Document and Entity Information
Document and Entity Information - shares | 9 Months Ended | |
Sep. 30, 2018 | Nov. 01, 2018 | |
Entity Information [Line Items] | ||
Entity Registrant Name | PINNACLE WEST CAPITAL CORPORATION | |
Entity Central Index Key | 764,622 | |
Document Type | 10-Q | |
Document Period End Date | Sep. 30, 2018 | |
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 | 112,079,739 | |
Document Fiscal Year Focus | 2,018 | |
Document Fiscal Period Focus | Q3 | |
APS | ||
Entity Information [Line Items] | ||
Entity Registrant Name | ARIZONA PUBLIC SERVICE COMPANY | |
Entity Central Index Key | 7,286 | |
Document Type | 10-Q | |
Document Period End Date | Sep. 30, 2018 | |
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 | 71,264,947 | |
Document Fiscal Year Focus | 2,018 | |
Document Fiscal Period Focus | Q3 |
CONDENSED CONSOLIDATED STATEMEN
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited) - USD ($) shares in Thousands, $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
OPERATING REVENUES | $ 1,268,034 | $ 1,183,322 | $ 2,934,871 | $ 2,805,637 |
OPERATING EXPENSES | ||||
Fuel and purchased power | 389,936 | 310,469 | 844,133 | 777,475 |
Operations and maintenance | 246,545 | 230,839 | 780,624 | 677,895 |
Depreciation and amortization | 145,971 | 133,912 | 436,232 | 387,278 |
Taxes other than income taxes | 51,375 | 45,169 | 158,582 | 133,294 |
Other expenses | 900 | 3,385 | 8,497 | 5,479 |
Total | 834,727 | 723,774 | 2,228,068 | 1,981,421 |
OPERATING INCOME | 433,307 | 459,548 | 706,803 | 824,216 |
OTHER INCOME (DEDUCTIONS) | ||||
Allowance for equity funds used during construction | 12,259 | 12,728 | 39,411 | 32,666 |
Pension and other postretirement non-service credits - net | 12,449 | 6,534 | 37,314 | 19,601 |
Other income (Note 9) | 6,958 | 1,091 | 17,541 | 2,055 |
Other expense (Note 9) | (5,063) | (4,993) | (12,063) | (12,495) |
Total | 26,603 | 15,360 | 82,203 | 41,827 |
INTEREST EXPENSE | ||||
Interest charges | 61,605 | 55,644 | 181,267 | 162,477 |
Allowance for borrowed funds used during construction | (5,913) | (6,000) | (18,959) | (15,378) |
Total | 55,692 | 49,644 | 162,308 | 147,099 |
INCOME BEFORE INCOME TAXES | 404,218 | 425,264 | 626,698 | 718,944 |
INCOME TAXES | 84,333 | 144,319 | 127,107 | 237,497 |
NET INCOME | 319,885 | 280,945 | 499,591 | 481,447 |
Less: Net income attributable to noncontrolling interests (Note 6) | 4,873 | 4,873 | 14,620 | 14,620 |
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS | $ 315,012 | $ 276,072 | $ 484,971 | $ 466,827 |
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING | ||||
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - BASIC (in shares) | 112,148 | 111,835 | 112,094 | 111,787 |
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - DILUTED (in shares) | 112,533 | 112,401 | 112,499 | 112,314 |
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING | ||||
Net income attributable to common shareholders - basic (in dollars per share) | $ 2.81 | $ 2.47 | $ 4.33 | $ 4.18 |
Net income attributable to common shareholders - diluted (in dollars per share) | $ 2.80 | $ 2.46 | $ 4.31 | $ 4.16 |
APS | ||||
OPERATING REVENUES | $ 1,267,997 | $ 1,178,846 | $ 2,931,966 | $ 2,799,840 |
OPERATING EXPENSES | ||||
Fuel and purchased power | 389,889 | 309,045 | 862,037 | 786,041 |
Operations and maintenance | 226,346 | 222,374 | 732,946 | 657,157 |
Depreciation and amortization | 145,949 | 133,486 | 434,594 | 386,010 |
Taxes other than income taxes | 51,366 | 44,898 | 157,877 | 132,478 |
Other expenses | 900 | 3,385 | 1,497 | 5,527 |
Total | 814,450 | 713,188 | 2,188,951 | 1,967,213 |
OPERATING INCOME | 453,547 | 465,658 | 743,015 | 832,627 |
OTHER INCOME (DEDUCTIONS) | ||||
Allowance for equity funds used during construction | 12,259 | 12,728 | 39,411 | 32,666 |
Pension and other postretirement non-service credits - net | 12,812 | 6,477 | 38,398 | 19,430 |
Other income (Note 9) | 6,153 | 738 | 16,160 | 1,432 |
Other expense (Note 9) | (3,361) | (2,178) | (9,679) | (8,608) |
Total | 27,863 | 17,765 | 84,290 | 44,920 |
INTEREST EXPENSE | ||||
Interest charges | 58,551 | 53,760 | 172,440 | 158,074 |
Allowance for borrowed funds used during construction | (5,913) | (6,000) | (18,959) | (15,378) |
Total | 52,638 | 47,760 | 153,481 | 142,696 |
INCOME BEFORE INCOME TAXES | 428,772 | 435,663 | 673,824 | 734,851 |
INCOME TAXES | 85,533 | 146,534 | 133,415 | 243,708 |
NET INCOME | 343,239 | 289,129 | 540,409 | 491,143 |
Less: Net income attributable to noncontrolling interests (Note 6) | 4,873 | 4,873 | 14,620 | 14,620 |
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS | $ 338,366 | $ 284,256 | $ 525,789 | $ 476,523 |
CONDENSED CONSOLIDATED STATEM_2
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
NET INCOME | $ 319,885 | $ 280,945 | $ 499,591 | $ 481,447 |
Derivative instruments: | ||||
Net unrealized gain (loss), net of tax expense | 0 | 9 | (96) | (754) |
Reclassification of net realized loss, net of tax expense | 451 | 710 | 1,316 | 2,480 |
Pension and other postretirement benefits activity, net of tax benefit | 1,099 | 790 | (2,740) | (21) |
Total other comprehensive income | 1,550 | 1,509 | (1,520) | 1,705 |
COMPREHENSIVE INCOME | 321,435 | 282,454 | 498,071 | 483,152 |
Less: Comprehensive income attributable to noncontrolling interests | 4,873 | 4,873 | 14,620 | 14,620 |
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS | 316,562 | 277,581 | 483,451 | 468,532 |
APS | ||||
NET INCOME | 343,239 | 289,129 | 540,409 | 491,143 |
Derivative instruments: | ||||
Net unrealized gain (loss), net of tax expense | 0 | 9 | (96) | (754) |
Reclassification of net realized loss, net of tax expense | 451 | 710 | 1,316 | 2,480 |
Pension and other postretirement benefits activity, net of tax benefit | 952 | 777 | (2,955) | 81 |
Total other comprehensive income | 1,403 | 1,496 | (1,735) | 1,807 |
COMPREHENSIVE INCOME | 344,642 | 290,625 | 538,674 | 492,950 |
Less: Comprehensive income attributable to noncontrolling interests | 4,873 | 4,873 | 14,620 | 14,620 |
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS | $ 339,769 | $ 285,752 | $ 524,054 | $ 478,330 |
CONDENSED CONSOLIDATED STATEM_3
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) (Parenthetical) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Net unrealized loss, tax expense | $ 0 | $ 5 | $ 96 | $ 684 |
Reclassification of net realized loss, tax expense (benefit) | 149 | 438 | 381 | 430 |
Pension and other postretirement (benefits) activity, tax benefit (expense) | 361 | 487 | (754) | 369 |
APS | ||||
Net unrealized loss, tax expense | 0 | 5 | 96 | 684 |
Reclassification of net realized loss, tax expense (benefit) | 149 | 438 | 381 | 430 |
Pension and other postretirement (benefits) activity, tax benefit (expense) | $ 313 | $ 480 | $ (947) | $ 262 |
CONDENSED CONSOLIDATED BALANCE
CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($) $ in Thousands | Sep. 30, 2018 | Dec. 31, 2017 |
CURRENT ASSETS | ||
Cash and cash equivalents | $ 64,991 | $ 13,892 |
Customer and other receivables | 370,714 | 305,147 |
Accrued unbilled revenues | 196,373 | 112,434 |
Allowance for doubtful accounts | (5,215) | (2,513) |
Materials and supplies (at average cost) | 268,184 | 264,012 |
Fossil fuel (at average cost) | 40,398 | 25,258 |
Assets from risk management activities (Note 7) | 1,224 | 1,931 |
Deferred fuel and purchased power regulatory asset (Note 4) | 65,726 | 75,637 |
Other regulatory assets (Note 4) | 143,849 | 172,451 |
Other current assets | 60,946 | 48,039 |
Total current assets | 1,207,190 | 1,016,288 |
INVESTMENTS AND OTHER ASSETS | ||
Nuclear decommissioning trust (Note 12) | 906,687 | 871,000 |
Other special use funds (Note 12) | 233,740 | 32,542 |
Other assets | 106,988 | 52,040 |
Total investments and other assets | 1,247,415 | 955,582 |
PROPERTY, PLANT AND EQUIPMENT | ||
Plant in service and held for future use | 18,443,985 | 17,798,061 |
Accumulated depreciation and amortization | (6,328,751) | (6,128,535) |
Net | 12,115,234 | 11,669,526 |
Construction work in progress | 1,200,625 | 1,291,498 |
Palo Verde sale leaseback, net of accumulated depreciation (Note 6) | 106,743 | 109,645 |
Intangible assets, net of accumulated amortization | 268,630 | 257,189 |
Nuclear fuel, net of accumulated amortization | 134,812 | 117,408 |
Total property, plant and equipment | 13,826,044 | 13,445,266 |
DEFERRED DEBITS | ||
Regulatory assets (Note 4) | 1,221,293 | 1,202,302 |
Assets for other postretirement benefits (Note 5) | 29,094 | 268,978 |
Other | 140,919 | 130,666 |
Total deferred debits | 1,391,306 | 1,601,946 |
TOTAL ASSETS | 17,671,955 | 17,019,082 |
CURRENT LIABILITIES | ||
Accounts payable | 249,059 | 256,442 |
Accrued taxes | 226,846 | 148,946 |
Accrued interest | 53,021 | 56,397 |
Common dividends payable | 0 | 77,667 |
Short-term borrowings (Note 3) | 128,200 | 95,400 |
Current maturities of long-term debt (Note 3) | 600,000 | 82,000 |
Customer deposits | 89,916 | 70,388 |
Liabilities from risk management activities (Note 7) | 45,504 | 59,252 |
Liabilities for asset retirements | 13,000 | 4,745 |
Regulatory liabilities (Note 4) | 159,788 | 100,086 |
Other current liabilities | 169,454 | 246,529 |
Total current liabilities | 1,734,788 | 1,197,852 |
DEFERRED CREDITS AND OTHER | ||
Deferred income taxes | 1,813,472 | 1,690,805 |
Regulatory liabilities (Note 4) | 2,410,597 | 2,452,536 |
Liabilities for asset retirements | 682,389 | 674,784 |
Liabilities for pension benefits (Note 5) | 316,423 | 327,300 |
Liabilities from risk management activities (Note 7) | 34,226 | 37,170 |
Customer advances | 125,267 | 113,996 |
Coal mine reclamation | 210,030 | 231,597 |
Deferred investment tax credit | 198,178 | 205,575 |
Unrecognized tax benefits | 11,896 | 13,115 |
Other | 161,464 | 148,909 |
Total deferred credits and other | 5,963,942 | 5,895,787 |
COMMITMENTS AND CONTINGENCIES (SEE NOTE 8) | ||
EQUITY | ||
Common stock, no par value; authorized 150,000,000 shares, 112,015,949 and 111,816,170 issued at respective dates | 2,629,627 | 2,614,805 |
Treasury stock at cost; 17,368 and 64,463 shares at respective dates | (1,409) | (5,624) |
Total common stock | 2,628,218 | 2,609,181 |
Retained earnings | 2,780,428 | 2,442,511 |
Accumulated other comprehensive loss | (55,074) | (45,002) |
Total shareholders’ equity | 5,353,572 | 5,006,690 |
Noncontrolling interests (Note 6) | 132,289 | 129,040 |
Total equity | 5,485,861 | 5,135,730 |
Long-term debt less current maturities (Note 3) | 4,487,364 | 4,789,713 |
TOTAL LIABILITIES AND EQUITY | 17,671,955 | 17,019,082 |
APS | ||
CURRENT ASSETS | ||
Cash and cash equivalents | 64,825 | 13,851 |
Customer and other receivables | 350,028 | 292,791 |
Accrued unbilled revenues | 196,373 | 112,434 |
Allowance for doubtful accounts | (5,215) | (2,513) |
Materials and supplies (at average cost) | 268,184 | 262,630 |
Fossil fuel (at average cost) | 40,398 | 25,258 |
Assets from risk management activities (Note 7) | 1,224 | 1,931 |
Deferred fuel and purchased power regulatory asset (Note 4) | 65,726 | 75,637 |
Other regulatory assets (Note 4) | 143,849 | 172,451 |
Other current assets | 41,196 | 41,055 |
Total current assets | 1,166,588 | 995,525 |
INVESTMENTS AND OTHER ASSETS | ||
Nuclear decommissioning trust (Note 12) | 906,687 | 871,000 |
Other special use funds (Note 12) | 233,740 | 30,358 |
Other assets | 40,710 | 36,796 |
Total investments and other assets | 1,181,137 | 938,154 |
PROPERTY, PLANT AND EQUIPMENT | ||
Plant in service and held for future use | 18,440,499 | 17,654,078 |
Accumulated depreciation and amortization | (6,325,513) | (6,041,965) |
Net | 12,114,986 | 11,612,113 |
Construction work in progress | 1,200,625 | 1,266,636 |
Palo Verde sale leaseback, net of accumulated depreciation (Note 6) | 106,743 | 109,645 |
Intangible assets, net of accumulated amortization | 268,474 | 257,028 |
Nuclear fuel, net of accumulated amortization | 134,812 | 117,408 |
Total property, plant and equipment | 13,825,640 | 13,362,830 |
DEFERRED DEBITS | ||
Regulatory assets (Note 4) | 1,221,293 | 1,202,302 |
Assets for other postretirement benefits (Note 5) | 25,455 | 265,139 |
Other | 129,026 | 129,801 |
Total deferred debits | 1,375,774 | 1,597,242 |
TOTAL ASSETS | 17,549,139 | 16,893,751 |
CURRENT LIABILITIES | ||
Accounts payable | 241,548 | 247,852 |
Accrued taxes | 263,521 | 157,349 |
Accrued interest | 50,416 | 55,533 |
Common dividends payable | 0 | 77,700 |
Current maturities of long-term debt (Note 3) | 600,000 | 82,000 |
Customer deposits | 89,916 | 70,388 |
Liabilities from risk management activities (Note 7) | 45,504 | 59,252 |
Liabilities for asset retirements | 13,000 | 4,192 |
Regulatory liabilities (Note 4) | 159,788 | 100,086 |
Other current liabilities | 165,206 | 243,922 |
Total current liabilities | 1,628,899 | 1,098,274 |
DEFERRED CREDITS AND OTHER | ||
Deferred income taxes | 1,834,691 | 1,742,485 |
Regulatory liabilities (Note 4) | 2,410,597 | 2,452,536 |
Liabilities for asset retirements | 682,389 | 666,527 |
Liabilities for pension benefits (Note 5) | 296,987 | 306,542 |
Liabilities from risk management activities (Note 7) | 34,226 | 37,170 |
Customer advances | 125,267 | 113,996 |
Coal mine reclamation | 210,030 | 215,830 |
Deferred investment tax credit | 198,178 | 205,575 |
Unrecognized tax benefits | 41,673 | 43,876 |
Other | 139,907 | 133,779 |
Total deferred credits and other | 5,973,945 | 5,918,316 |
COMMITMENTS AND CONTINGENCIES (SEE NOTE 8) | ||
EQUITY | ||
Total common stock | 178,162 | 178,162 |
Additional paid-in capital | 2,571,696 | 2,571,696 |
Retained earnings | 2,909,180 | 2,533,954 |
Accumulated other comprehensive loss | (33,756) | (26,983) |
Total shareholders’ equity | 5,625,282 | 5,256,829 |
Noncontrolling interests (Note 6) | 132,289 | 129,040 |
Total equity | 5,757,571 | 5,385,869 |
Long-term debt less current maturities (Note 3) | 4,188,724 | 4,491,292 |
Total capitalization | 9,946,295 | 9,877,161 |
TOTAL LIABILITIES AND EQUITY | $ 17,549,139 | $ 16,893,751 |
CONDENSED CONSOLIDATED BALANC_2
CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical) - $ / shares | Sep. 30, 2018 | Dec. 31, 2017 |
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) | 112,015,949 | 111,816,170 |
Treasury stock at cost, shares (in shares) | 17,368 | 64,463 |
CONDENSED CONSOLIDATED STATEM_4
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($) $ in Thousands | 9 Months Ended | |
Sep. 30, 2018 | Sep. 30, 2017 | |
CASH FLOWS FROM OPERATING ACTIVITIES | ||
NET INCOME | $ 499,591 | $ 481,447 |
Adjustments to reconcile net income to net cash provided by operating activities: | ||
Depreciation and amortization including nuclear fuel | 489,861 | 445,707 |
Deferred fuel and purchased power | (82,486) | (43,348) |
Deferred fuel and purchased power amortization | 92,397 | (18,153) |
Allowance for equity funds used during construction | (39,411) | (32,666) |
Deferred income taxes | 117,571 | 211,249 |
Deferred investment tax credit | (7,397) | (4,293) |
Change in derivative instruments fair value | 0 | (254) |
Stock compensation | 16,140 | 16,553 |
Changes in current assets and liabilities: | ||
Customer and other receivables | (65,203) | (206,920) |
Accrued unbilled revenues | (83,939) | (44,027) |
Materials, supplies and fossil fuel | (20,591) | (1,881) |
Income tax receivable | 0 | 3,751 |
Other current assets | 23,661 | (22,043) |
Accounts payable | (11,399) | (24,258) |
Accrued taxes | 78,624 | 89,827 |
Other current liabilities | 12,852 | 3,936 |
Change in margin and collateral accounts — assets | (588) | (1,826) |
Change in margin and collateral accounts — liabilities | (982) | (1,625) |
Change in unrecognized tax benefits | (1,235) | 5,891 |
Change in other long-term assets | 14,708 | (59,963) |
Change in other long-term liabilities | (72,411) | (25,180) |
Net cash flow provided by operating activities | 959,763 | 771,924 |
CASH FLOWS FROM INVESTING ACTIVITIES | ||
Capital expenditures | (898,455) | (1,027,753) |
Contributions in aid of construction | 22,611 | 24,924 |
Allowance for borrowed funds used during construction | (18,959) | (15,378) |
Proceeds from nuclear decommissioning trust sales and other special use funds | 443,215 | 351,860 |
Investment in nuclear decommissioning trust and other special use funds | (461,777) | (353,001) |
Other | 49 | (20,291) |
Net cash flow used for investing activities | (913,316) | (1,039,639) |
CASH FLOWS FROM FINANCING ACTIVITIES | ||
Issuance of long-term debt | 295,245 | 549,478 |
Short-term borrowing and payments — net | 19,800 | (68,800) |
Short-term debt borrowings under revolving credit facility | 45,000 | 23,000 |
Short-term debt repayments under revolving credit facility | (32,000) | 0 |
Repayment of long-term debt | (82,000) | 0 |
Dividends paid on common stock | (228,037) | (213,927) |
Common stock equity issuance - net of purchases | (1,984) | (8,870) |
Distributions to noncontrolling interests | (11,372) | (11,372) |
Other | 0 | (1) |
Net cash flow provided by financing activities | 4,652 | 269,508 |
NET INCREASE IN CASH AND CASH EQUIVALENTS | 51,099 | 1,793 |
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD | 13,892 | 8,881 |
CASH AND CASH EQUIVALENTS AT END OF PERIOD | 64,991 | 10,674 |
Supplemental disclosure of cash flow information | ||
Income taxes, net of refunds | 10,091 | 2,185 |
Interest, net of amounts capitalized | 161,875 | 147,149 |
Significant non-cash investing and financing activities: | ||
Accrued capital expenditures | 99,405 | 93,031 |
APS | ||
CASH FLOWS FROM OPERATING ACTIVITIES | ||
NET INCOME | 540,409 | 491,143 |
Adjustments to reconcile net income to net cash provided by operating activities: | ||
Depreciation and amortization including nuclear fuel | 488,223 | 444,439 |
Deferred fuel and purchased power | (82,486) | (43,348) |
Deferred fuel and purchased power amortization | 92,397 | (18,153) |
Allowance for equity funds used during construction | (39,411) | (32,666) |
Deferred income taxes | 86,319 | 202,256 |
Deferred investment tax credit | (7,397) | (4,293) |
Change in derivative instruments fair value | 0 | (254) |
Changes in current assets and liabilities: | ||
Customer and other receivables | (56,874) | (185,130) |
Accrued unbilled revenues | (83,939) | (44,027) |
Materials, supplies and fossil fuel | (20,694) | (1,755) |
Income tax receivable | 0 | 11,174 |
Other current assets | 20,258 | (19,100) |
Accounts payable | (8,857) | (29,784) |
Accrued taxes | 106,172 | 102,638 |
Other current liabilities | 9,289 | 11,747 |
Change in margin and collateral accounts — assets | (588) | (1,826) |
Change in margin and collateral accounts — liabilities | (982) | (1,625) |
Change in unrecognized tax benefits | (1,235) | 5,891 |
Change in other long-term assets | 25,993 | (56,375) |
Change in other long-term liabilities | (78,678) | (26,049) |
Net cash flow provided by operating activities | 987,919 | 804,903 |
CASH FLOWS FROM INVESTING ACTIVITIES | ||
Capital expenditures | (889,347) | (1,008,723) |
Contributions in aid of construction | 22,611 | 24,924 |
Allowance for borrowed funds used during construction | (18,959) | (15,378) |
Proceeds from nuclear decommissioning trust sales and other special use funds | 443,040 | 351,860 |
Investment in nuclear decommissioning trust and other special use funds | (461,602) | (353,001) |
Other | (1,261) | (18,098) |
Net cash flow used for investing activities | (905,518) | (1,018,416) |
CASH FLOWS FROM FINANCING ACTIVITIES | ||
Issuance of long-term debt | 295,245 | 549,478 |
Short-term borrowing and payments — net | 0 | (103,700) |
Short-term debt borrowings under revolving credit facility | 25,000 | 0 |
Short-term debt repayments under revolving credit facility | (25,000) | 0 |
Repayment of long-term debt | (82,000) | 0 |
Dividends paid on common stock | (233,300) | (219,100) |
Distributions to noncontrolling interests | (11,372) | (11,372) |
Net cash flow provided by financing activities | (31,427) | 215,306 |
NET INCREASE IN CASH AND CASH EQUIVALENTS | 50,974 | 1,793 |
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD | 13,851 | 8,840 |
CASH AND CASH EQUIVALENTS AT END OF PERIOD | 64,825 | 10,633 |
Supplemental disclosure of cash flow information | ||
Income taxes, net of refunds | 24,746 | 132 |
Interest, net of amounts capitalized | 154,788 | 142,779 |
Significant non-cash investing and financing activities: | ||
Accrued capital expenditures | $ 99,405 | $ 94,769 |
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, 2016 | 111,392,053 | 55,317 | 71,264,947 | ||||||||||
Balance at beginning of period at Dec. 31, 2016 | $ 4,935,912 | $ 2,596,030 | $ (4,133) | $ 2,255,547 | $ (43,822) | $ 132,290 | $ 5,037,970 | $ 178,162 | $ 2,421,696 | $ 2,331,245 | $ (25,423) | $ 132,290 | |
Increase (Decrease) in Shareholders' Equity | |||||||||||||
Net income | 481,447 | 466,827 | 14,620 | 491,143 | 476,523 | 14,620 | |||||||
Other comprehensive income | 1,705 | 1,705 | 1,807 | 1,807 | |||||||||
Dividends on common stock ($1.31 per share) | (146,204) | (146,204) | (146,198) | (146,198) | |||||||||
Issuance of common stock (in shares) | 274,823 | ||||||||||||
Issuance of common stock | 12,795 | $ 12,795 | |||||||||||
Purchase of treasury stock (in shares) | [1] | (162,312) | |||||||||||
Purchase of treasury stock | [1] | (12,964) | $ (12,964) | ||||||||||
Reissuance of treasury stock for stock-based compensation and other (in shares) | 207,765 | ||||||||||||
Reissuance of treasury stock for stock-based compensation and other | 16,288 | $ 16,264 | 23 | 1 | |||||||||
Net capital activities by noncontrolling interests | (11,372) | (11,372) | (11,372) | (11,372) | |||||||||
Ending balance (in shares) at Sep. 30, 2017 | 111,666,876 | 9,864 | 71,264,947 | ||||||||||
Increase (Decrease) in Shareholders' Equity | |||||||||||||
Other | 1 | 0 | 1 | ||||||||||
Balance at end of period at Sep. 30, 2017 | 5,277,607 | $ 2,608,825 | $ (833) | 2,576,193 | (42,117) | 135,539 | 5,373,351 | $ 178,162 | 2,421,696 | 2,661,570 | (23,616) | 135,539 | |
Balance at beginning of period at Jun. 30, 2017 | (43,626) | (25,112) | |||||||||||
Increase (Decrease) in Shareholders' Equity | |||||||||||||
Net income | 280,945 | 289,129 | |||||||||||
Other comprehensive income | 1,509 | 1,496 | |||||||||||
Ending balance (in shares) at Sep. 30, 2017 | 111,666,876 | 9,864 | 71,264,947 | ||||||||||
Balance at end of period at Sep. 30, 2017 | $ 5,277,607 | $ 2,608,825 | $ (833) | 2,576,193 | (42,117) | 135,539 | 5,373,351 | $ 178,162 | 2,421,696 | 2,661,570 | (23,616) | 135,539 | |
Beginning balance (in shares) at Dec. 31, 2017 | 111,816,170 | 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 | (1,520) | (1,520) | (1,735) | (1,735) | |||||||||
Dividends on common stock ($1.31 per share) | (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 | 0 | |||||||||
Reclassification of income tax effects related to new tax reform (See Note 13) | (8,552) | 8,552 | (8,552) | (5,038) | 5,038 | (5,038) | |||||||
Net capital activities by noncontrolling interests | $ (11,372) | (11,372) | (11,372) | (11,372) | |||||||||
Ending balance (in shares) at Sep. 30, 2018 | 112,015,949 | 112,015,949 | 17,368 | 71,264,947 | |||||||||
Increase (Decrease) in Shareholders' Equity | |||||||||||||
Other | $ 1 | 1 | 1 | ||||||||||
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 | |
Balance at beginning of period at Jun. 30, 2018 | (56,624) | (35,159) | |||||||||||
Increase (Decrease) in Shareholders' Equity | |||||||||||||
Net income | 319,885 | 343,239 | |||||||||||
Other comprehensive income | $ 1,550 | 1,403 | |||||||||||
Ending balance (in shares) at Sep. 30, 2018 | 112,015,949 | 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 | |
[1] | 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) CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Unaudited) (Parenthetical) - $ / shares | 9 Months Ended | |
Sep. 30, 2018 | Sep. 30, 2017 | |
Statement of Stockholders' Equity [Abstract] | ||
Dividends on common stock (in usd per share) | $ 1.39 | $ 1.31 |
Consolidation and Nature of Ope
Consolidation and Nature of Operations | 9 Months Ended |
Sep. 30, 2018 | |
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 2017 Form 10-K. These condensed consolidated financial statements and notes have been prepared consistently, with the exception of the reclassification of certain prior year amounts on our Condensed Consolidated Statements of Income and APS's Condensed Consolidated Statements of Income. Beginning in the quarter ended March 31, 2018, APS changed the format of presentation of its Condensed Consolidated Statements of Income from a utility ratemaking format to a commercial format. Minor changes were made in the description of certain income statement line items and the amounts presented in the comparable prior period also changed by immaterial amounts due to the change from a utility to a non-utility format and also from the adoption of the new accounting guidance for net periodic pension cost and net periodic postretirement benefit cost. In addition, the prior year amounts were reclassified to conform to the current year presentation for the other special use funds in the investment and other assets section on the Condensed Consolidated Balance Sheets. Supplemental Cash Flow Information The following table summarizes supplemental Pinnacle West cash flow information (dollars in thousands): Nine Months Ended 2018 2017 Cash paid during the period for: Income taxes, net of refunds $ 10,091 $ 2,185 Interest, net of amounts capitalized 161,875 147,149 Significant non-cash investing and financing activities: Accrued capital expenditures $ 99,405 $ 93,031 Sale of 4CA's 7% interest in Four Corners 68,907 — |
Revenue
Revenue | 9 Months Ended |
Sep. 30, 2018 | |
Revenue from Contract with Customer [Abstract] | |
Revenue | Revenue Adoption of Accounting Standards Update ("ASU") 2014-09, Revenue from Contracts with Customers On January 1, 2018, we adopted new revenue guidance in ASU 2014-09 and related amendments. The new revenue guidance requires entities to recognize revenue when control of the promised good or service is transferred to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. We applied the new guidance using the modified retrospective method applied to contracts which were not completed as of January 1, 2018. The adoption of the new revenue guidance resulted in expanded disclosures but otherwise did not have a material impact on our financial statements. New revenue disclosures required by the standard are included below. See Note 13 for additional information regarding the new accounting standard. Revenue Recognition and Sources of Revenue Our revenues are primarily derived from sales of electricity to our regulated retail customers. Our retail electric services and tariff rates are regulated by the ACC. Revenues related to the sale of electric services are recognized when service is rendered or electricity is delivered to the customer. Electricity sales generally represent a single performance obligation delivered over time. We have elected to apply the invoice practical expedient and, as such, we recognize revenue based on the amount to which we have a right to invoice for services performed. 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, 2018 2018 Retail residential electric service $ 695,480 $ 1,512,402 Retail non-residential electric service 496,809 1,275,498 Wholesale energy sales 53,501 80,982 Transmission services for others 15,902 46,235 Other sources 6,342 19,754 Total operating revenues $ 1,268,034 $ 2,934,871 The billing of regulated retail electricity sales to individual customers is based on data obtained from the customer’s meter. 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. We do not assess transactions for significant financing components when the period of time between when the goods or services are transferred to the customer and when the customer pays for those goods or services is less than one year. Unbilled revenues are estimated by applying an average revenue per kilowatt-hour (“kWh”) to the number of estimated kWhs delivered but not billed by customer class. Historically, differences between the actual and estimated unbilled revenues have been immaterial. We exclude sales tax and franchise fees on electric revenues from both revenue and taxes other than income taxes. Revenues from wholesale energy sales and transmission services for others represent energy and transmission sales to wholesale customers. Our wholesale activities and tariff rates are regulated by the United States Federal Energy Regulatory Commission ("FERC"). 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 are primarily derived from activities that are classified as revenues from contracts with customers. This includes sales of electricity to our regulated retail customers and wholesale and transmission activities. Our revenues from contracts with customers for the three and 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, 2018 , our revenues that do not qualify as revenue from contracts with customers 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, 2018 |
Long-Term Debt and Liquidity Ma
Long-Term Debt and Liquidity Matters | 9 Months Ended |
Sep. 30, 2018 | |
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 June 28, 2018, Pinnacle West refinanced its 364 -day $125 million unsecured revolving credit facility that would have matured on July 30, 2018 with a new 364 -day $150 million credit facility that matures June 27, 2019. Borrowings under the facility bear interest at LIBOR plus 0.70% per annum. At September 30, 2018 , Pinnacle West had $79 million outstanding under the facility. On July 12, 2018, Pinnacle West replaced its $200 million revolving credit facility that would have matured in May 2021, with a new $200 million 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. At September 30, 2018 , Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding and $49 million of commercial paper borrowings. APS On May 30, 2018, APS purchased all $32 million of Maricopa County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds, 2009 Series C, due 2029. These bonds were classified as current maturities of long-term debt on our Consolidated Balance Sheets at December 31, 2017. On June 26, 2018, APS repaid at maturity APS’s $50 million term loan facility. On July 12, 2018, APS replaced its $500 million revolving credit facility that would have matured in May 2021, with a new $500 million facility that matures in July 2023. On August 9, 2018, APS issued $300 million of 4.20% unsecured senior notes that mature on August 15, 2048. The net proceeds from the sale of the notes were used to repay commercial paper borrowings. At September 30, 2018 , APS had two revolving credit facilities totaling $1 billion , including a $500 million credit facility that matures in June 2022 and the above-mentioned $500 million facility. 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, 2018 , APS had no 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 APS’s 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, 2018 As of December 31, 2017 Carrying Amount Fair Value Carrying Amount Fair Value Pinnacle West $ 298,640 $ 292,185 $ 298,421 $ 298,608 APS 4,788,724 4,900,210 4,573,292 5,006,348 Total $ 5,087,364 $ 5,192,395 $ 4,871,713 $ 5,304,956 Debt Provisions An existing ACC order requires APS to maintain a common equity ratio of at least 40% . As defined in the ACC order, the common equity ratio is total shareholder equity divided by the sum of total shareholder equity and long-term debt, including current maturities of long-term debt. At September 30, 2018 , APS was in compliance with this common equity ratio requirement. Its total shareholder equity was approximately $5.6 billion , and total capitalization was approximately $10.6 billion . APS would be prohibited from paying dividends if the payment would reduce its total shareholder equity below approximately $4.2 billion |
Regulatory Matters
Regulatory Matters | 9 Months Ended |
Sep. 30, 2018 | |
Regulated Operations [Abstract] | |
Regulatory Matters | Regulatory Matters Retail Rate Case Filing with the Arizona Corporation Commission On June 1, 2016, APS filed an application with the ACC for an annual increase in retail base rates of $165.9 million . This amount excluded amounts that were then collected on customer bills through adjustor mechanisms. The application requested that some of the balances in these adjustor accounts (aggregating to approximately $267.6 million as of December 31, 2015) be transferred into base rates through the ratemaking process. This transfer would not have had an incremental effect on average customer bills. The average annual customer bill impact of APS’s request was an increase of 5.74% (the average annual bill impact for a typical APS residential customer was 7.96% ) . On March 27, 2017, a majority of the stakeholders in the general retail rate case, including the ACC Staff, the Residential Utility Consumer Office, limited income advocates and private rooftop solar organizations signed a settlement agreement (the "2017 Settlement Agreement") and filed it with the ACC. The 2017 Settlement Agreement provides for a net retail base rate increase of $94.6 million , excluding the transfer of adjustor balances, consisting of: (1) a non-fuel, non-depreciation, base rate increase of $87.2 million per year; (2) a base rate decrease of $53.6 million attributable to reduced fuel and purchased power costs; and (3) a base rate increase of $61.0 million due to changes in depreciation schedules. The average annual customer bill impact under the 2017 Settlement Agreement was calculated as an increase of 3.28% (the average annual bill impact for a typical APS residential customer was calculated as 4.54% ). Other key provisions of the agreement include the following: • an agreement by APS not to file another general retail rate case application before June 1, 2019; • an authorized return on common equity of 10.0% ; • a capital structure comprised of 44.2% debt and 55.8% common equity; • a cost deferral order for potential future recovery in APS’s next general retail rate case for the construction and operating costs APS incurs for its Ocotillo modernization project; • a cost deferral and procedure to allow APS to request rate adjustments prior to its next general retail rate case related to its share of the construction costs associated with installing selective catalytic reduction ("SCR") equipment at the Four Corners Power Plant ("Four Corners"); • a deferral for future recovery (or credit to customers) of the Arizona property tax expense above or below a specified test year level caused by changes to the applicable Arizona property tax rate; • an expansion of the Power Supply Adjustor (“PSA”) to include certain environmental chemical costs and third-party battery storage costs; • a new AZ Sun II program (now known as "APS Solar Communities") for utility-owned solar distributed generation with the purpose of expanding access to rooftop solar for low and moderate income Arizonans, recoverable through the Arizona Renewable Energy Standard and Tariff ("RES"), to be no less than $10 million per year, and not more than $15 million per year; • an increase to the per kWh cap for the environmental improvement surcharge from $0.00016 to $0.00050 and the addition of a balancing account; • rate design changes, including: ▪ a change in the on-peak time of use period from noon - 7 p.m. to 3 p.m. - 8 p.m. Monday through Friday, excluding holidays; ▪ non-grandfathered distributed generation ("DG") customers would be required to select a rate option that has time of use rates and either a new grid access charge or demand component; ▪ a Resource Comparison Proxy (“RCP”) for exported energy of 12.9 cents per kWh in year one; and • an agreement by APS not to pursue any new self-build generation (with certain exceptions) having an in-service date prior to January 1, 2022 (extended to December 31, 2027 for combined-cycle generating units), unless expressly authorized by the ACC. Through a separate agreement, APS, industry representatives, and solar advocates committed to stand by the 2017 Settlement Agreement and refrain from seeking to undermine it through ballot initiatives, legislation or advocacy at the ACC. On August 15, 2017, the ACC approved (by a vote of 4-1), the 2017 Settlement Agreement without material modifications. On August 18, 2017, the ACC issued a final written Opinion and Order reflecting its decision in APS’s general retail rate case (the "2017 Rate Case Decision"), which is subject to requests for rehearing and potential appeal. The new rates went into effect on August 19, 2017. On October 17, 2017, Warren Woodward (an intervener in APS's general retail rate case) filed a Notice of Appeal in the Arizona Court of Appeals, Division One. The notice raises a single issue related to the application of certain rate schedules to new APS residential customers after May 1, 2018. Mr. Woodward filed a second notice of appeal on November 13, 2017 challenging APS’s $5 per month automated metering infrastructure opt-out program. Mr. Woodward’s two appeals have been consolidated, and APS requested and was granted intervention. Mr. Woodward filed his opening brief on March 28, 2018. The ACC and APS filed responsive briefs on June 21, 2018. The Arizona Court of Appeals conferenced this matter on October 17, 2018, and APS anticipates a decision from the Arizona Court of Appeals by the end of 2018 or within the first half of 2019; however, the Arizona Court of Appeals is under no deadline to rule within a certain time period. APS cannot predict the outcome of this consolidated appeal but does not believe it will have a material impact on our financial position, results of operations or cash flows. On January 3, 2018, an APS customer filed a petition with the ACC that was determined by the ACC Staff to be a complaint filed pursuant to Arizona Revised Statute §40-246 (the “Complaint”) and not a request for rehearing. Arizona Revised Statute §40-246 requires the ACC to hold a hearing regarding any complaint alleging that a public service corporation is in violation of any commission order or that the rates being charged are not just and reasonable if the complaint is signed by at least twenty-five customers of the public service corporation. The Complaint alleged that APS is “in violation of commission order” [sic]. On February 13, 2018, the complainant filed an amended Complaint alleging that the rates and charges in the 2017 Rate Case Decision are not just and reasonable. The complainant requested that the ACC hold a hearing on the amended Complaint to determine if the average bill impact on residential customers of the rates and charges approved in the 2017 Rate Case Decision is greater than 4.54% (the average annual bill impact for a typical APS residential customer estimated by APS) and, if so, what effect the alleged greater bill impact has on APS's revenues and the overall reasonableness and justness of APS's rates and charges, in order to determine if there is sufficient evidence to warrant a full-scale rate hearing. The ACC held a hearing on this matter beginning in September 2018 and the hearing was concluded on October 1, 2018. The parties filed the initial briefs in October 2018 and reply briefs are due on November 16, 2018. APS expects a recommended opinion and order from the judge within the first quarter of 2019. APS cannot predict the outcome of this matter. Prior Rate Case Filing with the Arizona Corporation Commission On June 1, 2011, APS filed an application with the ACC for a net retail base rate increase of $95.5 million . On January 6, 2012, APS and other parties to the general retail rate case entered into an agreement (the "2012 Settlement Agreement") detailing the terms upon which the parties agreed to settle the rate case. On May 15, 2012, the ACC approved the 2012 Settlement Agreement without material modifications. Cost Recovery Mechanisms APS has received regulatory decisions that allow for more timely recovery of certain costs outside of a general retail rate case through the following recovery mechanisms. Renewable Energy Standard . In 2006, the ACC approved the RES. Under the RES, electric utilities that are regulated by the ACC must supply an increasing percentage of their retail electric energy sales from eligible renewable resources, including solar, wind, biomass, biogas and geothermal technologies. In order to achieve these requirements, the ACC allows APS to include a RES surcharge as part of customer bills to recover the approved amounts for use on renewable energy projects. Each year APS is required to file a five -year implementation plan with the ACC and seek approval for funding the upcoming year’s RES budget. In 2013, the ACC conducted a hearing to consider APS’s proposal to establish compliance with distributed energy requirements by tracking and recording distributed energy, rather than acquiring and retiring renewable energy credits. On February 6, 2014, the ACC established a proceeding to modify the renewable energy rules to establish a process for compliance with the renewable energy requirement that is not based solely on the use of renewable energy credits. On September 9, 2014, the ACC authorized a rulemaking process to modify the RES rules. The proposed changes would permit the ACC to find that utilities have complied with the distributed energy requirement in light of all available information. The ACC adopted these changes on December 18, 2014. The revised rules went into effect on April 21, 2015. In December 2014, the ACC voted that it had no objection to APS implementing an APS-owned rooftop solar research and development program aimed at learning how to efficiently enable the integration of rooftop solar and battery storage with the grid. The first stage of the program, called the "Solar Partner Program," placed 8 megawatts ("MW") of residential rooftop solar on strategically selected distribution feeders in an effort to maximize potential system benefits, as well as made systems available to limited-income customers who could not easily install solar through transactions with third parties. The second stage of the program, which included an additional 2 MW of rooftop solar and energy storage, placed two energy storage systems sized at 2 MW on two different high solar penetration feeders to test various grid-related operation improvements and system interoperability, and was in operation by the end of 2016. The costs for this program have been included in APS's rate base as part of the 2017 Rate Case Decision. On July 1, 2016, APS filed its 2017 RES Implementation Plan and proposed a budget of approximately $150 million . APS’s budget request included additional funding to process the high volume of residential rooftop solar interconnection requests and also requested a permanent waiver of the residential distributed energy requirement for 2017 contained in the RES rules. On April 7, 2017, APS filed an amended 2017 RES Implementation Plan and updated budget request which included the revenue neutral transfer of specific revenue requirements into base rates in accordance with the 2017 Settlement Agreement. On August 15, 2017, the ACC approved the 2017 RES Implementation Plan. On June 30, 2017, APS filed its 2018 RES Implementation Plan and proposed a budget of approximately $90 million . APS’s budget request supports existing approved projects and commitments and includes the anticipated transfer of specific revenue requirements into base rates in accordance with the 2017 Settlement Agreement and also requests a permanent waiver of the residential distributed energy requirement for 2018 contained in the RES rules. APS's 2018 RES budget request is lower than the 2017 RES budget due in part to a certain portion of the RES being collected by APS in base rates rather than through the RES adjustor. On November 20, 2017, APS filed an updated 2018 RES budget to include budget adjustments for APS Solar Communities (formerly known as AZ Sun II), which was approved as part of the 2017 Rate Case Decision. APS Solar Communities is a 3 -year program requiring APS to spend $10 million to $15 million in capital costs each year to install utility-owned DG systems for low to moderate income residential homes, buildings of non-profit entities, Title I schools and rural government facilities. The 2017 Rate Case Decision provided that all operations and maintenance expenses, property taxes, marketing and advertising expenses, and the capital carrying costs for this program will be recovered through the RES. On June 12, 2018, the ACC approved the 2018 RES Implementation Plan. On June 29, 2018, APS filed its 2019 RES Implementation Plan and proposed a budget of approximately $ 89.9 million . APS’s budget request supports existing approved projects and commitments and requests a permanent waiver of the residential distributed energy requirement for 2019 contained in the RES rules. In September 2016, the ACC initiated a proceeding which will examine the possible modernization and expansion of the RES. On January 30, 2018, ACC Commissioner Tobin proposed a plan in this proceeding which would broaden the RES to include a series of energy policies tied to clean energy sources (the "Energy Modernization Plan"). The Energy Modernization Plan incl udes replacing the current RES standard with a new standard called the Clean Resource Energy Standard and Tariff ("CREST"), which incorporates the proposals in the Energy Modernization Plan. A set of draft CREST rules for the ACC’s consideration was issued by Commissioner Tobin’s office on July 5, 2018. See "Energy Modernization Plan" below for more information on CREST. Demand Side Management Adjustor Charge ("DSMAC") . 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. On March 20, 2015, APS filed an application with the ACC requesting a budget of $68.9 million for 2015 and minor modifications to its DSM portfolio going forward, including for the first time three resource savings projects which reflect energy savings on APS's system. The ACC approved APS’s 2015 DSM budget on November 25, 2015. In its decision, the ACC also ruled that verified energy savings from APS's resource savings projects could be counted toward compliance with the Electric Energy Efficiency Standards; however, the ACC ruled that APS was not allowed to count savings from systems savings projects toward determination of the achievement of performance incentives, nor may APS include savings from conservation voltage reduction in the calculation of its Lost Fixed Cost Recovery Mechanism (“LFCR”) mechanism. On June 1, 2016, APS filed its 2017 DSM Plan, in which APS proposed programs and measures that specifically focus on reducing peak demand, shifting load to off-peak periods and educating customers about strategies to manage their energy and demand. The requested budget in the 2017 DSM Plan was $62.6 million . On January 27, 2017, APS filed an updated and modified 2017 DSM Plan that incorporated the proposed Residential Demand Response, Energy Storage and Load Management Program and requested that the budget be increased to $66.6 million . On August 15, 2017, the ACC approved the amended 2017 DSM Plan. On September 1, 2017, APS filed its 2018 DSM Plan, which proposes modifications to the demand side management portfolio to better meet system and customer needs by focusing on peak demand reductions, storage, load shifting and demand response programs in addition to traditional energy savings measures. The 2018 DSM Plan seeks a reduced requested budget of $52.6 million and requests a waiver of the 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. Power Supply Adjustor ("PSA") 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 (liability) for 2018 and 2017 (dollars in thousands): Nine Months Ended 2018 2017 Beginning balance $ 75,637 $ 12,465 Deferred fuel and purchased power costs — current period 82,486 43,348 Amounts refunded/(charged) to customers (92,397 ) 18,153 Ending balance $ 65,726 $ 73,966 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 will roll over until the following year and will be reflected in the 2019 reset of the PSA. 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 2012 Settlement Agreement, however, an adjustment to rates to recover the Retail Transmission Charges will be made annually each June 1 and will go into effect automatically unless suspended by the ACC. The formula rate is updated each year effective June 1 on the basis of APS's actual cost of service, as disclosed in APS's FERC Form 1 report for the previous fiscal year. Items to be updated include actual capital expenditures made as compared with previous projections, transmission revenue credits and other items. The resolution of proposed adjustments can result in significant volatility in the revenues to be collected. APS reviews the proposed formula rate filing amounts with the ACC Staff. Any items or adjustments which are not agreed to by APS and the ACC Staff can remain in dispute until settled or litigated at FERC. Settlement or litigated resolution of disputed issues could require an extended period of time and could have a significant effect on the Retail Transmission Charges because any adjustment, though applied prospectively, may be calculated to account for previously over- or under-collected amounts. Effective June 1, 2017, APS's annual wholesale transmission rates for all users of its transmission system increased by approximately $35.1 million for the twelve-month period beginning June 1, 2017 in accordance with the FERC-approved formula. An adjustment to APS’s retail rates to recover FERC approved transmission charges went into effect automatically on June 1, 2017. Effective June 1, 2018, APS's annual wholesale transmission rates for all users of its transmission system decreased by approximately $22.7 million for the twelve-month period beginning June 1, 2018 in accordance with the FERC-approved formula. An adjustment to APS’s retail rates to recover FERC approved transmission charges went into effect automatically on June 1, 2018. On January 31, 2017, APS made a filing with FERC to reduce the Post-Employment Benefits Other than Pension expense reflected in its FERC transmission formula rate calculation to recognize certain savings resulting from plan design changes to the other postretirement benefit plans. A transmission customer intervened and protested certain aspects of APS’s filing. FERC initiated a proceeding under Section 206 of the Federal Power Act to evaluate the justness and reasonableness of the revised formula rate filing APS proposed. APS entered into a settlement agreement with the intervening transmission customer, which was filed with FERC for approval on September 26, 2017. FERC approved the settlement agreement without modification or condition on December 21, 2017. On March 7, 2018, APS made a filing to make modifications to its annual transmission formula to provide transmission customers the benefit of the reduced federal corporate income tax rate resulting from the Tax Cuts and Jobs Act of 2017 (the “Tax Act”) beginning in its 2018 annual transmission formula rate update filing. These modifications were approved by FERC on May 22, 2018 and reduced APS’s transmission rates compared to the rate that would have gone into effect absent these changes. Lost Fixed Cost Recovery Mechanism . The LFCR mechanism permits APS to recover on an after-the-fact basis a portion of its fixed costs that would otherwise have been collected by APS in the kWh sales lost due to APS energy efficiency programs and to DG such as rooftop solar arrays. The fixed costs recoverable by the LFCR mechanism were first established in the 2012 Settlement Agreement and amount to approximately 3.1 cents per residential kWh lost and 2.3 cents per non-residential kWh lost. These amounts were revised in the 2017 Settlement Agreement to 2.5 cents for both lost residential and non-residential kWh. The LFCR adjustment has a year-over-year cap of 1% of retail revenues. Any amounts left unrecovered in a particular year because of this cap can be carried over for recovery in a future year. The 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 2016 annual LFCR adjustment on January 15, 2016, requesting an LFCR adjustment of $46.4 million (a $7.9 million annual increase). The ACC approved the 2016 annual LFCR effective beginning in May 2016. APS filed its 2017 LFCR adjustment on January 13, 2017 requesting an LFCR adjustment of $63.7 million (a $17.3 million per year increase over 2016 levels). On April 5, 2017, the ACC approved the 2017 annual LFCR adjustment as filed, effective with the first billing cycle of April 2017. On February 15, 2018, APS filed its 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). The ACC has not yet ruled on APS’s 2018 LFCR adjustment request. Because the LFCR mechanism has a balancing account that trues up any under or over recoveries, a delay in implementation does not have an adverse effect on APS. Tax Expense Adjustor Mechanism ("TEAM") and FERC Tax Filing . As part of the 2017 Settlement Agreement, the parties agreed to a rate adjustment mechanism to address potential federal income tax reform and enable the pass-through of certain income tax effects to customers. On December 22, 2017, the Tax Act was enacted. This legislation made significant changes to the federal income tax laws including a reduction in the corporate tax rate from 35% to 21% effective January 1, 2018. On January 8, 2018, APS filed an application with the ACC requesting that the TEAM be implemented in two steps. The first addresses the change in the marginal federal tax rate from 35% to 21% resulting from the Tax Act and, if approved, would reduce rates by $119.1 million annually through an equal cents per kWh credit. APS asked that this decrease become effective February 1, 2018. On February 22, 2018, the ACC approved the reduction of rates by $119.1 million for the remainder of 2018 through an equal cents per kWh credit applied to all but a small subset of customers who are taking service under specially-approved tariffs. The rate reduction was effective for the first billing cycle in March 2018. The amount of the benefit of the lower federal income tax rate is based on our quarterly pre-tax earnings pattern, while the reduction in revenues from lower customer rates through the TEAM is based on a per kWh sales credit which follows our seasonal kWh sales pattern and is not impacted by earnings of the Company. On August 13, 2018, APS filed a second request with the ACC to return an additional $86.5 million in tax savings to customers, starting January 1, 2019. This second request addresses amortization of non-depreciation related excess deferred taxes previously collected from customers. Additionally, as part of this second request, APS informed the ACC of its intent to file a third future request to address the amortization of depreciation related excess deferred taxes, as the Company is currently seeking IRS guidance regarding the amortization method and period it should apply to these depreciation related excess deferred taxes. The ACC has not yet approved this request. The TEAM expressly applies to APS's retail rates with the exception noted above. As discussed under "Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters" above, FERC issued an order on May 22, 2018 authorizing APS to provide for the cost reductions resulting from the income tax changes in its wholesale transmission rates. Net Metering In 2015, the ACC voted to conduct a generic evidentiary hearing on the value and cost of DG to gather information that will inform the ACC on net metering issues and cost of service studies in upcoming utility rate cases. A hearing was held in April 2016. On October 7, 2016, the Administrative Law Judge issued a recommendation in the docket concerning the value and cost of DG solar installations. On December 20, 2016, the ACC completed its open meeting to consider the recommended opinion and order by the Administrative Law Judge. After making several amendments, the ACC approved the recommended decision by a 4-1 vote. As a result of the ACC’s action, effective with APS’s 2017 Rate Case Decision, the net metering tariff that governs payments for energy exported to the grid from residential rooftop solar systems was replaced by a more formula-driven approach that utilizes inputs from historical wholesale solar power until an avoided cost methodology is developed by the ACC. As amended, the decision provides that payments by utilities for energy exported to the grid from DG solar facilities will be determined using a RCP methodology, a method that is based on the most recent five-year rolling average price that APS pays for utility-scale solar projects, while a forecasted avoided cost methodology is being developed. The price established by this RCP method will be updated annually (between general retail rate cases) but will not be decreased by more than 10% per year. Once the avoided cost methodology is developed, the ACC will determine in APS's subsequent rate cases which method (or a combination of methods) is appropriate to determine the actual price to be paid by APS for exported distributed energy. In addition, the ACC made the following determinations: • Customers who have interconnected a DG system or submitted an application for interconnection for DG systems prior to August 19, 2017, the date new rates were effective based on APS's 2017 Rate Case Decision, will be grandfathered for a period of 20 years from the date the customer’s interconnection application was accepted by the utility; • Customers with DG solar systems are to be considered a separate class of customers for ratemaking purposes; and • Once an export price is set for APS, no netting or banking of retail credits will be available for new DG customers, and the then-applicable export price will be guaranteed for new customers for a period of 10 years. This decision of the ACC addresses policy determinations only. The decision states that its principles will be applied in future general retail rate cases, and the policy determinations themselves may be subject to future change, as are all ACC policies. A first-year export energy price of 12.9 cents per kWh is included in the 2017 Settlement Agreement and became effective on August 19, 2017. In accordance with the 2017 Rate Case Decision, APS filed its request for a second-year export energy price of 11.6 cents per kWh on May 1, 2018. This price reflects the 10% annual reduction discussed above. The new tariff became effective on October 1, 2018. On January 23, 2017, 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 Court of Appeals and filed a Complaint and Statutory Appeal in the Maricopa County Superior Court on March 10, 2017. As part of the 2017 Settlement Agreement described above, TASC agreed to withdraw these appeals when the ACC decision implementing the 2017 Settlement Agreement is no longer subject to appellate review. Subpoena from Arizona Corporation Commissioner Robert Burns On August 25, 2016, Commissioner Burns, individually and not by action of the ACC as a whole, served subpoenas in APS’s then current retail rate proceeding on APS and Pinnacle West for the production of records and information relating to a range of expenditures from 2011 through 2016. The subpoenas requested information concerning marketing and advertising expenditures, charitable donations, lobbying expenses, contributions to 501(c)(3) and (c)(4) nonprofits and political contributions. The return date for the production of information was set as September 15, 2016. The subpoenas also sought testimony from Company personnel having knowledge of the material, including the Chief Executive Officer. On September 9, 2016, APS filed with the ACC a motion to quash the subpoenas or, alternatively, to stay APS's obligations to comply with the subpoenas and decline to decide APS's motion pending court proceedings. Contemporaneously with the filing of this motion, APS and Pinnacle West filed a complaint for special action and declaratory judgment in the Superior Court of Arizona for Maricopa County, seeking a declaratory judgment that Commissioner Burns’ subpoenas are contrary to law. On September 15, 2016, APS produced all non-confidential and responsive documents and offered to produce any remaining responsive documents that are confidential after an appropriate confidentiality agreement is signed. On February 7, 2017, Commissioner Burns opened a new ACC docket and indicated that its purpose is to study and rectify problems with transparency and disclosure regarding financial contributions from regulated monopolies or other stakeholders who may appear before the ACC that may directly or indirectly benefit an ACC Commissioner, a candidate for ACC Commissioner, or key ACC Staff. As part of this docket, Commissioner Burns set March 24, 2017 as a deadline for the production of all information previously requested through the subpoenas. Neither APS nor Pinnacle West produced the information requested and instead objected to the subpoena. On March 10, 2017, Commissioner Burns filed suit against APS and Pinnacle West in the Superior Court of Arizona for Maricopa County in an effort to enforce his subpoenas. On March 30, 2017, APS filed a motion to dismiss Commissioner Burns' suit against APS and Pinnacle West. In response to the motion to dismiss, the court stayed the suit and ordered Commissioner Burns to file a motion to compel the production of the information sought by the subpoenas with the ACC. On June 20, 2017, the ACC denied the motion to compel. On August 4, 2017, Commissioner Burns amended his complaint to add all of the ACC Commissioners and the ACC itself as defendants. All defendants moved to dismiss the amended complaint. On February 15, 2018, the Superior Court dismissed Commissioner Burns’ amended complaint. On March 6, 2018, C |
Retirement Plans and Other Post
Retirement Plans and Other Postretirement Benefits | 9 Months Ended |
Sep. 30, 2018 | |
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. Because of plan changes in September 2014, the Company sought IRS approval to move approximately $186 million of other postretirement benefit trust assets into a new trust account to pay for active union employee medical costs. In December 2016, FERC approved a methodology for determining the amount of other postretirement benefit trust assets to transfer into a new trust account to pay for active union employee medical costs. On January 2, 2018, these funds were moved to the new trust account which is included in the other special use funds on the Condensed Consolidated Balance Sheets. The Company negotiated a draft Closing Agreement granting tentative approval from the IRS prior to the transfer. Subsequent to the transfer, the Company submitted proof of the transfer to the IRS. The Company and the IRS executed a final Closing Agreement on March 2, 2018. Per the terms of an order from FERC, the Company must also make an informational filing with FERC. The Company made this FERC filing during February 2018. It is the Company’s understanding that completion of these regulatory requirements permits access to approximately $186 million for the sole purpose of paying active union employee medical benefits. 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 2018 2017 2018 2017 2018 2017 2018 2017 Service cost — benefits earned during the period $ 14,167 $ 13,715 $ 42,501 $ 41,144 $ 5,275 $ 4,280 $ 15,825 $ 12,839 Non-service costs (credits): Interest cost on benefit obligation 31,172 32,439 93,517 97,316 7,037 7,490 21,111 22,470 Expected return on plan assets (45,713 ) (43,568 ) (137,140 ) (130,703 ) (10,520 ) (13,350 ) (31,561 ) (40,051 ) Amortization of: Prior service cost (credit) — 20 — 61 (9,461 ) (9,461 ) (28,382 ) (28,382 ) Net actuarial loss 8,021 11,975 24,062 35,924 — 1,279 — 3,838 Net periodic benefit cost (credit) $ 7,647 $ 14,581 $ 22,940 $ 43,742 $ (7,669 ) $ (9,762 ) $ (23,007 ) $ (29,286 ) Portion of cost (credit) charged to expense $ 2,524 $ 7,231 $ 7,535 $ 21,692 $ (5,359 ) $ (4,841 ) $ (16,083 ) $ (14,523 ) On January 1, 2018, we adopted new accounting standard ASU 2017-07, Compensation-Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. This new standard changed our income statement presentation of net periodic benefit cost/(credits) and allows only the service cost component of net periodic benefit cost to be eligible for capitalization. See Note 13 for additional information. Contributions We have made voluntary contributions of $50 million to our pension plan year-to-date in 2018. 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 $250 million during the 2018-2020 period. We do not expect to make any contributions over the next three years to our other postretirement benefit plans. Year to date in 2018, the Company was reimbursed $72 million |
Palo Verde Sale Leaseback Varia
Palo Verde Sale Leaseback Variable Interest Entities | 9 Months Ended |
Sep. 30, 2018 | |
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, 2018 of $ 5 million and $ 15 million respectively, and for the three and nine months ended September 30, 2017 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, 2018 and December 31, 2017 include the following amounts relating to the VIEs (dollars in thousands): September 30, 2018 December 31, 2017 Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation $ 106,743 $ 109,645 Equity — Noncontrolling interests 132,289 129,040 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 $295 million beginning in 2018, and up to $456 million over the lease terms. |
Derivative Accounting
Derivative Accounting | 9 Months Ended |
Sep. 30, 2018 | |
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, coal and 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, 2018 and December 31, 2017 , 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, 2018 December 31, 2017 Power GWh 287 583 Gas Billion cubic feet 192 240 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, 2018 and 2017 (dollars in thousands): Financial Statement Location Three Months Ended Nine Months Ended Commodity Contracts 2018 2017 2018 2017 Gain (Loss) Recognized in OCI on Derivative Instruments (Effective Portion) OCI — derivative instruments $ — $ 14 $ — $ (70 ) Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a) Fuel and purchased power (b) (600 ) (1,148 ) (1,697 ) (2,910 ) (a) During the three and nine months ended September 30, 2018 and 2017 , we had no gains or losses reclassified from accumulated OCI to earnings due to the discontinuance of cash flow hedges where the forecasted transaction is not probable of occurring. (b) Amounts are before the effect of PSA deferrals. During the next twelve months, we estimate that a net loss of $2 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, 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, 2018 and 2017 (dollars in thousands): Financial Statement Location Three Months Ended Nine Months Ended Commodity Contracts 2018 2017 2018 2017 Net Loss Recognized in Income Operating revenues $ (1,029 ) $ (128 ) $ (2,590 ) $ (474 ) Net Gain (Loss) Recognized in Income Fuel and purchased power (a) 4,263 (6,100 ) (26,442 ) (64,143 ) Total $ 3,234 $ (6,228 ) $ (29,032 ) $ (64,617 ) (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, 2018 and December 31, 2017 . 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, 2018: Gross Recognized Derivatives (a) Amounts Offset (b) Net Recognized Derivatives Other (c) Amount Reported on Balance Sheets Current assets $ 2,609 $ (2,273 ) $ 336 $ 888 $ 1,224 Investments and other assets 314 (314 ) — — — Total assets 2,923 (2,587 ) 336 888 1,224 Current liabilities (45,238 ) 2,273 (42,965 ) (2,539 ) (45,504 ) Deferred credits and other (34,540 ) 314 (34,226 ) — (34,226 ) Total liabilities (79,778 ) 2,587 (77,191 ) (2,539 ) (79,730 ) Total $ (76,855 ) $ — $ (76,855 ) $ (1,651 ) $ (78,506 ) (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 are 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. Amounts include cash collateral received from counterparties of $2,539 and cash margin provided to counterparties of $888 . As of December 31, 2017: Gross Recognized Derivatives (a) Amounts Offset (b) Net Recognized Derivatives Other (c) Amount Reported on Balance Sheets Current assets $ 5,427 $ (3,796 ) $ 1,631 $ 300 $ 1,931 Investments and other assets 1,292 (1,241 ) 51 — 51 Total assets 6,719 (5,037 ) 1,682 300 1,982 Current liabilities (59,527 ) 3,796 (55,731 ) (3,521 ) (59,252 ) Deferred credits and other (38,411 ) 1,241 (37,170 ) — (37,170 ) Total liabilities (97,938 ) 5,037 (92,901 ) (3,521 ) (96,422 ) Total $ (91,219 ) $ — $ (91,219 ) $ (3,221 ) $ (94,440 ) (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. Amounts include cash collateral received from counterparties of $3,521 and cash margin provided to counterparties of $300 . 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, 2018 , Pinnacle West has no counterparties with positive exposures of greater than 10% of risk management assets. Our risk management process assesses and monitors the financial exposure of all counterparties. Despite the fact that the great majority of our trading counterparties' debt is rated as investment grade by the credit rating agencies, there is still a possibility that one or more of these counterparties could default, resulting in a material impact on consolidated earnings for a given period. Counterparties in the portfolio consist principally of financial institutions, major energy companies, municipalities and local distribution companies. We maintain credit policies that we believe minimize overall credit risk to within acceptable limits. Determination of the credit quality of our counterparties is based upon a number of factors, including credit ratings and our evaluation of their financial condition. To manage credit risk, we employ collateral requirements and standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty. Valuation adjustments are established representing our estimated credit losses on our overall exposure to counterparties. Certain of our derivative instrument contracts contain credit-risk-related contingent features including, among other things, investment grade credit rating provisions, credit-related cross-default provisions, and adequate assurance provisions. Adequate assurance provisions allow a counterparty with reasonable grounds for uncertainty to demand additional collateral based on subjective events and/or conditions. For those derivative instruments in a net liability position, with investment grade credit contingencies, the counterparties could demand additional collateral if our debt credit rating were to fall below investment grade (below BBB- for Standard & Poor’s or Fitch or Baa3 for Moody’s). The following table provides information about our derivative instruments that have credit-risk-related contingent features at September 30, 2018 (dollars in thousands): September 30, 2018 Aggregate fair value of derivative instruments in a net liability position $ 79,778 Cash collateral posted — Additional cash collateral in the event credit-risk-related contingent features were fully triggered (a) 76,299 (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 $94 million |
Commitments and Contingencies
Commitments and Contingencies | 9 Months Ended |
Sep. 30, 2018 | |
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 three claims pursuant to the terms of the August 18, 2014 settlement agreement, for three separate time periods during July 1, 2011 through June 30, 2017. The DOE has approved and paid $74.2 million for these claims (APS’s share is $21.6 million ). The amounts recovered were primarily recorded as adjustments to a regulatory liability and had no impact on reported net income. In accordance with the 2017 Rate Case Decision, this regulatory liability is being refunded to customers (see Note 4). APS's next claim pursuant to the terms of the August 18, 2014 settlement agreement is required to be filed with DOE no later than October 31, 2018. The amounts recovered were primarily recorded as adjustments to a regulatory liability and had no impact on reported net income. 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 occurring on or prior to October 31, 2018 of up to approximately $13.1 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 $12.6 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. For losses on or prior to October 31, 2018, t he maximum total deferred premium per reactor under the program for each nuclear liability incident is approximately $127.3 million , subject to a maximum annual premium of $19 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 $111.1 million , with a maximum annual standard deferred premium of approximately $16.6 million . On September 24, 2018, the NRC announced a statutorily mandated once per five year inflation adjustment to the maximum total deferred premium and the annual standard deferred premium. Effective November 1, 2018, the inflation adjusted maximum total deferred premium per reactor is approximately $137.6 million per incident, subject to the maximum annual deferred premium of approximately $20.5 million . Based on APS’s ownership interest in the three Palo Verde units, for covered incidents occurring on or after November 1, 2018, APS’s maximum total deferred premium per incident for all three units is approximately $120.1 million , with a maximum annual standard deferred 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 $24.8 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 $71.2 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 For the nine months ended September 30, 2018, our fuel and purchased power commitments decreased approximately $166 million from amounts reported at December 31, 2017, primarily due to the amended and restated Four Corners 2016 Coal Supply Agreement effective in the second quarter of 2018. The majority of these changes relate to the years 2023 and thereafter. Other than the items described above, there have been no material changes, as of September 30, 2018 , outside the normal course of business in contractual obligations from the information provided in our 2017 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 generated, transported or disposed of hazardous substances at a contaminated site are among those who are potentially responsible parties ("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, APS anticipates finalizing the RI/FS in the spring 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, the Roosevelt Irrigation District ("RID") filed a lawsuit in Arizona District Court against APS and 24 other defendants, alleging that RID’s groundwater wells were contaminated by the release of hazardous substances from facilities owned or operated by the defendants. The lawsuit also alleges that, under Superfund laws, the defendants are jointly and severally liable to RID. The allegations against APS arise out of APS’s current and former ownership of facilities in and around OU3. As part of a state governmental investigation into groundwater contamination in this area, on January 25, 2015, the Arizona Department of Environmental Quality ("ADEQ") sent a letter to APS seeking information concerning the degree to which, if any, APS’s current and former ownership of these facilities may have contributed to groundwater contamination in this area. APS responded to ADEQ on May 4, 2015. On December 16, 2016, two RID environmental and engineering contractors filed an ancillary lawsuit for recovery of costs against APS and the other defendants in the RID litigation. That same day, another RID service provider filed an additional ancillary CERCLA lawsuit against certain of the defendants in the main RID litigation, but excluded APS and certain other parties as named defendants. Because the ancillary lawsuits concern past costs allegedly incurred by these RID vendors, which were ruled unrecoverable directly by RID in November of 2016, the additional lawsuits do not increase APS's exposure or risk related to these matters. On April 5, 2018, RID and the defendants in that particular litigation executed a settlement agreement, fully resolving RID's CERCLA claims concerning both past and future cost recovery. APS's share of this settlement was immaterial. In addition, the two environmental and engineering vendors voluntarily dismissed their lawsuit against APS and the other named defendants without prejudice. An order to this effect was entered on April 17, 2018. With this disposition of the case, the vendors may file their lawsuit again in the future. In addition, APS and certain other parties not named in the remaining RID service provider lawsuit may be brought into the litigation via third-party complaints filed by the current direct defendants. We are unable to predict the outcome of these matters; however, we do not expect the outcome to have a material impact on our financial position, results of operations or cash flows. Environmental Matters APS is subject to numerous environmental laws and regulations affecting many aspects of its present and future operations, including air emissions of both conventional pollutants and greenhouse gases, water quality, wastewater discharges, solid waste, hazardous waste, and coal combustion residuals ("CCRs"). These laws and regulations can change from time to time, imposing new obligations on APS resulting in increased capital, operating, and other costs. Associated capital expenditures or operating costs could be material. APS intends to seek recovery of any such environmental compliance costs through our rates, but cannot predict whether it will obtain such recovery. The following proposed and final rules involve material compliance costs to APS. Regional Haze Rules. APS has received the final rulemaking imposing new pollution control requirements on Four Corners and the Navajo Plant. EPA will require these plants to install pollution control equipment that constitutes best available retrofit technology ("BART") to lessen the impacts of emissions on visibility surrounding the plants. In addition, EPA has 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 . 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 Coal Supply Agreement - 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. 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. APS would permanently close Cholla Unit 2 and cease burning coal at Units 1 and 3 by the mid-2020s. (See Note 4 for 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 current BART requirements for NOx imposed on the Cholla units under EPA's BART FIP. On October 16, 2015, ADEQ issued a revised operating permit for Cholla, which incorporates APS's proposal, and subsequently submitted a proposed revision to the SIP to EPA, which would incorporate the new permit terms. On June 30, 2016, EPA issued a proposed rule approving a revision to the Arizona SIP that incorporates APS’s compromise approach for compliance with the Regional Haze program. 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 March 1, 2018, EPA issued a proposed rule that, among other things, seeks comment on potential changes to the federal CCR regulations, including allowances for greater flexibility in setting groundwater protection standards for certain regulated CCR constituents and with respect to implementing corrective action. On July 17, 2018, EPA finalized a revision to its RCRA Subtitle D regulations for CCR, only addressing certain portions of EPA's March 2018 proposal, while deferring for further consideration the vast majority of the potential regulatory changes contemplated in the March 2018 proposal. For the final rule issued on July 17, 2018, EPA established nationwide health-based standards for certain constituents of CCR subject to groundwater corrective action and delayed the closure deadlines for certain unlined CCR surface impoundments by 18 months (for example, those disposal units required to undergo forced closure). These changes to the federal regulations governing CCR disposal are unlikely to have a material impact on APS. As for those aspects of the March 2018 rulemaking proposal for which EPA has yet to take final action, it remains unclear which specific provisions of the federal CCR rules will ultimately be modified, how they will be modified, or when such modification will occur. Pursuant to a June 24, 2016 order by the D.C. Circuit Court of Appeals in the litigation by industry- and environmental-groups challenging EPA’s CCR regulations, EPA is required to complete a rulemaking proceeding in the near future concerning whether or not boron must be included on the list of groundwater constituents that might trigger corrective action under EPA’s CCR rules. Simultaneously with the issuance of EPA's proposed modifications to the federal CCR rules in response to industry petitions, on March 1, 2018, EPA issued a proposed rule seeking comment as to whether or not boron should be included on this list. EPA is not required to take final action approving the inclusion of boron. Should EPA take final action adding boron to the list of groundwater constituents that might trigger corrective action, any resulting corrective action measures may increase APS's costs of compliance with the CCR rule at our coal-fired generating facilities. At this time APS cannot predict the eventual results of this rulemaking proceeding concerning boron. On August 21, 2018, the D.C. Circuit Court issued its decision on the merits in this litigation. The Court upheld the legality of EPA’s CCR regulations, though it vacated and remanded back to EPA a number of specific provisions, which are to be corrected in accordance with the Court’s order. Among the issues affecting APS’s management of CCR, the D.C. Circuit’s decision vacated and remanded those provisions of the EPA CCR regulations that allow for the operation of unlined CCR surface impoundments, even where those unlined impoundments have not otherwise violated a regulatory location restriction or groundwater protection standard (i.e., otherwise triggering forced closure). At this time, it remains unclear how this D.C. Circuit Court decision will affect APS’s operations or any financial impacts, as EPA has yet to take regulatory action on remand to revise its 2015 CCR regulations consistent with the Court’s order. 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 $20 million . The Navajo Plant currently disposes of CCR in a dry landfill storage area. APS estimates that its share of incremental costs to comply with the CCR rule for the Navajo Plant is approximately $1 million . 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 recently 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, to the extent that compliance with the CCR rule did not otherwise trigger the need for these CCR disposal units to close, such units must all 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 will initiate an assessment of corrective measures by January of 2019, during which APS will gather additional groundwater data, solicit input from the public, host a public hearing, and select a remedy. As such, this $ 5 million cost estimate may change based upon APS’s performance of the CCR rule’s corrective action assessment process, which APS anticipates completing during the summer or fall of 2019. 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. On August 3, 2015, EPA finalized carbon pollution standards for EGUs. Shortly thereafter, a coalition of states, industry groups and electric utilities challenged the legality of these standards, including EPA's Clean Power Plan for existing EGUs, in the U.S. Court of Appeals for the D.C. Circuit. On February 9, 2016, the U.S. Supreme Court granted a stay of the Clean Power Plan pending judicial review of the rule, which temporarily delays compliance obligations under the Clean Power Plan. On March 28, 2017, President Trump issued an Executive Order that, among other things, instructs EPA to reevaluate Agency regulations concerning carbon emissions from EGUs and take appropriate action to suspend, revise or rescind the August 2015 carbon pollution standards for EGUs, including the Clean Power Plan. Also on March 28, 2017, the U.S. Department of Justice, on behalf of EPA, filed a motion with the U.S. Court of Appeals for the D.C. Circuit Court to hold the ongoing litigation over the Clean Power Plan in abeyance pending EPA action in accordance with the Executive Order. At this time, the D.C. Circuit Court proceedings evaluating the legality of the Clean Power Plan remain on hold. Based upon EPA's reevaluation of the August 2015 carbon pollution standards and the legal basis for these regulations, on October 10, 2017, EPA issued a proposal to repeal the Clean Power Plan. That proposal relies on EPA's current view as to the Agency's legal authority under Clean Air Act Section 111(d), which (in contrast to the Clean Power Plan) would limit the scope of any future Section 111(d) regulations to measures undertaken exclusively at a power plant's source of greenhouse gas ("GHG") emissions. On December 18, 2017, EPA issued an Advanced Notice of Proposed Rulemaking through which EPA is soliciting comments as to potential replacements for the Clean Power Plan that would be consistent with EPA's current legal interpretation of the Clean Air Act. On August 21, 2018, EPA issued a Notice of Proposed Rulemaking for regulations that would replace the Clean Power Plan, which are based entirely upon measures that can be implemented to improve the heat rate of steam-electric power plants, essentially coal-fired EGUs. In contrast with the Clean Power Plan, EPA’s proposed “Affordable Clean Energy Rule” 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. In addition, to address the New Source Review implications of power plant upgrades potentially necessary to achieve compliance with the proposed Affordable Clean Energy Rule standards, EPA also proposed to revise the EPA's New Source Review regulations to more readily authorize the implementation of EGU efficiency upgrades. We cannot predict the outcome of EPA's regulatory actions related to the August 2015 carbon pollution standards for EGU's, including any actions related to EPA's repeal proposal for the Clean Power Plan or additional rulemaking actions to approve the EPA's recently proposed Affordable Clean Energy Rule. In addition, we cannot predict whether the D.C. Circuit Court will continue to hold the litigation challenging the original Clean Power Plan in abeyance in light of EPA's repeal proposal, which is still pending. 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. The parties anticipate oral arguments to be heard in early 2019. We cannot predict whether this appeal will be successful and, if it is successful, the outcome of further district court 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. These groups are seeking to have the permit remanded back to EPA for revision to address these allegations. At this time, we cannot predict whether this EAB permit appeal will be successful, and if so whether the results of those proceedings will have a material impact on our financial position, results of operations or cash flows. Four Corners Coal Supply Agreement Arbitration On June 13, 2017, APS received a Demand for Arbitration from NTEC in connection with the Coal Supply Agreement, dated December 30, 2013, under which NTEC supplies coal to APS and the other Four Corners owners (collectively, the “Buyer”) for use at the Four Corners Power Plant (the "2016 Coal Supply Agreement"). NTEC was originally seeking a declaratory judgment to support its interpretation of a provision regarding uncontrollable forces in the agreement that relates to annual minimum quantities of coal to be purchased by the Buyer. NTEC also alleged a shortfall in the Buyer’s purchases for the initial contract year of approximately $30 million . APS’s share of this amount is approximately $17 million . On September 20, 2017, NTEC amended its Demand for Arbitration, removing its request for a declaratory judgment and at such time was only seeking relief for the alleged shortfall in the Buyer's purchases for the initial contract year. On June 29, 2018, the parties settled the dispute for $45 million , which includes settlement for the initial contract year and the current contract year. APS’s share of this amount is approximately $34 million . In connection with the settlement, the parties amended the 2016 Coal Supply Agreement, including modifying the provisions that gave rise to this dispute. (See “4CA Matter” below for additional matters agreed to between 4CA and NTEC in the settlement arrangement.) The arbitration was dismissed on July 9, 2018. Coal Advance Purchase On March 12, 2018, APS paid to NTEC approximately $24 million as an advance payment for APS’s share of coal under the 2016 Coal Supply Agreement. The coal inventory purchased represents an amount that APS expects to use for its plant operations within the next year. 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 within a certain timeframe pursuant to an option granted to NTEC. On December 29, 2015, NTEC provided notice of its intent to exercise the option. The purchase did not occur during the originally contemplated timeframe. Concurrent with the settlement of the 2016 Coal Supply Agreement matter described above, NTEC and 4CA agreed to allow for the purchase by NTEC of the 7% interest, consistent with the option. On June 29, 2018, 4CA and NTEC entered into an asset purchase agreement p |
Other Income and Other Expense
Other Income and Other Expense | 9 Months Ended |
Sep. 30, 2018 | |
Component of Other Income and Other Expense Nonoperating [Line Items] | |
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, 2018 and 2017 (dollars in thousands): Three Months Ended Nine Months Ended 2018 2017 2018 2017 Other income: Interest income $ 1,957 $ 917 $ 6,256 $ 1,782 Debt return on Four Corners SCR deferral (Note 4) 4,910 — 11,190 — Miscellaneous 91 174 95 273 Total other income $ 6,958 $ 1,091 $ 17,541 $ 2,055 Other expense: Non-operating costs $ (2,480 ) $ (1,978 ) $ (7,404 ) $ (7,338 ) Investment losses — net — (231 ) (268 ) (759 ) Miscellaneous (2,583 ) (2,784 ) (4,391 ) (4,398 ) Total other expense $ (5,063 ) $ (4,993 ) $ (12,063 ) $ (12,495 ) |
APS | |
Component of Other Income and Other Expense Nonoperating [Line Items] | |
Other Income and Other Expense | The following table provides detail of APS’s other income and other expense for the three and nine months ended September 30, 2018 and 2017 (dollars in thousands): Three Months Ended Nine Months Ended 2018 2017 2018 2017 Other income: Interest income $ 1,151 $ 683 $ 4,874 $ 1,278 Debt return on Four Corners SCR deferral (Note 4) 4,910 — 11,190 — Miscellaneous 92 55 96 154 Total other income $ 6,153 $ 738 $ 16,160 $ 1,432 Other expense: Non-operating costs $ (2,334 ) $ (1,734 ) $ (6,931 ) $ (6,625 ) Miscellaneous (1,027 ) (444 ) (2,748 ) (1,983 ) Total other expense $ (3,361 ) $ (2,178 ) $ (9,679 ) $ (8,608 ) |
Earnings Per Share
Earnings Per Share | 9 Months Ended |
Sep. 30, 2018 | |
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, 2018 and 2017 (in thousands, except per share amounts): Three Months Ended Nine Months Ended 2018 2017 2018 2017 Net income attributable to common shareholders $ 315,012 $ 276,072 $ 484,971 $ 466,827 Weighted average common shares outstanding — basic 112,148 111,835 112,094 111,787 Net effect of dilutive securities: Contingently issuable performance shares and restricted stock units 385 566 405 527 Weighted average common shares outstanding — diluted 112,533 112,401 112,499 112,314 Earnings per weighted-average common share outstanding Net income attributable to common shareholders — basic $ 2.81 $ 2.47 $ 4.33 $ 4.18 Net income attributable to common shareholders — diluted $ 2.80 $ 2.46 $ 4.31 $ 4.16 |
Fair Value Measurements
Fair Value Measurements | 9 Months Ended |
Sep. 30, 2018 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements | Fair Value Measurements We classify our assets and liabilities that are carried at fair value within the fair value hierarchy. This hierarchy ranks the quality and reliability of the inputs used to determine fair values, which are then classified and disclosed in one of three categories. The three levels of the fair value hierarchy are: Level 1 — Unadjusted quoted prices in active markets for identical assets or liabilities. Level 2 — Other significant observable inputs, including quoted prices in active markets for similar assets or liabilities; quoted prices in markets that are not active, and model-derived valuations whose inputs are observable (such as yield curves). Level 3 — Valuation models with significant unobservable inputs that are supported by little or no market activity. Instruments in this category include long-dated derivative transactions where valuations are unobservable due to the length of the transaction, options, and transactions in locations where observable market data does not exist. The valuation models we employ utilize spot prices, forward prices, historical market data and other factors to forecast future prices. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Thus, a valuation may be classified in Level 3 even though the valuation may include significant inputs that are readily observable. We maximize the use of observable inputs and minimize the use of unobservable inputs. We rely primarily on the market approach of using prices and other market information for identical and/or comparable assets and liabilities. If market data is not readily available, inputs may reflect our own assumptions about the inputs market participants would use. Our assessment of the inputs and the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities as well as their placement within the fair value hierarchy levels. We assess whether a market is active by obtaining observable broker quotes, reviewing actual market activity, and assessing the volume of transactions. We consider broker quotes observable inputs when the quote is binding on the broker, we can validate the quote with market activity, or we can determine that the inputs the broker used to arrive at the quoted price are observable. Certain instruments have been valued using the concept of Net Asset Value ("NAV"), as a practical expedient. These instruments are typically structured as investment companies offering shares or units to multiple investors for the purpose of providing a return. These instruments are similar to mutual funds; however, their NAV is generally not published and publicly available, nor are these instruments traded on an exchange. Instruments valued using NAV, as a practical expedient are included in our fair value disclosures however, in accordance with GAAP are not classified within the fair value hierarchy levels. Recurring Fair Value Measurements We apply recurring fair value measurements to cash equivalents, derivative instruments, and investments held in the nuclear decommissioning trust and other special use funds. On an annual basis we apply fair value measurements to plan assets held in our retirement and other benefit plans. See Note 7 in the 2017 Form 10-K for fair value discussion of plan assets held in our retirement and other benefit plans. Cash Equivalents Cash equivalents represent certain investments in money market funds that are valued using quoted prices in active markets. Risk Management Activities — Derivative Instruments Exchange traded commodity contracts are valued using unadjusted quoted prices. For non-exchange traded commodity contracts, we calculate fair value based on the average of the bid and offer price, discounted to reflect net present value. We maintain certain valuation adjustments for a number of risks associated with the valuation of future commitments. These include valuation adjustments for liquidity and credit risks. The liquidity valuation adjustment represents the cost that would be incurred if all unmatched positions were closed out or hedged. The credit valuation adjustment represents estimated credit losses on our net exposure to counterparties, taking into account netting agreements, expected default experience for the credit rating of the counterparties and the overall diversification of the portfolio. We maintain credit policies that management believes minimize overall credit risk. Certain non-exchange traded commodity contracts are valued based on unobservable inputs due to the long-term nature of contracts, characteristics of the product, or the unique location of the transactions. Our long-dated energy transactions consist of observable valuations for the near-term portion and unobservable valuations for the long-term portions of the transaction. We rely primarily on broker quotes to value these instruments. When our valuations utilize broker quotes, we perform various control procedures to ensure the quote has been developed consistent with fair value accounting guidance. These controls include assessing the quote for reasonableness by comparison against other broker quotes, reviewing historical price relationships, and assessing market activity. When broker quotes are not available, the primary valuation technique used to calculate the fair value is the extrapolation of forward pricing curves using observable market data for more liquid delivery points in the same region and actual transactions at more illiquid delivery points. When the unobservable portion is significant to the overall valuation of the transaction, the entire transaction is classified as Level 3. Our classification of instruments as Level 3 is primarily reflective of the long-term nature of our energy transactions. Our energy risk management committee, consisting of officers and key management personnel, oversees our energy risk management activities to ensure compliance with our stated energy risk management policies. We have a risk control function that is responsible for valuing our derivative commodity instruments in accordance with established policies and procedures. The risk control function reports to the chief financial officer’s organization. Investments Held in Nuclear Decommissioning Trust and Other Special Use Funds The nuclear decommissioning trust and other special use funds invest in fixed income and equity securities. Other special use funds include the coal reclamation escrow account and the active union medical trust. 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, 2018 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands): Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (a) (Level 3) Other Balance at September 30, 2018 Assets Cash equivalents $ 5,600 $ — $ — $ — $ 5,600 Risk management activities — derivative instruments: Commodity contracts — 2,865 58 (1,699 ) (b) 1,224 Nuclear decommissioning trust: Equity securities 6,213 — — (625 ) (c) 5,588 U.S. commingled equity funds — — — 459,790 (d) 459,790 U.S. Treasury debt 134,462 — — — 134,462 Corporate debt — 104,953 — — 104,953 Mortgage-backed debt securities — 112,036 — — 112,036 Municipal bonds — 80,787 — — 80,787 Other fixed income — 9,071 — — 9,071 Subtotal nuclear decommissioning trust 140,675 306,847 — 459,165 906,687 Other special use funds: Equity securities 12,033 — — 1,722 (c) 13,755 U.S. Treasury debt 199,094 — — — 199,094 Municipal bonds — 20,891 — — 20,891 Subtotal other special use funds 211,127 20,891 — 1,722 233,740 Total Assets $ 357,402 $ 330,603 $ 58 $ 459,188 $ 1,147,251 Liabilities Risk management activities — derivative instruments: Commodity contracts $ — $ (69,857 ) $ (9,921 ) $ 48 (b) $ (79,730 ) (a) Primarily consists of long-dated electricity contracts. (b) Represents counterparty netting, margin and collateral. See Note 7 . (c) Represents net pending securities sales and purchases. (d) 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, 2017 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands): Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (a) (Level 3) Other Balance at December 31, 2017 Assets Cash equivalents $ 10,630 $ — $ — $ — $ 10,630 Risk management activities — derivative instruments: Commodity contracts — 5,683 1,036 (4,737 ) (b) 1,982 Nuclear decommissioning trust: Cash and cash equivalents 7,224 — — 109 (d) 7,333 U.S. commingled equity funds — — — 417,390 (e) 417,390 U.S. Treasury debt 127,662 — — — 127,662 Corporate debt — 114,007 — — 114,007 Mortgage-backed debt securities — 111,874 — — 111,874 Municipal bonds — 79,049 — — 79,049 Other fixed income — 13,685 — — 13,685 Subtotal nuclear decommissioning trust 134,886 318,615 — 417,499 871,000 Other special use funds (c): 455 31,562 — 525 32,542 Total Assets $ 145,971 $ 355,860 $ 1,036 $ 413,287 $ 916,154 Liabilities Risk management activities — derivative instruments: Commodity contracts $ — $ (78,646 ) $ (19,292 ) $ 1,516 (b) $ (96,422 ) (a) Primarily consists of long-dated electricity contracts. (b) Represents counterparty netting, margin, and collateral. See Note 7. (c) Primarily consists of fixed income municipal bonds. Presented as coal reclamation escrow in 2017. (d) Represents nuclear decommissioning trust net pending securities sales and purchases. (e) 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, 2018 and December 31, 2017 : September 30, 2018 Valuation Technique Significant Unobservable Input Weighted-Average Commodity Contracts Assets Liabilities Range Natural Gas: Forward Contracts (a) $ 58 $ 9,921 Discounted cash flows Natural gas forward price (per MMBtu) $1.75 - $2.74 $ 2.23 Total $ 58 $ 9,921 (a) Includes swaps and physical and financial contracts. December 31, 2017 Valuation Technique Significant Unobservable Input Weighted-Average Commodity Contracts Assets Liabilities Range Electricity: Forward Contracts (a) $ 21 $ 15,485 Discounted cash flows Electricity forward price (per MWh) $18.51 - $38.75 $ 27.89 Natural Gas: Forward Contracts (a) 1,015 3,807 Discounted cash flows Natural gas forward price (per MMBtu) $2.33 - $3.11 $ 2.71 Total $ 1,036 $ 19,292 (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, 2018 and 2017 (dollars in thousands): Three Months Ended Nine Months Ended Commodity Contracts 2018 2017 2018 2017 Net derivative balance at beginning of period $ (9,358 ) $ (36,245 ) $ (18,256 ) $ (47,406 ) Total net gains (losses) realized/unrealized: Included in OCI — (4 ) — (10 ) Deferred as a regulatory asset or liability 1,244 (3,769 ) (2,067 ) (11,272 ) Settlements (2,332 ) 1,733 (1,056 ) 4,855 Transfers into Level 3 from Level 2 (2,246 ) (5,952 ) (7,225 ) (10,340 ) Transfers from Level 3 into Level 2 2,829 5,632 18,741 25,568 Net derivative balance at end of period $ (9,863 ) $ (38,605 ) $ (9,863 ) $ (38,605 ) 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 $65 million |
Investments in Nuclear Decommis
Investments in Nuclear Decommissioning Trusts and Other Special Use Funds | 9 Months Ended |
Sep. 30, 2018 | |
Investments, Debt and Equity Securities [Abstract] | |
Investments in Nuclear Decommissioning Trusts and Other Special Use Funds | Investments in Nuclear Decommissioning Trusts and Other Special Use Funds We have investments in debt and equity securities held in Nuclear Decommissioning Trusts, Coal Reclamation Escrow Accounts, 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 Trusts - To fund the future costs APS expects to incur to decommission Palo Verde, APS established external decommissioning trusts 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 trusts. 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 Accounts - 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 2017 Form 10-K). These investments may be used to pay active union employee medical costs incurred in the current period and in future periods. The account is invested primarily in fixed income securities. In accordance with the ratemaking treatment, APS has deferred the unrealized gains and losses (including other-than-temporary impairments) in other regulatory assets. Activities relating to active union employee medical account investments are included within the other special use funds in the table below. APS The following tables present the unrealized gains and losses based on the original cost of the investment and summarizes the fair value of APS's nuclear decommissioning trust and other special use fund assets at September 30, 2018 and December 31, 2017 (dollars in thousands): September 30, 2018 Fair Value Total Unrealized Gains Total Unrealized Losses Investment Type: Nuclear Decommissioning Trusts Other Special Use Funds Total Equity securities $ 466,002 $ 12,033 $ 478,035 $ 286,121 $ (47 ) Available for sale-fixed income securities 441,309 219,985 661,294 (a) 5,631 (11,423 ) Other (624 ) 1,722 1,098 (b) — — Total $ 906,687 $ 233,740 $ 1,140,427 $ 291,752 $ (11,470 ) (a) As of September 30, 2018 , the amortized cost basis of these available-for-sale investments is $667 million . (b) Represents net pending securities sales and purchases. December 31, 2017 Fair Value Total Unrealized Gains Total Unrealized Losses Investment Type: Nuclear Decommissioning Trusts Other Special Use Funds Total Equity securities $ 424,614 $ 430 $ 425,044 $ 248,623 $ — Available for sale-fixed income securities 446,277 29,439 475,716 (a) 11,537 (2,996 ) Other 109 489 598 (b) — — Total $ 871,000 $ 30,358 $ 901,358 $ 260,160 $ (2,996 ) (a) As of December 31, 2017, the amortized cost basis of these available-for-sale investments is $467 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, 2018 and September 30, 2017 (dollars in thousands): Three Months Ended Three Months Ended Nuclear Decommissioning Trusts Other Special Use Funds Total Nuclear Decommissioning Trusts Other Special Use Funds Total Realized gains $ 653 $ — $ 653 $ 598 $ — $ 598 Realized losses (1,965 ) — (1,965 ) (1,022 ) — (1,022 ) Proceeds from the sale of securities (a) 148,150 25,127 173,277 76,496 — 76,496 (a) Proceeds are reinvested in the nuclear decommissioning trusts or other special use funds. Nine Months Ended Nine Months Ended Nuclear Decommissioning Trusts Other Special Use Funds Total Nuclear Decommissioning Trusts Other Special Use Funds Total Realized gains $ 2,951 $ 1 $ 2,952 $ 3,904 $ 17 $ 3,921 Realized losses (6,990 ) — (6,990 ) (4,634 ) (9 ) (4,643 ) Proceeds from the sale of securities (a) 401,396 41,644 443,040 351,860 4,093 355,953 (a) Proceeds are reinvested in the nuclear decommissioning trusts or other special use funds. The fair value of APS's fixed income securities, summarized by contractual maturities, at September 30, 2018 , is as follows (dollars in thousands): Nuclear Decommissioning Trusts (a) Coal Reclamation Escrow Accounts Active Union Medical Trust Total Less than one year $ 19,917 $ 17,244 $ 30,593 $ 67,754 1 year – 5 years 98,235 17,170 142,598 258,003 5 years – 10 years 126,279 2,529 — 128,808 Greater than 10 years 196,878 9,851 — 206,729 Total $ 441,309 $ 46,794 $ 173,191 $ 661,294 (a) |
New Accounting Standards
New Accounting Standards | 9 Months Ended |
Sep. 30, 2018 | |
New Accounting Pronouncements and Changes in Accounting Principles [Abstract] | |
New Accounting Standards | New Accounting Standards Standards Adopted during 2018 ASU 2014-09, Revenue from Contracts with Customers In May 2014, a new revenue recognition accounting standard was issued. This standard provides a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most prior revenue recognition guidance. Since the issuance of the new revenue standard, additional guidance was issued to clarify certain aspects of the new revenue standard, including principal versus agent considerations, identifying performance obligations, and other narrow scope improvements. The new revenue standard, and related amendments, were effective for us on January 1, 2018. The standard may be adopted using a full retrospective application or a simplified transition method that allows entities to record a cumulative effect adjustment in retained earnings at the date of initial application. We adopted this standard, and related amendments, on January 1, 2018, using the modified retrospective transition approach. The adoption of the new revenue guidance resulted in expanded disclosures, but otherwise did not have a material impact on our financial statements. See Note 2. ASU 2016-01, Financial Instruments: Recognition and Measurement In January 2016, a new accounting standard was issued relating to the recognition and measurement of financial instruments. The new guidance requires certain investments in equity securities to be measured at fair value with changes in fair value recognized in net income, and modifies the impairment assessment of certain equity securities. The new standard was effective for us on January 1, 2018. The standard required modified retrospective application, with the exception of certain aspects of the standard that required prospective application. We adopted this standard on January 1, 2018, using primarily a retrospective approach. Due to regulatory accounting treatment, the adoption of this standard did not have a material impact on our financial statements. See Notes 11 and 12 for disclosures relating to our investments in debt and equity securities. ASU 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments In August 2016, a new accounting standard was issued that clarifies how entities should present certain specific cash flow activities on the statement of cash flows. The guidance is intended to eliminate diversity in practice in how entities classify these specific activities between cash flows from operating activities, investing activities and financing activities. The specific activities addressed include debt prepayments and extinguishment costs, proceeds from the settlement of insurance claims, proceeds from corporate owned life insurance policies, and other activities. The standard also addresses how entities should apply the predominance principle when a transaction includes separately identifiable cash flows. The new standard was effective for us, and was adopted on January 1, 2018, using a retrospective transition method. The adoption of this guidance did not have a significant impact on our financial statements, as either our statement of cash flow presentation is consistent with the new prescribed guidance or we do not have significant activities relating to the specific transactions that are addressed by the new standard. ASU 2016-18, Statement of Cash Flows: Restricted Cash In November 2016, a new accounting standard was issued that clarifies how restricted cash and restricted cash equivalents should be presented on the statement of cash flows. The new guidance requires entities to include restricted cash and restricted cash equivalents as a component of the beginning and ending cash and cash equivalent balances on the statement of cash flows. The new standard is effective for us, and was adopted on January 1, 2018, using a retrospective transition method. The adoption of this guidance did not impact our financial statements, as our holdings and activities designated as restricted cash and restricted cash equivalents at transition and in prior periods are insignificant. ASU 2017-01, Business Combinations: Clarifying the Definition of a Business In January 2017, a new accounting standard was issued that clarifies the definition of a business. This standard is intended to assist entities with evaluating whether a transaction should be accounted for as an acquisition (or disposal) of assets or a business. The definition of a business affects many areas of accounting including acquisitions, disposals, goodwill, and consolidation. The new standard was effective for us, and was adopted on January 1, 2018, using a prospective transition approach. This standard did not have an impact on our financial statements on the date of adoption. ASU 2017-05, Other Income: Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets In February 2017, a new accounting standard was issued that intended to clarify the scope of accounting guidance pertaining to gains and losses from the derecognition of nonfinancial assets, and to add guidance for partial sales of nonfinancial assets. The new standard was effective for us, and was adopted on January 1, 2018, using a modified retrospective transition approach. This standard did not have a significant impact on our financial statements on the date of adoption. On July 3, 2018, 4CA sold its 7% interest in Four Corners. The sale transaction was accounted for in accordance with the guidance in ASU 2017-05, see Note 8. ASU 2017-07, Compensation-Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost In March 2017, a new accounting standard was issued that modifies how plan sponsors present net periodic pension cost and net periodic postretirement benefit cost (net benefit costs). The presentation changes require net benefit costs to be disaggregated on the income statement by the various components that comprise these costs. Specifically, only the service cost component is eligible for presentation as an operating income item, and all other cost components are now presented as non-operating items. This presentation change must be applied retrospectively. Furthermore, the new standard only allows the service cost component to be eligible for capitalization. The change in capitalization requirements must be applied prospectively. The new guidance was effective for us on January 1, 2018. We adopted this new accounting standard on January 1, 2018. As a result of adopting this standard we have presented the non-service cost components of net benefits costs in other income instead of operating income. Prior year non-service cost components have also been reclassified to conform to this new presentation. We elected to apply the practical expedient guidance. As such, prior period costs have been estimated based on amounts previously disclosed in our pension and other postretirement benefit plan notes. The changes impacting capitalization have been adopted prospectively. As such, upon adoption, we are no longer capitalizing a portion of the non-service cost components of net benefit costs. In 2018, because the non-service cost components are a reduction to total benefit costs, we estimate this change will result in the capitalization of an additional $15 million of net benefit costs, with a corresponding increase to pretax income for the year. For the three and nine months ended September 30, 2018 , this change increased pre-tax income by approximately $4 million and $11 million respectively. See Note 5. ASU 2018-02, Income Statement-Reporting Comprehensive Income: Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income In February 2018, new accounting guidance was issued that allows entities an optional election to reclassify the income tax effects of the Tax Act on items within accumulated other comprehensive income to retained earnings. Amounts eligible for reclassification must relate to the effects from the Tax Act remaining in accumulated other comprehensive income. The new guidance also requires expanded disclosures. This guidance is effective for us on January 1, 2019 with early application permitted. The guidance should be applied either in the period of adoption or retrospectively to each period in which the effect of the Tax Act was recognized. We early adopted this guidance in the quarter ended March 31, 2018, and we have elected to reclassify the income tax effects of the Tax Act related to other comprehensive income activities to retained earnings. As of September 30, 2018 , on a consolidated basis our accumulated other comprehensive income decreased $9 million , and APS’s accumulated other comprehensive income decreased $5 million , as a result of adopting this guidance. Amounts were reclassified from accumulated other comprehensive income to retained earnings, and related to tax rate changes. The adoption of this guidance did not impact our income from continuing operations. See Note 15. Standards Pending Adoption 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 will require a lessee to reflect most operating lease arrangements on the balance sheets by recording a right-of-use asset and a lease liability that will initially be 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 will be 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 plan on adopting this standard, and related amendments, on January 1, 2019. We plan to elect the transition method that allows us to apply the guidance on the date of adoption and will not retrospectively adjust prior periods. We also plan on electing certain transition practical expedients that would 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 will apply to leases that commenced prior to January 1, 2019. Furthermore, we plan to elect the practical expedient transition provisions relating to the treatment of existing land easements. Our evaluation of this new accounting standard and the impacts it will have on our financial statements is on-going. The adoption of the new standard will result in the recognition of certain operating lease arrangements on our Consolidated Balance Sheets. We are currently evaluating the significance of the balance sheet impacts, and the impacts, if any, the lease guidance will have on our other financial statements. Our evaluation includes assessing leasing activities, implementing new processes and procedures, and preparing the expanded lease disclosures. ASU 2016-13, Financial Instruments: Measurement of Credit Losses In June 2016, a new accounting standard was issued that amends the measurement of credit losses on certain financial instruments. The new standard will require entities to use a current expected credit loss model to measure impairment of certain investments in debt securities, trade accounts receivables, and other financial instruments. The new standard is effective for us on January 1, 2020 and must be adopted using a modified retrospective approach for certain aspects of the standard, and a prospective approach for other aspects of the standard. We are currently evaluating this new accounting standard and the impacts it may have on our financial statements. ASU 2017-12, Derivatives and Hedging: Targeted Improvements to Accounting for Hedging Activities In August 2017, a new accounting standard was issued that modifies hedge accounting guidance with the intent of simplifying the application of hedge accounting. The new standard is effective for us on January 1, 2019, with early application permitted. At transition the guidance requires the changes to be applied to hedging relationships existing on the date of adoption, with the effect of adoption reflected as of the beginning of the fiscal year of adoption using a cumulative effect adjustment approach. The presentation and disclosure changes may be applied prospectively. We are currently evaluating the new guidance, but at this time we d o not expect the adoption of this guidance will have a significant impact on our financial statements, as we are currently not applying hedge accounting. ASU 2018-15, Internal-Use Software: Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract |
Changes in Accumulated Other Co
Changes in Accumulated Other Comprehensive Loss | 9 Months Ended |
Sep. 30, 2018 | |
Accumulated Other Comprehensive Income (Loss) [Line Items] | |
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, 2018 and 2017 (dollars in thousands): Pension and Other Postretirement Benefits Derivative Instruments Total Three Months Ended September 30 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 ) Balance June 30, 2017 $ (39,881 ) $ (3,745 ) $ (43,626 ) OCI (loss) before reclassifications — 9 9 Amounts reclassified from accumulated other comprehensive loss 790 (a) 710 (b) 1,500 Balance September 30, 2017 $ (39,091 ) $ (3,026 ) $ (42,117 ) Pension and Other Postretirement Benefits Derivative Instruments Total Nine Months Ended September 30 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 ) (598 ) (8,552 ) Balance September 30, 2018 $ (53,134 ) $ (1,940 ) $ (55,074 ) Balance December 31, 2016 $ (39,070 ) $ (4,752 ) $ (43,822 ) OCI (loss) before reclassifications (2,157 ) (754 ) (2,911 ) Amounts reclassified from accumulated other comprehensive loss 2,136 (a) 2,480 (b) 4,616 Balance September 30, 2017 $ (39,091 ) $ (3,026 ) $ (42,117 ) (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 |
APS | |
Accumulated Other Comprehensive Income (Loss) [Line Items] | |
Changes in Accumulated Other Comprehensive Loss | 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, 2018 and 2017 (dollars in thousands): Pension and Other Postretirement Benefits Derivative Instruments Total Three Months Ended September 30 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 ) Balance June 30, 2017 $ (21,367 ) $ (3,745 ) $ (25,112 ) OCI (loss) before reclassifications — 9 9 Amounts reclassified from accumulated other comprehensive loss 777 (a) 710 (b) 1,487 Balance September 30, 2017 $ (20,590 ) $ (3,026 ) $ (23,616 ) Pension and Other Postretirement Benefits Derivative Instruments Total Nine Months Ended September 30 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 ) (598 ) (5,038 ) Balance September 30, 2018 $ (31,816 ) $ (1,940 ) $ (33,756 ) Balance December 31, 2016 $ (20,671 ) $ (4,752 ) $ (25,423 ) OCI (loss) before reclassifications (2,121 ) (754 ) (2,875 ) Amounts reclassified from accumulated other comprehensive loss 2,202 (a) 2,480 (b) 4,682 Balance September 30, 2017 $ (20,590 ) $ (3,026 ) $ (23,616 ) (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 |
Income Taxes
Income Taxes | 9 Months Ended |
Sep. 30, 2018 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | Income Taxes On December 22, 2017, the Tax Act was enacted. This legislation made significant changes to the federal income tax laws, including a reduction in the corporate tax rate to 21% effective January 1, 2018. As a result of this rate reduction, the Company recognized a $1.14 billion reduction in its net deferred income tax liabilities as of December 31, 2017. In accordance with accounting for regulated companies, the effect of this rate reduction is substantially offset by a net regulatory liability. As of December 31, 2017, to reflect the $1.14 billion reduction in its net deferred income tax liabilities caused by the rate reduction, APS has recorded a net regulatory liability of $1.52 billion and a new $377 million net deferred tax asset. The Company will amortize the net regulatory liability in accordance with applicable federal income tax laws, which require the amortization of a majority of the balance over the remaining regulatory life of the related property. As a result of the modifications made to the annual transmission formula rate during the second quarter, the Company has recorded amortization of FERC jurisdictional net excess deferred tax liabilities, retroactive to January 1, 2018. The Company continues to work with the ACC on a plan to amortize the remaining net excess deferred tax liabilities subject to its jurisdiction. See Note 4 for more details. Several sections of the Tax Act contain technical ambiguities. Management has recognized tax positions which it believes are more likely than not to be sustained upon examination based upon its interpretation of this legislation. In August 2018, Treasury proposed regulations that would clarify bonus depreciation rules under the Tax Act for property placed in service after September 27, 2017. During the third quarter the Company recorded deferred tax liabilities of approximately $11 million and an increase in its net regulatory liability for excess deferred taxes of approximately $9 million , primarily related to bonus depreciation benefits claimed on the Company’s 2017 tax return as a result of this clarifying guidance. Additional clarifying guidance may be issued through additional legislation, Treasury regulations, or other technical guidance, which may impact the income tax effects of the Tax Act as recorded by the Company. As of September 30, 2018, the Company does not have a reasonable estimate of what the income tax effects of additional clarifying guidance may be. For the quarter ending March 31, 2018, the Company early adopted ASU 2018-02, Income Statement-Reporting Comprehensive Income: Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income and elected to reclassify the income tax effects of the Tax Act on items within accumulated other comprehensive income to retained earnings. See Note 13 for additional information. Net income associated with the Palo Verde sale leaseback VIEs is not subject to tax (see Note 6). As a result, there is no income tax expense associated with the VIEs recorded on the Pinnacle West Condensed Consolidated and APS Condensed Consolidated Statements of Income. |
New Accounting Standards (Polic
New Accounting Standards (Policies) | 9 Months Ended |
Sep. 30, 2018 | |
New Accounting Pronouncements and Changes in Accounting Principles [Abstract] | |
New Accounting Standards | Standards Adopted during 2018 ASU 2014-09, Revenue from Contracts with Customers In May 2014, a new revenue recognition accounting standard was issued. This standard provides a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most prior revenue recognition guidance. Since the issuance of the new revenue standard, additional guidance was issued to clarify certain aspects of the new revenue standard, including principal versus agent considerations, identifying performance obligations, and other narrow scope improvements. The new revenue standard, and related amendments, were effective for us on January 1, 2018. The standard may be adopted using a full retrospective application or a simplified transition method that allows entities to record a cumulative effect adjustment in retained earnings at the date of initial application. We adopted this standard, and related amendments, on January 1, 2018, using the modified retrospective transition approach. The adoption of the new revenue guidance resulted in expanded disclosures, but otherwise did not have a material impact on our financial statements. See Note 2. ASU 2016-01, Financial Instruments: Recognition and Measurement In January 2016, a new accounting standard was issued relating to the recognition and measurement of financial instruments. The new guidance requires certain investments in equity securities to be measured at fair value with changes in fair value recognized in net income, and modifies the impairment assessment of certain equity securities. The new standard was effective for us on January 1, 2018. The standard required modified retrospective application, with the exception of certain aspects of the standard that required prospective application. We adopted this standard on January 1, 2018, using primarily a retrospective approach. Due to regulatory accounting treatment, the adoption of this standard did not have a material impact on our financial statements. See Notes 11 and 12 for disclosures relating to our investments in debt and equity securities. ASU 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments In August 2016, a new accounting standard was issued that clarifies how entities should present certain specific cash flow activities on the statement of cash flows. The guidance is intended to eliminate diversity in practice in how entities classify these specific activities between cash flows from operating activities, investing activities and financing activities. The specific activities addressed include debt prepayments and extinguishment costs, proceeds from the settlement of insurance claims, proceeds from corporate owned life insurance policies, and other activities. The standard also addresses how entities should apply the predominance principle when a transaction includes separately identifiable cash flows. The new standard was effective for us, and was adopted on January 1, 2018, using a retrospective transition method. The adoption of this guidance did not have a significant impact on our financial statements, as either our statement of cash flow presentation is consistent with the new prescribed guidance or we do not have significant activities relating to the specific transactions that are addressed by the new standard. ASU 2016-18, Statement of Cash Flows: Restricted Cash In November 2016, a new accounting standard was issued that clarifies how restricted cash and restricted cash equivalents should be presented on the statement of cash flows. The new guidance requires entities to include restricted cash and restricted cash equivalents as a component of the beginning and ending cash and cash equivalent balances on the statement of cash flows. The new standard is effective for us, and was adopted on January 1, 2018, using a retrospective transition method. The adoption of this guidance did not impact our financial statements, as our holdings and activities designated as restricted cash and restricted cash equivalents at transition and in prior periods are insignificant. ASU 2017-01, Business Combinations: Clarifying the Definition of a Business In January 2017, a new accounting standard was issued that clarifies the definition of a business. This standard is intended to assist entities with evaluating whether a transaction should be accounted for as an acquisition (or disposal) of assets or a business. The definition of a business affects many areas of accounting including acquisitions, disposals, goodwill, and consolidation. The new standard was effective for us, and was adopted on January 1, 2018, using a prospective transition approach. This standard did not have an impact on our financial statements on the date of adoption. ASU 2017-05, Other Income: Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets In February 2017, a new accounting standard was issued that intended to clarify the scope of accounting guidance pertaining to gains and losses from the derecognition of nonfinancial assets, and to add guidance for partial sales of nonfinancial assets. The new standard was effective for us, and was adopted on January 1, 2018, using a modified retrospective transition approach. This standard did not have a significant impact on our financial statements on the date of adoption. On July 3, 2018, 4CA sold its 7% interest in Four Corners. The sale transaction was accounted for in accordance with the guidance in ASU 2017-05, see Note 8. ASU 2017-07, Compensation-Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost In March 2017, a new accounting standard was issued that modifies how plan sponsors present net periodic pension cost and net periodic postretirement benefit cost (net benefit costs). The presentation changes require net benefit costs to be disaggregated on the income statement by the various components that comprise these costs. Specifically, only the service cost component is eligible for presentation as an operating income item, and all other cost components are now presented as non-operating items. This presentation change must be applied retrospectively. Furthermore, the new standard only allows the service cost component to be eligible for capitalization. The change in capitalization requirements must be applied prospectively. The new guidance was effective for us on January 1, 2018. We adopted this new accounting standard on January 1, 2018. As a result of adopting this standard we have presented the non-service cost components of net benefits costs in other income instead of operating income. Prior year non-service cost components have also been reclassified to conform to this new presentation. We elected to apply the practical expedient guidance. As such, prior period costs have been estimated based on amounts previously disclosed in our pension and other postretirement benefit plan notes. The changes impacting capitalization have been adopted prospectively. As such, upon adoption, we are no longer capitalizing a portion of the non-service cost components of net benefit costs. In 2018, because the non-service cost components are a reduction to total benefit costs, we estimate this change will result in the capitalization of an additional $15 million of net benefit costs, with a corresponding increase to pretax income for the year. For the three and nine months ended September 30, 2018 , this change increased pre-tax income by approximately $4 million and $11 million respectively. See Note 5. ASU 2018-02, Income Statement-Reporting Comprehensive Income: Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income In February 2018, new accounting guidance was issued that allows entities an optional election to reclassify the income tax effects of the Tax Act on items within accumulated other comprehensive income to retained earnings. Amounts eligible for reclassification must relate to the effects from the Tax Act remaining in accumulated other comprehensive income. The new guidance also requires expanded disclosures. This guidance is effective for us on January 1, 2019 with early application permitted. The guidance should be applied either in the period of adoption or retrospectively to each period in which the effect of the Tax Act was recognized. We early adopted this guidance in the quarter ended March 31, 2018, and we have elected to reclassify the income tax effects of the Tax Act related to other comprehensive income activities to retained earnings. As of September 30, 2018 , on a consolidated basis our accumulated other comprehensive income decreased $9 million , and APS’s accumulated other comprehensive income decreased $5 million , as a result of adopting this guidance. Amounts were reclassified from accumulated other comprehensive income to retained earnings, and related to tax rate changes. The adoption of this guidance did not impact our income from continuing operations. See Note 15. Standards Pending Adoption 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 will require a lessee to reflect most operating lease arrangements on the balance sheets by recording a right-of-use asset and a lease liability that will initially be 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 will be 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 plan on adopting this standard, and related amendments, on January 1, 2019. We plan to elect the transition method that allows us to apply the guidance on the date of adoption and will not retrospectively adjust prior periods. We also plan on electing certain transition practical expedients that would 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 will apply to leases that commenced prior to January 1, 2019. Furthermore, we plan to elect the practical expedient transition provisions relating to the treatment of existing land easements. Our evaluation of this new accounting standard and the impacts it will have on our financial statements is on-going. The adoption of the new standard will result in the recognition of certain operating lease arrangements on our Consolidated Balance Sheets. We are currently evaluating the significance of the balance sheet impacts, and the impacts, if any, the lease guidance will have on our other financial statements. Our evaluation includes assessing leasing activities, implementing new processes and procedures, and preparing the expanded lease disclosures. ASU 2016-13, Financial Instruments: Measurement of Credit Losses In June 2016, a new accounting standard was issued that amends the measurement of credit losses on certain financial instruments. The new standard will require entities to use a current expected credit loss model to measure impairment of certain investments in debt securities, trade accounts receivables, and other financial instruments. The new standard is effective for us on January 1, 2020 and must be adopted using a modified retrospective approach for certain aspects of the standard, and a prospective approach for other aspects of the standard. We are currently evaluating this new accounting standard and the impacts it may have on our financial statements. ASU 2017-12, Derivatives and Hedging: Targeted Improvements to Accounting for Hedging Activities In August 2017, a new accounting standard was issued that modifies hedge accounting guidance with the intent of simplifying the application of hedge accounting. The new standard is effective for us on January 1, 2019, with early application permitted. At transition the guidance requires the changes to be applied to hedging relationships existing on the date of adoption, with the effect of adoption reflected as of the beginning of the fiscal year of adoption using a cumulative effect adjustment approach. The presentation and disclosure changes may be applied prospectively. We are currently evaluating the new guidance, but at this time we d o not expect the adoption of this guidance will have a significant impact on our financial statements, as we are currently not applying hedge accounting. 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, we expect certain cloud computing service arrangement implementation costs will now be subject to capitalization and amortized on a straight-line basis over the cloud computing service arrangement term. The new standard is effective for us on January 1, 2020, with early application permitted, and may be applied using either a retrospective or prospective transition approach. We are currently evaluating the impacts of adopting this new standard and the transition approach we will elect. |
Consolidation and Nature of O_2
Consolidation and Nature of Operations (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
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 2018 2017 Cash paid during the period for: Income taxes, net of refunds $ 10,091 $ 2,185 Interest, net of amounts capitalized 161,875 147,149 Significant non-cash investing and financing activities: Accrued capital expenditures $ 99,405 $ 93,031 Sale of 4CA's 7% interest in Four Corners 68,907 — |
Revenue (Tables)
Revenue (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
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, 2018 2018 Retail residential electric service $ 695,480 $ 1,512,402 Retail non-residential electric service 496,809 1,275,498 Wholesale energy sales 53,501 80,982 Transmission services for others 15,902 46,235 Other sources 6,342 19,754 Total operating revenues $ 1,268,034 $ 2,934,871 |
Long-Term Debt and Liquidity _2
Long-Term Debt and Liquidity Matters (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
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, 2018 As of December 31, 2017 Carrying Amount Fair Value Carrying Amount Fair Value Pinnacle West $ 298,640 $ 292,185 $ 298,421 $ 298,608 APS 4,788,724 4,900,210 4,573,292 5,006,348 Total $ 5,087,364 $ 5,192,395 $ 4,871,713 $ 5,304,956 |
Regulatory Matters (Tables)
Regulatory Matters (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Regulated Operations [Abstract] | |
Schedule of changes in the deferred fuel and purchased power regulatory asset | The following table shows the changes in the deferred fuel and purchased power regulatory asset (liability) for 2018 and 2017 (dollars in thousands): Nine Months Ended 2018 2017 Beginning balance $ 75,637 $ 12,465 Deferred fuel and purchased power costs — current period 82,486 43,348 Amounts refunded/(charged) to customers (92,397 ) 18,153 Ending balance $ 65,726 $ 73,966 |
Schedule of regulatory assets | The detail of regulatory assets is as follows (dollars in thousands): Amortization Through September 30, 2018 December 31, 2017 Current Non-Current Current Non-Current Pension (a) $ — $ 598,031 $ — $ 576,188 Retired power plant costs 2033 28,182 174,257 27,402 188,843 Income taxes — allowance for funds used during construction ("AFUDC") equity 2048 5,882 150,684 3,828 142,852 Deferred fuel and purchased power — mark-to-market (Note 7) 2022 41,062 33,215 52,100 34,845 Deferred fuel and purchased power (b) (d) 2019 65,726 — 75,637 — Four Corners cost deferral 2024 8,077 42,247 8,077 48,305 Income taxes — investment tax credit basis adjustment 2047 1,066 25,239 1,066 26,218 Lost fixed cost recovery (b) 2019 36,125 — 59,844 — Palo Verde VIEs (Note 6) 2046 — 19,860 — 19,395 Deferred compensation 2036 — 37,854 — 36,413 Deferred property taxes 2027 8,569 68,499 8,569 74,926 Loss on reacquired debt 2038 1,637 14,078 1,637 15,305 Tax expense of Medicare subsidy 2024 1,235 6,253 1,236 7,415 TCA balancing account (b) 2019 7,087 — 1,220 — AG-1 deferral 2022 2,654 6,482 2,654 8,472 Mead-Phoenix transmission line CIAC 2050 332 10,127 332 10,376 Coal reclamation 2026 1,546 11,695 1,068 12,396 SCR deferral N/A — 16,319 — 353 Other Various 395 6,453 3,418 — Total regulatory assets (c) $ 209,575 $ 1,221,293 $ 248,088 $ 1,202,302 (a) This asset represents the future recovery of pension benefit obligations through retail rates. If these costs are disallowed by the ACC, this regulatory asset would be charged to OCI and result in lower future revenues. (b) See "Cost Recovery Mechanisms" discussion above. (c) 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." (d) Subject to a carrying charge. |
Schedule of regulatory liabilities | The detail of regulatory liabilities is as follows (dollars in thousands): Amortization Through September 30, 2018 December 31, 2017 Current Non-Current Current Non-Current Excess deferred income taxes - ACC - Tax Cuts and Jobs Act (a) $ — $ 1,273,153 $ — $ 1,266,104 Excess deferred income taxes - FERC - Tax Cuts and Jobs Act 2058 6,284 243,369 — 254,170 Asset retirement obligations 2057 — 344,402 — 332,171 Removal costs (b) 30,871 196,065 18,238 209,191 Other postretirement benefits (d) 37,842 123,683 37,642 151,985 Income taxes — deferred investment tax credit 2047 2,137 50,555 2,164 52,497 Income taxes — change in rates 2047 2,799 71,137 2,573 70,537 Spent nuclear fuel 2027 7,769 57,400 6,924 62,132 Renewable energy standard (c) 2019 41,912 92 23,155 — Demand side management (c) 2019 16,099 4,124 3,066 4,921 Sundance maintenance 2030 — 18,104 — 16,897 Deferred gains on utility property 2022 4,423 7,704 4,423 10,988 Four Corners coal reclamation 2038 1,858 17,972 1,858 18,921 Tax expense adjustor mechanism (c) 2018 7,433 — — — Other Various 361 2,837 43 2,022 Total regulatory liabilities $ 159,788 $ 2,410,597 $ 100,086 $ 2,452,536 (a) While the majority of the excess deferred tax balance shown is subject to special amortization rules under federal income tax laws, which require amortization of the balance over the remaining regulatory life of the related property, treatment of a portion of the liability, and the month in which pass-through of the excess deferred tax balance will begin is subject to regulatory approval. This approval will be sought through the Company's TEAM adjustor mechanism. As a result, the Company cannot estimate the amount of this regulatory liability which is expected to reverse within the next 12 months. See Note 15. (b) In accordance with regulatory accounting guidance, APS accrues for removal costs for its regulated assets, even if there is no legal obligation for removal. (c) See “Cost Recovery Mechanisms” discussion above. (d) |
Retirement Plans and Other Po_2
Retirement Plans and Other Postretirement Benefits (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
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 2018 2017 2018 2017 2018 2017 2018 2017 Service cost — benefits earned during the period $ 14,167 $ 13,715 $ 42,501 $ 41,144 $ 5,275 $ 4,280 $ 15,825 $ 12,839 Non-service costs (credits): Interest cost on benefit obligation 31,172 32,439 93,517 97,316 7,037 7,490 21,111 22,470 Expected return on plan assets (45,713 ) (43,568 ) (137,140 ) (130,703 ) (10,520 ) (13,350 ) (31,561 ) (40,051 ) Amortization of: Prior service cost (credit) — 20 — 61 (9,461 ) (9,461 ) (28,382 ) (28,382 ) Net actuarial loss 8,021 11,975 24,062 35,924 — 1,279 — 3,838 Net periodic benefit cost (credit) $ 7,647 $ 14,581 $ 22,940 $ 43,742 $ (7,669 ) $ (9,762 ) $ (23,007 ) $ (29,286 ) Portion of cost (credit) charged to expense $ 2,524 $ 7,231 $ 7,535 $ 21,692 $ (5,359 ) $ (4,841 ) $ (16,083 ) $ (14,523 ) |
Palo Verde Sale Leaseback Var_2
Palo Verde Sale Leaseback Variable Interest Entities (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Variable Interest Entities [Abstract] | |
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets | Our Condensed Consolidated Balance Sheets at September 30, 2018 and December 31, 2017 include the following amounts relating to the VIEs (dollars in thousands): September 30, 2018 December 31, 2017 Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation $ 106,743 $ 109,645 Equity — Noncontrolling interests 132,289 129,040 |
Derivative Accounting (Tables)
Derivative Accounting (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
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, 2018 and December 31, 2017 , 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, 2018 December 31, 2017 Power GWh 287 583 Gas Billion cubic feet 192 240 |
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, 2018 and 2017 (dollars in thousands): Financial Statement Location Three Months Ended Nine Months Ended Commodity Contracts 2018 2017 2018 2017 Gain (Loss) Recognized in OCI on Derivative Instruments (Effective Portion) OCI — derivative instruments $ — $ 14 $ — $ (70 ) Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a) Fuel and purchased power (b) (600 ) (1,148 ) (1,697 ) (2,910 ) (a) During the three and nine months ended September 30, 2018 and 2017 , we had no gains or losses reclassified from accumulated OCI to earnings due to the discontinuance of cash flow hedges where the forecasted transaction is not probable of occurring. (b) |
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, 2018 and 2017 (dollars in thousands): Financial Statement Location Three Months Ended Nine Months Ended Commodity Contracts 2018 2017 2018 2017 Net Loss Recognized in Income Operating revenues $ (1,029 ) $ (128 ) $ (2,590 ) $ (474 ) Net Gain (Loss) Recognized in Income Fuel and purchased power (a) 4,263 (6,100 ) (26,442 ) (64,143 ) Total $ 3,234 $ (6,228 ) $ (29,032 ) $ (64,617 ) (a) |
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, 2018 and December 31, 2017 . 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, 2018: Gross Recognized Derivatives (a) Amounts Offset (b) Net Recognized Derivatives Other (c) Amount Reported on Balance Sheets Current assets $ 2,609 $ (2,273 ) $ 336 $ 888 $ 1,224 Investments and other assets 314 (314 ) — — — Total assets 2,923 (2,587 ) 336 888 1,224 Current liabilities (45,238 ) 2,273 (42,965 ) (2,539 ) (45,504 ) Deferred credits and other (34,540 ) 314 (34,226 ) — (34,226 ) Total liabilities (79,778 ) 2,587 (77,191 ) (2,539 ) (79,730 ) Total $ (76,855 ) $ — $ (76,855 ) $ (1,651 ) $ (78,506 ) (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 are 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. Amounts include cash collateral received from counterparties of $2,539 and cash margin provided to counterparties of $888 . As of December 31, 2017: Gross Recognized Derivatives (a) Amounts Offset (b) Net Recognized Derivatives Other (c) Amount Reported on Balance Sheets Current assets $ 5,427 $ (3,796 ) $ 1,631 $ 300 $ 1,931 Investments and other assets 1,292 (1,241 ) 51 — 51 Total assets 6,719 (5,037 ) 1,682 300 1,982 Current liabilities (59,527 ) 3,796 (55,731 ) (3,521 ) (59,252 ) Deferred credits and other (38,411 ) 1,241 (37,170 ) — (37,170 ) Total liabilities (97,938 ) 5,037 (92,901 ) (3,521 ) (96,422 ) Total $ (91,219 ) $ — $ (91,219 ) $ (3,221 ) $ (94,440 ) (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. Amounts include cash collateral received from counterparties of $3,521 and cash margin provided to counterparties of $300 |
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, 2018 and December 31, 2017 . 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, 2018: Gross Recognized Derivatives (a) Amounts Offset (b) Net Recognized Derivatives Other (c) Amount Reported on Balance Sheets Current assets $ 2,609 $ (2,273 ) $ 336 $ 888 $ 1,224 Investments and other assets 314 (314 ) — — — Total assets 2,923 (2,587 ) 336 888 1,224 Current liabilities (45,238 ) 2,273 (42,965 ) (2,539 ) (45,504 ) Deferred credits and other (34,540 ) 314 (34,226 ) — (34,226 ) Total liabilities (79,778 ) 2,587 (77,191 ) (2,539 ) (79,730 ) Total $ (76,855 ) $ — $ (76,855 ) $ (1,651 ) $ (78,506 ) (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 are 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. Amounts include cash collateral received from counterparties of $2,539 and cash margin provided to counterparties of $888 . As of December 31, 2017: Gross Recognized Derivatives (a) Amounts Offset (b) Net Recognized Derivatives Other (c) Amount Reported on Balance Sheets Current assets $ 5,427 $ (3,796 ) $ 1,631 $ 300 $ 1,931 Investments and other assets 1,292 (1,241 ) 51 — 51 Total assets 6,719 (5,037 ) 1,682 300 1,982 Current liabilities (59,527 ) 3,796 (55,731 ) (3,521 ) (59,252 ) Deferred credits and other (38,411 ) 1,241 (37,170 ) — (37,170 ) Total liabilities (97,938 ) 5,037 (92,901 ) (3,521 ) (96,422 ) Total $ (91,219 ) $ — $ (91,219 ) $ (3,221 ) $ (94,440 ) (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. Amounts include cash collateral received from counterparties of $3,521 and cash margin provided to counterparties of $300 |
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, 2018 (dollars in thousands): September 30, 2018 Aggregate fair value of derivative instruments in a net liability position $ 79,778 Cash collateral posted — Additional cash collateral in the event credit-risk-related contingent features were fully triggered (a) 76,299 (a) |
Other Income and Other Expense
Other Income and Other Expense (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Component of Other Income and Other Expense Nonoperating [Line Items] | |
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, 2018 and 2017 (dollars in thousands): Three Months Ended Nine Months Ended 2018 2017 2018 2017 Other income: Interest income $ 1,957 $ 917 $ 6,256 $ 1,782 Debt return on Four Corners SCR deferral (Note 4) 4,910 — 11,190 — Miscellaneous 91 174 95 273 Total other income $ 6,958 $ 1,091 $ 17,541 $ 2,055 Other expense: Non-operating costs $ (2,480 ) $ (1,978 ) $ (7,404 ) $ (7,338 ) Investment losses — net — (231 ) (268 ) (759 ) Miscellaneous (2,583 ) (2,784 ) (4,391 ) (4,398 ) Total other expense $ (5,063 ) $ (4,993 ) $ (12,063 ) $ (12,495 ) |
APS | |
Component of Other Income and Other Expense Nonoperating [Line Items] | |
Detail of other income and other expense | The following table provides detail of APS’s other income and other expense for the three and nine months ended September 30, 2018 and 2017 (dollars in thousands): Three Months Ended Nine Months Ended 2018 2017 2018 2017 Other income: Interest income $ 1,151 $ 683 $ 4,874 $ 1,278 Debt return on Four Corners SCR deferral (Note 4) 4,910 — 11,190 — Miscellaneous 92 55 96 154 Total other income $ 6,153 $ 738 $ 16,160 $ 1,432 Other expense: Non-operating costs $ (2,334 ) $ (1,734 ) $ (6,931 ) $ (6,625 ) Miscellaneous (1,027 ) (444 ) (2,748 ) (1,983 ) Total other expense $ (3,361 ) $ (2,178 ) $ (9,679 ) $ (8,608 ) |
Earnings Per Share (Tables)
Earnings Per Share (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
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, 2018 and 2017 (in thousands, except per share amounts): Three Months Ended Nine Months Ended 2018 2017 2018 2017 Net income attributable to common shareholders $ 315,012 $ 276,072 $ 484,971 $ 466,827 Weighted average common shares outstanding — basic 112,148 111,835 112,094 111,787 Net effect of dilutive securities: Contingently issuable performance shares and restricted stock units 385 566 405 527 Weighted average common shares outstanding — diluted 112,533 112,401 112,499 112,314 Earnings per weighted-average common share outstanding Net income attributable to common shareholders — basic $ 2.81 $ 2.47 $ 4.33 $ 4.18 Net income attributable to common shareholders — diluted $ 2.80 $ 2.46 $ 4.31 $ 4.16 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
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, 2018 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands): Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (a) (Level 3) Other Balance at September 30, 2018 Assets Cash equivalents $ 5,600 $ — $ — $ — $ 5,600 Risk management activities — derivative instruments: Commodity contracts — 2,865 58 (1,699 ) (b) 1,224 Nuclear decommissioning trust: Equity securities 6,213 — — (625 ) (c) 5,588 U.S. commingled equity funds — — — 459,790 (d) 459,790 U.S. Treasury debt 134,462 — — — 134,462 Corporate debt — 104,953 — — 104,953 Mortgage-backed debt securities — 112,036 — — 112,036 Municipal bonds — 80,787 — — 80,787 Other fixed income — 9,071 — — 9,071 Subtotal nuclear decommissioning trust 140,675 306,847 — 459,165 906,687 Other special use funds: Equity securities 12,033 — — 1,722 (c) 13,755 U.S. Treasury debt 199,094 — — — 199,094 Municipal bonds — 20,891 — — 20,891 Subtotal other special use funds 211,127 20,891 — 1,722 233,740 Total Assets $ 357,402 $ 330,603 $ 58 $ 459,188 $ 1,147,251 Liabilities Risk management activities — derivative instruments: Commodity contracts $ — $ (69,857 ) $ (9,921 ) $ 48 (b) $ (79,730 ) (a) Primarily consists of long-dated electricity contracts. (b) Represents counterparty netting, margin and collateral. See Note 7 . (c) Represents net pending securities sales and purchases. (d) 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, 2017 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands): Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (a) (Level 3) Other Balance at December 31, 2017 Assets Cash equivalents $ 10,630 $ — $ — $ — $ 10,630 Risk management activities — derivative instruments: Commodity contracts — 5,683 1,036 (4,737 ) (b) 1,982 Nuclear decommissioning trust: Cash and cash equivalents 7,224 — — 109 (d) 7,333 U.S. commingled equity funds — — — 417,390 (e) 417,390 U.S. Treasury debt 127,662 — — — 127,662 Corporate debt — 114,007 — — 114,007 Mortgage-backed debt securities — 111,874 — — 111,874 Municipal bonds — 79,049 — — 79,049 Other fixed income — 13,685 — — 13,685 Subtotal nuclear decommissioning trust 134,886 318,615 — 417,499 871,000 Other special use funds (c): 455 31,562 — 525 32,542 Total Assets $ 145,971 $ 355,860 $ 1,036 $ 413,287 $ 916,154 Liabilities Risk management activities — derivative instruments: Commodity contracts $ — $ (78,646 ) $ (19,292 ) $ 1,516 (b) $ (96,422 ) (a) Primarily consists of long-dated electricity contracts. (b) Represents counterparty netting, margin, and collateral. See Note 7. (c) Primarily consists of fixed income municipal bonds. Presented as coal reclamation escrow in 2017. (d) Represents nuclear decommissioning trust net pending securities sales and purchases. (e) |
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, 2018 and December 31, 2017 : September 30, 2018 Valuation Technique Significant Unobservable Input Weighted-Average Commodity Contracts Assets Liabilities Range Natural Gas: Forward Contracts (a) $ 58 $ 9,921 Discounted cash flows Natural gas forward price (per MMBtu) $1.75 - $2.74 $ 2.23 Total $ 58 $ 9,921 (a) Includes swaps and physical and financial contracts. December 31, 2017 Valuation Technique Significant Unobservable Input Weighted-Average Commodity Contracts Assets Liabilities Range Electricity: Forward Contracts (a) $ 21 $ 15,485 Discounted cash flows Electricity forward price (per MWh) $18.51 - $38.75 $ 27.89 Natural Gas: Forward Contracts (a) 1,015 3,807 Discounted cash flows Natural gas forward price (per MMBtu) $2.33 - $3.11 $ 2.71 Total $ 1,036 $ 19,292 (a) |
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, 2018 and 2017 (dollars in thousands): Three Months Ended Nine Months Ended Commodity Contracts 2018 2017 2018 2017 Net derivative balance at beginning of period $ (9,358 ) $ (36,245 ) $ (18,256 ) $ (47,406 ) Total net gains (losses) realized/unrealized: Included in OCI — (4 ) — (10 ) Deferred as a regulatory asset or liability 1,244 (3,769 ) (2,067 ) (11,272 ) Settlements (2,332 ) 1,733 (1,056 ) 4,855 Transfers into Level 3 from Level 2 (2,246 ) (5,952 ) (7,225 ) (10,340 ) Transfers from Level 3 into Level 2 2,829 5,632 18,741 25,568 Net derivative balance at end of period $ (9,863 ) $ (38,605 ) $ (9,863 ) $ (38,605 ) 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, 2018 | |
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, 2018 and December 31, 2017 (dollars in thousands): September 30, 2018 Fair Value Total Unrealized Gains Total Unrealized Losses Investment Type: Nuclear Decommissioning Trusts Other Special Use Funds Total Equity securities $ 466,002 $ 12,033 $ 478,035 $ 286,121 $ (47 ) Available for sale-fixed income securities 441,309 219,985 661,294 (a) 5,631 (11,423 ) Other (624 ) 1,722 1,098 (b) — — Total $ 906,687 $ 233,740 $ 1,140,427 $ 291,752 $ (11,470 ) (a) As of September 30, 2018 , the amortized cost basis of these available-for-sale investments is $667 million . (b) Represents net pending securities sales and purchases. December 31, 2017 Fair Value Total Unrealized Gains Total Unrealized Losses Investment Type: Nuclear Decommissioning Trusts Other Special Use Funds Total Equity securities $ 424,614 $ 430 $ 425,044 $ 248,623 $ — Available for sale-fixed income securities 446,277 29,439 475,716 (a) 11,537 (2,996 ) Other 109 489 598 (b) — — Total $ 871,000 $ 30,358 $ 901,358 $ 260,160 $ (2,996 ) (a) As of December 31, 2017, the amortized cost basis of these available-for-sale investments is $467 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, 2018 and September 30, 2017 (dollars in thousands): Three Months Ended Three Months Ended Nuclear Decommissioning Trusts Other Special Use Funds Total Nuclear Decommissioning Trusts Other Special Use Funds Total Realized gains $ 653 $ — $ 653 $ 598 $ — $ 598 Realized losses (1,965 ) — (1,965 ) (1,022 ) — (1,022 ) Proceeds from the sale of securities (a) 148,150 25,127 173,277 76,496 — 76,496 (a) Proceeds are reinvested in the nuclear decommissioning trusts or other special use funds. Nine Months Ended Nine Months Ended Nuclear Decommissioning Trusts Other Special Use Funds Total Nuclear Decommissioning Trusts Other Special Use Funds Total Realized gains $ 2,951 $ 1 $ 2,952 $ 3,904 $ 17 $ 3,921 Realized losses (6,990 ) — (6,990 ) (4,634 ) (9 ) (4,643 ) Proceeds from the sale of securities (a) 401,396 41,644 443,040 351,860 4,093 355,953 (a) Proceeds are reinvested in the nuclear decommissioning trusts or other special use funds. |
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, 2018 , is as follows (dollars in thousands): Nuclear Decommissioning Trusts (a) Coal Reclamation Escrow Accounts Active Union Medical Trust Total Less than one year $ 19,917 $ 17,244 $ 30,593 $ 67,754 1 year – 5 years 98,235 17,170 142,598 258,003 5 years – 10 years 126,279 2,529 — 128,808 Greater than 10 years 196,878 9,851 — 206,729 Total $ 441,309 $ 46,794 $ 173,191 $ 661,294 (a) |
Changes in Accumulated Other _2
Changes in Accumulated Other Comprehensive Loss (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Accumulated Other Comprehensive Income (Loss) [Line Items] | |
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, 2018 and 2017 (dollars in thousands): Pension and Other Postretirement Benefits Derivative Instruments Total Three Months Ended September 30 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 ) Balance June 30, 2017 $ (39,881 ) $ (3,745 ) $ (43,626 ) OCI (loss) before reclassifications — 9 9 Amounts reclassified from accumulated other comprehensive loss 790 (a) 710 (b) 1,500 Balance September 30, 2017 $ (39,091 ) $ (3,026 ) $ (42,117 ) Pension and Other Postretirement Benefits Derivative Instruments Total Nine Months Ended September 30 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 ) (598 ) (8,552 ) Balance September 30, 2018 $ (53,134 ) $ (1,940 ) $ (55,074 ) Balance December 31, 2016 $ (39,070 ) $ (4,752 ) $ (43,822 ) OCI (loss) before reclassifications (2,157 ) (754 ) (2,911 ) Amounts reclassified from accumulated other comprehensive loss 2,136 (a) 2,480 (b) 4,616 Balance September 30, 2017 $ (39,091 ) $ (3,026 ) $ (42,117 ) (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 |
APS | |
Accumulated Other Comprehensive Income (Loss) [Line Items] | |
Schedule of changes in accumulated other comprehensive loss including reclassification adjustments, net of tax, by component | 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, 2018 and 2017 (dollars in thousands): Pension and Other Postretirement Benefits Derivative Instruments Total Three Months Ended September 30 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 ) Balance June 30, 2017 $ (21,367 ) $ (3,745 ) $ (25,112 ) OCI (loss) before reclassifications — 9 9 Amounts reclassified from accumulated other comprehensive loss 777 (a) 710 (b) 1,487 Balance September 30, 2017 $ (20,590 ) $ (3,026 ) $ (23,616 ) Pension and Other Postretirement Benefits Derivative Instruments Total Nine Months Ended September 30 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 ) (598 ) (5,038 ) Balance September 30, 2018 $ (31,816 ) $ (1,940 ) $ (33,756 ) Balance December 31, 2016 $ (20,671 ) $ (4,752 ) $ (25,423 ) OCI (loss) before reclassifications (2,121 ) (754 ) (2,875 ) Amounts reclassified from accumulated other comprehensive loss 2,202 (a) 2,480 (b) 4,682 Balance September 30, 2017 $ (20,590 ) $ (3,026 ) $ (23,616 ) (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 |
Consolidation and Nature of O_3
Consolidation and Nature of Operations (Details) - USD ($) $ in Thousands | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Jul. 03, 2018 | |
Cash paid during the period for: | |||
Income taxes, net of refunds | $ 10,091 | $ 2,185 | |
Interest, net of amounts capitalized | 161,875 | 147,149 | |
Significant non-cash investing and financing activities: | |||
Accrued capital expenditures | 99,405 | 93,031 | |
Sale of 4CA's 7% interest in Four Corners | 68,907 | 0 | |
APS | |||
Cash paid during the period for: | |||
Income taxes, net of refunds | 24,746 | 132 | |
Interest, net of amounts capitalized | 154,788 | 142,779 | |
Significant non-cash investing and financing activities: | |||
Accrued capital expenditures | $ 99,405 | $ 94,769 | |
APS | Four Corners | |||
Investment [Line Items] | |||
Ownership percentage | 7.00% | 7.00% |
Revenue (Details)
Revenue (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended |
Sep. 30, 2018 | Sep. 30, 2018 | |
Disaggregation of Revenue [Line Items] | ||
Operating revenues | $ 1,268,034 | $ 2,934,871 |
Regulatory cost recovery revenue | 11,000 | 38,000 |
Electric Service | Retail residential electric service | ||
Disaggregation of Revenue [Line Items] | ||
Operating revenues | 695,480 | 1,512,402 |
Electric Service | Retail non-residential electric service | ||
Disaggregation of Revenue [Line Items] | ||
Operating revenues | 496,809 | 1,275,498 |
Electric Service | Wholesale energy sales | ||
Disaggregation of Revenue [Line Items] | ||
Operating revenues | 53,501 | 80,982 |
Transmission Services For Others | ||
Disaggregation of Revenue [Line Items] | ||
Operating revenues | 15,902 | 46,235 |
Other sources | ||
Disaggregation of Revenue [Line Items] | ||
Operating revenues | 6,342 | 19,754 |
Electric and Transmission Service | ||
Disaggregation of Revenue [Line Items] | ||
Operating revenues | $ 1,257,000 | $ 2,897,000 |
Long-Term Debt and Liquidity _3
Long-Term Debt and Liquidity Matters - Narrative (Details) | Jun. 28, 2018USD ($) | Jun. 27, 2018 | Jun. 26, 2018USD ($) | May 30, 2018USD ($) | Sep. 30, 2018USD ($)Facility | Aug. 09, 2018USD ($) | Jul. 12, 2018USD ($) | Dec. 31, 2017USD ($) | Jul. 31, 2017USD ($) |
Long-Term Debt and Liquidity Matters | |||||||||
Shot-term debt | $ 128,200,000 | $ 95,400,000 | |||||||
Debt Provisions | |||||||||
Total shareholder equity | 5,353,572,000 | 5,006,690,000 | |||||||
Pinnacle West | Revolving Credit Facility | Revolving credit facility maturing July 2018 | |||||||||
Long-Term Debt and Liquidity Matters | |||||||||
Debt instrument, term | 364 days | ||||||||
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders (up to) | $ 125,000,000 | ||||||||
Pinnacle West | Revolving Credit Facility | Revolving credit facility maturing June 2019 | |||||||||
Long-Term Debt and Liquidity Matters | |||||||||
Debt instrument, term | 364 days | ||||||||
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders (up to) | $ 150,000,000 | ||||||||
Shot-term debt | 79,000,000 | ||||||||
Pinnacle West | Revolving Credit Facility | Revolving Credit Facility Maturing May 2021 | |||||||||
Long-Term Debt and Liquidity Matters | |||||||||
Current borrowing capacity on credit facility | $ 200,000,000 | ||||||||
Pinnacle West | Revolving Credit Facility | Revolving credit Facility maturing July 2023 | |||||||||
Long-Term Debt and Liquidity Matters | |||||||||
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders (up to) | 300,000,000 | ||||||||
Current borrowing capacity on credit facility | 200,000,000 | ||||||||
Long-term line of credit | 0 | ||||||||
Pinnacle West | 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 | 49,000,000 | ||||||||
APS | |||||||||
Long-Term Debt and Liquidity Matters | |||||||||
Extinguishment of debt | $ 32,000,000 | ||||||||
Debt Provisions | |||||||||
Total shareholder equity | 5,625,282,000 | $ 5,256,829,000 | |||||||
APS | ACC | |||||||||
Debt Provisions | |||||||||
Total shareholder equity | 5,600,000,000 | ||||||||
Total capitalization | 10,600,000,000 | ||||||||
Dividend restrictions, shareholder equity required | $ 4,200,000,000 | ||||||||
APS | ACC | Minimum | |||||||||
Debt Provisions | |||||||||
Required common equity ratio ordered by ACC (as a percent) (at least) | 40.00% | ||||||||
APS | Senior notes | |||||||||
Long-Term Debt and Liquidity Matters | |||||||||
Debt instrument, face amount | $ 300,000,000 | ||||||||
Debt instrument, interest rate | 4.20% | ||||||||
APS | Revolving Credit Facility | Revolving Credit Facility Maturing May 2021 | |||||||||
Long-Term Debt and Liquidity Matters | |||||||||
Current borrowing capacity on credit facility | $ 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 | $ 500,000,000 | |||||||
APS | Revolving Credit Facility | Revolving Credit Facility Maturing in 2022 and 2023 | |||||||||
Long-Term Debt and Liquidity Matters | |||||||||
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders (up to) | 1,400,000,000 | ||||||||
Current borrowing capacity on credit facility | 1,000,000,000 | ||||||||
Long-term line of credit | $ 0 | ||||||||
Number of line of credit facilities | Facility | 2 | ||||||||
APS | Revolving Credit Facility | Term Loan Facility | |||||||||
Long-Term Debt and Liquidity Matters | |||||||||
Extinguishment of debt | $ 50,000,000 | ||||||||
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 | $ 0 | ||||||||
LIBOR | Pinnacle West | Revolving Credit Facility | Revolving credit facility maturing June 2019 | |||||||||
Long-Term Debt and Liquidity Matters | |||||||||
Debt instrument, basis spread on variable rate | 0.70% |
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, 2018 | Dec. 31, 2017 |
Estimated fair value of long-term debt, including current maturities | ||
Carrying Amount | $ 5,087,364 | $ 4,871,713 |
Fair Value | 5,192,395 | 5,304,956 |
Pinnacle West | ||
Estimated fair value of long-term debt, including current maturities | ||
Carrying Amount | 298,640 | 298,421 |
Fair Value | 292,185 | 298,608 |
APS | ||
Estimated fair value of long-term debt, including current maturities | ||
Carrying Amount | 4,788,724 | 4,573,292 |
Fair Value | $ 4,900,210 | $ 5,006,348 |
Regulatory Matters - Retail Rat
Regulatory Matters - Retail Rate Case Filing (Details) - Retail Rate Case Filing with Arizona Corporation Commission - ACC - APS | Jan. 03, 2018Customer | Nov. 13, 2017USD ($) | Mar. 27, 2017USD ($)$ / kWh | Mar. 26, 2017$ / kWh | Jun. 01, 2016USD ($) | Dec. 31, 2015USD ($) | Jun. 01, 2011USD ($) | Sep. 30, 2018appeal |
Public Utilities, General Disclosures [Line Items] | ||||||||
Net retail rate increase | $ 165,900,000 | $ 95,500,000 | ||||||
Adjustor account balance transferred into base rates, amount | $ 267,600,000 | |||||||
Approximate percentage of increase in average customer bill | 3.28% | 5.74% | ||||||
Approximate percentage of increase in average residential customer bill | 4.54% | 4.54% | 7.96% | |||||
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 | |||||||
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, environmental surcharge cap rate (in dollars per kWh) | $ / kWh | 0.00050 | 0.00016 | ||||||
Rate matter, resource comparison proxy for exported energy (in dollars per kWh) | $ / kWh | 0.129 | |||||||
Periodic metering infrastructure opt-out fee | $ 5 | |||||||
Number of appeals | appeal | 2 | |||||||
Number of customers named in complaint | Customer | 25 | |||||||
AZ Sun Program Phase 2 | ||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||
Public utilities, minimum annual renewable energy standard and tariff | $ 10,000,000 | |||||||
Public utilities, maximum annual renewable energy standard and tariff | $ 15,000,000 |
Regulatory Matters - Cost Recov
Regulatory Matters - Cost Recovery Mechanism and Net Metering (Details) | Aug. 13, 2018USD ($) | Jun. 01, 2018USD ($) | May 01, 2018$ / kWh | Feb. 22, 2018USD ($) | Feb. 20, 2018 | Feb. 15, 2018USD ($) | 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 | Jan. 15, 2016USD ($) | Dec. 31, 2014penetration_feederstorage_systemMW | Sep. 30, 2018USD ($) | Sep. 30, 2017USD ($) | Dec. 31, 2017USD ($)$ / kWh | Dec. 31, 2012$ / kWh | Jun. 29, 2018USD ($) | Nov. 14, 2017USD ($) | Sep. 01, 2017USD ($) | Jun. 30, 2017USD ($) | Jan. 27, 2017USD ($) | Jul. 01, 2016USD ($) | Jun. 01, 2016USD ($) | Nov. 25, 2015USD ($)project |
Change in regulatory asset | |||||||||||||||||||||||||||||
Deferred fuel and purchased power costs — current period | $ 82,486,000 | $ 43,348,000 | |||||||||||||||||||||||||||
Amounts refunded/(charged) to customers | (92,397,000) | 18,153,000 | |||||||||||||||||||||||||||
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 | 82,486,000 | 43,348,000 | |||||||||||||||||||||||||||
Amounts refunded/(charged) to customers | $ (92,397,000) | 18,153,000 | |||||||||||||||||||||||||||
Gross-up for revenue requirement of rate regulation | $ (377,000,000) | ||||||||||||||||||||||||||||
RES 2014 | APS | Alternative to AZ Sun Program, Phase 1 | |||||||||||||||||||||||||||||
Settlement Agreement | |||||||||||||||||||||||||||||
Request to build additional utility scale solar, capacity (in MW) | MW | 8 | ||||||||||||||||||||||||||||
RES 2014 | APS | Alternative to AZ Sun Program Phase 2 | |||||||||||||||||||||||||||||
Settlement Agreement | |||||||||||||||||||||||||||||
Request to build additional utility scale solar, capacity (in MW) | MW | 2 | ||||||||||||||||||||||||||||
Number of energy storage systems | storage_system | 2 | ||||||||||||||||||||||||||||
Solar storage system, capacity (in MW) | MW | 2 | ||||||||||||||||||||||||||||
Number of high solar penetration feeders | penetration_feeder | 2 | ||||||||||||||||||||||||||||
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 | $ 46,400,000 | |||||||||||||||||||||||||||
Increase (decrease) in amount of adjustment representing prorated sales losses | $ (3,000,000) | $ 17,300,000 | $ 7,900,000 | ||||||||||||||||||||||||||
Amount of adjustment representing prorated sales losses pending approval | $ 60,700,000 | ||||||||||||||||||||||||||||
ACC | APS | |||||||||||||||||||||||||||||
Change in regulatory asset | |||||||||||||||||||||||||||||
Gross-up for revenue requirement of rate regulation | $ 86,500,000 | $ 119,100,000 | |||||||||||||||||||||||||||
Provisional income tax benefit | $ 119,100,000 | ||||||||||||||||||||||||||||
ACC | RES | APS | |||||||||||||||||||||||||||||
Settlement Agreement | |||||||||||||||||||||||||||||
Plan term | 5 years | ||||||||||||||||||||||||||||
ACC | RES 2017 | APS | |||||||||||||||||||||||||||||
Settlement Agreement | |||||||||||||||||||||||||||||
Amount of approved budget | $ 150,000,000 | ||||||||||||||||||||||||||||
ACC | RES 2018 | APS | |||||||||||||||||||||||||||||
Settlement Agreement | |||||||||||||||||||||||||||||
Amount of proposed budget | $ 89,900,000 | $ 90,000,000 | |||||||||||||||||||||||||||
ACC | RES 2018 | APS | Solar Communities | |||||||||||||||||||||||||||||
Change in regulatory asset | |||||||||||||||||||||||||||||
Program term | 3 years | ||||||||||||||||||||||||||||
ACC | DSMAC 2015 | APS | |||||||||||||||||||||||||||||
Settlement Agreement | |||||||||||||||||||||||||||||
Amount of approved budget | $ 68,900,000 | ||||||||||||||||||||||||||||
Number of resource savings projects | project | 3 | ||||||||||||||||||||||||||||
ACC | Demand Side Management Adjustor Charge 2017 | APS | |||||||||||||||||||||||||||||
Settlement Agreement | |||||||||||||||||||||||||||||
Amount of approved budget | $ 66,600,000 | ||||||||||||||||||||||||||||
Amount of proposed budget | $ 62,600,000 | ||||||||||||||||||||||||||||
ACC | Demand Side Management Adjustor Charge 2018 | APS | |||||||||||||||||||||||||||||
Settlement Agreement | |||||||||||||||||||||||||||||
Amount of proposed budget | $ 52,600,000 | $ 52,600,000 | |||||||||||||||||||||||||||
ACC | Power Supply Adjustor (PSA) | APS | |||||||||||||||||||||||||||||
Change in regulatory asset | |||||||||||||||||||||||||||||
Beginning balance | $ 75,637,000 | 12,465,000 | $ 12,465,000 | ||||||||||||||||||||||||||
Deferred fuel and purchased power costs — current period | 82,486,000 | 43,348,000 | |||||||||||||||||||||||||||
Amounts refunded/(charged) to customers | (92,397,000) | 18,153,000 | |||||||||||||||||||||||||||
Ending balance | 65,726,000 | $ 73,966,000 | $ 75,637,000 | ||||||||||||||||||||||||||
PSA rate (in dollars per kWh) | $ / kWh | 0.004555 | 0.000555 | (0.001348) | ||||||||||||||||||||||||||
Forward component of increase in PSA (in dollars per kWh) | $ / kWh | 0.002009 | 0.000876 | (0.001027) | ||||||||||||||||||||||||||
Historical component of increase in PSA (in dollars per kWh) | $ / kWh | 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 | $ (22,700,000) | $ 35,100,000 | |||||||||||||||||||||||||||
Cost Recovery Mechanisms | ACC | Power Supply Adjustor (PSA) | APS | |||||||||||||||||||||||||||||
Change in regulatory asset | |||||||||||||||||||||||||||||
PSA rate for prior year (in dollars per kWh) | $ / kWh | 0.001678 | ||||||||||||||||||||||||||||
Minimum | ACC | RES 2018 | APS | Solar Communities | |||||||||||||||||||||||||||||
Change in regulatory asset | |||||||||||||||||||||||||||||
Required annual capital investment | $ 10,000,000 | ||||||||||||||||||||||||||||
Maximum | ACC | RES 2018 | APS | Solar Communities | |||||||||||||||||||||||||||||
Change in regulatory asset | |||||||||||||||||||||||||||||
Required annual capital investment | $ 15,000,000 |
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, 2018 | 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 | 50 | $ 50 | |||||
Regulatory noncurrent asset amortization period | 10 years | ||||||
Retired power plant costs | |||||||
Business Acquisition [Line Items] | |||||||
Net book value | 93 | $ 93 | |||||
Navajo Plant | |||||||
Business Acquisition [Line Items] | |||||||
Net book value | $ 90 | $ 90 | |||||
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, 2018 | Dec. 31, 2017 |
Detail of regulatory assets | ||
Regulatory assets, current | $ 209,575 | $ 248,088 |
Regulatory assets, non-current | 1,221,293 | 1,202,302 |
Pension | ||
Detail of regulatory assets | ||
Regulatory assets, current | 0 | 0 |
Regulatory assets, non-current | 598,031 | 576,188 |
Retired power plant costs | ||
Detail of regulatory assets | ||
Regulatory assets, current | 28,182 | 27,402 |
Regulatory assets, non-current | 174,257 | 188,843 |
Income taxes — allowance for funds used during construction (AFUDC) equity | ||
Detail of regulatory assets | ||
Regulatory assets, current | 5,882 | 3,828 |
Regulatory assets, non-current | 150,684 | 142,852 |
Deferred fuel and purchased power — mark-to-market (Note 7) | ||
Detail of regulatory assets | ||
Regulatory assets, current | 41,062 | 52,100 |
Regulatory assets, non-current | 33,215 | 34,845 |
Deferred fuel and purchased power | ||
Detail of regulatory assets | ||
Regulatory assets, current | 65,726 | 75,637 |
Regulatory assets, non-current | 0 | 0 |
Four Corners cost deferral | ||
Detail of regulatory assets | ||
Regulatory assets, current | 8,077 | 8,077 |
Regulatory assets, non-current | 42,247 | 48,305 |
Income taxes — investment tax credit basis adjustment | ||
Detail of regulatory assets | ||
Regulatory assets, current | 1,066 | 1,066 |
Regulatory assets, non-current | 25,239 | 26,218 |
Lost fixed cost recovery | ||
Detail of regulatory assets | ||
Regulatory assets, current | 36,125 | 59,844 |
Regulatory assets, non-current | 0 | 0 |
Palo Verde VIEs (Note 6) | ||
Detail of regulatory assets | ||
Regulatory assets, current | 0 | 0 |
Regulatory assets, non-current | 19,860 | 19,395 |
Deferred compensation | ||
Detail of regulatory assets | ||
Regulatory assets, current | 0 | 0 |
Regulatory assets, non-current | 37,854 | 36,413 |
Deferred property taxes | ||
Detail of regulatory assets | ||
Regulatory assets, current | 8,569 | 8,569 |
Regulatory assets, non-current | 68,499 | 74,926 |
Loss on reacquired debt | ||
Detail of regulatory assets | ||
Regulatory assets, current | 1,637 | 1,637 |
Regulatory assets, non-current | 14,078 | 15,305 |
Tax expense of Medicare subsidy | ||
Detail of regulatory assets | ||
Regulatory assets, current | 1,235 | 1,236 |
Regulatory assets, non-current | 6,253 | 7,415 |
TCA balancing account | ||
Detail of regulatory assets | ||
Regulatory assets, current | 7,087 | 1,220 |
Regulatory assets, non-current | 0 | 0 |
AG-1 deferral | ||
Detail of regulatory assets | ||
Regulatory assets, current | 2,654 | 2,654 |
Regulatory assets, non-current | 6,482 | 8,472 |
Mead-Phoenix transmission line CIAC | ||
Detail of regulatory assets | ||
Regulatory assets, current | 332 | 332 |
Regulatory assets, non-current | 10,127 | 10,376 |
Coal reclamation | ||
Detail of regulatory assets | ||
Regulatory assets, current | 1,546 | 1,068 |
Regulatory assets, non-current | 11,695 | 12,396 |
SCR deferral | ||
Detail of regulatory assets | ||
Regulatory assets, current | 0 | 0 |
Regulatory assets, non-current | 16,319 | 353 |
Other | ||
Detail of regulatory assets | ||
Regulatory assets, current | 395 | 3,418 |
Regulatory assets, non-current | $ 6,453 | $ 0 |
Regulatory Matters - Schedule_2
Regulatory Matters - Schedule of Regulatory Liabilities (Details) - USD ($) $ in Thousands | Sep. 30, 2018 | Dec. 31, 2017 |
Detail of regulatory liabilities | ||
Regulatory liabilities, current | $ 159,788 | $ 100,086 |
Regulatory liabilities, non-current | 2,410,597 | 2,452,536 |
Asset retirement obligations | ||
Detail of regulatory liabilities | ||
Regulatory liabilities, current | 0 | 0 |
Regulatory liabilities, non-current | 344,402 | 332,171 |
Removal costs | ||
Detail of regulatory liabilities | ||
Regulatory liabilities, current | 30,871 | 18,238 |
Regulatory liabilities, non-current | 196,065 | 209,191 |
Other postretirement benefits | ||
Detail of regulatory liabilities | ||
Regulatory liabilities, current | 37,842 | 37,642 |
Regulatory liabilities, non-current | 123,683 | 151,985 |
Income taxes — deferred investment tax credit | ||
Detail of regulatory liabilities | ||
Regulatory liabilities, current | 2,137 | 2,164 |
Regulatory liabilities, non-current | 50,555 | 52,497 |
Income taxes — change in rates | ||
Detail of regulatory liabilities | ||
Regulatory liabilities, current | 2,799 | 2,573 |
Regulatory liabilities, non-current | 71,137 | 70,537 |
Spent nuclear fuel | ||
Detail of regulatory liabilities | ||
Regulatory liabilities, current | 7,769 | 6,924 |
Regulatory liabilities, non-current | 57,400 | 62,132 |
Renewable energy standard | ||
Detail of regulatory liabilities | ||
Regulatory liabilities, current | 41,912 | 23,155 |
Regulatory liabilities, non-current | 92 | 0 |
Demand side management | ||
Detail of regulatory liabilities | ||
Regulatory liabilities, current | 16,099 | 3,066 |
Regulatory liabilities, non-current | 4,124 | 4,921 |
Sundance maintenance | ||
Detail of regulatory liabilities | ||
Regulatory liabilities, current | 0 | 0 |
Regulatory liabilities, non-current | 18,104 | 16,897 |
Deferred gains on utility property | ||
Detail of regulatory liabilities | ||
Regulatory liabilities, current | 4,423 | 4,423 |
Regulatory liabilities, non-current | 7,704 | 10,988 |
Four Corners coal reclamation | ||
Detail of regulatory liabilities | ||
Regulatory liabilities, current | 1,858 | 1,858 |
Regulatory liabilities, non-current | 17,972 | 18,921 |
Tax expense adjustor mechanism | ||
Detail of regulatory liabilities | ||
Regulatory liabilities, current | 7,433 | 0 |
Regulatory liabilities, non-current | 0 | 0 |
Other | ||
Detail of regulatory liabilities | ||
Regulatory liabilities, current | 361 | 43 |
Regulatory liabilities, non-current | 2,837 | 2,022 |
ACC | Excess deferred income taxes - ACC - Tax Cuts and Jobs Act | ||
Detail of regulatory liabilities | ||
Regulatory liabilities, current | 0 | 0 |
Regulatory liabilities, non-current | 1,273,153 | 1,266,104 |
United States Federal Energy Regulatory Commission | Excess deferred income taxes - ACC - Tax Cuts and Jobs Act | ||
Detail of regulatory liabilities | ||
Regulatory liabilities, current | 6,284 | 0 |
Regulatory liabilities, non-current | $ 243,369 | $ 254,170 |
Retirement Plans and Other Po_3
Retirement Plans and Other Postretirement Benefits - Narrative (Details) | 9 Months Ended |
Sep. 30, 2018USD ($) | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Amount of other postretirement benefit trust assets for union employee medical costs | $ 186,000,000 |
Pension Benefits | |
Contributions | |
Voluntary employer contributions to pension plan | 50,000,000 |
Minimum employer contributions for the next three years | 0 |
Maximum employer contributions for the next two years (up to) | 250,000,000 |
Other Benefits | |
Contributions | |
Estimated future employer contributions in next three years | 0 |
Retiree medical claim reimbursements | $ 72,000,000 |
Retirement Plans and Other Po_4
Retirement Plans and Other Postretirement Benefits - Schedule of Net Benefit Cost (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Amortization of: | ||||
Portion of cost (credit) charged to expense | $ (12,449) | $ (6,534) | $ (37,314) | $ (19,601) |
Pension Benefits | ||||
Retirement Plans and Other Benefits | ||||
Service cost — benefits earned during the period | 14,167 | 13,715 | 42,501 | 41,144 |
Interest cost on benefit obligation | 31,172 | 32,439 | 93,517 | 97,316 |
Expected return on plan assets | (45,713) | (43,568) | (137,140) | (130,703) |
Amortization of: | ||||
Prior service cost (credit) | 0 | 20 | 0 | 61 |
Net actuarial loss | 8,021 | 11,975 | 24,062 | 35,924 |
Net periodic benefit cost (credit) | 7,647 | 14,581 | 22,940 | 43,742 |
Portion of cost (credit) charged to expense | 2,524 | 7,231 | 7,535 | 21,692 |
Other Benefits | ||||
Retirement Plans and Other Benefits | ||||
Service cost — benefits earned during the period | 5,275 | 4,280 | 15,825 | 12,839 |
Interest cost on benefit obligation | 7,037 | 7,490 | 21,111 | 22,470 |
Expected return on plan assets | (10,520) | (13,350) | (31,561) | (40,051) |
Amortization of: | ||||
Prior service cost (credit) | (9,461) | (9,461) | (28,382) | (28,382) |
Net actuarial loss | 0 | 1,279 | 0 | 3,838 |
Net periodic benefit cost (credit) | (7,669) | (9,762) | (23,007) | (29,286) |
Portion of cost (credit) charged to expense | $ (5,359) | $ (4,841) | $ (16,083) | $ (14,523) |
Palo Verde Sale Leaseback Var_3
Palo Verde Sale Leaseback Variable Interest Entities - Narrative (Details) | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2018USD ($)power_plant | Sep. 30, 2017USD ($) | Sep. 30, 2018USD ($)power_plantLease | Sep. 30, 2017USD ($) | 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 | 295,000,000 | ||||
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, 2018 | Dec. 31, 2017 |
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets | ||
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation | $ 106,743 | $ 109,645 |
Equity — Noncontrolling interests | 132,289 | 129,040 |
APS | ||
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets | ||
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation | 106,743 | 109,645 |
Equity — Noncontrolling interests | 132,289 | 129,040 |
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 | 106,743 | 109,645 |
Equity — Noncontrolling interests | $ 132,289 | $ 129,040 |
Derivative Accounting - Narrati
Derivative Accounting - Narrative (Details) $ in Millions | 9 Months Ended |
Sep. 30, 2018USD ($) | |
Commodity Contracts | |
Derivative Accounting | |
Additional collateral to counterparties for energy related non-derivative instrument contracts | $ 94 |
Commodity Contracts | Designated as Hedging Instruments | |
Derivative Accounting | |
Estimated loss before income taxes to be reclassified from accumulated other comprehensive income | $ 2 |
APS | |
Derivative Accounting | |
Percentage of unrealized gains and losses on certain derivatives deferred for future rate treatment | 100.00% |
Derivative Accounting - Schedul
Derivative Accounting - Schedule of Gross Notional Amounts Outstanding (Details) - Commodity Contracts MWh in Thousands, MMcf in Thousands | Dec. 31, 2017MWhMMcf | Sep. 30, 2018MWhMMcf |
Outstanding gross notional amount of derivatives | ||
Power | MWh | 583 | 287 |
Gas | MMcf | 240 | 192 |
Derivative Accounting - Gains a
Derivative Accounting - Gains and Losses from Derivative Instruments (Details) - Commodity Contracts - USD ($) | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
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) | (600,000) | (1,148,000) | (1,697,000) | (2,910,000) |
Not Designated as Hedging Instruments | ||||
Gains and losses from derivative instruments | ||||
Net Gain (Loss) Recognized in Income | 3,234,000 | (6,228,000) | (29,032,000) | (64,617,000) |
Not Designated as Hedging Instruments | Operating revenues | ||||
Gains and losses from derivative instruments | ||||
Net Gain (Loss) Recognized in Income | (1,029,000) | (128,000) | (2,590,000) | (474,000) |
Not Designated as Hedging Instruments | Fuel and purchased power | ||||
Gains and losses from derivative instruments | ||||
Net Gain (Loss) Recognized in Income | 4,263,000 | (6,100,000) | (26,442,000) | (64,143,000) |
Other comprehensive income | Designated as Hedging Instruments | ||||
Gains and losses from derivative instruments | ||||
Gain (Loss) Recognized in OCI on Derivative Instruments (Effective Portion) | $ 0 | $ 14,000 | $ 0 | $ (70,000) |
Derivative Accounting - Derivat
Derivative Accounting - Derivative Instruments in the Balance Sheets (Details) - USD ($) | Sep. 30, 2018 | Dec. 31, 2017 |
Assets | ||
Gross Recognized Derivatives | $ 1,224,000 | $ 1,982,000 |
Liabilities | ||
Amount Reported on Balance Sheets | (79,730,000) | (96,422,000) |
Commodity Contracts | ||
Assets | ||
Gross Recognized Derivatives | 2,923,000 | 6,719,000 |
Amounts Offset | (2,587,000) | (5,037,000) |
Net Recognized Derivatives | 336,000 | 1,682,000 |
Other | 888,000 | 300,000 |
Amount Reported on Balance Sheets | 1,224,000 | 1,982,000 |
Liabilities | ||
Gross Recognized Derivatives | (79,778,000) | (97,938,000) |
Amounts Offset | 2,587,000 | 5,037,000 |
Net Recognized Derivatives | (77,191,000) | (92,901,000) |
Other | (2,539,000) | (3,521,000) |
Amount Reported on Balance Sheets | (79,730,000) | (96,422,000) |
Assets and Liabilities | ||
Gross Recognized Derivatives | (76,855,000) | (91,219,000) |
Amounts Offset | 0 | 0 |
Net Recognized Derivatives | (76,855,000) | (91,219,000) |
Other | (1,651,000) | (3,221,000) |
Amount Reported on Balance Sheets | (78,506,000) | (94,440,000) |
Commodity Contracts | Current assets | ||
Assets | ||
Gross Recognized Derivatives | 2,609,000 | 5,427,000 |
Amounts Offset | (2,273,000) | (3,796,000) |
Net Recognized Derivatives | 336,000 | 1,631,000 |
Other | 888,000 | 300,000 |
Amount Reported on Balance Sheets | 1,224,000 | 1,931,000 |
Commodity Contracts | Investments and other assets | ||
Assets | ||
Gross Recognized Derivatives | 314,000 | 1,292,000 |
Amounts Offset | (314,000) | (1,241,000) |
Net Recognized Derivatives | 0 | 51,000 |
Other | 0 | 0 |
Amount Reported on Balance Sheets | 0 | 51,000 |
Commodity Contracts | Current liabilities | ||
Liabilities | ||
Gross Recognized Derivatives | (45,238,000) | (59,527,000) |
Amounts Offset | 2,273,000 | 3,796,000 |
Net Recognized Derivatives | (42,965,000) | (55,731,000) |
Other | (2,539,000) | (3,521,000) |
Amount Reported on Balance Sheets | (45,504,000) | (59,252,000) |
Commodity Contracts | Deferred credits and other | ||
Liabilities | ||
Gross Recognized Derivatives | (34,540,000) | (38,411,000) |
Amounts Offset | 314,000 | 1,241,000 |
Net Recognized Derivatives | (34,226,000) | (37,170,000) |
Other | 0 | 0 |
Amount Reported on Balance Sheets | $ (34,226,000) | $ (37,170,000) |
Derivative Accounting - Credit
Derivative Accounting - Credit Risk and Credit Related Contingent Features (Details) - Commodity Contracts $ in Thousands | Sep. 30, 2018USD ($) |
Credit Risk and Credit-Related Contingent Features | |
Aggregate fair value of derivative instruments in a net liability position | $ 79,778 |
Cash collateral posted | 0 |
Additional cash collateral in the event credit-risk-related contingent features were fully triggered | $ 76,299 |
Commitments and Contingencies -
Commitments and Contingencies - Palo Verde Nuclear Generating Station and Contractual Obligations (Details) | Nov. 08, 2018USD ($) | Aug. 18, 2014USD ($) | Sep. 30, 2018USD ($)power_plant | Sep. 30, 2018USD ($)power_planttime_periodclaim | Nov. 01, 2018power_plant | 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 | |||||
Payments for legal settlements | $ 74,200,000 | |||||
APS | ||||||
Commitments and Contingencies | ||||||
Maximum insurance against public liability per occurrence for a nuclear incident (up to) | 13,100,000,000 | |||||
Maximum available nuclear liability insurance (up to) | 450,000,000 | |||||
Remaining nuclear liability insurance through mandatory industry wide retrospective assessment program | 12,600,000,000 | |||||
Maximum retrospective premium assessment per reactor for each nuclear liability incident | 127,300,000 | |||||
Annual limit per incident with respect to maximum retrospective premium assessment | $ 19,000,000 | |||||
Number of VIE lessor trusts | 3 | 3 | 3 | |||
Maximum potential retrospective assessment per incident of APS | $ 111,100,000 | |||||
Annual payment limitation with respect to maximum potential retrospective premium assessment | 16,600,000 | |||||
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 | 24,800,000 | |||||
Collateral assurance provided based on rating triggers | $ 71,200,000 | |||||
Period to provide collateral assurance based on rating triggers | 20 days | |||||
Purchase obligation, decrease | $ 166,000,000 | |||||
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 | |||||
Number of claims submitted | claim | 3 | |||||
Number of settlement agreement time periods | time_period | 3 | |||||
Payments for legal settlements | $ 21,600,000 | |||||
Subsequent Event | APS | ||||||
Commitments and Contingencies | ||||||
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 | power_plant | 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 |
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, 2018plaintiff | Dec. 16, 2016plaintiff | Aug. 06, 2013Defendant | Sep. 30, 2018USD ($) |
Loss Contingencies [Line Items] | ||||
Costs related to investigation and study under Superfund site | $ | $ 2 | |||
Number of defendants against whom Roosevelt Irrigation District (RID) filed lawsuit | Defendant | 24 | |||
Number of plaintiffs | 2 | |||
Settled Litigation | ||||
Loss Contingencies [Line Items] | ||||
Number of plaintiffs | 2 |
Commitments and Contingencies_3
Commitments and Contingencies - Environmental Matters and Financial Assurances (Details) $ in Millions | Jul. 03, 2018USD ($) | Jun. 29, 2018USD ($) | Jun. 13, 2017USD ($) | Jul. 06, 2016guarantee | Sep. 30, 2018USD ($) | Dec. 31, 2017USD ($) | Mar. 12, 2018USD ($) |
Coal Supply Agreement Arbitration | Four Corners | |||||||
Four Corners Coal Supply Agreement | |||||||
Damages sought | $ 30 | ||||||
Settlement amount | $ 45 | ||||||
APS | Coal Supply Agreement Arbitration | Four Corners | |||||||
Four Corners Coal Supply Agreement | |||||||
Damages sought | $ 17 | ||||||
Settlement amount | $ 34 | ||||||
Coal advance purchase | $ 24 | ||||||
APS | Letters of Credit Expiring in 2018, 2019 | |||||||
Financial Assurances | |||||||
Outstanding letters of credit | $ 0.2 | ||||||
APS | Letters of Credit Expiring in 2019 | |||||||
Financial Assurances | |||||||
Surety bonds expiring, amount | $ 36 | ||||||
4C Acquisition, LLC | Four Corners Units 4 and 5 | |||||||
Environmental Matters | |||||||
Percentage of share of cost of control | 7.00% | ||||||
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 | $ 20 | ||||||
Payment Guarantee | |||||||
Financial Assurances | |||||||
Number of parental guarantees | guarantee | 5 |
Other Income and Other Expens_2
Other Income and Other Expense (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Other income: | ||||
Interest income | $ 1,957 | $ 917 | $ 6,256 | $ 1,782 |
Debt return on Four Corners SCR deferral (Note 4) | 4,910 | 0 | 11,190 | 0 |
Miscellaneous | 91 | 174 | 95 | 273 |
Total other income | 6,958 | 1,091 | 17,541 | 2,055 |
Other expense: | ||||
Non-operating costs | (2,480) | (1,978) | (7,404) | (7,338) |
Investment losses — net | 0 | (231) | (268) | (759) |
Miscellaneous | (2,583) | (2,784) | (4,391) | (4,398) |
Total other expense | (5,063) | (4,993) | (12,063) | (12,495) |
APS | ||||
Other income: | ||||
Interest income | 1,151 | 683 | 4,874 | 1,278 |
Debt return on Four Corners SCR deferral (Note 4) | 4,910 | 0 | 11,190 | 0 |
Miscellaneous | 92 | 55 | 96 | 154 |
Total other income | 6,153 | 738 | 16,160 | 1,432 |
Other expense: | ||||
Non-operating costs | (2,334) | (1,734) | (6,931) | (6,625) |
Miscellaneous | (1,027) | (444) | (2,748) | (1,983) |
Total other expense | $ (3,361) | $ (2,178) | $ (9,679) | $ (8,608) |
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, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Earnings Per Share [Abstract] | ||||
Net income attributable to common shareholders | $ 315,012 | $ 276,072 | $ 484,971 | $ 466,827 |
Weighted average common shares outstanding - basic (in shares) | 112,148 | 111,835 | 112,094 | 111,787 |
Net effect of dilutive securities: | ||||
Contingently issuable performance shares and restricted stock units (in shares) | 385 | 566 | 405 | 527 |
Weighted average common shares outstanding — diluted (in shares) | 112,533 | 112,401 | 112,499 | 112,314 |
Earnings per weighted-average common share outstanding | ||||
Net income attributable to common shareholders - basic (in dollars per share) | $ 2.81 | $ 2.47 | $ 4.33 | $ 4.18 |
Net income attributable to common shareholders - diluted (in dollars per share) | $ 2.80 | $ 2.46 | $ 4.31 | $ 4.16 |
Fair Value Measurements - Asset
Fair Value Measurements - Assets and Liabilities Measured on a Recurring Basis (Details) - USD ($) $ in Thousands | Sep. 30, 2018 | Dec. 31, 2017 |
Assets | ||
Cash equivalents | $ 5,600 | $ 10,630 |
Commodity contracts, assets | 1,224 | 1,982 |
Commodity contracts, liabilities | (1,699) | (4,737) |
Nuclear decommissioning trust | 906,687 | 871,000 |
Nuclear decommissioning trust, other | 459,165 | 417,499 |
Other special use funds | 233,740 | 32,542 |
Other special use funds, other | 1,722 | 525 |
Total assets | 1,147,251 | 916,154 |
Total assets, other | 459,188 | 413,287 |
Liabilities | ||
Total, other | 48 | 1,516 |
Amount reported on balance sheet | (79,730) | (96,422) |
Cash and cash equivalent funds | ||
Assets | ||
Nuclear decommissioning trust | 7,333 | |
Nuclear decommissioning trust, other | 109 | |
Equity securities | ||
Assets | ||
Nuclear decommissioning trust | 5,588 | |
Nuclear decommissioning trust, other | (625) | |
Other special use funds | 13,755 | |
Other special use funds, other | 1,722 | |
U.S. commingled equity funds | ||
Assets | ||
Nuclear decommissioning trust | 459,790 | 417,390 |
U.S. Treasury debt | ||
Assets | ||
Nuclear decommissioning trust | 134,462 | 127,662 |
Other special use funds | 199,094 | |
Corporate debt | ||
Assets | ||
Nuclear decommissioning trust | 104,953 | 114,007 |
Mortgage-backed debt securities | ||
Assets | ||
Nuclear decommissioning trust | 112,036 | 111,874 |
Municipal bonds | ||
Assets | ||
Nuclear decommissioning trust | 80,787 | 79,049 |
Other special use funds | 20,891 | |
Other fixed income | ||
Assets | ||
Nuclear decommissioning trust | 9,071 | 13,685 |
Quoted Prices in Active Markets for Identical Assets (Level 1) | ||
Assets | ||
Cash equivalents | 5,600 | 10,630 |
Commodity contracts, assets | 0 | 0 |
Nuclear decommissioning trust | 140,675 | 134,886 |
Other special use funds | 211,127 | 455 |
Total assets | 357,402 | 145,971 |
Liabilities | ||
Gross derivative liability | 0 | 0 |
Quoted Prices in Active Markets for Identical Assets (Level 1) | Cash and cash equivalent funds | ||
Assets | ||
Nuclear decommissioning trust | 7,224 | |
Quoted Prices in Active Markets for Identical Assets (Level 1) | Equity securities | ||
Assets | ||
Nuclear decommissioning trust | 6,213 | |
Other special use funds | 12,033 | |
Quoted Prices in Active Markets for Identical Assets (Level 1) | U.S. commingled equity funds | ||
Assets | ||
Nuclear decommissioning trust | 0 | 0 |
Quoted Prices in Active Markets for Identical Assets (Level 1) | U.S. Treasury debt | ||
Assets | ||
Nuclear decommissioning trust | 134,462 | 127,662 |
Other special use funds | 199,094 | |
Quoted Prices in Active Markets for Identical Assets (Level 1) | Corporate debt | ||
Assets | ||
Nuclear decommissioning trust | 0 | 0 |
Quoted Prices in Active Markets for Identical Assets (Level 1) | Mortgage-backed debt securities | ||
Assets | ||
Nuclear decommissioning trust | 0 | 0 |
Quoted Prices in Active Markets for Identical Assets (Level 1) | Municipal bonds | ||
Assets | ||
Nuclear decommissioning trust | 0 | 0 |
Other special use funds | 0 | |
Quoted Prices in Active Markets for Identical Assets (Level 1) | Other fixed income | ||
Assets | ||
Nuclear decommissioning trust | 0 | 0 |
Significant Other Observable Inputs (Level 2) | ||
Assets | ||
Cash equivalents | 0 | |
Commodity contracts, assets | 2,865 | 5,683 |
Nuclear decommissioning trust | 306,847 | 318,615 |
Other special use funds | 20,891 | 31,562 |
Total assets | 330,603 | 355,860 |
Liabilities | ||
Gross derivative liability | (69,857) | (78,646) |
Significant Other Observable Inputs (Level 2) | Cash and cash equivalent funds | ||
Assets | ||
Nuclear decommissioning trust | 0 | |
Significant Other Observable Inputs (Level 2) | Equity securities | ||
Assets | ||
Nuclear decommissioning trust | 0 | |
Other special use funds | 0 | |
Significant Other Observable Inputs (Level 2) | U.S. commingled equity funds | ||
Assets | ||
Nuclear decommissioning trust | 0 | 0 |
Significant Other Observable Inputs (Level 2) | U.S. Treasury debt | ||
Assets | ||
Nuclear decommissioning trust | 0 | 0 |
Other special use funds | 0 | |
Significant Other Observable Inputs (Level 2) | Corporate debt | ||
Assets | ||
Nuclear decommissioning trust | 104,953 | 114,007 |
Significant Other Observable Inputs (Level 2) | Mortgage-backed debt securities | ||
Assets | ||
Nuclear decommissioning trust | 112,036 | 111,874 |
Significant Other Observable Inputs (Level 2) | Municipal bonds | ||
Assets | ||
Nuclear decommissioning trust | 80,787 | 79,049 |
Other special use funds | 20,891 | |
Significant Other Observable Inputs (Level 2) | Other fixed income | ||
Assets | ||
Nuclear decommissioning trust | 9,071 | 13,685 |
Significant Unobservable Inputs (Level 3) | ||
Assets | ||
Cash equivalents | 0 | |
Commodity contracts, assets | 58 | 1,036 |
Nuclear decommissioning trust | 0 | 0 |
Other special use funds | 0 | 0 |
Total assets | 58 | 1,036 |
Liabilities | ||
Gross derivative liability | (9,921) | (19,292) |
Amount reported on balance sheet | (9,921) | (19,292) |
Significant Unobservable Inputs (Level 3) | Cash and cash equivalent funds | ||
Assets | ||
Nuclear decommissioning trust | 0 | |
Significant Unobservable Inputs (Level 3) | Equity securities | ||
Assets | ||
Nuclear decommissioning trust | 0 | |
Other special use funds | 0 | |
Significant Unobservable Inputs (Level 3) | U.S. commingled equity funds | ||
Assets | ||
Nuclear decommissioning trust | 0 | 0 |
Significant Unobservable Inputs (Level 3) | U.S. Treasury debt | ||
Assets | ||
Nuclear decommissioning trust | 0 | 0 |
Other special use funds | 0 | |
Significant Unobservable Inputs (Level 3) | Corporate debt | ||
Assets | ||
Nuclear decommissioning trust | 0 | 0 |
Significant Unobservable Inputs (Level 3) | Mortgage-backed debt securities | ||
Assets | ||
Nuclear decommissioning trust | 0 | 0 |
Significant Unobservable Inputs (Level 3) | Municipal bonds | ||
Assets | ||
Nuclear decommissioning trust | 0 | 0 |
Other special use funds | 0 | |
Significant Unobservable Inputs (Level 3) | Other fixed income | ||
Assets | ||
Nuclear decommissioning trust | 0 | 0 |
Fair Value Measured at Net Asset Value Per Share | U.S. commingled equity funds | ||
Assets | ||
Nuclear decommissioning trust | $ 459,790 | $ 417,390 |
Fair Value Measurements - Signi
Fair Value Measurements - Significant Unobservable Inputs Used to Value Level 3 Instruments (Details 2) $ in Thousands | Sep. 30, 2018USD ($)$ / MMBTU$ / MWh | Dec. 31, 2017USD ($)$ / MMBTU$ / MWh |
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments | ||
Liabilities | $ 79,730 | $ 96,422 |
Significant Unobservable Inputs (Level 3) | ||
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments | ||
Assets | 58 | 1,036 |
Liabilities | 9,921 | 19,292 |
Significant Unobservable Inputs (Level 3) | Electricity forward contracts | ||
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments | ||
Assets | 21 | |
Liabilities | 15,485 | |
Significant Unobservable Inputs (Level 3) | Natural gas contracts | ||
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments | ||
Assets | 58 | 1,015 |
Liabilities | $ 9,921 | $ 3,807 |
Discounted cash flows | Forward Price | Electricity forward contracts | Weighted Average | ||
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments | ||
Significant Unobservable Input | $ / MWh | 27.89 | |
Discounted cash flows | Forward Price | Natural gas contracts | Weighted Average | ||
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments | ||
Significant Unobservable Input | $ / MWh | 2.71 | |
Discounted cash flows | Significant Unobservable Inputs (Level 3) | Forward Price | Electricity forward contracts | Minimum | ||
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments | ||
Significant Unobservable Input | $ / MWh | 18.51 | |
Discounted cash flows | Significant Unobservable Inputs (Level 3) | Forward Price | Electricity forward contracts | Maximum | ||
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments | ||
Significant Unobservable Input | $ / MWh | 38.75 | |
Discounted cash flows | Significant Unobservable Inputs (Level 3) | Forward Price | Natural gas contracts | Minimum | ||
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments | ||
Significant Unobservable Input | $ / MMBTU | 1.75 | 2.33 |
Discounted cash flows | Significant Unobservable Inputs (Level 3) | Forward Price | Natural gas contracts | Maximum | ||
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments | ||
Significant Unobservable Input | $ / MMBTU | 2.74 | 3.11 |
Discounted cash flows | Significant Unobservable Inputs (Level 3) | Forward Price | Natural gas contracts | Weighted Average | ||
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments | ||
Significant Unobservable Input | $ / MWh | 2.23 |
Fair Value Measurements - Level
Fair Value Measurements - Level 3 Rollforward Derivatives (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward] | ||||
Net derivative balance at beginning of period | $ (9,358) | $ (36,245) | $ (18,256) | $ (47,406) |
Included in OCI | 0 | (4) | 0 | (10) |
Deferred as a regulatory asset or liability | 1,244 | (3,769) | (2,067) | (11,272) |
Settlements | (2,332) | 1,733 | (1,056) | 4,855 |
Transfers into Level 3 from Level 2 | (2,246) | (5,952) | (7,225) | (10,340) |
Transfers from Level 3 into Level 2 | 2,829 | 5,632 | 18,741 | 25,568 |
Net derivative balance at end of period | (9,863) | (38,605) | (9,863) | (38,605) |
Net unrealized gains included in earnings related to instruments still held at end of period | $ 0 | $ 0 | $ 0 | $ 0 |
Fair Value Measurements Fair Va
Fair Value Measurements Fair Value Measurements- Financial Instruments Not Carried at Fair Value (Details) $ in Millions | Sep. 30, 2018USD ($) |
Fair Value Disclosures [Abstract] | |
Stated interest rate for notes receivable | 3.90% |
Note receivable, net book value | $ 65 |
Investments in Nuclear Decomm_3
Investments in Nuclear Decommissioning Trusts and Other Special Use Funds (Details) - APS - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | Dec. 31, 2017 | |
Nuclear decommissioning trust fund assets | |||||
Fair Value | $ 1,140,427 | $ 1,140,427 | $ 901,358 | ||
Total Unrealized Gains | 291,752 | 291,752 | 260,160 | ||
Total Unrealized Losses | (11,470) | (11,470) | (2,996) | ||
Amortized cost | 667,000 | 667,000 | 467,000 | ||
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds | |||||
Realized gains | 653 | $ 598 | 2,952 | $ 3,921 | |
Realized losses | (1,965) | (1,022) | (6,990) | (4,643) | |
Proceeds from the sale of securities | 173,277 | 76,496 | 443,040 | 355,953 | |
Equity securities | |||||
Nuclear decommissioning trust fund assets | |||||
Fair Value | 478,035 | 478,035 | |||
Total Unrealized Gains | 286,121 | 286,121 | |||
Total Unrealized Losses | (47) | (47) | |||
Fair Value | 425,044 | ||||
Total Unrealized Gains | 248,623 | ||||
Total Unrealized Losses | 0 | ||||
Available for sale-fixed income securities | |||||
Nuclear decommissioning trust fund assets | |||||
Fair Value | 661,294 | 661,294 | 475,716 | ||
Total Unrealized Gains | 5,631 | 5,631 | 11,537 | ||
Total Unrealized Losses | (11,423) | (11,423) | (2,996) | ||
Fair value of fixed income securities, summarized by contractual maturities | |||||
Less than one year | 67,754 | 67,754 | |||
1 year – 5 years | 258,003 | 258,003 | |||
5 years – 10 years | 128,808 | 128,808 | |||
Greater than 10 years | 206,729 | 206,729 | |||
Total | 661,294 | 661,294 | |||
Other | |||||
Nuclear decommissioning trust fund assets | |||||
Fair Value | 1,098 | 1,098 | 598 | ||
Total Unrealized Gains | 0 | 0 | 0 | ||
Total Unrealized Losses | 0 | 0 | 0 | ||
Nuclear Decommissioning Trusts | |||||
Nuclear decommissioning trust fund assets | |||||
Fair Value | 906,687 | 906,687 | 871,000 | ||
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds | |||||
Realized gains | 653 | 598 | 2,951 | 3,904 | |
Realized losses | (1,965) | (1,022) | (6,990) | (4,634) | |
Proceeds from the sale of securities | 148,150 | 76,496 | 401,396 | 351,860 | |
Nuclear Decommissioning Trusts | Equity securities | |||||
Nuclear decommissioning trust fund assets | |||||
Fair Value | 466,002 | 466,002 | |||
Fair Value | 424,614 | ||||
Nuclear Decommissioning Trusts | Available for sale-fixed income securities | |||||
Nuclear decommissioning trust fund assets | |||||
Fair Value | 441,309 | 441,309 | |||
Fair Value | 446,277 | ||||
Fair value of fixed income securities, summarized by contractual maturities | |||||
Less than one year | 19,917 | 19,917 | |||
1 year – 5 years | 98,235 | 98,235 | |||
5 years – 10 years | 126,279 | 126,279 | |||
Greater than 10 years | 196,878 | 196,878 | |||
Total | 441,309 | 441,309 | |||
Nuclear Decommissioning Trusts | Other | |||||
Nuclear decommissioning trust fund assets | |||||
Fair Value | (624) | (624) | 109 | ||
Other Special Use Funds | |||||
Nuclear decommissioning trust fund assets | |||||
Fair Value | 233,740 | 233,740 | 30,358 | ||
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds | |||||
Realized gains | 0 | 0 | 1 | 17 | |
Realized losses | 0 | 0 | 0 | (9) | |
Proceeds from the sale of securities | 25,127 | $ 0 | 41,644 | $ 4,093 | |
Other Special Use Funds | Equity securities | |||||
Nuclear decommissioning trust fund assets | |||||
Fair Value | 12,033 | 12,033 | |||
Fair Value | 430 | ||||
Other Special Use Funds | Available for sale-fixed income securities | |||||
Nuclear decommissioning trust fund assets | |||||
Fair Value | 219,985 | 219,985 | |||
Fair Value | 29,439 | ||||
Other Special Use Funds | Other | |||||
Nuclear decommissioning trust fund assets | |||||
Fair Value | 1,722 | 1,722 | $ 489 | ||
Coal Reclamation Escrow Accounts | Available for sale-fixed income securities | |||||
Fair value of fixed income securities, summarized by contractual maturities | |||||
Less than one year | 17,244 | 17,244 | |||
1 year – 5 years | 17,170 | 17,170 | |||
5 years – 10 years | 2,529 | 2,529 | |||
Greater than 10 years | 9,851 | 9,851 | |||
Total | 46,794 | 46,794 | |||
Active Union Medical Trust | Available for sale-fixed income securities | |||||
Fair value of fixed income securities, summarized by contractual maturities | |||||
Less than one year | 30,593 | 30,593 | |||
1 year – 5 years | 142,598 | 142,598 | |||
5 years – 10 years | 0 | 0 | |||
Greater than 10 years | 0 | 0 | |||
Total | $ 173,191 | $ 173,191 |
New Accounting Standards (Detai
New Accounting Standards (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | 12 Months Ended | |||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | Dec. 31, 2018 | Jul. 03, 2018 | |
Error Corrections and Prior Period Adjustments Restatement [Line Items] | ||||||
Pre-tax income | $ 404,218 | $ 425,264 | $ 626,698 | $ 718,944 | ||
Reclassification of income tax effect related to tax reform | (8,552) | |||||
APS | ||||||
Error Corrections and Prior Period Adjustments Restatement [Line Items] | ||||||
Pre-tax income | 428,772 | $ 435,663 | 673,824 | $ 734,851 | ||
Reclassification of income tax effect related to tax reform | (5,038) | |||||
Accounting Standards Update 2017-07 | ||||||
Error Corrections and Prior Period Adjustments Restatement [Line Items] | ||||||
Pre-tax income | $ 4,000 | 11,000 | ||||
Accounting Standards Update 2017-07 | Scenario, Forecast | ||||||
Error Corrections and Prior Period Adjustments Restatement [Line Items] | ||||||
Net periodic benefit cost (credit) | $ 15,000 | |||||
Accounting Standards Update 2018-02 | ||||||
Error Corrections and Prior Period Adjustments Restatement [Line Items] | ||||||
Reclassification of income tax effect related to tax reform | 9,000 | |||||
Accounting Standards Update 2018-02 | APS | ||||||
Error Corrections and Prior Period Adjustments Restatement [Line Items] | ||||||
Reclassification of income tax effect related to tax reform | $ 5,000 | |||||
Four Corners | APS | ||||||
Error Corrections and Prior Period Adjustments Restatement [Line Items] | ||||||
Ownership interest (as a percent) | 7.00% | 7.00% | 7.00% |
Changes in Accumulated Other _3
Changes in Accumulated Other Comprehensive Loss (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | ||||
Balance at beginning of period | $ (43,626) | $ 5,135,730 | $ 4,935,912 | |
OCI (loss) before reclassifications | 9 | (6,024) | (2,911) | |
Amounts reclassified from accumulated other comprehensive loss | $ 1,550 | 1,500 | 4,504 | 4,616 |
Reclassification of income tax effect related to tax reform | (8,552) | |||
Balance at end of period | 5,485,861 | 5,277,607 | 5,485,861 | 5,277,607 |
Pension and Other Postretirement Benefits | ||||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | ||||
Balance at beginning of period | (54,233) | (39,881) | (42,440) | (39,070) |
OCI (loss) before reclassifications | 0 | (5,928) | (2,157) | |
Amounts reclassified from accumulated other comprehensive loss | 1,099 | 790 | 3,188 | 2,136 |
Reclassification of income tax effect related to tax reform | (7,954) | |||
Balance at end of period | (53,134) | (39,091) | (53,134) | (39,091) |
Derivative Instruments | ||||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | ||||
Balance at beginning of period | (2,391) | (3,745) | (2,562) | (4,752) |
OCI (loss) before reclassifications | 9 | (96) | (754) | |
Amounts reclassified from accumulated other comprehensive loss | 451 | 710 | 1,316 | 2,480 |
Reclassification of income tax effect related to tax reform | (598) | |||
Balance at end of period | (1,940) | (3,026) | (1,940) | (3,026) |
Accumulated Other Comprehensive Income (Loss) | ||||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | ||||
Balance at beginning of period | (56,624) | (45,002) | (43,822) | |
Reclassification of income tax effect related to tax reform | (8,552) | |||
Balance at end of period | (55,074) | (42,117) | (55,074) | (42,117) |
APS | ||||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | ||||
Balance at beginning of period | 5,385,869 | 5,037,970 | ||
OCI (loss) before reclassifications | 9 | (5,887) | (2,875) | |
Amounts reclassified from accumulated other comprehensive loss | 1,403 | 1,487 | 4,152 | 4,682 |
Reclassification of income tax effect related to tax reform | (5,038) | |||
Balance at end of period | 5,757,571 | 5,373,351 | 5,757,571 | 5,373,351 |
APS | Pension and Other Postretirement Benefits | ||||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | ||||
Balance at beginning of period | (32,768) | (21,367) | (24,421) | (20,671) |
OCI (loss) before reclassifications | 0 | (5,791) | (2,121) | |
Amounts reclassified from accumulated other comprehensive loss | 952 | 777 | 2,836 | 2,202 |
Reclassification of income tax effect related to tax reform | (4,440) | |||
Balance at end of period | (31,816) | (20,590) | (31,816) | (20,590) |
APS | Derivative Instruments | ||||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | ||||
Balance at beginning of period | (2,391) | (3,745) | (2,562) | (4,752) |
OCI (loss) before reclassifications | 9 | (96) | (754) | |
Amounts reclassified from accumulated other comprehensive loss | 451 | 710 | 1,316 | 2,480 |
Reclassification of income tax effect related to tax reform | (598) | |||
Balance at end of period | (1,940) | (3,026) | (1,940) | (3,026) |
APS | Accumulated Other Comprehensive Income (Loss) | ||||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | ||||
Balance at beginning of period | (35,159) | (25,112) | (26,983) | (25,423) |
Reclassification of income tax effect related to tax reform | (5,038) | |||
Balance at end of period | $ (33,756) | $ (23,616) | $ (33,756) | $ (23,616) |
Income Taxes (Details)
Income Taxes (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended |
Sep. 30, 2018 | Dec. 31, 2017 | |
Income Taxes | ||
Reduction in net deferred income tax liabilities | $ 11,000 | $ 1,140,000 |
Regulatory liabilities, non-current | 2,410,597 | 2,452,536 |
APS | ||
Income Taxes | ||
Reduction in net deferred income tax liabilities | 1,140,000 | |
Regulatory liabilities, non-current | 2,410,597 | 2,452,536 |
Gross-up for revenue requirement of rate regulation | 377,000 | |
Excess deferred income taxes - ACC - Tax Cuts and Jobs Act | APS | ||
Income Taxes | ||
Regulatory liabilities, non-current | $ 9,000 | $ 1,520,000 |