ||||
Net Gain (Loss) Recognized in Income | 0 | (1,029,000) | 0 | (2,590,000) |
Not Designated as Hedging Instruments | Fuel and purchased power | ||||
Gains and losses from derivative instruments | ||||
Net Gain (Loss) Recognized in Income | $ (28,249,000) | $ 4,263,000 | $ (69,765,000) | $ (26,442,000) |
Derivative Accounting - Derivat
Derivative Accounting - Derivative Instruments in the Balance Sheets (Details) - USD ($) | Sep. 30, 2019 | Dec. 31, 2018 |
Assets | ||
Gross Recognized Derivatives | $ 817,000 | $ 1,113,000 |
Liabilities | ||
Amount Reported on Balance Sheets | (71,654,000) | (60,037,000) |
Commodity Contracts | ||
Assets | ||
Gross Recognized Derivatives | 1,776,000 | 3,142,000 |
Amounts Offset | (1,266,000) | (2,185,000) |
Net Recognized Derivatives | 510,000 | 957,000 |
Other | 307,000 | 156,000 |
Amount Reported on Balance Sheets | 817,000 | 1,113,000 |
Liabilities | ||
Gross Recognized Derivatives | (71,734,000) | (60,912,000) |
Amounts Offset | 1,266,000 | 2,185,000 |
Net Recognized Derivatives | (70,468,000) | (58,727,000) |
Other | (1,186,000) | (1,310,000) |
Amount Reported on Balance Sheets | (71,654,000) | (60,037,000) |
Assets and Liabilities | ||
Gross Recognized Derivatives | (69,958,000) | (57,770,000) |
Amounts Offset | 0 | 0 |
Net Recognized Derivatives | (69,958,000) | (57,770,000) |
Other | (879,000) | (1,154,000) |
Amount Reported on Balance Sheets | (70,837,000) | (58,924,000) |
Cash collateral received from counterparties | 1,186,000 | 1,310,000 |
Commodity Contracts | Current assets | ||
Assets | ||
Gross Recognized Derivatives | 1,776,000 | 3,106,000 |
Amounts Offset | (1,266,000) | (2,149,000) |
Net Recognized Derivatives | 510,000 | 957,000 |
Other | 307,000 | 156,000 |
Amount Reported on Balance Sheets | 817,000 | 1,113,000 |
Commodity Contracts | Investments and other assets | ||
Assets | ||
Gross Recognized Derivatives | 36,000 | |
Amounts Offset | (36,000) | |
Net Recognized Derivatives | 0 | |
Other | 0 | |
Amount Reported on Balance Sheets | 0 | |
Commodity Contracts | Current liabilities | ||
Liabilities | ||
Gross Recognized Derivatives | (44,429,000) | (36,345,000) |
Amounts Offset | 1,266,000 | 2,149,000 |
Net Recognized Derivatives | (43,163,000) | (34,196,000) |
Other | (1,186,000) | (1,310,000) |
Amount Reported on Balance Sheets | (44,349,000) | (35,506,000) |
Assets and Liabilities | ||
Cash collateral received from counterparties | 1,186,000 | 1,310,000 |
Commodity Contracts | Deferred credits and other | ||
Liabilities | ||
Gross Recognized Derivatives | (27,305,000) | (24,567,000) |
Amounts Offset | 0 | 36,000 |
Net Recognized Derivatives | (27,305,000) | (24,531,000) |
Other | 0 | 0 |
Amount Reported on Balance Sheets | (27,305,000) | (24,531,000) |
Assets and Liabilities | ||
Cash collateral received from counterparties | $ 0 | $ 0 |
Derivative Accounting - Credit
Derivative Accounting - Credit Risk and Credit Related Contingent Features (Details) - Commodity Contracts $ in Thousands | Sep. 30, 2019USD ($) |
Credit Risk and Credit-Related Contingent Features | |
Aggregate fair value of derivative instruments in a net liability position | $ 71,503 |
Cash collateral posted | 0 |
Additional cash collateral in the event credit-risk-related contingent features were fully triggered | $ 70,230 |
Commitments and Contingencies -
Commitments and Contingencies - Palo Verde Nuclear Generating Station and Contractual Obligations (Details) | Oct. 31, 2019USD ($) | Aug. 18, 2014USD ($) | Sep. 30, 2019USD ($)power_plant | Jun. 30, 2018USD ($)time_periodclaim | Dec. 31, 1986Trust |
Breach of Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste | |||||
Commitments and Contingencies | |||||
Litigation settlement amount | $ 57,400,000 | $ 84,300,000 | |||
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 | ||||
Purchase obligation, increase | $ (260,000,000) | ||||
APS | Breach of Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste | |||||
Commitments and Contingencies | |||||
Litigation settlement amount | $ 16,700,000 | $ 24,500,000 | |||
Number of claims submitted | claim | 5 | ||||
Number of settlement agreement time periods | time_period | 5 | ||||
Four Corners coal reclamation | APS | |||||
Commitments and Contingencies | |||||
Purchase obligation, increase | $ 100,000,000 | ||||
Subsequent Event | Breach of Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste | |||||
Commitments and Contingencies | |||||
Litigation settlement amount | $ 16,000,000 | ||||
Subsequent Event | APS | Breach of Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste | |||||
Commitments and Contingencies | |||||
Litigation settlement amount | $ 4,700,000 |
Commitments and Contingencies_2
Commitments and Contingencies - Superfund-Related Matters, Southwest Power Outage and Clean Air Act (Details) - APS - Contaminated groundwater wells $ in Millions | Apr. 05, 2018plaintiffDefendant | Dec. 16, 2016plaintiff | Aug. 06, 2013Defendant | Sep. 30, 2019USD ($) |
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 | 28 | 24 | ||
Number of plaintiffs | 2 | |||
Settled Litigation | ||||
Loss Contingencies [Line Items] | ||||
Number of plaintiffs | 2 |
Commitments and Contingencies_3
Commitments and Contingencies - Environmental Matters and Financial Assurances (Details) - USD ($) $ in Millions | Jul. 03, 2018 | Jul. 06, 2016 | Sep. 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 | 14 | ||||
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 | ||||
Reimbursement payments due to 4CA | $ 10 | $ 20 | |||
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 | ||||
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 | ||||
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 | ||||
Regional Haze Rules | APS | Navajo Plant | |||||
Environmental Matters | |||||
Expected environmental cost | 200 | ||||
Coal combustion waste | APS | Four Corners | |||||
Environmental Matters | |||||
Site contingency increase in loss exposure not accrued, best estimate | 22 | ||||
Coal combustion waste | APS | Navajo Plant | |||||
Environmental Matters | |||||
Site contingency increase in loss exposure not accrued, best estimate | 1 | ||||
Coal combustion waste | APS | Cholla and Four Corners | |||||
Environmental Matters | |||||
Site contingency increase in loss exposure not accrued, best estimate | 5 | ||||
Minimum | Coal combustion waste | APS | Cholla | |||||
Environmental Matters | |||||
Site contingency increase in loss exposure not accrued, best estimate | $ 15 |
Other Income and Other Expens_2
Other Income and Other Expense (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2019 | Sep. 30, 2018 | Sep. 30, 2019 | Sep. 30, 2018 | |
Other income: | ||||
Interest income | $ 2,694 | $ 1,957 | $ 7,695 | $ 6,256 |
Miscellaneous | 22 | 91 | 50 | 95 |
Total other income | 15,191 | 6,958 | 35,245 | 17,541 |
Other expense: | ||||
Non-operating costs | (2,647) | (2,480) | (8,832) | (7,404) |
Investment losses — net | (716) | 0 | (1,445) | (268) |
Miscellaneous | (2,377) | (2,583) | (4,171) | (4,391) |
Total other expense | (5,740) | (5,063) | (14,448) | (12,063) |
APS | ||||
Other income: | ||||
Interest income | 2,037 | 1,151 | 5,091 | 4,874 |
Miscellaneous | 22 | 92 | 50 | 96 |
Total other income | 14,534 | 6,153 | 32,641 | 16,160 |
Other expense: | ||||
Non-operating costs | (2,448) | (2,334) | (7,965) | (6,931) |
Miscellaneous | (378) | (1,027) | (2,167) | (2,748) |
Total other expense | (2,826) | (3,361) | (10,132) | (9,679) |
SCR deferral | ||||
Other income: | ||||
Debt return on Four Corners SCR (Note 4) | 4,920 | 4,910 | 14,651 | 11,190 |
SCR deferral | APS | ||||
Other income: | ||||
Debt return on Four Corners SCR (Note 4) | 4,920 | 4,910 | 14,651 | 11,190 |
Ocotillo deferral | ||||
Other income: | ||||
Debt return on Four Corners SCR (Note 4) | 7,555 | 0 | 12,849 | 0 |
Ocotillo deferral | APS | ||||
Other income: | ||||
Debt return on Four Corners SCR (Note 4) | $ 7,555 | $ 0 | $ 12,849 | $ 0 |
Earnings Per Share (Details)
Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2019 | Sep. 30, 2018 | Sep. 30, 2019 | Sep. 30, 2018 | |
Earnings Per Share [Abstract] | ||||
Net income attributable to common shareholders | $ 312,276 | $ 315,012 | $ 474,339 | $ 484,971 |
Weighted average common shares outstanding - basic (in shares) | 112,463 | 112,148 | 112,408 | 112,094 |
Net effect of dilutive securities: | ||||
Contingently issuable performance shares and restricted stock units (in shares) | 283 | 385 | 331 | 405 |
Weighted average common shares outstanding — diluted (in shares) | 112,746 | 112,533 | 112,739 | 112,499 |
Earnings per weighted-average common share outstanding | ||||
Net income attributable to common shareholders - basic (in dollars per share) | $ 2.78 | $ 2.81 | $ 4.22 | $ 4.33 |
Net income attributable to common shareholders - diluted (in dollars per share) | $ 2.77 | $ 2.80 | $ 4.21 | $ 4.31 |
Fair Value Measurements - Asset
Fair Value Measurements - Assets and Liabilities Measured on a Recurring Basis (Details) - USD ($) $ in Thousands | Sep. 30, 2019 | Dec. 31, 2018 |
Assets | ||
Cash equivalents | $ 1,200 | |
Commodity contracts, assets | $ 817 | 1,113 |
Commodity contracts, liabilities | (959) | (2,029) |
Nuclear decommissioning trust | 967,673 | 851,134 |
Nuclear decommissioning trust, other | 475,371 | 398,953 |
Other special use funds | 243,982 | 236,101 |
Other special use funds, other | 1,418 | 593 |
Total assets | 1,212,472 | 1,089,548 |
Total assets, other | 475,830 | 397,517 |
Liabilities | ||
Total, other | 80 | 875 |
Amount reported on balance sheet | (71,654) | (60,037) |
Equity securities | ||
Assets | ||
Nuclear decommissioning trust | 7,452 | 7,351 |
Nuclear decommissioning trust, other | (1,322) | 2,148 |
Other special use funds | 3,400 | 45,723 |
Other special use funds, other | 1,418 | 593 |
U.S. commingled equity funds | ||
Assets | ||
Nuclear decommissioning trust | 476,693 | 396,805 |
U.S. Treasury debt | ||
Assets | ||
Nuclear decommissioning trust | 162,092 | 148,173 |
Other special use funds | 232,165 | 173,310 |
Corporate debt | ||
Assets | ||
Nuclear decommissioning trust | 124,026 | 96,656 |
Mortgage-backed securities | ||
Assets | ||
Nuclear decommissioning trust | 112,704 | 113,115 |
Municipal bonds | ||
Assets | ||
Nuclear decommissioning trust | 74,202 | 79,073 |
Other special use funds | 8,417 | 17,068 |
Other fixed income | ||
Assets | ||
Nuclear decommissioning trust | 10,504 | 9,961 |
Level 1 | ||
Assets | ||
Cash equivalents | 1,200 | |
Commodity contracts, assets | 0 | 0 |
Nuclear decommissioning trust | 170,866 | 153,376 |
Other special use funds | 234,147 | 218,440 |
Total assets | 405,013 | 373,016 |
Liabilities | ||
Gross derivative liability | 0 | 0 |
Level 1 | Equity securities | ||
Assets | ||
Nuclear decommissioning trust | 8,774 | 5,203 |
Other special use funds | 1,982 | 45,130 |
Level 1 | U.S. commingled equity funds | ||
Assets | ||
Nuclear decommissioning trust | 0 | 0 |
Level 1 | U.S. Treasury debt | ||
Assets | ||
Nuclear decommissioning trust | 162,092 | 148,173 |
Other special use funds | 232,165 | 173,310 |
Level 1 | Corporate debt | ||
Assets | ||
Nuclear decommissioning trust | 0 | 0 |
Level 1 | Mortgage-backed securities | ||
Assets | ||
Nuclear decommissioning trust | 0 | 0 |
Level 1 | Municipal bonds | ||
Assets | ||
Nuclear decommissioning trust | 0 | 0 |
Other special use funds | 0 | 0 |
Level 1 | Other fixed income | ||
Assets | ||
Nuclear decommissioning trust | 0 | 0 |
Level 2 | ||
Assets | ||
Cash equivalents | 0 | |
Commodity contracts, assets | 1,388 | 3,140 |
Nuclear decommissioning trust | 321,436 | 298,805 |
Other special use funds | 8,417 | 17,068 |
Total assets | 331,241 | 319,013 |
Liabilities | ||
Gross derivative liability | (69,752) | (52,696) |
Level 2 | Equity securities | ||
Assets | ||
Nuclear decommissioning trust | 0 | 0 |
Other special use funds | 0 | 0 |
Level 2 | U.S. commingled equity funds | ||
Assets | ||
Nuclear decommissioning trust | 0 | 0 |
Level 2 | U.S. Treasury debt | ||
Assets | ||
Nuclear decommissioning trust | 0 | 0 |
Other special use funds | 0 | 0 |
Level 2 | Corporate debt | ||
Assets | ||
Nuclear decommissioning trust | 124,026 | 96,656 |
Level 2 | Mortgage-backed securities | ||
Assets | ||
Nuclear decommissioning trust | 112,704 | 113,115 |
Level 2 | Municipal bonds | ||
Assets | ||
Nuclear decommissioning trust | 74,202 | 79,073 |
Other special use funds | 8,417 | 17,068 |
Level 2 | Other fixed income | ||
Assets | ||
Nuclear decommissioning trust | 10,504 | 9,961 |
Level 3 | ||
Assets | ||
Cash equivalents | 0 | |
Commodity contracts, assets | 388 | 2 |
Nuclear decommissioning trust | 0 | 0 |
Other special use funds | 0 | 0 |
Total assets | 388 | 2 |
Liabilities | ||
Gross derivative liability | (1,982) | (8,216) |
Level 3 | Equity securities | ||
Assets | ||
Nuclear decommissioning trust | 0 | 0 |
Other special use funds | 0 | 0 |
Level 3 | U.S. commingled equity funds | ||
Assets | ||
Nuclear decommissioning trust | 0 | 0 |
Level 3 | U.S. Treasury debt | ||
Assets | ||
Nuclear decommissioning trust | 0 | 0 |
Other special use funds | 0 | 0 |
Level 3 | Corporate debt | ||
Assets | ||
Nuclear decommissioning trust | 0 | 0 |
Level 3 | Mortgage-backed securities | ||
Assets | ||
Nuclear decommissioning trust | 0 | 0 |
Level 3 | Municipal bonds | ||
Assets | ||
Nuclear decommissioning trust | 0 | 0 |
Other special use funds | 0 | 0 |
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 | $ 476,693 | $ 396,805 |
Fair Value Measurements - Signi
Fair Value Measurements - Significant Unobservable Inputs Used to Value Level 3 Instruments (Details 2) - Forward Price $ in Thousands | Sep. 30, 2019USD ($)$ / MWh | Dec. 31, 2018USD ($)$ / MWh |
Level 3 | ||
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments | ||
Assets | $ | $ 388 | $ 2 |
Financial and Nonfinancial Liabilities, Fair Value Disclosure | $ | 1,982 | $ 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 | Level 3 | ||
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments | ||
Assets | $ | 388 | $ 0 |
Financial and Nonfinancial Liabilities, Fair Value Disclosure | $ | $ 489 | $ 2,456 |
Electricity forward contracts | Level 3 | Weighted-Average | ||
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments | ||
Significant Unobservable Input | 17.79 | 26.10 |
Electricity forward contracts | Level 3 | Minimum | ||
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments | ||
Significant Unobservable Input | 17.79 | |
Electricity forward contracts | Level 3 | Maximum | ||
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments | ||
Significant Unobservable Input | 17.19 | |
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 | Level 3 | ||
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments | ||
Assets | $ | $ 0 | $ 2 |
Financial and Nonfinancial Liabilities, Fair Value Disclosure | $ | $ 1,493 | $ 5,760 |
Natural gas contracts | Level 3 | Weighted-Average | ||
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments | ||
Significant Unobservable Input | 2.64 | 2.48 |
Natural gas contracts | Level 3 | Minimum | ||
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments | ||
Significant Unobservable Input | 2.53 | |
Natural gas contracts | Level 3 | Maximum | ||
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments | ||
Significant Unobservable Input | 2.79 |
Fair Value Measurements - Level
Fair Value Measurements - Level 3 Rollforward Derivatives (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2019 | Sep. 30, 2018 | Sep. 30, 2019 | Sep. 30, 2018 | |
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward] | ||||
Net derivative balance at beginning of period | $ (12,753) | $ (9,358) | $ (8,214) | $ (18,256) |
Deferred as a regulatory asset or liability | (2,324) | 1,244 | (12,634) | (2,067) |
Settlements | 8,980 | (2,332) | 11,929 | (1,056) |
Transfers into Level 3 from Level 2 | (613) | (2,246) | (3,711) | (7,225) |
Transfers from Level 3 into Level 2 | 5,116 | 2,829 | 11,036 | 18,741 |
Net derivative balance at end of period | (1,594) | (9,863) | (1,594) | (9,863) |
Net unrealized gains included in earnings related to instruments still held at end of period | $ 0 | $ 0 | $ 0 | $ 0 |
Fair Value Measurements - Finan
Fair Value Measurements - Financial Instruments Not Carried at Fair Value (Details) - USD ($) $ in Millions | Sep. 30, 2019 | Dec. 31, 2018 |
Fair Value Disclosures [Abstract] | ||
Stated interest rate for notes receivable | 3.90% | |
Note receivable, net book value | $ 49 | $ 61 |
Investments in Nuclear Decomm_3
Investments in Nuclear Decommissioning Trusts and Other Special Use Funds (Details) - APS - USD ($) $ in Thousands | Aug. 31, 2019 | Sep. 30, 2019 | Sep. 30, 2018 | Sep. 30, 2019 | Sep. 30, 2018 | Dec. 31, 2018 |
Nuclear decommissioning trust fund assets | ||||||
Fair Value | $ 1,211,655 | $ 1,211,655 | $ 1,087,235 | |||
Total Unrealized Gains | 325,782 | 325,782 | 230,781 | |||
Total Unrealized Losses | (476) | (476) | (7,237) | |||
Amortized cost | 696,000 | 696,000 | 635,000 | |||
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds | ||||||
Realized gains | 4,736 | $ 653 | 8,482 | $ 2,952 | ||
Realized losses | (2,360) | (1,965) | (5,465) | (6,990) | ||
Proceeds from the sale of securities | 211,641 | 173,277 | 520,996 | 443,040 | ||
Fair value of fixed income securities, summarized by contractual maturities | ||||||
Employee medical claims amount | $ 15,000 | |||||
Equity securities | ||||||
Nuclear decommissioning trust fund assets | ||||||
Equity securities | 487,449 | 487,449 | 447,138 | |||
Total Unrealized Gains | 297,032 | 297,032 | 222,147 | |||
Total Unrealized Losses | 0 | 0 | (459) | |||
Available for sale-fixed income securities | ||||||
Nuclear decommissioning trust fund assets | ||||||
Fair Value | 724,110 | 724,110 | 637,356 | |||
Total Unrealized Gains | 28,750 | 28,750 | 8,634 | |||
Total Unrealized Losses | (476) | (476) | (6,778) | |||
Fair value of fixed income securities, summarized by contractual maturities | ||||||
Less than one year | 109,950 | 109,950 | ||||
1 year – 5 years | 300,311 | 300,311 | ||||
5 years – 10 years | 104,693 | 104,693 | ||||
Greater than 10 years | 209,156 | 209,156 | ||||
Total | 724,110 | 724,110 | ||||
Other | ||||||
Nuclear decommissioning trust fund assets | ||||||
Fair Value | 96 | 96 | 2,741 | |||
Total Unrealized Gains | 0 | 0 | 0 | |||
Total Unrealized Losses | 0 | 0 | 0 | |||
Nuclear Decommissioning Trusts [Member] | ||||||
Nuclear decommissioning trust fund assets | ||||||
Fair Value | 967,673 | 967,673 | 851,134 | |||
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds | ||||||
Realized gains | 4,732 | 653 | 8,478 | 2,951 | ||
Realized losses | (2,360) | (1,965) | (5,465) | (6,990) | ||
Proceeds from the sale of securities | 155,386 | 148,150 | 371,538 | 401,396 | ||
Nuclear Decommissioning Trusts [Member] | Equity securities | ||||||
Nuclear decommissioning trust fund assets | ||||||
Equity securities | 485,467 | 485,467 | 402,008 | |||
Nuclear Decommissioning Trusts [Member] | Available for sale-fixed income securities | ||||||
Nuclear decommissioning trust fund assets | ||||||
Fair Value | 483,528 | 483,528 | 446,978 | |||
Fair value of fixed income securities, summarized by contractual maturities | ||||||
Less than one year | 40,309 | 40,309 | ||||
1 year – 5 years | 133,488 | 133,488 | ||||
5 years – 10 years | 103,973 | 103,973 | ||||
Greater than 10 years | 205,758 | 205,758 | ||||
Total | 483,528 | 483,528 | ||||
Nuclear Decommissioning Trusts [Member] | Other | ||||||
Nuclear decommissioning trust fund assets | ||||||
Fair Value | (1,322) | (1,322) | 2,148 | |||
Other Special Use Funds [Member] | ||||||
Nuclear decommissioning trust fund assets | ||||||
Fair Value | 243,982 | 243,982 | 236,101 | |||
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds | ||||||
Realized gains | 4 | 0 | 4 | 1 | ||
Realized losses | 0 | 0 | 0 | 0 | ||
Proceeds from the sale of securities | 56,255 | $ 25,127 | 149,458 | $ 41,644 | ||
Other Special Use Funds [Member] | Equity securities | ||||||
Nuclear decommissioning trust fund assets | ||||||
Equity securities | 1,982 | 1,982 | 45,130 | |||
Other Special Use Funds [Member] | Available for sale-fixed income securities | ||||||
Nuclear decommissioning trust fund assets | ||||||
Fair Value | 240,582 | 240,582 | 190,378 | |||
Other Special Use Funds [Member] | Other | ||||||
Nuclear decommissioning trust fund assets | ||||||
Fair Value | 1,418 | 1,418 | $ 593 | |||
Coal Reclamation Escrow Accounts [Member] | Available for sale-fixed income securities | ||||||
Fair value of fixed income securities, summarized by contractual maturities | ||||||
Less than one year | 32,628 | 32,628 | ||||
1 year – 5 years | 25,928 | 25,928 | ||||
5 years – 10 years | 720 | 720 | ||||
Greater than 10 years | 3,398 | 3,398 | ||||
Total | 62,674 | 62,674 | ||||
Active Union Medical Trust [Member] | Available for sale-fixed income securities | ||||||
Fair value of fixed income securities, summarized by contractual maturities | ||||||
Less than one year | 37,013 | 37,013 | ||||
1 year – 5 years | 140,895 | 140,895 | ||||
5 years – 10 years | 0 | 0 | ||||
Greater than 10 years | 0 | 0 | ||||
Total | $ 177,908 | $ 177,908 |
Changes in Accumulated Other _3
Changes in Accumulated Other Comprehensive Loss (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2019 | Sep. 30, 2018 | Sep. 30, 2019 | Sep. 30, 2018 | ||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | |||||
Balance at beginning of period | $ 5,357,243 | $ 5,159,434 | $ 5,348,705 | $ 5,135,730 | |
OCI (loss) before reclassifications | (2,422) | (6,024) | |||
Amounts reclassified from accumulated other comprehensive loss | 1,098 | 1,550 | 3,592 | 4,504 | |
Reclassification of income tax effect related to tax reform | (8,552) | ||||
Balance at end of period | 5,681,705 | 5,485,861 | 5,681,705 | 5,485,861 | |
Pension and Other Postretirement Benefits | |||||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | |||||
Balance at beginning of period | (46,657) | (54,233) | (45,997) | (42,440) | |
OCI (loss) before reclassifications | (2,422) | (5,928) | |||
Amounts reclassified from accumulated other comprehensive loss | 880 | 1,099 | 2,642 | 3,188 | |
Reclassification of income tax effect related to tax reform | (7,954) | ||||
Balance at end of period | (45,777) | (53,134) | (45,777) | (53,134) | |
Derivative Instruments | |||||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | |||||
Balance at beginning of period | (979) | (2,391) | (1,711) | (2,562) | |
OCI (loss) before reclassifications | 0 | (96) | |||
Amounts reclassified from accumulated other comprehensive loss | 218 | 451 | 950 | 1,316 | |
Reclassification of income tax effect related to tax reform | (598) | ||||
Balance at end of period | (761) | (1,940) | (761) | (1,940) | |
Accumulated Other Comprehensive Income (Loss) | |||||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | |||||
Balance at beginning of period | (47,636) | (56,624) | (47,708) | (45,002) | |
Reclassification of income tax effect related to tax reform | [1] | (8,552) | |||
Balance at end of period | (46,538) | (55,074) | (46,538) | (55,074) | |
APS | |||||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | |||||
Balance at beginning of period | 5,797,857 | 5,412,930 | 5,786,797 | 5,385,869 | |
Amounts reclassified from accumulated other comprehensive loss | 973 | 1,403 | |||
Balance at end of period | 6,122,571 | 5,757,571 | 6,122,571 | 5,757,571 | |
APS | Pension and Other Postretirement Benefits | |||||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | |||||
Balance at beginning of period | (26,297) | (32,768) | (25,396) | (24,421) | |
OCI (loss) before reclassifications | (2,414) | (5,791) | |||
Amounts reclassified from accumulated other comprehensive loss | 755 | 952 | 2,268 | 2,836 | |
Reclassification of income tax effect related to tax reform | (4,440) | ||||
Balance at end of period | (25,542) | (31,816) | (25,542) | (31,816) | |
APS | Derivative Instruments | |||||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | |||||
Balance at beginning of period | (979) | (2,391) | (1,711) | (2,562) | |
OCI (loss) before reclassifications | 0 | (96) | |||
Amounts reclassified from accumulated other comprehensive loss | 218 | 451 | 950 | 1,316 | |
Reclassification of income tax effect related to tax reform | (598) | ||||
Balance at end of period | (761) | (1,940) | (761) | (1,940) | |
APS | Accumulated Other Comprehensive Income (Loss) | |||||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | |||||
Balance at beginning of period | (27,276) | (35,159) | (27,107) | (26,983) | |
OCI (loss) before reclassifications | (2,414) | (5,887) | |||
Amounts reclassified from accumulated other comprehensive loss | 3,218 | 4,152 | |||
Reclassification of income tax effect related to tax reform | [2] | (5,038) | |||
Balance at end of period | $ (26,303) | $ (33,756) | $ (26,303) | $ (33,756) | |
[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. |
Income Taxes (Details)
Income Taxes (Details) - USD ($) $ in Millions | Sep. 30, 2019 | Dec. 31, 2017 |
Income Tax Disclosure [Abstract] | ||
Reduction in net deferred income tax liabilities | $ 1,140 | |
Amortization of an excess deferred tax liability | $ 42 | |
Deferred tax liability | $ 56 |
Leases - Additional information
Leases - Additional information (Details) $ in Thousands | Sep. 30, 2019USD ($)Lease | Jan. 01, 2019USD ($) | Dec. 31, 2018USD ($) |
Operating Leased Assets [Line Items] | |||
Number of lease agreements | Lease | 3 | ||
Operating lease right-of-use assets (Note 16) | $ 156,050 | $ 194,000 | $ 0 |
Operating lease, liability | 78,693 | 119,000 | |
Other | (37,976) | (129,312) | |
Other current liabilities | (161,716) | $ (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 |
Leases - Lease costs (Details)
Leases - Lease costs (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended |
Sep. 30, 2019 | Sep. 30, 2019 | |
Operating Leased Assets [Line Items] | ||
Operating lease cost | $ 25,676 | $ 48,502 |
Variable lease cost | 37,100 | 96,279 |
Short-term lease cost | 812 | 3,477 |
Total lease cost | 63,588 | 148,258 |
Purchased Power Lease Contracts | ||
Operating Leased Assets [Line Items] | ||
Operating lease cost | 21,095 | 35,159 |
Variable lease cost | 36,917 | 95,736 |
Short-term lease cost | 0 | 0 |
Total lease cost | 58,012 | 130,895 |
Land, Property & Equipment Leases | ||
Operating Leased Assets [Line Items] | ||
Operating lease cost | 4,581 | 13,343 |
Variable lease cost | 183 | 543 |
Short-term lease cost | 812 | 3,477 |
Total lease cost | $ 5,576 | $ 17,363 |
Leases - Maturity of our operat
Leases - Maturity of our operating lease liabilities (Details) - USD ($) $ in Thousands | Sep. 30, 2019 | Jan. 01, 2019 | Dec. 31, 2018 |
Lessee, Lease, Description [Line Items] | |||
2019 (remaining three months of 2019) | $ 16,977 | ||
2019 | $ 68,246 | ||
2020 | 14,083 | 12,428 | |
2021 | 11,244 | 9,478 | |
2022 | 7,727 | 6,513 | |
2023 | 6,101 | 5,359 | |
2024 | 3,915 | ||
Thereafter | 38,697 | ||
Thereafter | 42,236 | ||
Total lease commitments | 98,744 | 144,260 | |
Less imputed interest | 20,051 | ||
Total lease liabilities | 78,693 | $ 119,000 | |
Purchased Power Lease Contracts | |||
Lessee, Lease, Description [Line Items] | |||
2019 (remaining three months of 2019) | 13,625 | ||
2019 | 54,499 | ||
2020 | 0 | 0 | |
2021 | 0 | 0 | |
2022 | 0 | 0 | |
2023 | 0 | 0 | |
2024 | 0 | ||
Thereafter | 0 | ||
Thereafter | 0 | ||
Total lease commitments | 13,625 | 54,499 | |
Less imputed interest | 19 | ||
Total lease liabilities | 13,606 | ||
Land, Property & Equipment Leases | |||
Lessee, Lease, Description [Line Items] | |||
2019 (remaining three months of 2019) | 3,352 | ||
2019 | 13,747 | ||
2020 | 14,083 | 12,428 | |
2021 | 11,244 | 9,478 | |
2022 | 7,727 | 6,513 | |
2023 | 6,101 | 5,359 | |
2024 | 3,915 | ||
Thereafter | 38,697 | ||
Thereafter | 42,236 | ||
Total lease commitments | 85,119 | $ 89,761 | |
Less imputed interest | 20,032 | ||
Total lease liabilities | $ 65,087 |
Leases - Other additional infor
Leases - Other additional information related to operating lease liabilities (Details) $ in Thousands | 9 Months Ended |
Sep. 30, 2019USD ($) | |
Leases [Abstract] | |
Weighted average remaining lease term | 12 years |
Weighted average discount rate (a) | 3.73% |
Cash paid for amounts included in the measurement of lease liabilities - operating cash flows | $ 51,980 |