Document and Entity Information
Document and Entity Information - shares | 6 Months Ended | |
Jun. 30, 2015 | Jul. 24, 2015 | |
Entity Information [Line Items] | ||
Entity Registrant Name | PINNACLE WEST CAPITAL CORP | |
Entity Central Index Key | 764,622 | |
Document Type | 10-Q | |
Document Period End Date | Jun. 30, 2015 | |
Amendment Flag | false | |
Current Fiscal Year End Date | --12-31 | |
Entity Current Reporting Status | Yes | |
Entity Filer Category | Large Accelerated Filer | |
Entity Common Stock, Shares Outstanding | 110,813,659 | |
Document Fiscal Year Focus | 2,015 | |
Document Fiscal Period Focus | Q2 | |
Arizona Public Service Company | ||
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 | Jun. 30, 2015 | |
Amendment Flag | false | |
Current Fiscal Year End Date | --12-31 | |
Entity Current Reporting Status | Yes | |
Entity Filer Category | Non-accelerated Filer | |
Entity Common Stock, Shares Outstanding | 71,264,947 | |
Document Fiscal Year Focus | 2,015 | |
Document Fiscal Period Focus | Q2 |
CONDENSED CONSOLIDATED STATEMEN
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited) - USD ($) shares in Thousands, $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | |
OPERATING REVENUES | $ 890,648 | $ 906,264 | $ 1,561,867 | $ 1,592,515 |
OPERATING EXPENSES | ||||
Fuel and purchased power | 281,477 | 290,854 | 504,714 | 540,640 |
Operations and maintenance | 210,965 | 211,222 | 425,909 | 424,104 |
Depreciation and amortization | 122,739 | 105,150 | 243,688 | 206,922 |
Taxes other than income taxes | 43,032 | 44,004 | 86,248 | 89,849 |
Other expenses | 462 | 921 | 1,651 | 1,717 |
Total | 658,675 | 652,151 | 1,262,210 | 1,263,232 |
OPERATING INCOME | 231,973 | 254,113 | 299,657 | 329,283 |
OTHER INCOME (DEDUCTIONS) | ||||
Allowance for equity funds used during construction | 9,345 | 7,499 | 18,569 | 14,941 |
Other income (Note 9) | 175 | 2,781 | 410 | 5,148 |
Other expense (Note 9) | (2,609) | (508) | (6,895) | (5,192) |
Total | 6,911 | 9,772 | 12,084 | 14,897 |
INTEREST EXPENSE | ||||
Interest charges | 48,328 | 51,751 | 96,727 | 104,720 |
Allowance for borrowed funds used during construction | (4,322) | (3,790) | (8,538) | (7,560) |
Total | 44,006 | 47,961 | 88,189 | 97,160 |
INCOME BEFORE INCOME TAXES | 194,878 | 215,924 | 223,552 | 247,020 |
INCOME TAXES | 67,371 | 74,540 | 75,318 | 80,945 |
NET INCOME | 127,507 | 141,384 | 148,234 | 166,075 |
Less: Net income attributable to noncontrolling interests (Note 6) | 4,605 | 8,926 | 9,210 | 17,851 |
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS | $ 122,902 | $ 132,458 | $ 139,024 | $ 148,224 |
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING | ||||
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - BASIC (in shares) | 110,986 | 110,565 | 110,958 | 110,546 |
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - DILUTED (in shares) | 111,460 | 111,002 | 111,426 | 110,925 |
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING | ||||
Net income attributable to common shareholders - basic (in dollars per share) | $ 1.11 | $ 1.20 | $ 1.25 | $ 1.34 |
Net income attributable to common shareholders - diluted (in dollars per share) | 1.10 | 1.19 | 1.25 | 1.34 |
DIVIDENDS DECLARED PER SHARE (in dollars per share) | $ 1.19 | $ 1.14 | $ 1.19 | $ 1.14 |
Arizona Public Service Company | ||||
ELECTRIC OPERATING REVENUES | $ 889,723 | $ 905,578 | $ 1,560,391 | $ 1,591,123 |
OPERATING EXPENSES | ||||
Fuel and purchased power | 281,477 | 290,854 | 504,714 | 540,640 |
Operations and maintenance | 208,031 | 208,059 | 417,978 | 416,344 |
Depreciation and amortization | 122,716 | 105,127 | 243,642 | 206,875 |
Income taxes | 71,672 | 77,371 | 83,911 | 87,849 |
Taxes other than income taxes | 43,123 | 43,773 | 86,109 | 89,386 |
Total | 727,019 | 725,184 | 1,336,354 | 1,341,094 |
OPERATING INCOME | 162,704 | 180,394 | 224,037 | 250,029 |
OTHER INCOME (DEDUCTIONS) | ||||
Income taxes | 2,980 | 1,568 | 5,131 | 2,778 |
Allowance for equity funds used during construction | 9,345 | 7,499 | 18,569 | 14,941 |
Other income (Note 9) | 710 | 3,221 | 1,349 | 5,983 |
Other expense (Note 9) | (2,449) | (1,477) | (7,803) | (6,533) |
Total | 10,586 | 10,811 | 17,246 | 17,169 |
INTEREST EXPENSE | ||||
Interest on long-term debt | 44,826 | 48,462 | 90,254 | 97,358 |
Interest on short-term borrowings | 1,705 | 1,637 | 2,879 | 3,050 |
Debt discount, premium and expense | 1,103 | 1,054 | 2,237 | 2,065 |
Allowance for borrowed funds used during construction | (4,311) | (3,790) | (8,527) | (7,560) |
Total | 43,323 | 47,363 | 86,843 | 94,913 |
NET INCOME | 129,967 | 143,842 | 154,440 | 172,285 |
Less: Net income attributable to noncontrolling interests (Note 6) | 4,605 | 8,926 | 9,210 | 17,851 |
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS | $ 125,362 | $ 134,916 | $ 145,230 | $ 154,434 |
CONDENSED CONSOLIDATED STATEME3
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | |
NET INCOME | $ 127,507 | $ 141,384 | $ 148,234 | $ 166,075 |
Derivative instruments: | ||||
Net unrealized gain (loss), net of tax benefit (expense) | 25 | 40 | (775) | (381) |
Reclassification of net realized loss, net of tax benefit | 874 | 1,955 | 2,850 | 5,070 |
Pension and other postretirement benefits activity, net of tax benefit (expense) | (117) | (1,310) | 466 | (853) |
Total other comprehensive income | 782 | 685 | 2,541 | 3,836 |
COMPREHENSIVE INCOME | 128,289 | 142,069 | 150,775 | 169,911 |
Less: Comprehensive income attributable to noncontrolling interests | 4,605 | 8,926 | 9,210 | 17,851 |
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS | 123,684 | 133,143 | 141,565 | 152,060 |
Arizona Public Service Company | ||||
NET INCOME | 129,967 | 143,842 | 154,440 | 172,285 |
Derivative instruments: | ||||
Net unrealized gain (loss), net of tax benefit (expense) | 25 | 40 | (775) | (381) |
Reclassification of net realized loss, net of tax benefit | 874 | 1,954 | 2,850 | 5,070 |
Pension and other postretirement benefits activity, net of tax benefit (expense) | (74) | (1,283) | 607 | (717) |
Total other comprehensive income | 825 | 711 | 2,682 | 3,972 |
COMPREHENSIVE INCOME | 130,792 | 144,553 | 157,122 | 176,257 |
Less: Comprehensive income attributable to noncontrolling interests | 4,605 | 8,926 | 9,210 | 17,851 |
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS | $ 126,187 | $ 135,627 | $ 147,912 | $ 158,406 |
CONDENSED CONSOLIDATED STATEME4
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) (Parenthetical) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | |
Net unrealized gain (loss), tax benefit (expense) | $ (16) | $ (26) | $ (489) | $ (624) |
Reclassification of net realized loss, tax benefit | 556 | 1,261 | 923 | 2,584 |
Pension and other postretirement benefits activity, tax benefit (expense) | 74 | 845 | (793) | 128 |
Arizona Public Service Company | ||||
Net unrealized gain (loss), tax benefit (expense) | (16) | (26) | (489) | (624) |
Reclassification of net realized loss, tax benefit | 556 | 1,261 | 923 | 2,584 |
Pension and other postretirement benefits activity, tax benefit (expense) | $ 47 | $ 828 | $ (722) | $ 222 |
CONDENSED CONSOLIDATED BALANCE
CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($) $ in Thousands | Jun. 30, 2015 | Dec. 31, 2014 |
CURRENT ASSETS | ||
Cash and cash equivalents | $ 13,557 | $ 7,604 |
Customer and other receivables | 289,236 | 297,740 |
Accrued unbilled revenues | 185,216 | 100,533 |
Allowance for doubtful accounts | (2,518) | (3,094) |
Materials and supplies (at average cost) | 231,101 | 218,889 |
Fossil fuel (at average cost) | 43,196 | 37,097 |
Deferred income taxes | 77,841 | 122,232 |
Income tax receivable (Note 5) | 0 | 3,098 |
Assets from risk management activities (Note 7) | 14,722 | 13,785 |
Deferred fuel and purchased power regulatory asset (Note 3) | 0 | 6,926 |
Other regulatory assets (Note 3) | 134,578 | 129,808 |
Other current assets | 44,827 | 38,817 |
Total current assets | 1,031,756 | 973,435 |
INVESTMENTS AND OTHER ASSETS | ||
Assets from risk management activities (Note 7) | 18,513 | 17,620 |
Nuclear decommissioning trust (Note 12) | 723,582 | 713,866 |
Other assets | 51,987 | 54,047 |
Total investments and other assets | 794,082 | 785,533 |
PROPERTY, PLANT AND EQUIPMENT | ||
Plant in service and held for future use | 15,926,594 | 15,543,063 |
Accumulated depreciation and amortization | (5,497,350) | (5,397,751) |
Net | 10,429,244 | 10,145,312 |
Construction work in progress | 638,285 | 682,807 |
Palo Verde sale leaseback, net of accumulated depreciation (Note 6) | 119,320 | 121,255 |
Intangible assets, net of accumulated amortization | 127,742 | 119,755 |
Nuclear fuel, net of accumulated amortization | 156,608 | 125,201 |
Total property, plant and equipment | 11,471,199 | 11,194,330 |
DEFERRED DEBITS | ||
Regulatory assets (Note 3) | 1,081,113 | 1,054,087 |
Assets for other postretirement benefits (Note 4) | 168,755 | 152,290 |
Other | 154,578 | 153,857 |
Total deferred debits | 1,404,446 | 1,360,234 |
TOTAL ASSETS | 14,701,483 | 14,313,532 |
CURRENT LIABILITIES | ||
Accounts payable | 326,119 | 295,211 |
Accrued taxes (Note 5) | 155,812 | 140,613 |
Accrued interest | 54,547 | 52,603 |
Common dividends payable | 65,933 | 65,790 |
Short-term borrowings (Note 2) | 157,500 | 147,400 |
Current maturities of long-term debt (Note 2) | 102,723 | 383,570 |
Customer deposits | 72,785 | 72,307 |
Liabilities from risk management activities (Note 7) | 60,673 | 59,676 |
Deferred fuel and purchased power regulatory liability (Note 3) | 16,209 | 0 |
Liabilities for asset retirements (Note 15) | 28,543 | 32,462 |
Other regulatory liabilities (Note 3) | 136,273 | 130,549 |
Other current liabilities | 162,742 | 178,962 |
Total current liabilities | 1,339,859 | 1,559,143 |
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 2) | 3,565,857 | 3,031,215 |
DEFERRED CREDITS AND OTHER | ||
Deferred income taxes | 2,614,274 | 2,582,636 |
Regulatory liabilities (Note 3) | 1,016,991 | 1,051,196 |
Liabilities for asset retirements (Note 15) | 419,072 | 358,288 |
Liabilities for pension benefits (Note 4) | 425,002 | 453,736 |
Liabilities from risk management activities (Note 7) | 87,689 | 50,602 |
Customer advances | 120,063 | 123,052 |
Coal mine reclamation | 200,155 | 198,292 |
Deferred investment tax credit | 176,389 | 178,607 |
Unrecognized tax benefits (Note 5) | 14,311 | 19,377 |
Other | 196,178 | 188,286 |
Total deferred credits and other | $ 5,270,124 | $ 5,204,072 |
COMMITMENTS AND CONTINGENCIES (SEE NOTES) | ||
EQUITY | ||
Common stock, no par value; authorized 150,000,000 shares, 110,865,030 and 110,649,762 issued at respective dates | $ 2,526,945 | $ 2,512,970 |
Treasury stock at cost; 53,559 and 78,400 shares at respective dates | (1,765) | (3,401) |
Total common stock | 2,525,180 | 2,509,569 |
Retained earnings | 1,933,256 | 1,926,065 |
Accumulated other comprehensive loss: | ||
Pension and other postretirement benefits | (57,290) | (57,756) |
Derivative instruments | (8,310) | (10,385) |
Total accumulated other comprehensive loss | (65,600) | (68,141) |
Total shareholders’ equity | 4,392,836 | 4,367,493 |
Noncontrolling interests (Note 6) | 132,807 | 151,609 |
Total equity | 4,525,643 | 4,519,102 |
TOTAL LIABILITIES AND EQUITY | 14,701,483 | 14,313,532 |
Arizona Public Service Company | ||
CURRENT ASSETS | ||
Cash and cash equivalents | 7,973 | 4,515 |
Customer and other receivables | 281,609 | 297,712 |
Accrued unbilled revenues | 185,216 | 100,533 |
Allowance for doubtful accounts | (2,518) | (3,094) |
Materials and supplies (at average cost) | 231,101 | 218,889 |
Fossil fuel (at average cost) | 43,196 | 37,097 |
Deferred income taxes | 54,789 | 55,253 |
Assets from risk management activities (Note 7) | 14,722 | 13,785 |
Deferred fuel and purchased power regulatory asset (Note 3) | 0 | 6,926 |
Other regulatory assets (Note 3) | 134,578 | 129,808 |
Other current assets | 44,168 | 38,693 |
Total current assets | 994,834 | 900,117 |
INVESTMENTS AND OTHER ASSETS | ||
Assets from risk management activities (Note 7) | 18,513 | 17,620 |
Nuclear decommissioning trust (Note 12) | 723,582 | 713,866 |
Other assets | 33,976 | 33,362 |
Total investments and other assets | 776,071 | 764,848 |
PROPERTY, PLANT AND EQUIPMENT | ||
Plant in service and held for future use | 15,923,342 | 15,539,811 |
Accumulated depreciation and amortization | (5,494,236) | (5,394,650) |
Net | 10,429,106 | 10,145,161 |
Construction work in progress | 636,927 | 682,807 |
Palo Verde sale leaseback, net of accumulated depreciation (Note 6) | 119,320 | 121,255 |
Intangible assets, net of accumulated amortization | 127,587 | 119,600 |
Nuclear fuel, net of accumulated amortization | 156,608 | 125,201 |
Total property, plant and equipment | 11,469,548 | 11,194,024 |
DEFERRED DEBITS | ||
Regulatory assets (Note 3) | 1,081,113 | 1,054,087 |
Assets for other postretirement benefits (Note 4) | 165,682 | 149,260 |
Unamortized debt issue costs | 27,843 | 24,642 |
Other | 125,694 | 128,026 |
Total deferred debits | 1,400,332 | 1,356,015 |
TOTAL ASSETS | 14,640,785 | 14,215,004 |
CURRENT LIABILITIES | ||
Accounts payable | 321,860 | 289,930 |
Accrued taxes (Note 5) | 199,492 | 131,110 |
Accrued interest | 54,314 | 52,358 |
Common dividends payable | 65,900 | 65,800 |
Short-term borrowings (Note 2) | 157,500 | 147,400 |
Current maturities of long-term debt (Note 2) | 102,723 | 383,570 |
Customer deposits | 72,785 | 72,307 |
Liabilities from risk management activities (Note 7) | 60,673 | 59,676 |
Deferred fuel and purchased power regulatory liability (Note 3) | 16,209 | 0 |
Liabilities for asset retirements (Note 15) | 28,543 | 32,462 |
Other regulatory liabilities (Note 3) | 136,273 | 130,549 |
Other current liabilities | 132,800 | 167,302 |
Total current liabilities | 1,349,072 | 1,532,464 |
DEFERRED CREDITS AND OTHER | ||
Deferred income taxes | 2,601,294 | 2,571,365 |
Regulatory liabilities (Note 3) | 1,016,991 | 1,051,196 |
Liabilities for asset retirements (Note 15) | 419,072 | 358,288 |
Liabilities for pension benefits (Note 4) | 397,160 | 424,508 |
Liabilities from risk management activities (Note 7) | 87,689 | 50,602 |
Customer advances | 120,063 | 123,052 |
Coal mine reclamation | 200,155 | 198,292 |
Deferred investment tax credit | 176,389 | 178,607 |
Unrecognized tax benefits (Note 5) | 45,305 | 45,740 |
Other | 159,574 | 144,823 |
Total deferred credits and other | $ 5,223,692 | $ 5,146,473 |
COMMITMENTS AND CONTINGENCIES (SEE NOTES) | ||
EQUITY | ||
Total common stock | $ 178,162 | $ 178,162 |
Additional paid-in capital | 2,379,696 | 2,379,696 |
Retained earnings | 1,982,150 | 1,968,718 |
Accumulated other comprehensive loss: | ||
Pension and other postretirement benefits | (37,341) | (37,948) |
Derivative instruments | (8,310) | (10,385) |
Total accumulated other comprehensive loss | (45,651) | (48,333) |
Total shareholders’ equity | 4,494,357 | 4,478,243 |
Noncontrolling interests (Note 6) | 132,807 | 151,609 |
Total equity | 4,627,164 | 4,629,852 |
Long-term debt less current maturities (Note 2) | 3,440,857 | 2,906,215 |
Total capitalization | 8,068,021 | 7,536,067 |
TOTAL LIABILITIES AND EQUITY | $ 14,640,785 | $ 14,215,004 |
CONDENSED CONSOLIDATED BALANCE6
CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical) - $ / shares None in scaling factor is -9223372036854775296 | Jun. 30, 2015 | Dec. 31, 2014 |
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest [Abstract] | ||
Common stock, par value (in dollars per share) | ||
Common stock, authorized shares | 150,000,000 | 150,000,000 |
Common stock, issued shares | 110,865,030 | 110,649,762 |
Treasury stock at cost, shares | 53,559 | 78,400 |
CONDENSED CONSOLIDATED STATEME7
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($) $ in Thousands | 6 Months Ended | |
Jun. 30, 2015 | Jun. 30, 2014 | |
CASH FLOWS FROM OPERATING ACTIVITIES | ||
NET INCOME | $ 148,234 | $ 166,075 |
Adjustments to reconcile net income to net cash provided by operating activities: | ||
Depreciation and amortization including nuclear fuel | 282,218 | 246,371 |
Deferred fuel and purchased power | 11,711 | 1,315 |
Deferred fuel and purchased power amortization | 11,424 | 18,399 |
Allowance for equity funds used during construction | (18,569) | (14,941) |
Deferred income taxes | 65,377 | 32,611 |
Deferred investment tax credit | (2,218) | 28,875 |
Change in derivative instruments fair value | (225) | 49 |
Changes in current assets and liabilities: | ||
Customer and other receivables | (17,402) | (64,986) |
Accrued unbilled revenues | (84,683) | (75,648) |
Materials, supplies and fossil fuel | (18,311) | (9,435) |
Income tax receivable | 3,098 | 135,517 |
Other current assets | (8,728) | (14,038) |
Accounts payable | 36,634 | 30,725 |
Accrued taxes | 15,199 | 30,709 |
Other current liabilities | (13,138) | 19,978 |
Change in margin and collateral accounts — assets | (4,552) | (2,107) |
Change in margin and collateral accounts — liabilities | 26,853 | (22,425) |
Change in other long-term assets | (4,817) | (19,243) |
Change in other long-term liabilities | (33,811) | (22,735) |
Net cash flow provided by operating activities | 394,294 | 465,066 |
CASH FLOWS FROM INVESTING ACTIVITIES | ||
Capital expenditures | (531,035) | (388,752) |
Contributions in aid of construction | 41,010 | 12,646 |
Allowance for borrowed funds used during construction | (8,538) | (7,560) |
Proceeds from nuclear decommissioning trust sales | 225,779 | 199,224 |
Investment in nuclear decommissioning trust | (234,651) | (207,848) |
Other | (2,068) | (678) |
Net cash flow used for investing activities | (509,503) | (392,968) |
CASH FLOWS FROM FINANCING ACTIVITIES | ||
Issuance of long-term debt | 600,000 | 535,975 |
Repayment of long-term debt | (344,847) | (503,583) |
Short-term borrowings and payments — net | 10,100 | 23,525 |
Dividends paid on common stock | (128,241) | (125,138) |
Common stock equity issuance | 12,161 | 12,625 |
Distributions to noncontrolling interest | (28,012) | (15,869) |
Other | 1 | 2 |
Net cash flow provided by (used for) financing activities | 121,162 | (72,463) |
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS | 5,953 | (365) |
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD | 7,604 | 9,526 |
CASH AND CASH EQUIVALENTS AT END OF PERIOD | 13,557 | 9,161 |
Cash paid (received) during the period for: | ||
Income taxes, net of refunds | 1,834 | (131,154) |
Interest, net of amounts capitalized | 84,008 | 90,707 |
Significant non-cash investing and financing activities: | ||
Accrued capital expenditures | 38,985 | 19,668 |
Dividends declared but not yet paid | 65,933 | 62,656 |
Arizona Public Service Company | ||
CASH FLOWS FROM OPERATING ACTIVITIES | ||
NET INCOME | 154,440 | 172,285 |
Adjustments to reconcile net income to net cash provided by operating activities: | ||
Depreciation and amortization including nuclear fuel | 282,172 | 246,324 |
Deferred fuel and purchased power | 11,711 | 1,315 |
Deferred fuel and purchased power amortization | 11,424 | 18,399 |
Allowance for equity funds used during construction | (18,569) | (14,941) |
Deferred income taxes | 24,442 | 34,133 |
Deferred investment tax credit | (2,218) | 28,875 |
Change in derivative instruments fair value | (225) | 49 |
Changes in current assets and liabilities: | ||
Customer and other receivables | (9,250) | (65,603) |
Accrued unbilled revenues | (84,683) | (75,648) |
Materials, supplies and fossil fuel | (18,311) | (9,435) |
Income tax receivable | 0 | 135,179 |
Other current assets | (8,193) | (14,120) |
Accounts payable | 37,656 | 28,465 |
Accrued taxes | 68,382 | 38,381 |
Other current liabilities | (31,408) | 31,296 |
Change in margin and collateral accounts — assets | (4,552) | (2,107) |
Change in margin and collateral accounts — liabilities | 26,853 | (22,425) |
Change in other long-term assets | (6,765) | (18,703) |
Change in other long-term liabilities | (27,136) | (24,467) |
Net cash flow provided by operating activities | 405,770 | 487,252 |
CASH FLOWS FROM INVESTING ACTIVITIES | ||
Capital expenditures | (530,850) | (388,752) |
Contributions in aid of construction | 41,010 | 12,646 |
Allowance for borrowed funds used during construction | (8,527) | (7,560) |
Proceeds from nuclear decommissioning trust sales | 225,779 | 199,224 |
Investment in nuclear decommissioning trust | (234,651) | (207,848) |
Other | (614) | (678) |
Net cash flow used for investing activities | (507,853) | (392,968) |
CASH FLOWS FROM FINANCING ACTIVITIES | ||
Issuance of long-term debt | 600,000 | 535,975 |
Repayment of long-term debt | (344,847) | (503,583) |
Short-term borrowings and payments — net | 10,100 | 19,650 |
Dividends paid on common stock | (131,700) | (125,100) |
Distributions to noncontrolling interest | (28,012) | (15,869) |
Net cash flow provided by (used for) financing activities | 105,541 | (88,927) |
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS | 3,458 | 5,357 |
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD | 4,515 | 3,725 |
CASH AND CASH EQUIVALENTS AT END OF PERIOD | 7,973 | 9,082 |
Cash paid (received) during the period for: | ||
Income taxes, net of refunds | 184 | (134,399) |
Interest, net of amounts capitalized | 82,651 | 88,461 |
Significant non-cash investing and financing activities: | ||
Accrued capital expenditures | 38,985 | 19,668 |
Dividends declared but not yet paid | $ 65,900 | $ 62,600 |
CONDENSED CONSOLIDATED STATEME8
CONDENSED CONSOLIDATED STATEMENTS OF EQUITY (Unaudited) - USD ($) $ in Thousands | Total | Common Stock | Treasury Stock | Retained Earnings | Accumulated Other Comprehensive Income (Loss) | Noncontrolling Interests | Arizona Public Service Company | Arizona Public Service CompanyCommon Stock | Arizona Public Service CompanyAdditional Paid-in Capital | Arizona Public Service CompanyRetained Earnings | Arizona Public Service CompanyAccumulated Other Comprehensive Income (Loss) | Arizona Public Service CompanyNoncontrolling Interests | |
Beginning balance (in shares) at Dec. 31, 2013 | 110,280,703 | 98,944 | 71,264,947 | ||||||||||
Beginning balance at Dec. 31, 2013 | $ 4,340,460 | $ 2,491,558 | $ (4,308) | $ 1,785,273 | $ (78,053) | $ 145,990 | $ 4,454,874 | $ 178,162 | $ 2,379,696 | $ 1,804,398 | $ (53,372) | $ 145,990 | |
Increase (Decrease) in Shareholders' Equity | |||||||||||||
Net income | 166,075 | 148,224 | 17,851 | 172,285 | 154,434 | 17,851 | |||||||
Other comprehensive income | 3,836 | 3,836 | 3,972 | 3,972 | |||||||||
Dividends on common stock | (125,265) | (125,265) | (125,200) | (125,200) | |||||||||
Other | 3 | 3 | |||||||||||
Issuance of common stock (in shares) | 149,753 | ||||||||||||
Issuance of common stock | 8,506 | $ 8,506 | |||||||||||
Purchase of treasury stock (in shares) | [1] | (82,474) | |||||||||||
Purchase of treasury stock | [1] | (4,535) | $ (4,535) | ||||||||||
Stock-based compensation and other (in shares) | 157,594 | ||||||||||||
Stock-based compensation and other | 8,654 | $ 8,654 | |||||||||||
Net capital activities by noncontrolling interests | (15,869) | (15,869) | (15,869) | (15,869) | |||||||||
Ending balance (in shares) at Jun. 30, 2014 | 110,430,456 | 23,824 | 71,264,947 | ||||||||||
Ending balance at Jun. 30, 2014 | $ 4,381,862 | $ 2,500,064 | $ (189) | 1,808,232 | (74,217) | 147,972 | 4,490,065 | $ 178,162 | 2,379,696 | 1,833,635 | (49,400) | 147,972 | |
Beginning balance (in shares) at Dec. 31, 2014 | 110,649,762 | 110,649,762 | 78,400 | 71,264,947 | |||||||||
Beginning balance at Dec. 31, 2014 | $ 4,519,102 | $ 2,512,970 | $ (3,401) | 1,926,065 | (68,141) | 151,609 | 4,629,852 | $ 178,162 | 2,379,696 | 1,968,718 | (48,333) | 151,609 | |
Increase (Decrease) in Shareholders' Equity | |||||||||||||
Net income | 148,234 | 139,024 | 9,210 | 154,440 | 145,230 | 9,210 | |||||||
Other comprehensive income | 2,541 | 2,541 | 2,682 | 2,682 | |||||||||
Dividends on common stock | (131,833) | (131,833) | (131,800) | (131,800) | |||||||||
Other | 2 | 2 | |||||||||||
Issuance of common stock (in shares) | 215,268 | ||||||||||||
Issuance of common stock | 13,975 | $ 13,975 | |||||||||||
Purchase of treasury stock (in shares) | [1] | (93,280) | |||||||||||
Purchase of treasury stock | [1] | (6,096) | $ (6,096) | ||||||||||
Stock-based compensation and other (in shares) | 118,121 | ||||||||||||
Stock-based compensation and other | 7,732 | $ 7,732 | |||||||||||
Net capital activities by noncontrolling interests | $ (28,012) | (28,012) | (28,012) | (28,012) | |||||||||
Ending balance (in shares) at Jun. 30, 2015 | 110,865,030 | 110,865,030 | 53,559 | 71,264,947 | |||||||||
Ending balance at Jun. 30, 2015 | $ 4,525,643 | $ 2,526,945 | $ (1,765) | $ 1,933,256 | $ (65,600) | $ 132,807 | $ 4,627,164 | $ 178,162 | $ 2,379,696 | $ 1,982,150 | $ (45,651) | $ 132,807 | |
[1] | Primarily represents shares of common stock withheld from certain stock awards for tax purposes. |
Consolidation and Nature of Ope
Consolidation and Nature of Operations | 6 Months Ended |
Jun. 30, 2015 | |
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, Bright Canyon Energy Corporation ("BCE") and El Dorado Investment Company ("El Dorado"). 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 Nuclear 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. Weather conditions cause significant seasonal fluctuations in our revenues; therefore, results for interim periods do not necessarily represent results expected for the year. Our condensed consolidated financial statements have been prepared pursuant to the rules and regulations of the United States Securities and Exchange Commission ("SEC"). 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. Supplemental Cash Flow Information The following table summarizes supplemental Pinnacle West cash flow information (dollars in thousands): Six Months Ended 2015 2014 Cash paid (received) during the period for: Income taxes, net of refunds $ 1,834 $ (131,154 ) Interest, net of amounts capitalized 84,008 90,707 Significant non-cash investing and financing activities: Accrued capital expenditures $ 38,985 $ 19,668 Dividends accrued but not yet paid 65,933 62,656 |
Long-Term Debt and Liquidity Ma
Long-Term Debt and Liquidity Matters | 6 Months Ended |
Jun. 30, 2015 | |
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. Pinnacle West Pinnacle West's $200 million revolving credit facility matures in May 2019. At June 30, 2015 , the facility was available to refinance indebtedness of the Company and for other general corporate purposes, including credit support for its $200 million commercial paper program. Pinnacle West has the option to increase the size of the facility up to a maximum of $300 million upon the satisfaction of certain conditions and with the consent of the lenders. At June 30, 2015 , Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding and no commercial paper borrowings. APS On January 12, 2015, APS issued $250 million of 2.20% unsecured senior notes that mature on January 15, 2020. The net proceeds from the sale were used to repay commercial paper borrowings and replenish cash used to fund capital expenditures. On May 19, 2015, APS issued $300 million of 3.15% unsecured senior notes that mature on May 15, 2025. The net proceeds from the sale were used to repay short-term indebtedness c onsisting of commercial paper borrowings and drawings under our revolving credit facilities, incurred in connection with the payment at maturity of our $300 million aggregate principal amount of 4.65% Notes due May 15, 2015. On May 28, 2015, APS purchased all $32 million of Maricopa County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds, 2009 Series B, due 2029 in connection with the mandatory tender provisions for this indebtedness. On June 26, 2015, APS entered into a $50 million term loan facility that matures June 26, 2018. Interest rates are based on APS’s senior unsecured debt credit ratings. APS used the proceeds to repay and refinance existing short-term indebtedness. At June 30, 2015 , APS had two credit facilities totaling $1 billion , including a $500 million credit facility that matures in April 2018 and a $500 million facility that matures in May 2019. APS may increase the size of each facility up to a maximum of $700 million upon the satisfaction of certain conditions and with the consent of the lenders. APS will use these facilities to refinance indebtedness and for other general corporate purposes. Interest rates are based on APS’s senior unsecured debt credit ratings. The facilities described above are available to support APS’s $250 million commercial paper program, for bank borrowings or for issuances of letters of credit. At June 30, 2015 , APS had $158 million of commercial paper outstanding and no outstanding borrowings or letters of credit under these credit facilities. See "Financial Assurances" in Note 8 for a discussion of APS’s separate outstanding letters of credit. Debt Fair Value Our long-term debt fair value estimates are based on quoted market prices for the same or similar issues, and are classified within Level 2 of the fair value hierarchy. Certain of our debt instruments contain third-party credit enhancements and, in accordance with GAAP, we do not consider the effect of these credit enhancements when determining fair value. The following table represents the estimated fair value of our long-term debt, including current maturities (dollars in millions): As of June 30, 2015 As of December 31, 2014 Carrying Amount Fair Value Carrying Amount Fair Value Pinnacle West $ 125 $ 125 $ 125 $ 125 APS 3,544 3,818 3,290 3,714 Total $ 3,669 $ 3,943 $ 3,415 $ 3,839 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 June 30, 2015 , APS was in compliance with this common equity ratio requirement. Its total shareholder equity was approximately $4.5 billion , and total capitalization was approximately $8.2 billion . APS would be prohibited from paying dividends if the payment would reduce its total shareholder equity below approximately $3.3 billion , assuming APS’s total capitalization remains the same. |
Regulatory Matters
Regulatory Matters | 6 Months Ended |
Jun. 30, 2015 | |
Regulated Operations [Abstract] | |
Regulatory Matters | Regulatory Matters Retail 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 . APS requested that the increase become effective July 1, 2012. The request would have increased the average retail customer bill by approximately 6.6% . 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. Settlement Agreement The 2012 Settlement Agreement provides for a zero net change in base rates, consisting of: (1) a non-fuel base rate increase of $116.3 million ; (2) a fuel-related base rate decrease of $153.1 million (to be implemented by a change in the base fuel rate for fuel and purchased power costs ("Base Fuel Rate") from $0.03757 to $0.03207 per kilowatt hour ("kWh"); and (3) the transfer of cost recovery for certain renewable energy projects from the Arizona Renewable Energy Standard and Tariff ("RES") surcharge to base rates in an estimated amount of $36.8 million . Other key provisions of the 2012 Settlement Agreement include the following: • An authorized return on common equity of 10.0% ; • A capital structure comprised of 46.1% debt and 53.9% common equity; • A test year ended December 31, 2010, adjusted to include plant that is in service as of March 31, 2012; • Deferral for future recovery or refund of property taxes above or below a specified 2010 test year level caused by changes to the Arizona property tax rate as follows: • Deferral of increases in property taxes of 25% in 2012, 50% in 2013 and 75% for 2014 and subsequent years if Arizona property tax rates increase; and • Deferral of 100% in all years if Arizona property tax rates decrease; • A procedure to allow APS to request rate adjustments prior to its next general rate case related to APS’s acquisition of additional interests in Units 4 and 5 and the related closure of Units 1-3 of the Four Corners Power Plant ("Four Corners") (APS made its filing under this provision on December 30, 2013, see "Four Corners" below); • Implementation of a Lost Fixed Cost Recovery ("LFCR") rate mechanism to support energy efficiency and distributed renewable generation; • Modifications to the Environmental Improvement Surcharge ("EIS") to allow for the recovery of carrying costs for capital expenditures associated with government-mandated environmental controls, subject to an existing cents per kWh cap on cost recovery that could produce up to approximately $5 million in revenues annually; • Modifications to the Power Supply Adjustor ("PSA"), including the elimination of the 9 0/10 sharing provision; • A limitation on the use of the RES surcharge and the Demand Side Management Adjustor Charge ("DSMAC") to recoup capital expenditures not required under the terms of APS’s 2009 retail rate case settlement agreement (the "2009 Settlement Agreement"); • Allowing a negative credit that existed in the PSA rate to continue until February 2013, rather than being reset on the anticipated July 1, 2012 rate effective date; • Modification of the transmission cost adjustor ("TCA") to streamline the process for future transmission-related rate changes; and • Implementation of various changes to rate schedules, including the adoption of an experimental "buy-through" rate that could allow certain large commercial and industrial customers to select alternative sources of generation to be supplied by APS. The 2012 Settlement Agreement was approved by the ACC on May 15, 2012, with new rates effective on July 1, 2012. This accomplished a goal set by the parties to the 2009 Settlement Agreement to process subsequent rate cases within twelve months of sufficiency findings from the ACC staff, which generally occurs within 30 days after the filing of a rate case. Cost Recovery Mechanisms APS has received regulatory decisions that allow for more timely recovery of certain costs 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. On July 12, 2013, APS filed its annual RES implementation plan, covering the 2014-2018 timeframe and requesting a 2014 RES budget of approximately $143 million . In a final order dated January 7, 2014, the ACC approved the requested budget. Also 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 accordance with the ACC’s decision on the 2014 RES plan, on April 15, 2014, APS filed an application with the ACC requesting pe rmission to build an additional 20 Megawatt ("MW") of APS-owned utility scale solar under the AZ Sun Program. In a subsequent filing, APS also offered an alternative proposal to replace the 20 MW of utility scale solar with 10 MW (approximately 1,500 customers) of APS-owned residential solar that will not be under the AZ Sun Program. On December 19, 2014, the ACC voted that it had no objection to APS implementing its residential rooftop solar program. The first stage of the residential rooftop solar program is to be 8 MW followed by a 2 MW second stage that will only be deployed if coupled with an appropriate amount of distributed storage. The program will target specific distribution feeders in an effort to maximize potential system benefits, as well as make systems available to limited-income customers who cannot easily install solar through transactions with third parties. The ACC expressly reserved that any determination of prudency of the residential rooftop solar program for rate making purposes shall not be made until the project is fully in service and APS requests cost recovery in a future rate case. On July 1, 2014, APS filed its 2015 RES implementation plan and proposed a RES budget of approximately $154 million . On December 31, 2014, the ACC issued a decision approving the 2015 RES implementation plan with minor modifications, including reducing the budget to approximately $152 million . On July 1, 2015, APS filed its 2016 RES implementation plan and proposed a RES budget of approximately $148 million . Demand Side Management Adjustor Charge . The ACC Electric Energy Efficiency Standards require APS to submit a Demand Side Management Implementation Plan ("DSM Plan") for review by and approval of the ACC. On June 1, 2012, APS filed its 2013 DSM Plan. In 2013, the standards required APS to achieve cumulative energy savings equal to 5% of its 2012 retail energy sales. Later in 2012, APS filed a supplement to its plan that included a proposed budget for 2013 of $87.6 million . On March 11, 2014, the ACC issued an order approving APS’s 2013 DSM Plan. The ACC approved a budget of $68.9 million for each of 2013 and 2014. The ACC also approved a Resource Savings Initiative that allows APS to count towards compliance with the ACC Electric Energy Efficiency Standards, savings for improvements to APS’s transmission and delivery system, generation and facilities that have been approved through a DSM Plan. 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. Consistent with the ACC’s March 11, 2014 order, APS intends to continue its other approved DSM programs in 2015. On June 1, 2015, APS filed its 2016 DSM Plan requesting a budget of $68.9 million and minor modifications to its DSM portfolio to increase energy savings and cost effectiveness of the programs. The DSM Plan also proposed a reduction in the DSMAC of approximately 12% . Electric Energy Efficiency On June 27, 2013, the ACC voted to open a new docket investigating whether the Electric Energy Efficiency Standards should be modified. The ACC held a series of three workshops in March and April 2014 to investigate methodologies used to determine cost effective energy efficiency programs, cost recovery mechanisms, incentives, and potential changes to the Electric Energy Efficiency and Resource Planning Rules. On November 4, 2014, the ACC staff issued a request for informal comment on a draft of possible amendments to Arizona’s Electric Energy Efficiency Standards. The draft proposed substantial changes to the rules and energy efficiency standards. The ACC accepted written comments and took public comment regarding the possible amendments on December 19, 2014. A formal rule making has not been initiated and there has been no additional action on the draft to date. PSA Mechanism and Balance. The PSA provides for the adjustment of retail rates to reflect variations in retail fuel and purchased power costs. The following table shows the changes in the deferred fuel and purchased power regulatory asset (liability) for 2015 and 2014 (dollars in millions): Six Months Ended 2015 2014 Beginning balance $ 7 $ 21 Deferred fuel and purchased power costs — current period (12 ) (1 ) Amounts charged to customers (11 ) (19 ) Ending balance $ (16 ) $ 1 The PSA rate for the PSA year beginning February 1, 2015 is $0.000887 per kWh, as compared to $0.001557 per kWh for the prior year. This new rate is comprised of a forward component of $0.001131 per kWh and a historical component of $(0.000244) per kWh. Any uncollected (overcollected) deferrals during the 2015 PSA year will be included in the calculation of the PSA rate for the PSA year beginning February 1, 2016. Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters . In July 2008, the United States Federal Energy Regulatory Commission ("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 Charge because any adjustment, though applied prospectively, may be calculated to account for previously over- or under-collected amounts. Effective June 1, 2014, APS’s annual wholesale transmission rates for all users of its transmission system increased by approximately $5.9 million for the twelve-month period beginning June 1, 2014 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, 2014. Effective June 1, 2015, APS’s annual wholesale transmission rates for all users of its transmission system decreased by approximately $17.6 million for the twelve-month period beginning June 1, 2015 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, 2015. APS's formula rate protocols have been in effect since 2008. Recent FERC orders suggest that FERC is examining the structure of formula rate protocols and may require companies such as APS to make changes to their protocols in the future. 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 distributed generation such as rooftop solar arrays. The fixed costs recoverable by the LFCR mechanism were 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. The LFCR adjustment has a year-over-year cap of 1% of retail revenues. Any amounts left unrecovered in a particular year because of this cap can be carried over for recovery in a future year. The kWh’s lost from energy efficiency are based on a third-party evaluation of APS’s energy efficiency programs. Distributed generation sales losses are determined from the metered output from the distributed generation units or if metering is unavailable, through accepted estimating techniques. APS files for a LFCR adjustment every January. APS filed its 2014 annual LFCR adjustment on January 15, 2014, requesting a LFCR adjustment of $25.3 million , effective March 1, 2014. The ACC approved APS’s LFCR adjustment without change on March 11, 2014, which became effective April 1, 2014. APS filed its 2015 annual LFCR adjustment on January 15, 2015, requesting an LFCR adjustment of $38.5 million , which was approved on March 2, 2015, effective for the first billing cycle of March. Deregulation On May 9, 2013, the ACC voted to re-examine the facilitation of a deregulated retail electric market in Arizona. The ACC subsequently opened a docket for this matter and received comments from a number of interested parties on the considerations involved in establishing retail electric deregulation in the state. One of these considerations is whether various aspects of a deregulated market, including setting utility rates on a "market" basis, would be consistent with the requirements of the Arizona Constitution. On September 11, 2013, after receiving legal advice from the ACC staff, the ACC voted 4-1 to close the current docket and await full Arizona Constitutional authority before any further examination of this matter. The motion approved by the ACC also included opening one or more new dockets in the future to explore options to offer more rate choices to customers and innovative changes within the existing cost-of-service regulatory model that could include elements of competition. The ACC opened a new docket on November 4, 2013 to explore technological advances and innovative changes within the electric utility industry. A series of workshops in this docket were held in 2014 and early 2015. No further action has been taken by the ACC to date. Net Metering On July 12, 2013, APS filed an application with the ACC proposing a solution to address the cost shift brought by the current net metering rules. On December 3, 2013, the ACC issued its order on APS’s net metering proposal. The ACC instituted a charge on customers who install rooftop solar panels after December 31, 2013. The charge of $0.70 per kilowatt became effective on January 1, 2014, and is estimated to collect $4.90 per month from a typical future rooftop solar customer to help pay for their use of the electricity grid. The fixed charge does not increase APS's revenue because it is credited to the LFCR. In making its decision, the ACC determined that the current net metering program creates a cost shift, causing non-solar utility customers to pay higher rates to cover the costs of maintaining the electrical grid. The ACC acknowledged that the $0.70 per kilowatt charge addresses only a portion of the cost shift. In its December 2013 order, the ACC directed APS to provide quarterly reports on the pace of rooftop solar adoption to assist the ACC in considering further increases. On April 2, 2015, APS filed an application with the ACC seeking to increase the fixed grid access charge to $3.00 per kilowatt, or approximately $21 per month for a typical new residential solar customer, effective August 1. Customers who installed rooftop solar panels prior to January 1, 2014 would continue to be grandfathered and would not pay a grid access charge, and those who installed panels between January 1, 2014 and the effective date of the requested change would continue paying a charge of $0.70 per kilowatt. Solar customers that take electric service under APS’s demand-based ECT-2 residential rate, an existing rate that includes time-of-use rates with a demand charge, are not subject to the grid access charge. APS cannot predict the outcome of this filing. The proposed grid access charge adjustment is designed to moderate the cost shift discussed above on an interim basis until the issue is further addressed in APS’s next general rate case. On September 29, 2014, the staff of the ACC filed in a new docket a proposal for permitting a utility to request ACC approval of its proposed rate design outside of and before a general rate case. On October 20, 2014, APS and other interested stakeholders filed comments to this proposal. No further action has been taken in this docket. Four Corners On December 30, 2013, APS purchased Southern California Edison Company's ("SCE’s") 48% ownership interest in each of Units 4 and 5 of Four Corners. The 2012 Settlement Agreement includes a procedure to allow APS to request rate adjustments prior to its next general rate case related to APS’s acquisition of the additional interests in Units 4 and 5 and the related closure of Units 1-3 of Four Corners. APS made its filing under this provision on December 30, 2013. On December 23, 2014, the ACC approved rate adjustments resulting in a revenue increase of $57.1 million on an annual basis. This includes the deferral for future recovery of all non-fuel operating costs for the acquired SCE interest in Four Corners, net of the non-fuel operating costs savings resulting from the closure of Units 1-3 from the date of closing of the purchase through its inclusion in rates. The 2012 Settlement Agreement also provides for deferral for future recovery of all unrecovered costs incurred in connection with the closure of Units 1-3. The deferral balance related to the acquisition of SCE’s interest in Units 4 and 5 and the closure of Units 1-3 was $74 million as of June 30, 2015 and is being amortized in rates over 10 years. On February 23, 2015, the Arizona School Boards Association and the Association of Business Officials filed a notice of appeal in Division 1 of the Arizona Court of Appeals of the ACC decision approving the rate adjustments. APS has intervened and will actively participate in the proceeding. We cannot predict when or how this appeal will be resolved. As part of APS’s acquisition of SCE’s interest in Units 4 and 5, APS and SCE agreed, via a "Transmission Termination Agreement" that, upon closing of the acquisition, the companies would terminate an existing transmission agreement ("Transmission Agreement") between the parties that provides transmission capacity on a system (the "Arizona Transmission System") for SCE to transmit its portion of the output from Four Corners to California. APS previously submitted a request to FERC related to this termination, which resulted in a FERC order denying rate recovery of $40 million that APS agreed to pay SCE associated with the termination. APS and SCE negotiated an alternate arrangement under which SCE would assign its 1,555 MW capacity rights over the Arizona Transmission System to third-parties, including 300 MW to APS’s marketing and trading group. However, this alternative arrangement was not approved by FERC. Although APS and SCE continue to evaluate potential paths forward, it is possible that the terms of the Transmission Termination Agreement may again control. APS believes that the original denial by FERC of rate recovery under the Transmission Termination Agreement constitutes the failure of a condition that relieves APS of its obligations under that agreement. If APS and SCE are unable to determine a resolution through negotiation, the Transmission Termination Agreement requires that disputes be resolved through arbitration. APS is unable to predict the outcome of this matter if it proceeds to arbitration. If the matter proceeds to arbitration and APS is not successful, APS may be required to record a charge to its results of operations. Cholla After considering the costs to comply with environmental regulations, on September 11, 2014, APS announced that it will close Unit 2 of the Cholla Power Plant ("Cholla") by April 2016 and cease burning coal at the other APS-owned units (Units 1 and 3) at the plant by the mid-2020s, if the United States Environmental Protection Agency ("EPA") approves a compromise proposal offered by APS to meet required environmental and emissions standards and rules. Previously, APS estimated Cholla Unit 2’s end of life to be 2033. APS is currently recovering depreciation and a return on the net book value of the unit in base rates and plans to seek recovery of all of the unit’s retirement-related costs in its next retail rate case. On April 14, 2015, the ACC approved APS's proposed retirement of Cholla Unit 2 in accordance with the ACC's Integrated Resource Planning rules. The ACC expressly stated that this approval does not imply any specific treatment or recommendation for rate making purposes. If APS closes Cholla Unit 2, APS believes it will be allowed recovery of the remaining net book value of Unit 2 ( $125 million as of June 30, 2015), in addition to a return on its investment. In accordance with GAAP, in the third quarter of 2014, Unit 2’s remaining net book value was reclassified from property, plant and equipment to a regulatory asset. If the ACC does not allow full recovery of the remaining net book value of Cholla Unit 2, all or a portion of the regulatory asset will be written off and APS’s net income, cash flows, and financial position will be negatively impacted. Regulatory Assets and Liabilities The detail of regulatory assets is as follows (dollars in millions): Remaining Amortization Period June 30, 2015 December 31, 2014 Current Non-Current Current Non-Current Pension benefits (a) $ — $ 505 $ — $ 485 Income taxes — allowance for funds used during construction ("AFUDC") equity 2044 5 122 5 118 Deferred fuel and purchased power — mark-to-market (Note 7) 2018 53 62 51 46 Transmission vegetation management 2016 9 — 9 5 Coal reclamation 2026 — 6 — 7 Palo Verde VIEs (Note 6) 2046 — 26 — 35 Deferred compensation 2036 — 36 — 34 Deferred fuel and purchased power (b) (c) 2015 — — 7 — Tax expense of Medicare subsidy 2024 2 13 2 14 Loss on reacquired debt 2034 1 16 1 16 Income taxes — investment tax credit basis adjustment 2044 2 46 2 46 Pension and other postretirement benefits deferral 2015 — — 4 — Four Corners cost deferral 2024 7 67 7 70 Lost fixed cost recovery (b) 2016 45 — 38 — Retired power plant costs 2033 10 131 10 136 Deferred property taxes (d) — 40 — 30 Other Various 1 11 2 12 Total regulatory assets (e) $ 135 $ 1,081 $ 138 $ 1,054 (a) This asset represents the future recovery of pension and other postretirement benefit obligations through retail rates. If these costs are disallowed by the ACC, this regulatory asset would be charged to Other Comprehensive Income ("OCI") and result in lower future revenues. See Note 4 for further discussion. (b) See "Cost Recovery Mechanisms" discussion above. (c) Subject to a carrying charge. (d) Per the provision of the 2012 Settlement Agreement. (e) There are no regulatory assets for which the ACC has allowed recovery of costs, but not allowed a return by exclusion from rate base. FERC rates are set using a formula rate as described in "Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters." The detail of regulatory liabilities is as follows (dollars in millions): Remaining Amortization Period June 30, 2015 December 31, 2014 Current Non-Current Current Non-Current Removal costs (a) $ 44 $ 245 $ 31 $ 273 Asset retirement obligations 2044 — 272 — 296 Renewable energy standard (b) 2017 29 20 25 23 Income taxes — change in rates 2043 1 71 — 72 Spent nuclear fuel 2047 3 68 5 66 Deferred gains on utility property 2019 2 7 2 8 Income taxes — deferred investment tax credit 2043 3 92 4 93 Deferred fuel and purchased power (b) (c) 2016 16 — — — Demand side management (b) 2017 8 27 31 — Other postretirement benefits (d) 33 189 32 199 Other Various 13 26 1 21 Total regulatory liabilities $ 152 $ 1,017 $ 131 $ 1,051 (a) In accordance with regulatory accounting guidance, APS accrues for removal costs for its regulated assets, even if there is no legal obligation for removal. (b) See "Cost Recovery Mechanisms" discussion above. (c) Subject to a carrying charge. (d) See Note 4. |
Retirement Plans and Other Bene
Retirement Plans and Other Benefits | 6 Months Ended |
Jun. 30, 2015 | |
Compensation and Retirement Disclosure [Abstract] | |
Retirement Plans and Other Benefits | Retirement Plans and Other 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. On September 30, 2014, Pinnacle West announced plan design changes to the other postretirement benefit plan. Because of these plan changes in 2014, the Company is currently in the process of seeking Internal Revenue Service ("IRS") and regulatory approval to move approximately $100 million of the other postretirement benefit trust assets into a new account to pay for active union employee medical costs. Certain pension and other postretirement benefit costs in excess of amounts recovered in electric retail rates were deferred in 2011 and 2012 as a regulatory asset for future recovery, pursuant to APS’s 2009 retail rate case settlement. Pursuant to this order, we began amortizing the regulatory asset over three years beginning in July 2012. We amortized approximately $2 million and $4 million for the three and six months ended June 30, 2015 and 2014, respectively. 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, billed to electric plant participants or charged or amortized to the regulatory asset) (dollars in millions): Pension Benefits Other Benefits Three Months Ended Six Months Ended Three Months Ended Six Months Ended 2015 2014 2015 2014 2015 2014 2015 2014 Service cost — benefits earned during the period $ 14 $ 12 $ 30 $ 27 $ 4 $ 5 $ 8 $ 9 Interest cost on benefit obligation 31 33 62 65 7 11 14 23 Expected return on plan assets (45 ) (39 ) (90 ) (79 ) (9 ) (13 ) (18 ) (25 ) Amortization of: Prior service cost — — — — (9 ) — (19 ) — Net actuarial loss 8 3 16 5 — — 2 — Net periodic benefit cost $ 8 $ 9 $ 18 $ 18 $ (7 ) $ 3 $ (13 ) $ 7 Portion of cost charged to expense $ 5 $ 5 $ 11 $ 11 $ (2 ) $ 3 $ (4 ) $ 5 Contributions We have made voluntary contributions of $80 million to our pension plan year-to-date in 2015. The minimum required contributions for the pension plan are zero for the next three years. We expect to make voluntary contributions totaling up to $300 million for the next three years (up to $100 million each year in 2015, 2016, and 2017). We expect to make contributions of approximately $1 million in each of the next three years to our other postretirement benefit plans. |
Income Taxes
Income Taxes | 6 Months Ended |
Jun. 30, 2015 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | Income Taxes On September 13, 2013, the U.S. Treasury Department released final income tax regulations on the deduction and capitalization of expenditures related to tangible property. These final regulations apply to tax years beginning on or after January 1, 2014. Several of the provisions within the regulations require a tax accounting method change to be filed with the IRS prior to September 15, 2015, resulting in a tax-effected cumulative effect adjustment of approximately $82 million . The anticipated impact of these final regulations were accounted for in the Condensed Consolidated Balance Sheets as of December 31, 2014. Net income associated with the Palo Verde sale leaseback variable interest entities is not subject to tax (see Note 6). As a result, there is no income tax expense associated with the VIEs recorded on the Condensed Consolidated Statements of Income. As of June 30, 2015 , the tax year ended December 31, 2011 and all subsequent tax years remain subject to examination by the IRS. With few exceptions, we are no longer subject to state income tax examinations by tax authorities for years before 2009. |
Palo Verde Sale Leaseback Varia
Palo Verde Sale Leaseback Variable Interest Entities | 6 Months Ended |
Jun. 30, 2015 | |
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. These lease agreements include fixed rate renewal periods. On July 7, 2014, APS notified the lessor trust entities of APS's intent to exercise the fixed rate lease renewal options. The length of the renewal options will result in APS retaining 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 $49 million in 2015, $23 million annually for the period 2016 through 2023, and $16 million annually for the period 2024 through 2033. At the end of the lease renewal periods, APS will have the option to purchase the leased assets at their fair market value, extend the leases for up to 2 years , or return the assets to the lessors. The fixed rate renewal periods 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. Predominately due to the fixed rate renewal periods, 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 and interest expense, resulting in an increase in net income for the three and six months ended June 30, 2015 of $5 million and $9 million , respectively, and for the three and six months ended June 30, 2014 of $9 million and $18 million , respectively, entirely attributable to the noncontrolling interests. The income attributable to the noncontrolling interests decreased because of lower rent income resulting from the July 7, 2014 lease extensions. In accordance with the regulatory treatment, higher depreciation expense and a regulatory liability were recorded in consolidation to offset the decrease in the noncontrolling interests’ share of net income. Accordingly, income attributable to Pinnacle West shareholders was not impacted by the consolidation or the lease extensions. Consolidation of these VIEs also results in changes to our Condensed Consolidated Statements of Cash Flows, but does not impact net cash flows. Our Condensed Consolidated Balance Sheets at June 30, 2015 and December 31, 2014 include the following amounts relating to the VIEs (in millions): June 30, 2015 December 31, 2014 Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation $ 119 $ 121 Current maturities of long-term debt 1 13 Equity — Noncontrolling interests 133 152 Assets of the VIEs are restricted and may only be used to settle the VIEs’ debt obligations and for payment to the noncontrolling interest holders. Other than the VIEs’ assets reported on our consolidated financial statements, the creditors of the VIEs have no other recourse to the assets of APS or Pinnacle West, except in certain circumstances such as a default by APS under the lease. 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 United States 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, assume the VIEs’ debt, 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 had occurred as of June 30, 2015 , APS would have been required to pay the noncontrolling equity participants approximately $114 million and assume $1 million of debt. Since APS consolidates these VIEs, the debt APS would be required to assume is already reflected in our Condensed Consolidated Balance Sheets. For regulatory ratemaking purposes, the agreements continue to be treated as operating leases and, as a result, we have recorded a regulatory asset relating to the arrangements. |
Derivative Accounting
Derivative Accounting | 6 Months Ended |
Jun. 30, 2015 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivative Accounting | Derivative Accounting We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas, coal, emissions allowances and in interest rates. We manage risks associated with market volatility 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. We also enter into derivative instruments for economic hedging purposes. While we believe the economic hedges 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. On June 1, 2012, we elected to discontinue cash flow hedge accounting treatment for the significant majority of our contracts that had previously been designated as cash flow hedges. This discontinuation is due to changes in PSA recovery (see Note 3), which now allows for 100% deferral of the unrealized gains and losses relating to these contracts. For those contracts that were de-designated, all changes in fair value after May 31, 2012 are no longer recorded through OCI, but are deferred through the PSA. The amounts previously recorded in accumulated OCI relating to these instruments will remain in accumulated OCI, and will transfer to earnings in the same period or periods during which the hedged transaction affects earnings or sooner if we determine it is probable that the forecasted transaction will not occur. When amounts have been reclassified from accumulated OCI to earnings, they will be subject to deferral in accordance with the PSA. Cash flow hedge accounting treatment will continue for a limited number of contracts that are not subject to PSA recovery. Our derivative instruments, excluding those qualifying for a scope exception, are recorded on the balance sheet 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. Hedge effectiveness is the degree to which the derivative instrument contract and the hedged item are correlated and is measured based on the relative changes in fair value of the derivative instrument contract and the hedged item over time. We assess hedge effectiveness both at inception and on a continuing basis. These assessments exclude the time value of certain options. For accounting hedges that are deemed an effective hedge, the effective portion of the gain or loss on the derivative instrument is reported as a component of OCI and reclassified into earnings in the same period during which the hedged transaction affects earnings. We recognize in current earnings, subject to the PSA, the gains and losses representing hedge ineffectiveness, and the gains and losses on any hedge components which are excluded from our effectiveness assessment. As cash flow hedge accounting has been discontinued for the significant majority of our contracts, after May 31, 2012, effectiveness testing is no longer being performed for these contracts. 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 3). Gains and losses from derivatives in the following tables represent the amounts reflected in income before the effect of PSA deferrals. As of June 30, 2015 , we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position): Commodity Quantity Power 3,808 GWh Gas 188 Billion cubic feet Gains and Losses from Derivative Instruments The following table provides information about gains and losses from derivative instruments in designated cash flow accounting hedging relationships during the three and six months ended June 30, 2015 and 2014 (dollars in thousands): Financial Statement Location Three Months Ended Six Months Ended Commodity Contracts 2015 2014 2015 2014 Gain (loss) recognized in OCI on derivative instruments (effective portion) OCI — derivative instruments $ 41 $ 66 $ (286 ) $ 243 Loss reclassified from accumulated OCI into income (effective portion realized) (a) Fuel and purchased power (b) (1,430 ) (3,216 ) (3,773 ) (7,654 ) (a) During the three and six months ended June 30, 2015 and 2014 , we had no amounts reclassified from accumulated OCI to earnings related to discontinued cash flow hedges. (b) Amounts are before the effect of PSA deferrals. During the next twelve months, we estimate that a net loss of $4 million before income taxes will be reclassified from accumulated OCI as an offset to the effect of market price changes for the related hedged transactions. In accordance with the PSA, most of these amounts will be recorded as either a regulatory asset or liability and have no immediate effect on earnings. The following table provides information about gains and losses from derivative instruments not designated as accounting hedging instruments during the three and six months ended June 30, 2015 and 2014 (dollars in thousands): Financial Statement Location Three Months Ended Six Months Ended June 30, Commodity Contracts 2015 2014 2015 2014 Net gain (loss) recognized in income Operating revenues (a) $ (66 ) $ 155 $ (114 ) $ 63 Net gain (loss) recognized in income Fuel and purchased power (a) 10,613 4,805 (34,190 ) 22,912 Total $ 10,547 $ 4,960 $ (34,304 ) $ 22,975 (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 significant majority of our derivative instruments are not currently designated as hedging instruments. The Condensed Consolidated Balance Sheets as of June 30, 2015 and December 31, 2014 , each include gross liabilities of $4 million of derivative instruments designated as hedging instruments. The following tables provide information about the fair value of our risk management activities reported on a gross basis, and the impacts of offsetting as of June 30, 2015 and December 31, 2014 . These amounts relate to commodity contracts and are located in the assets and liabilities from risk management activities lines of our Condensed Consolidated Balance Sheets. As of June 30, 2015: Gross Recognized Derivatives (a) Amounts Offset (b) Net Recognized Derivatives Other (c) Amount Reported on Balance Sheet Current assets $ 25,485 $ (12,925 ) $ 12,560 $ 2,162 $ 14,722 Investments and other assets 20,560 (4,787 ) 15,773 2,740 18,513 Total assets 46,045 (17,712 ) 28,333 4,902 33,235 Current liabilities (83,203 ) 30,626 (52,577 ) (8,096 ) (60,673 ) Deferred credits and other (92,475 ) 4,786 (87,689 ) — (87,689 ) Total liabilities (175,678 ) 35,412 (140,266 ) (8,096 ) (148,362 ) Total $ (129,633 ) $ 17,700 $ (111,933 ) $ (3,194 ) $ (115,127 ) (a) All of our gross recognized derivative instruments were subject to master netting arrangements. (b) Includes cash collateral provided to counterparties of $17,700 . (c) Represents cash collateral, cash margin and option premiums 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. Includes cash collateral received from counterparties of $8,096 , cash margin provided to counterparties of $2,162 and option premiums of $2,740 . As of December 31, 2014: Gross Recognized Derivatives (a) Amounts Offset (b) Net Recognized Derivatives Other (c) Amount Reported on Balance Sheet Current assets $ 28,562 $ (15,127 ) $ 13,435 $ 350 $ 13,785 Investments and other assets 24,810 (7,190 ) 17,620 — 17,620 Total assets 53,372 (22,317 ) 31,055 350 31,405 Current liabilities (86,062 ) 33,829 (52,233 ) (7,443 ) (59,676 ) Deferred credits and other (82,990 ) 32,388 (50,602 ) — (50,602 ) Total liabilities (169,052 ) 66,217 (102,835 ) (7,443 ) (110,278 ) Total $ (115,680 ) $ 43,900 $ (71,780 ) $ (7,093 ) $ (78,873 ) (a) All of our gross recognized derivative instruments were subject to master netting arrangements. (b) Includes cash collateral provided to counterparties of $43,900 . (c) Represents cash collateral and margin that is not subject to offsetting. Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument. Includes cash collateral received from counterparties of $7,443 , and cash margin provided to counterparties of $350 . Credit Risk and Credit Related Contingent Features We are exposed to losses in the event of nonperformance or nonpayment by counterparties. We have risk management contracts with many counterparties, including one counterparty for which our exposure represents approximately 81% of Pinnacle West’s $33 million of risk management assets as of June 30, 2015 . This exposure relates to a long-term traditional wholesale contract with a counterparty that has a high credit quality. Our risk management process assesses and monitors the financial exposure of all counterparties. Despite the fact that the great majority of trading counterparties’ debt is rated as investment grade by the credit rating agencies, there is still a possibility that one or more of these companies could default, resulting in a material impact on consolidated earnings for a given period. Counterparties in the portfolio consist principally of financial institutions, major energy companies, municipalities and local distribution companies. We maintain credit policies that we believe minimize overall credit risk to within acceptable limits. Determination of the credit quality of our counterparties is based upon a number of factors, including credit ratings and our evaluation of their financial condition. To manage credit risk, we employ collateral requirements and standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty. Valuation adjustments are established representing our estimated credit losses on our overall exposure to counterparties. Certain of our derivative instrument contracts contain credit-risk-related contingent features including, among other things, investment grade credit rating provisions, credit-related cross-default provisions, and adequate assurance provisions. Adequate assurance provisions allow a counterparty with reasonable grounds for uncertainty to demand additional collateral based on subjective events and/or conditions. For those derivative instruments in a net liability position, with investment grade credit contingencies, the counterparties could demand additional collateral if our debt credit rating were to fall below investment grade (below BBB- for Standard & Poor’s or Fitch or Baa3 for Moody’s). The following table provides information about our derivative instruments that have credit-risk-related contingent features at June 30, 2015 (dollars in millions): June 30, 2015 Aggregate fair value of derivative instruments in a net liability position $ 176 Cash collateral posted 18 Additional cash collateral in the event credit-risk-related contingent features were fully triggered (a) 89 (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 $161 million if our debt credit ratings were to fall below investment grade. |
Commitments and Contingencies
Commitments and Contingencies | 6 Months Ended |
Jun. 30, 2015 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | Commitments and Contingencies Palo Verde Nuclear 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 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 seeks 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 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 income. In addition, the settlement agreement provides APS with a method for submitting claims and getting recovery for costs incurred through 2016. On March 11, 2015, the DOE notified APS that it had approved APS’s claim for damages incurred due to DOE’s breach of the Standard Contract for the period July 1, 2011 through June 30, 2014. The claim for this period was the first claim made pursuant to the terms of the August 18, 2014 settlement agreement. The amount claimed was $42.0 million ; APS’s share of this amount is $12.2 million . The settlement payment was received on June 1, 2015. APS’s $12.2 million share was recorded as an adjustment to a regulatory liability and had no impact on 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 retrospective payment plan. In accordance with the Price-Anderson Act, the Palo Verde participants are insured against public liability for a nuclear incident up to $13.4 billion per occurrence. Palo Verde maintains the maximum available nuclear liability insurance in the amount of $375 million , which is provided by American Nuclear Insurers ("ANI"). The remaining balance of $12.98 billion of liability coverage is provided through a mandatory industry-wide retrospective assessment program. If losses at any nuclear power plant covered by the program exceed the accumulated funds, APS could be assessed retrospective premium adjustments. The maximum retrospective premium assessment per reactor under the program for each nuclear liability incident is approximately $127.3 million , subject to an annual limit of $19 million per incident, to be periodically adjusted for inflation. Based on APS’s ownership interest in the three Palo Verde units, APS’s maximum potential retrospective premium assessment per incident for all three units is approximately $111 million , with a maximum annual retrospective premium assessment of approximately $16.5 million . The Palo Verde participants maintain "all risk" (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.75 billion , a substantial portion of which must first be applied to stabilization and decontamination. APS has also secured insurance against portions of any increased cost of replacement generation or purchased power and business interruption resulting from a sudden and unforeseen accidental outage of any of the three units. The property damage, decontamination, and replacement power coverages are provided by Nuclear Electric Insurance Limited ("NEIL"). APS is subject to retrospective premium assessments 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 $23.1 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 $61.7 million of collateral assurance within 20 business days of a rating downgrade to non-investment grade. The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions, sublimits and exclusions. Contractual Obligations During the quarter our purchase obligations have increased by about $170 million relating to gas generation projects. The expected payments to be made are $26 million in 2015, $89 million in 2016, $46 million in 2017 and $9 million in 2018. Other than the item described above, there have been no material changes outside the normal course of business in contractual obligations from the information provided in our 2014 Form 10-K. Superfund-Related Matters The Comprehensive Environmental Response Compensation and Liability Act ("Superfund") 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 work plan. 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. 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. Southwest Power Outage On September 8, 2011 at approximately 3:30 PM, a 500 kilovolt ("kV") transmission line running between the Hassayampa and North Gila substations in southwestern Arizona tripped out of service due to a fault that occurred at a switchyard operated by APS. Approximately ten minutes after the transmission line went off-line, generation and transmission resources for the Yuma area were lost, resulting in approximately 69,700 APS customers losing service. On September 6, 2013, a purported consumer class action complaint was filed in Federal District Court in San Diego, California, naming APS and Pinnacle West as defendants and seeking damages for loss of perishable inventory and sales as a result of interruption of electrical service. APS and Pinnacle West filed a motion to dismiss, which the court granted on December 9, 2013. On January 13, 2014, the plaintiffs appealed the lower court’s decision. The appeal is now fully briefed and pending before the United States Court of Appeals for the Ninth Circuit. We are unable to predict the outcome of this matter. Clean Air Act Citizen Lawsuit On October 4, 2011, Earthjustice, on behalf of several environmental organizations, filed a lawsuit in the United States District Court for the District of New Mexico against APS and the other Four Corners participants alleging violations of the New Source Review ("NSR") provisions of the Clean Air Act. Subsequent to filing its original Complaint, on January 6, 2012, Earthjustice filed a First Amended Complaint adding claims for violations of the Clean Air Act’s New Source Performance Standards ("NSPS") program. Among other things, the environmental plaintiffs sought to have the court enjoin operations at Four Corners until APS applied for and obtained any required NSR permits and complied with the NSPS. The plaintiffs further requested the court to order the payment of civil penalties, including a beneficial mitigation project. The case was held in abeyance while APS negotiated a settlement with the United States Department of Justice ("DOJ") and environmental plaintiffs. In March 2015, the parties agreed in principle on final proposed language to settle the case, and on June 24, 2015, DOJ lodged the proposed consent decree with the United States District Court for the District of New Mexico. On that same day, DOJ also published notice of the filing in the Federal Register, which opened a 30 -day period for public comment. The settlement would resolve claims by the government and environmental plaintiffs that the co-owners violated the Clean Air Act by modifying Four Corners Units 4 and 5 without first obtaining a pre-construction permit from EPA. The settlement would require installation of pollution control technology and implementation of other measures to reduce sulfur dioxide and nitrogen oxide emissions from the two units, although installation of much of this equipment was already planned in order to comply with EPA's Regional Haze Rule best available retrofit technology ("BART") requirements. The settlement would also require Four Corners co-owners to pay a civil penalty of $1.5 million and spend $6.2 million for certain environmental mitigation projects to benefit the Navajo Nation. APS would be responsible for 15 percent of these costs based on its ownership interest in the units at the time of the alleged violations, which does not result in a material impact on our financial position, results of operations or cash flows. APS expects DOJ to file a motion to enter the consent decree with the court after expiration of the 30 -day comment period. Environmental Matters APS is subject to numerous environmental laws and regulations affecting many aspects of its present and future operations, including air emissions, 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 requirements on Four Corners, Cholla and the Navajo Generating Station ("Navajo Plant"). EPA and ADEQ will require these plants to install pollution control equipment that constitutes BART to lessen the impacts of emissions on visibility surrounding the plants. Four Corners. Based on EPA’s final standards, APS estimates that its 63% share of the cost of these controls for Four Corners Units 4 and 5 would be approximately $400 million . In addition, APS and 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. The cost of the controls related to the 7% interest is approximately $45 million . 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 . In October 2014, a coalition of environmental groups, an Indian tribe and others filed petitions for review in the United States Court of Appeals for the Ninth Circuit asking the Court to review EPA's final BART rule for the Navajo Plant. We cannot predict the outcome of this review process. Cholla. APS believes that EPA’s final rule as it applies to Cholla, which would require installation of selective catalytic reduction ("SCR") controls with a cost to APS of approximately $200 million , is unsupported and that EPA had no basis for disapproving Arizona’s State Implementation Plan ("SIP") and promulgating a FIP that is inconsistent with the state’s considered BART determinations under the regional haze program. Accordingly, on February 1, 2013, APS filed a Petition for Review of the final BART rule in the United States Court of Appeals for the Ninth Circuit. Briefing in the case was completed in February 2014. In September 2014, APS met with EPA to propose a compromise BART strategy wherein, pending certain regulatory approvals, APS would permanently close Cholla Unit 2 by April 2016 and cease burning coal at Units 1 and 3 by the mid-2020s. (See Note 3 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 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. APS’s proposal involves state and federal rule-making processes. In light of these ongoing administrative proceedings, on February 19, 2015, APS, PacifiCorp (owner of Cholla Unit 4), and EPA jointly moved the court to sever and hold in abeyance those claims in the litigation pertaining to Cholla pending regulatory actions by the state and EPA. The court granted the parties' unopposed motion on February 20, 2015. On June 10, 2015, ADEQ issued for public comment the draft Cholla permit, which memorializes APS's proposal, and a proposed revision to the SIP, which would incorporate the new permit terms. APS is unable to predict when or whether APS's proposal may ultimately be approved. Mercury and Air Toxic Standards ("MATS"). In 2011, EPA issued rules establishing maximum achievable control technology standards to regulate emissions of mercury and other hazardous air pollutants from fossil-fired plants. APS estimates that the cost for the remaining equipment necessary to meet these standards is approximately $130 million for Cholla, which would be avoided if EPA approves APS's compromise proposal discussed above. No additional equipment is needed for Four Corners Units 4 and 5 to comply with these rules. Salt River Project Agricultural Improvement and Power District ("SRP"), the operating agent for the Navajo Plant, estimates that APS's share of costs for equipment necessary to comply with the rules is approximately $1 million . The United States Supreme Court’s recent decision in Michigan vs. EPA reversed and remanded the MATS rule. This decision does not materially impact APS. Regardless of whether the MATS rule is ultimately vacated by the lower court, the Arizona State Mercury Rule, the stringency of which is roughly equivalent to that of MATS, would still apply to Cholla. 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. Because the Subtitle D rule is self-implementing, the CCR standards apply directly to the regulated facility, and facilities are directly responsible for ensuring that their operations comply with the rule’s requirements. While EPA has chosen to regulate the disposal of CCR in landfills and surface impoundments as non-hazardous waste under the final rule, the agency makes clear that it will continue to evaluate any risks associated with CCR disposal and leaves open the possibility that it may regulate CCR as a hazardous waste under RCRA Subtitle C in the future. 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 $15 million , and its share of incremental costs for Cholla is approximately $85 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 . Other future environmental rules that could involve material compliance costs include those related to effluent limitations, the ozone national ambient air quality standard, greenhouse gas ("GHG") emissions (such as the EPA’s proposed "Clean Power Plan" rule), and other rules or matters involving the Clean Air Act, Clean Water Act, Endangered Species Act, the Navajo Nation, and water supplies for our power plants. The financial impact of complying with these and other 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. New Mexico Tax Matter On May 23, 2013, the New Mexico Taxation and Revenue Department issued a notice of assessment for coal severance surtax, penalty, and interest totaling approximately $30 million related to coal supplied under the coal supply agreement for Four Corners (the "Assessment"). APS’s share of the Assessment is approximately $12 million . For procedural reasons, on behalf of the Four Corners co-owners, including APS, the coal supplier made a partial payment of the Assessment and immediately filed a refund claim with respect to that partial payment in August 2013. The New Mexico Taxation and Revenue Department denied the refund claim. On December 19, 2013, the coal supplier and APS, on its own behalf and as operating agent for Four Corners, filed a complaint with the New Mexico District Court contesting both the validity of the Assessment and the refund claim denial. On June 30, 2015, the court ruled that the Assessment was not valid and further ruled that APS and the other Four Corners co-owners receive a refund of all of the contested amounts previously paid under the applicable tax statute. The New Mexico Taxation and Revenue Department has indicated it intends to appeal the decision. We cannot predict the timing or outcome of any appeal; however, we do not expect the outcome to have a material impact on our financial position, results of operations or cash flows. Financial Assurances APS has entered into various agreements that require letters of credit for financial assurance purposes. At June 30, 2015 , approximately $76 million of letters of credit were outstanding to support existing pollution control bonds of a similar amount. The letters of credit are available to fund the payment of principal and interest of such debt obligations. Two of these letters of credit expire in 2016 and one expires in 2017. APS has also entered into letters of credit to support certain equity participants in the Palo Verde sale leaseback transactions (see Note 6 for further details on the Palo Verde sale leaseback transactions). These letters of credit will expire on December 31, 2015, and totaled approximately $20 million at June 30, 2015. Additionally, APS has issued letters of credit to support collateral obligations under certain risk management arrangements, including a natural gas tolling contract entered into with a third party. At June 30, 2015 , $35 million of such letters of credit were outstanding that will expire in 2015 and 2016. We enter into agreements that include indemnification provisions relating to liabilities arising from or related to certain of our agreements. Most significantly, APS has agreed to indemnify the equity participants and other parties in the Palo Verde sale leaseback transactions with respect to certain tax matters. Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnification provisions cannot be reasonably estimated. Based on historical experience and evaluation of the specific indemnities, we do not believe that any material loss related to such indemnification provisions is likely. Pinnacle West has issued parental guarantees and has provided indemnification under certain surety bonds for APS which were not material at June 30, 2015 . |
Other Income and Other Expense
Other Income and Other Expense | 6 Months Ended |
Jun. 30, 2015 | |
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 other income and other expense for the three and six months ended June 30, 2015 and 2014 (dollars in thousands): Three Months Ended Six Months Ended 2015 2014 2015 2014 Other income: Interest income $ 184 $ 495 $ 294 $ 746 Miscellaneous (9 ) 2,286 116 4,402 Total other income $ 175 $ 2,781 $ 410 $ 5,148 Other expense: Non-operating costs $ (1,952 ) $ (2,620 ) $ (4,200 ) $ (4,992 ) Investment losses — net (650 ) (105 ) (1,145 ) (246 ) Miscellaneous (7 ) 2,217 (1,550 ) 46 Total other expense $ (2,609 ) $ (508 ) $ (6,895 ) $ (5,192 ) |
Arizona Public Service Company | |
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 APS’s other income and other expense for the three and six months ended June 30, 2015 and 2014 (dollars in thousands): Three Months Ended Six Months Ended 2015 2014 2015 2014 Other income: Interest income $ 6 $ 417 $ 73 $ 554 Gain on disposition of property 478 328 685 645 Miscellaneous 226 2,476 591 4,784 Total other income $ 710 $ 3,221 $ 1,349 $ 5,983 Other expense: Non-operating costs (a) $ (1,878 ) $ (2,868 ) $ (4,395 ) $ (5,455 ) Loss on disposition of property (251 ) (285 ) (894 ) (468 ) Miscellaneous (320 ) 1,676 (2,514 ) (610 ) Total other expense $ (2,449 ) $ (1,477 ) $ (7,803 ) $ (6,533 ) (a) As defined by FERC, includes below-the-line non-operating utility expense (items excluded from utility rate recovery). |
Earnings Per Share
Earnings Per Share | 6 Months Ended |
Jun. 30, 2015 | |
Earnings Per Share [Abstract] | |
Earnings Per Share | Earnings Per Share The following table presents the calculation of Pinnacle West’s basic and diluted earnings per share for the three and six months ended June 30, 2015 and 2014 (in thousands, except per share amounts): Three Months Ended Six Months Ended 2015 2014 2015 2014 Net income attributable to common shareholders $ 122,902 $ 132,458 $ 139,024 $ 148,224 Weighted average common shares outstanding — basic 110,986 110,565 110,958 110,546 Net effect of dilutive securities: Contingently issuable performance shares and restricted stock units 474 437 468 379 Weighted average common shares outstanding — diluted 111,460 111,002 111,426 110,925 Earnings per average common share attributable to common shareholders — basic $ 1.11 $ 1.20 $ 1.25 $ 1.34 Earnings per average common share attributable to common shareholders — diluted $ 1.10 $ 1.19 $ 1.25 $ 1.34 |
Fair Value Measurements
Fair Value Measurements | 6 Months Ended |
Jun. 30, 2015 | |
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 that we have the ability to access at the measurement date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide information on an ongoing basis. This category includes exchange traded equities, exchange traded derivative instruments, cash equivalents, and investments in U.S. Treasury securities. Level 2 — Utilizes 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). This category includes non-exchange traded contracts such as forwards, options, swaps and certain investments in fixed income securities. This category also includes investments that are redeemable and valued based on NAV, such as common and collective trusts and commingled funds. 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. Recurring Fair Value Measurements We apply recurring fair value measurements to certain cash equivalents, derivative instruments, investments held in our nuclear decommissioning trust and plan assets held in our retirement and other benefit plans. See Note 7 in the 2014 Form 10-K for the fair value discussion of plan assets held in our retirement and other benefit plans. Cash Equivalents Cash equivalents represent short-term investments with original maturities of three months or less in exchange traded 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. Option contracts are primarily valued using a Black-Scholes option valuation model, which utilizes both observable and unobservable inputs such as broker quotes, interest rates and price volatilities. 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 and the use of option valuation models with significant unobservable inputs. 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 our Nuclear Decommissioning Trust The nuclear decommissioning trust invests in fixed income securities and equity securities. Equity securities are held indirectly through commingled funds. The commingled funds are valued based on the concept of Net Asset Value ("NAV"), which is a value primarily derived from the quoted active market prices of the underlying equity securities. We may transact in these commingled funds on a semi-monthly basis at the NAV, and accordingly classify these investments as Level 2. The commingled funds, which are similar to mutual 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 fund shares are offered to a limited group of investors, they are not considered to be traded in an active market. Cash equivalents reported within Level 2 represent investments held in a short-term investment commingled fund, valued using NAV, which invests in certificates of deposit, variable rate notes, time deposit accounts, U.S. Treasury and Agency obligations, U.S. Treasury repurchase agreements, and commercial paper. We may transact in this commingled fund on a daily basis at the NAV. Fixed income securities issued by the U.S. Treasury held directly by the nuclear decommissioning trust 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 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. We price securities using information provided by our trustee for our nuclear decommissioning trust assets. Our trustee uses pricing services that utilize the valuation methodologies described 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 trustee’s internal operating controls and valuation processes. See Note 12 for additional discussion about our nuclear decommissioning trust. Fair Value Tables The following table presents the fair value at June 30, 2015 , of our assets and liabilities that are measured at fair value on a recurring basis (dollars in millions): 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 June 30, 2015 Assets Risk management activities — derivative instruments: Commodity contracts $ — $ 16 $ 30 $ (13 ) (b) $ 33 Nuclear decommissioning trust: U.S. commingled equity funds — 314 — — 314 Cash and cash equivalent funds — 11 — (4 ) (c) 7 Fixed income securities: U.S. Treasury 93 2 — — 95 Corporate debt — 116 — — 116 Mortgage-backed securities — 87 — — 87 Municipal bonds — 86 — — 86 Other — 19 — — 19 Subtotal nuclear decommissioning trust 93 635 — (4 ) 724 Total $ 93 $ 651 $ 30 $ (17 ) $ 757 Liabilities Risk management activities — derivative instruments: Commodity contracts $ — $ (103 ) $ (73 ) $ 28 (b) $ (148 ) (a) Primarily consists of heat rate options and other long-dated electricity contracts. (b) Represents counterparty netting, margin and collateral (see Note 7). (c) Represents nuclear decommissioning trust net pending securities sales and purchases. The following table presents the fair value at December 31, 2014 , of our assets and liabilities that are measured at fair value on a recurring basis (dollars in millions): 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, 2014 Assets Risk management activities — derivative instruments: Commodity contracts $ — $ 21 $ 33 $ (23 ) (b) $ 31 Nuclear decommissioning trust: U.S. commingled equity funds — 310 — — 310 Fixed income securities: U.S. Treasury 119 — — — 119 Cash and cash equivalent funds — 11 — (7 ) (c) 4 Corporate debt — 109 — — 109 Mortgage-backed securities — 89 — — 89 Municipal bonds — 69 — — 69 Other — 14 — — 14 Subtotal nuclear decommissioning trust 119 602 — (7 ) 714 Total $ 119 $ 623 $ 33 $ (30 ) $ 745 Liabilities Risk management activities — derivative instruments: Commodity contracts $ — $ (95 ) $ (74 ) $ 59 (b) $ (110 ) (a) Primarily consists of heat rate options and other long-dated electricity contracts. (b) Represents counterparty netting, margin and collateral (see Note 7). (c) Represents nuclear decommissioning trust net pending securities sales and purchases. 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 and option model inputs. 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 3). 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. Our option contracts classified as Level 3 primarily relate to purchase heat rate options. The significant unobservable inputs at June 30, 2015 for these instruments include electricity prices, and volatilities. The significant unobservable inputs at December 31, 2014 for these instruments include electricity prices, gas prices and volatilities. If electricity prices and electricity price volatilities increase, we would expect the fair value of these options to increase, and if these valuation inputs decrease, we would expect the fair value of these options to decrease. If natural gas prices and natural gas price volatilities increase, we would expect the fair value of these options to decrease, and if these inputs decrease, we would expect the fair value of the options to increase. The commodity prices and volatilities do not always move in corresponding directions. The options’ fair values are impacted by the net changes of these various inputs. Other unobservable valuation inputs include credit and liquidity reserves which do not have a material impact on our valuations; however, significant changes in these inputs could also result in higher or lower fair value measurements. The following tables provide information regarding our significant unobservable inputs used to value our risk management derivative Level 3 instruments at June 30, 2015 and December 31, 2014 : June 30, 2015 Valuation Technique Significant Unobservable Input Weighted-Average Commodity Contracts Assets Liabilities Range Electricity: Forward Contracts (a) $ 28 $ 57 Discounted cash flows Electricity forward price (per MWh) $21.07 - $67.74 $ 31.46 Option Contracts (b) — 12 Option model Electricity forward price (per MWh) $32.85 - $67.74 $ 46.13 Electricity price volatilities 26% - 115% 68 % Natural gas price volatilities 27% - 42% 31 % Natural Gas: Forward Contracts (a) 2 4 Discounted cash flows Natural gas forward price (per MMBtu) $2.69 - $3.61 $ 3.23 Total $ 30 $ 73 (a) Includes swaps and physical and financial contracts. (b) Electricity and natural gas price volatilities are estimated based on historical forward price movements due to lack of market quotes for implied volatilities. December 31, 2014 Valuation Technique Significant Unobservable Input Weighted-Average Commodity Contracts Assets Liabilities Range Electricity: Forward Contracts (a) $ 30 $ 56 Discounted cash flows Electricity forward price (per MWh) $19.51 - $56.72 $ 35.27 Option Contracts (b) — 15 Option model Electricity forward price (per MWh) $32.14 - $66.09 $ 45.83 Natural gas forward price (per MMBtu) $3.18 - $3.29 $ 3.25 Electricity price volatilities 23% - 63% 41 % Natural gas price volatilities 23% - 41% 31 % Natural Gas: Forward Contracts (a) 3 3 Discounted cash flows Natural gas forward price (per MMBtu) $2.98 - $4.13 $ 3.45 Total $ 33 $ 74 (a) Includes swaps and physical and financial contracts. (b) Electricity and natural gas price volatilities are estimated based on historical forward price movements due to lack of market quotes for implied volatilities. The following table shows the changes in fair value for our risk management activities' assets and liabilities that are measured at fair value on a recurring basis using Level 3 inputs for the three and six months ended June 30, 2015 and 2014 (dollars in millions): Three Months Ended Six Months Ended Commodity Contracts 2015 2014 2015 2014 Net derivative balance at beginning of period $ (49 ) $ (49 ) $ (41 ) $ (49 ) Total net gains (losses) realized/unrealized: Deferred as a regulatory asset or liability 6 3 (5 ) 6 Settlements 5 4 5 5 Transfers into Level 3 from Level 2 (4 ) 1 (4 ) (2 ) Transfers from Level 3 into Level 2 (1 ) — 2 (1 ) Net derivative balance at end of period $ (43 ) $ (41 ) $ (43 ) $ (41 ) Net unrealized gains included in earnings related to instruments still held at end of period $ — $ — $ — $ — Amounts included in earnings are recorded in either operating revenues or fuel and purchased power depending on the nature of the underlying contract. Transfers 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 net accounts receivable, accounts payable and short-term borrowings approximate fair value. Our short-term borrowings are classified within Level 2 of the fair value hierarchy. For our long-term debt fair values, see Note 2. |
Nuclear Decommissioning Trusts
Nuclear Decommissioning Trusts | 6 Months Ended |
Jun. 30, 2015 | |
Investments, Debt and Equity Securities [Abstract] | |
Nuclear Decommissioning Trusts | Nuclear Decommissioning Trusts To fund the 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. APS classifies investments in decommissioning trust funds as available for sale. As a result, we record the decommissioning trust funds 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 nuclear decommissioning trust investments within the fair value hierarchy. Because of the ability of APS to recover decommissioning costs in rates and in accordance with the regulatory treatment for decommissioning trust funds, we have deferred realized and unrealized gains and losses (including other-than-temporary impairments on investment securities) in other regulatory liabilities . The following table includes the unrealized gains and losses based on the original cost of the investment and summarizes the fair value of APS’s nuclear decommissioning trust fund assets at June 30, 2015 and December 31, 2014 (dollars in millions): Fair Value Total Unrealized Gains Total Unrealized Losses June 30, 2015 Equity securities $ 314 $ 160 $ — Fixed income securities 414 13 (3 ) Net payables (a) (4 ) — — Total $ 724 $ 173 $ (3 ) Fair Value Total Unrealized Gains Total Unrealized Losses December 31, 2014 Equity securities $ 310 $ 159 $ — Fixed income securities 411 17 (1 ) Net payables (a) (7 ) — — Total $ 714 $ 176 $ (1 ) (a) Net payables relate to pending purchases and sales of securities. The costs of securities sold are determined on the basis of specific identification. The following table sets forth approximate gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds (dollars in millions): Three Months Ended Six Months Ended 2015 2014 2015 2014 Realized gains $ 1 $ 1 $ 2 $ 2 Realized losses (1 ) (1 ) (2 ) (3 ) Proceeds from the sale of securities (a) 110 96 226 199 (a) Proceeds are reinvested in the trust. The fair value of fixed income securities, summarized by contractual maturities, at June 30, 2015 is as follows (dollars in millions): Fair Value Less than one year $ 13 1 year – 5 years 111 5 years – 10 years 123 Greater than 10 years 167 Total $ 414 |
New Accounting Standards
New Accounting Standards | 6 Months Ended |
Jun. 30, 2015 | |
New Accounting Pronouncements and Changes in Accounting Principles [Abstract] | |
New Accounting Standards | New Accounting Standards In May 2014, new revenue recognition guidance was issued. This guidance provides a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance. The guidance 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. The new revenue standard will be effective for us on January 1, 2018. We are currently evaluating this new guidance and the impacts it may have on our financial statements. In February 2015, new guidance was issued that amends the consolidation accounting guidance. The amendments modify many aspects of the guidance relating to the analysis and consolidation of variable interest entities. These changes include impacts on the following: limited partnerships, fees paid to decision makers, related parties, and the determination of whether an entity qualifies as a variable interest entity. The new guidance is effective for us on January 1, 2016, and may be adopted using either a full retrospective or modified retrospective approach. We are currently evaluating this amended guidance and the impacts it may have on our financial statements. In April 2015, the Financial Accounting Standards Board issued new guidance that changes the balance sheet presentation of debt issuance costs. Currently, debt issuance costs are presented on the balance sheet as assets. The new guidance requires us to reflect debt issuance costs as a reduction to the related debt liabilities, consistent with the presentation of debt discounts. The new guidance is effective for us during the first quarter of 2016, and must be adopted retrospectively. We do not expect these presentation changes to be material to our balance sheet. The adoption of this new guidance will not impact our results of operations or cash flows. |
Changes in Accumulated Other Co
Changes in Accumulated Other Comprehensive Loss | 6 Months Ended |
Jun. 30, 2015 | |
Accumulated Other Comprehensive Income (Loss) [Line Items] | |
Changes in Accumulated Other Comprehensive Loss | Changes in Accumulated Other Comprehensive Loss The following tables show the changes in accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the three and six months ended June 30, 2015 and 2014 (dollars in thousands): Three Months Ended June 30, 2015 Three Months Ended June 30, 2014 Derivative Instruments Pension and Other Postretirement Benefits Total Derivative Instruments Pension and Other Postretirement Benefits Total Beginning balance, April 1 $ (9,209 ) $ (57,173 ) $ (66,382 ) $ (20,364 ) $ (54,538 ) $ (74,902 ) OCI (loss) before reclassifications 25 (969 ) (944 ) 40 (2,072 ) (2,032 ) Amounts reclassified from accumulated other comprehensive loss 874 (a) 852 (b) 1,726 1,955 (a) 762 (b) 2,717 Net current period OCI (loss) 899 (117 ) 782 1,995 (1,310 ) 685 Ending balance, June 30 $ (8,310 ) $ (57,290 ) $ (65,600 ) $ (18,369 ) $ (55,848 ) $ (74,217 ) (a) 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. (b) These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost. See Note 4. Six Months Ended June 30, 2015 Six Months Ended June 30, 2014 Derivative Instruments Pension and Other Postretirement Benefits Total Derivative Instruments Pension and Other Postretirement Benefits Total Beginning balance, January 1 $ (10,385 ) $ (57,756 ) $ (68,141 ) $ (23,058 ) $ (54,995 ) $ (78,053 ) OCI (loss) before reclassifications (775 ) (969 ) (1,744 ) (381 ) (2,072 ) (2,453 ) Amounts reclassified from accumulated other comprehensive loss 2,850 (a) 1,435 (b) 4,285 5,070 (a) 1,219 (b) 6,289 Net current period OCI (loss) 2,075 466 2,541 4,689 (853 ) 3,836 Ending balance, June 30 $ (8,310 ) $ (57,290 ) $ (65,600 ) $ (18,369 ) $ (55,848 ) $ (74,217 ) (a) 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. (b) These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost. See Note 4. |
Arizona Public Service Company | |
Accumulated Other Comprehensive Income (Loss) [Line Items] | |
Changes in Accumulated Other Comprehensive Loss | Changes in Accumulated Other Comprehensive Loss The following tables show the changes in accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the three and six months ended June 30, 2015 and 2014 (dollars in thousands): Three Months Ended June 30, 2015 Three Months Ended June 30, 2014 Derivative Instruments Pension and Other Postretirement Benefits Total Derivative Instruments Pension and Other Postretirement Benefits Total Beginning balance, April 1 $ (9,209 ) $ (37,267 ) $ (46,476 ) $ (20,364 ) $ (29,747 ) $ (50,111 ) OCI (loss) before reclassifications 25 (927 ) (902 ) 40 (2,041 ) (2,001 ) Amounts reclassified from accumulated other comprehensive loss 874 (a) 853 (b) 1,727 1,954 (a) 758 (b) 2,712 Net current period OCI (loss) 899 (74 ) 825 1,994 (1,283 ) 711 Ending balance, June 30 $ (8,310 ) $ (37,341 ) $ (45,651 ) $ (18,370 ) $ (31,030 ) $ (49,400 ) (a) 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. (b) These amounts primarily represent amortization of actuarial loss and are included in the computation of net periodic pension cost. See Note 4. Six Months Ended June 30, 2015 Six Months Ended June 30, 2014 Derivative Instruments Pension and Other Postretirement Benefits Total Derivative Instruments Pension and Other Postretirement Benefits Total Beginning balance, January 1 $ (10,385 ) $ (37,948 ) $ (48,333 ) $ (23,059 ) $ (30,313 ) $ (53,372 ) OCI (loss) before reclassifications (775 ) (927 ) (1,702 ) (381 ) (2,041 ) (2,422 ) Amounts reclassified from accumulated other comprehensive loss 2,850 (a) 1,534 (b) 4,384 5,070 (a) 1,324 (b) 6,394 Net current period OCI (loss) 2,075 607 2,682 4,689 (717 ) 3,972 Ending balance, June 30 $ (8,310 ) $ (37,341 ) $ (45,651 ) $ (18,370 ) $ (31,030 ) $ (49,400 ) (a) 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. (b) These amounts primarily represent amortization of actuarial loss and are included in the computation of net periodic pension cost. See Note 4. |
Asset Retirement Obligations
Asset Retirement Obligations | 6 Months Ended |
Jun. 30, 2015 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Asset Retirement Obligations | Asset Retirement Obligations In the first quarter of 2015, an updated decommissioning study was completed for the Four Corners coal-fired plant, which resulted in an increase to the asset retirement obligation ("ARO") in the amount of $18 million . In the second quarter of 2015, there was a revision in estimated cash flows for the Four Corners decommissioning, which resulted in an increase to the ARO in the amount of $6 million . In addition, APS recognized an ARO for Cholla as a result of new CCR environmental rulings that were published in the Federal Register in the second quarter of 2015. See Note 8 for additional information related to the CCR environmental rulings. This resulted in an increase to the ARO in the amount of $39 million , an increase in plant in service of $23 million and a reduction of the regulatory liability of $16 million . The following schedule shows the change in our asset retirement obligations for the six months ended June 30, 2015 (dollars in millions): Asset retirement obligations at January 1, 2015 $ 391 Changes attributable to: Accretion expense 12 Settlements (18 ) Estimated cash flow revisions 24 Newly incurred liabilities 39 Asset retirement obligations at June 30, 2015 $ 448 Decommissioning activities for Four Corners Units 1-3 began in January 2014; thus, $29 million of the total asset retirement obligation of $448 million at June 30, 2015 , is classified as a current liability on the balance sheet. In accordance with regulatory accounting, APS accrues removal costs for its regulated utility assets, even if there is no legal obligation for removal. See detail of regulatory liabilities in Note 3. |
New Accounting Standards (Polic
New Accounting Standards (Policies) | 6 Months Ended |
Jun. 30, 2015 | |
New Accounting Pronouncements and Changes in Accounting Principles [Abstract] | |
New Accounting Standards | In May 2014, new revenue recognition guidance was issued. This guidance provides a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance. The guidance 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. The new revenue standard will be effective for us on January 1, 2018. We are currently evaluating this new guidance and the impacts it may have on our financial statements. In February 2015, new guidance was issued that amends the consolidation accounting guidance. The amendments modify many aspects of the guidance relating to the analysis and consolidation of variable interest entities. These changes include impacts on the following: limited partnerships, fees paid to decision makers, related parties, and the determination of whether an entity qualifies as a variable interest entity. The new guidance is effective for us on January 1, 2016, and may be adopted using either a full retrospective or modified retrospective approach. We are currently evaluating this amended guidance and the impacts it may have on our financial statements. In April 2015, the Financial Accounting Standards Board issued new guidance that changes the balance sheet presentation of debt issuance costs. Currently, debt issuance costs are presented on the balance sheet as assets. The new guidance requires us to reflect debt issuance costs as a reduction to the related debt liabilities, consistent with the presentation of debt discounts. The new guidance is effective for us during the first quarter of 2016, and must be adopted retrospectively. We do not expect these presentation changes to be material to our balance sheet. The adoption of this new guidance will not impact our results of operations or cash flows. |
Consolidation and Nature of O25
Consolidation and Nature of Operations (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Summary of supplemental cash flow information | The following table summarizes supplemental Pinnacle West cash flow information (dollars in thousands): Six Months Ended 2015 2014 Cash paid (received) during the period for: Income taxes, net of refunds $ 1,834 $ (131,154 ) Interest, net of amounts capitalized 84,008 90,707 Significant non-cash investing and financing activities: Accrued capital expenditures $ 38,985 $ 19,668 Dividends accrued but not yet paid 65,933 62,656 |
Long-Term Debt and Liquidity 26
Long-Term Debt and Liquidity Matters (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
Debt Disclosure [Abstract] | |
Schedule of estimated fair value of long-term debt, including current maturities | The following table represents the estimated fair value of our long-term debt, including current maturities (dollars in millions): As of June 30, 2015 As of December 31, 2014 Carrying Amount Fair Value Carrying Amount Fair Value Pinnacle West $ 125 $ 125 $ 125 $ 125 APS 3,544 3,818 3,290 3,714 Total $ 3,669 $ 3,943 $ 3,415 $ 3,839 |
Regulatory Matters (Tables)
Regulatory Matters (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
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 2015 and 2014 (dollars in millions): Six Months Ended 2015 2014 Beginning balance $ 7 $ 21 Deferred fuel and purchased power costs — current period (12 ) (1 ) Amounts charged to customers (11 ) (19 ) Ending balance $ (16 ) $ 1 |
Schedule of regulatory assets | The detail of regulatory assets is as follows (dollars in millions): Remaining Amortization Period June 30, 2015 December 31, 2014 Current Non-Current Current Non-Current Pension benefits (a) $ — $ 505 $ — $ 485 Income taxes — allowance for funds used during construction ("AFUDC") equity 2044 5 122 5 118 Deferred fuel and purchased power — mark-to-market (Note 7) 2018 53 62 51 46 Transmission vegetation management 2016 9 — 9 5 Coal reclamation 2026 — 6 — 7 Palo Verde VIEs (Note 6) 2046 — 26 — 35 Deferred compensation 2036 — 36 — 34 Deferred fuel and purchased power (b) (c) 2015 — — 7 — Tax expense of Medicare subsidy 2024 2 13 2 14 Loss on reacquired debt 2034 1 16 1 16 Income taxes — investment tax credit basis adjustment 2044 2 46 2 46 Pension and other postretirement benefits deferral 2015 — — 4 — Four Corners cost deferral 2024 7 67 7 70 Lost fixed cost recovery (b) 2016 45 — 38 — Retired power plant costs 2033 10 131 10 136 Deferred property taxes (d) — 40 — 30 Other Various 1 11 2 12 Total regulatory assets (e) $ 135 $ 1,081 $ 138 $ 1,054 (a) This asset represents the future recovery of pension and other postretirement benefit obligations through retail rates. If these costs are disallowed by the ACC, this regulatory asset would be charged to Other Comprehensive Income ("OCI") and result in lower future revenues. See Note 4 for further discussion. (b) See "Cost Recovery Mechanisms" discussion above. (c) Subject to a carrying charge. (d) Per the provision of the 2012 Settlement Agreement. (e) There are no regulatory assets for which the ACC has allowed recovery of costs, but not allowed a return by exclusion from rate base. FERC rates are set using a formula rate as described in "Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters. |
Schedule of regulatory liabilities | The detail of regulatory liabilities is as follows (dollars in millions): Remaining Amortization Period June 30, 2015 December 31, 2014 Current Non-Current Current Non-Current Removal costs (a) $ 44 $ 245 $ 31 $ 273 Asset retirement obligations 2044 — 272 — 296 Renewable energy standard (b) 2017 29 20 25 23 Income taxes — change in rates 2043 1 71 — 72 Spent nuclear fuel 2047 3 68 5 66 Deferred gains on utility property 2019 2 7 2 8 Income taxes — deferred investment tax credit 2043 3 92 4 93 Deferred fuel and purchased power (b) (c) 2016 16 — — — Demand side management (b) 2017 8 27 31 — Other postretirement benefits (d) 33 189 32 199 Other Various 13 26 1 21 Total regulatory liabilities $ 152 $ 1,017 $ 131 $ 1,051 (a) In accordance with regulatory accounting guidance, APS accrues for removal costs for its regulated assets, even if there is no legal obligation for removal. (b) See "Cost Recovery Mechanisms" discussion above. (c) Subject to a carrying charge. (d) See Note 4. |
Retirement Plans and Other Be28
Retirement Plans and Other Benefits (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
Compensation and Retirement Disclosure [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, billed to electric plant participants or charged or amortized to the regulatory asset) (dollars in millions): Pension Benefits Other Benefits Three Months Ended Six Months Ended Three Months Ended Six Months Ended 2015 2014 2015 2014 2015 2014 2015 2014 Service cost — benefits earned during the period $ 14 $ 12 $ 30 $ 27 $ 4 $ 5 $ 8 $ 9 Interest cost on benefit obligation 31 33 62 65 7 11 14 23 Expected return on plan assets (45 ) (39 ) (90 ) (79 ) (9 ) (13 ) (18 ) (25 ) Amortization of: Prior service cost — — — — (9 ) — (19 ) — Net actuarial loss 8 3 16 5 — — 2 — Net periodic benefit cost $ 8 $ 9 $ 18 $ 18 $ (7 ) $ 3 $ (13 ) $ 7 Portion of cost charged to expense $ 5 $ 5 $ 11 $ 11 $ (2 ) $ 3 $ (4 ) $ 5 |
Palo Verde Sale Leaseback Var29
Palo Verde Sale Leaseback Variable Interest Entities (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
Variable Interest Entities [Abstract] | |
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets | Our Condensed Consolidated Balance Sheets at June 30, 2015 and December 31, 2014 include the following amounts relating to the VIEs (in millions): June 30, 2015 December 31, 2014 Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation $ 119 $ 121 Current maturities of long-term debt 1 13 Equity — Noncontrolling interests 133 152 |
Derivative Accounting (Tables)
Derivative Accounting (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Outstanding gross notional amount of derivatives, which represents both purchases and sales (does not reflect net position) | As of June 30, 2015 , we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position): Commodity Quantity Power 3,808 GWh Gas 188 Billion cubic feet |
Gains and losses from derivative instruments in designated cash flow accounting hedges relationships | The following table provides information about gains and losses from derivative instruments in designated cash flow accounting hedging relationships during the three and six months ended June 30, 2015 and 2014 (dollars in thousands): Financial Statement Location Three Months Ended Six Months Ended Commodity Contracts 2015 2014 2015 2014 Gain (loss) recognized in OCI on derivative instruments (effective portion) OCI — derivative instruments $ 41 $ 66 $ (286 ) $ 243 Loss reclassified from accumulated OCI into income (effective portion realized) (a) Fuel and purchased power (b) (1,430 ) (3,216 ) (3,773 ) (7,654 ) (a) During the three and six months ended June 30, 2015 and 2014 , we had no amounts reclassified from accumulated OCI to earnings related to discontinued cash flow hedges. (b) Amounts are before the effect of PSA deferrals. |
Gains and losses from derivative instruments not designated as accounting hedges instruments | The following table provides information about gains and losses from derivative instruments not designated as accounting hedging instruments during the three and six months ended June 30, 2015 and 2014 (dollars in thousands): Financial Statement Location Three Months Ended Six Months Ended June 30, Commodity Contracts 2015 2014 2015 2014 Net gain (loss) recognized in income Operating revenues (a) $ (66 ) $ 155 $ (114 ) $ 63 Net gain (loss) recognized in income Fuel and purchased power (a) 10,613 4,805 (34,190 ) 22,912 Total $ 10,547 $ 4,960 $ (34,304 ) $ 22,975 (a) Amounts are before the effect of PSA deferrals. |
Schedule of offsetting assets | The following tables provide information about the fair value of our risk management activities reported on a gross basis, and the impacts of offsetting as of June 30, 2015 and December 31, 2014 . These amounts relate to commodity contracts and are located in the assets and liabilities from risk management activities lines of our Condensed Consolidated Balance Sheets. As of June 30, 2015: Gross Recognized Derivatives (a) Amounts Offset (b) Net Recognized Derivatives Other (c) Amount Reported on Balance Sheet Current assets $ 25,485 $ (12,925 ) $ 12,560 $ 2,162 $ 14,722 Investments and other assets 20,560 (4,787 ) 15,773 2,740 18,513 Total assets 46,045 (17,712 ) 28,333 4,902 33,235 Current liabilities (83,203 ) 30,626 (52,577 ) (8,096 ) (60,673 ) Deferred credits and other (92,475 ) 4,786 (87,689 ) — (87,689 ) Total liabilities (175,678 ) 35,412 (140,266 ) (8,096 ) (148,362 ) Total $ (129,633 ) $ 17,700 $ (111,933 ) $ (3,194 ) $ (115,127 ) (a) All of our gross recognized derivative instruments were subject to master netting arrangements. (b) Includes cash collateral provided to counterparties of $17,700 . (c) Represents cash collateral, cash margin and option premiums 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. Includes cash collateral received from counterparties of $8,096 , cash margin provided to counterparties of $2,162 and option premiums of $2,740 . As of December 31, 2014: Gross Recognized Derivatives (a) Amounts Offset (b) Net Recognized Derivatives Other (c) Amount Reported on Balance Sheet Current assets $ 28,562 $ (15,127 ) $ 13,435 $ 350 $ 13,785 Investments and other assets 24,810 (7,190 ) 17,620 — 17,620 Total assets 53,372 (22,317 ) 31,055 350 31,405 Current liabilities (86,062 ) 33,829 (52,233 ) (7,443 ) (59,676 ) Deferred credits and other (82,990 ) 32,388 (50,602 ) — (50,602 ) Total liabilities (169,052 ) 66,217 (102,835 ) (7,443 ) (110,278 ) Total $ (115,680 ) $ 43,900 $ (71,780 ) $ (7,093 ) $ (78,873 ) (a) All of our gross recognized derivative instruments were subject to master netting arrangements. (b) Includes cash collateral provided to counterparties of $43,900 . (c) Represents cash collateral and margin that is not subject to offsetting. Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument. Includes cash collateral received from counterparties of $7,443 , and cash margin provided to counterparties of $350 . |
Schedule of offsetting liabilities | The following tables provide information about the fair value of our risk management activities reported on a gross basis, and the impacts of offsetting as of June 30, 2015 and December 31, 2014 . These amounts relate to commodity contracts and are located in the assets and liabilities from risk management activities lines of our Condensed Consolidated Balance Sheets. As of June 30, 2015: Gross Recognized Derivatives (a) Amounts Offset (b) Net Recognized Derivatives Other (c) Amount Reported on Balance Sheet Current assets $ 25,485 $ (12,925 ) $ 12,560 $ 2,162 $ 14,722 Investments and other assets 20,560 (4,787 ) 15,773 2,740 18,513 Total assets 46,045 (17,712 ) 28,333 4,902 33,235 Current liabilities (83,203 ) 30,626 (52,577 ) (8,096 ) (60,673 ) Deferred credits and other (92,475 ) 4,786 (87,689 ) — (87,689 ) Total liabilities (175,678 ) 35,412 (140,266 ) (8,096 ) (148,362 ) Total $ (129,633 ) $ 17,700 $ (111,933 ) $ (3,194 ) $ (115,127 ) (a) All of our gross recognized derivative instruments were subject to master netting arrangements. (b) Includes cash collateral provided to counterparties of $17,700 . (c) Represents cash collateral, cash margin and option premiums 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. Includes cash collateral received from counterparties of $8,096 , cash margin provided to counterparties of $2,162 and option premiums of $2,740 . As of December 31, 2014: Gross Recognized Derivatives (a) Amounts Offset (b) Net Recognized Derivatives Other (c) Amount Reported on Balance Sheet Current assets $ 28,562 $ (15,127 ) $ 13,435 $ 350 $ 13,785 Investments and other assets 24,810 (7,190 ) 17,620 — 17,620 Total assets 53,372 (22,317 ) 31,055 350 31,405 Current liabilities (86,062 ) 33,829 (52,233 ) (7,443 ) (59,676 ) Deferred credits and other (82,990 ) 32,388 (50,602 ) — (50,602 ) Total liabilities (169,052 ) 66,217 (102,835 ) (7,443 ) (110,278 ) Total $ (115,680 ) $ 43,900 $ (71,780 ) $ (7,093 ) $ (78,873 ) (a) All of our gross recognized derivative instruments were subject to master netting arrangements. (b) Includes cash collateral provided to counterparties of $43,900 . (c) Represents cash collateral and margin that is not subject to offsetting. Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument. Includes cash collateral received from counterparties of $7,443 , and cash margin provided to counterparties of $350 . |
Information about derivative instruments that have credit-risk-related contingent features | The following table provides information about our derivative instruments that have credit-risk-related contingent features at June 30, 2015 (dollars in millions): June 30, 2015 Aggregate fair value of derivative instruments in a net liability position $ 176 Cash collateral posted 18 Additional cash collateral in the event credit-risk-related contingent features were fully triggered (a) 89 (a) This amount is after counterparty netting and includes those contracts which qualify for scope exceptions, which are excluded from the derivative details above. |
Other Income and Other Expense
Other Income and Other Expense (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
Component of Other Income and Other Expense Nonoperating [Line Items] | |
Detail of other income and other expense | The following table provides detail of other income and other expense for the three and six months ended June 30, 2015 and 2014 (dollars in thousands): Three Months Ended Six Months Ended 2015 2014 2015 2014 Other income: Interest income $ 184 $ 495 $ 294 $ 746 Miscellaneous (9 ) 2,286 116 4,402 Total other income $ 175 $ 2,781 $ 410 $ 5,148 Other expense: Non-operating costs $ (1,952 ) $ (2,620 ) $ (4,200 ) $ (4,992 ) Investment losses — net (650 ) (105 ) (1,145 ) (246 ) Miscellaneous (7 ) 2,217 (1,550 ) 46 Total other expense $ (2,609 ) $ (508 ) $ (6,895 ) $ (5,192 ) |
Arizona Public Service Company | |
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 six months ended June 30, 2015 and 2014 (dollars in thousands): Three Months Ended Six Months Ended 2015 2014 2015 2014 Other income: Interest income $ 6 $ 417 $ 73 $ 554 Gain on disposition of property 478 328 685 645 Miscellaneous 226 2,476 591 4,784 Total other income $ 710 $ 3,221 $ 1,349 $ 5,983 Other expense: Non-operating costs (a) $ (1,878 ) $ (2,868 ) $ (4,395 ) $ (5,455 ) Loss on disposition of property (251 ) (285 ) (894 ) (468 ) Miscellaneous (320 ) 1,676 (2,514 ) (610 ) Total other expense $ (2,449 ) $ (1,477 ) $ (7,803 ) $ (6,533 ) (a) As defined by FERC, includes below-the-line non-operating utility expense (items excluded from utility rate recovery). |
Earnings Per Share (Tables)
Earnings Per Share (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
Earnings Per Share [Abstract] | |
Schedule of earnings per weighted average common share outstanding | The following table presents the calculation of Pinnacle West’s basic and diluted earnings per share for the three and six months ended June 30, 2015 and 2014 (in thousands, except per share amounts): Three Months Ended Six Months Ended 2015 2014 2015 2014 Net income attributable to common shareholders $ 122,902 $ 132,458 $ 139,024 $ 148,224 Weighted average common shares outstanding — basic 110,986 110,565 110,958 110,546 Net effect of dilutive securities: Contingently issuable performance shares and restricted stock units 474 437 468 379 Weighted average common shares outstanding — diluted 111,460 111,002 111,426 110,925 Earnings per average common share attributable to common shareholders — basic $ 1.11 $ 1.20 $ 1.25 $ 1.34 Earnings per average common share attributable to common shareholders — diluted $ 1.10 $ 1.19 $ 1.25 $ 1.34 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
Fair Value Disclosures [Abstract] | |
Fair value of assets and liabilities that are measured at fair value on a recurring basis | The following table presents the fair value at June 30, 2015 , of our assets and liabilities that are measured at fair value on a recurring basis (dollars in millions): 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 June 30, 2015 Assets Risk management activities — derivative instruments: Commodity contracts $ — $ 16 $ 30 $ (13 ) (b) $ 33 Nuclear decommissioning trust: U.S. commingled equity funds — 314 — — 314 Cash and cash equivalent funds — 11 — (4 ) (c) 7 Fixed income securities: U.S. Treasury 93 2 — — 95 Corporate debt — 116 — — 116 Mortgage-backed securities — 87 — — 87 Municipal bonds — 86 — — 86 Other — 19 — — 19 Subtotal nuclear decommissioning trust 93 635 — (4 ) 724 Total $ 93 $ 651 $ 30 $ (17 ) $ 757 Liabilities Risk management activities — derivative instruments: Commodity contracts $ — $ (103 ) $ (73 ) $ 28 (b) $ (148 ) (a) Primarily consists of heat rate options and other long-dated electricity contracts. (b) Represents counterparty netting, margin and collateral (see Note 7). (c) Represents nuclear decommissioning trust net pending securities sales and purchases. The following table presents the fair value at December 31, 2014 , of our assets and liabilities that are measured at fair value on a recurring basis (dollars in millions): 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, 2014 Assets Risk management activities — derivative instruments: Commodity contracts $ — $ 21 $ 33 $ (23 ) (b) $ 31 Nuclear decommissioning trust: U.S. commingled equity funds — 310 — — 310 Fixed income securities: U.S. Treasury 119 — — — 119 Cash and cash equivalent funds — 11 — (7 ) (c) 4 Corporate debt — 109 — — 109 Mortgage-backed securities — 89 — — 89 Municipal bonds — 69 — — 69 Other — 14 — — 14 Subtotal nuclear decommissioning trust 119 602 — (7 ) 714 Total $ 119 $ 623 $ 33 $ (30 ) $ 745 Liabilities Risk management activities — derivative instruments: Commodity contracts $ — $ (95 ) $ (74 ) $ 59 (b) $ (110 ) (a) Primarily consists of heat rate options and other long-dated electricity contracts. (b) Represents counterparty netting, margin and collateral (see Note 7). (c) Represents nuclear decommissioning trust net pending securities sales and purchases. |
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments | The following tables provide information regarding our significant unobservable inputs used to value our risk management derivative Level 3 instruments at June 30, 2015 and December 31, 2014 : June 30, 2015 Valuation Technique Significant Unobservable Input Weighted-Average Commodity Contracts Assets Liabilities Range Electricity: Forward Contracts (a) $ 28 $ 57 Discounted cash flows Electricity forward price (per MWh) $21.07 - $67.74 $ 31.46 Option Contracts (b) — 12 Option model Electricity forward price (per MWh) $32.85 - $67.74 $ 46.13 Electricity price volatilities 26% - 115% 68 % Natural gas price volatilities 27% - 42% 31 % Natural Gas: Forward Contracts (a) 2 4 Discounted cash flows Natural gas forward price (per MMBtu) $2.69 - $3.61 $ 3.23 Total $ 30 $ 73 (a) Includes swaps and physical and financial contracts. (b) Electricity and natural gas price volatilities are estimated based on historical forward price movements due to lack of market quotes for implied volatilities. December 31, 2014 Valuation Technique Significant Unobservable Input Weighted-Average Commodity Contracts Assets Liabilities Range Electricity: Forward Contracts (a) $ 30 $ 56 Discounted cash flows Electricity forward price (per MWh) $19.51 - $56.72 $ 35.27 Option Contracts (b) — 15 Option model Electricity forward price (per MWh) $32.14 - $66.09 $ 45.83 Natural gas forward price (per MMBtu) $3.18 - $3.29 $ 3.25 Electricity price volatilities 23% - 63% 41 % Natural gas price volatilities 23% - 41% 31 % Natural Gas: Forward Contracts (a) 3 3 Discounted cash flows Natural gas forward price (per MMBtu) $2.98 - $4.13 $ 3.45 Total $ 33 $ 74 (a) Includes swaps and physical and financial contracts. (b) Electricity and natural gas price volatilities are estimated based on historical forward price movements due to lack of market quotes for implied volatilities. |
Changes in fair value for assets and liabilities that are measured at fair value on a recurring basis using Level 3 inputs | The following table shows the changes in fair value for our risk management activities' assets and liabilities that are measured at fair value on a recurring basis using Level 3 inputs for the three and six months ended June 30, 2015 and 2014 (dollars in millions): Three Months Ended Six Months Ended Commodity Contracts 2015 2014 2015 2014 Net derivative balance at beginning of period $ (49 ) $ (49 ) $ (41 ) $ (49 ) Total net gains (losses) realized/unrealized: Deferred as a regulatory asset or liability 6 3 (5 ) 6 Settlements 5 4 5 5 Transfers into Level 3 from Level 2 (4 ) 1 (4 ) (2 ) Transfers from Level 3 into Level 2 (1 ) — 2 (1 ) Net derivative balance at end of period $ (43 ) $ (41 ) $ (43 ) $ (41 ) Net unrealized gains included in earnings related to instruments still held at end of period $ — $ — $ — $ — |
Nuclear Decommissioning Trusts
Nuclear Decommissioning Trusts (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
Investments, Debt and Equity Securities [Abstract] | |
Fair value of APS's nuclear decommissioning trust fund assets | The following table includes the unrealized gains and losses based on the original cost of the investment and summarizes the fair value of APS’s nuclear decommissioning trust fund assets at June 30, 2015 and December 31, 2014 (dollars in millions): Fair Value Total Unrealized Gains Total Unrealized Losses June 30, 2015 Equity securities $ 314 $ 160 $ — Fixed income securities 414 13 (3 ) Net payables (a) (4 ) — — Total $ 724 $ 173 $ (3 ) Fair Value Total Unrealized Gains Total Unrealized Losses December 31, 2014 Equity securities $ 310 $ 159 $ — Fixed income securities 411 17 (1 ) Net payables (a) (7 ) — — Total $ 714 $ 176 $ (1 ) (a) Net payables relate to pending purchases and sales of securities. |
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds | The following table sets forth approximate gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds (dollars in millions): Three Months Ended Six Months Ended 2015 2014 2015 2014 Realized gains $ 1 $ 1 $ 2 $ 2 Realized losses (1 ) (1 ) (2 ) (3 ) Proceeds from the sale of securities (a) 110 96 226 199 (a) Proceeds are reinvested in the trust. |
Fair value of fixed income securities, summarized by contractual maturities | The fair value of fixed income securities, summarized by contractual maturities, at June 30, 2015 is as follows (dollars in millions): Fair Value Less than one year $ 13 1 year – 5 years 111 5 years – 10 years 123 Greater than 10 years 167 Total $ 414 |
Changes in Accumulated Other 35
Changes in Accumulated Other Comprehensive Loss (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
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 tables show the changes in accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the three and six months ended June 30, 2015 and 2014 (dollars in thousands): Three Months Ended June 30, 2015 Three Months Ended June 30, 2014 Derivative Instruments Pension and Other Postretirement Benefits Total Derivative Instruments Pension and Other Postretirement Benefits Total Beginning balance, April 1 $ (9,209 ) $ (57,173 ) $ (66,382 ) $ (20,364 ) $ (54,538 ) $ (74,902 ) OCI (loss) before reclassifications 25 (969 ) (944 ) 40 (2,072 ) (2,032 ) Amounts reclassified from accumulated other comprehensive loss 874 (a) 852 (b) 1,726 1,955 (a) 762 (b) 2,717 Net current period OCI (loss) 899 (117 ) 782 1,995 (1,310 ) 685 Ending balance, June 30 $ (8,310 ) $ (57,290 ) $ (65,600 ) $ (18,369 ) $ (55,848 ) $ (74,217 ) (a) 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. (b) These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost. See Note 4. Six Months Ended June 30, 2015 Six Months Ended June 30, 2014 Derivative Instruments Pension and Other Postretirement Benefits Total Derivative Instruments Pension and Other Postretirement Benefits Total Beginning balance, January 1 $ (10,385 ) $ (57,756 ) $ (68,141 ) $ (23,058 ) $ (54,995 ) $ (78,053 ) OCI (loss) before reclassifications (775 ) (969 ) (1,744 ) (381 ) (2,072 ) (2,453 ) Amounts reclassified from accumulated other comprehensive loss 2,850 (a) 1,435 (b) 4,285 5,070 (a) 1,219 (b) 6,289 Net current period OCI (loss) 2,075 466 2,541 4,689 (853 ) 3,836 Ending balance, June 30 $ (8,310 ) $ (57,290 ) $ (65,600 ) $ (18,369 ) $ (55,848 ) $ (74,217 ) (a) 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. (b) These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost. See Note 4. |
Arizona Public Service Company | |
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 tables show the changes in accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the three and six months ended June 30, 2015 and 2014 (dollars in thousands): Three Months Ended June 30, 2015 Three Months Ended June 30, 2014 Derivative Instruments Pension and Other Postretirement Benefits Total Derivative Instruments Pension and Other Postretirement Benefits Total Beginning balance, April 1 $ (9,209 ) $ (37,267 ) $ (46,476 ) $ (20,364 ) $ (29,747 ) $ (50,111 ) OCI (loss) before reclassifications 25 (927 ) (902 ) 40 (2,041 ) (2,001 ) Amounts reclassified from accumulated other comprehensive loss 874 (a) 853 (b) 1,727 1,954 (a) 758 (b) 2,712 Net current period OCI (loss) 899 (74 ) 825 1,994 (1,283 ) 711 Ending balance, June 30 $ (8,310 ) $ (37,341 ) $ (45,651 ) $ (18,370 ) $ (31,030 ) $ (49,400 ) (a) 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. (b) These amounts primarily represent amortization of actuarial loss and are included in the computation of net periodic pension cost. See Note 4. Six Months Ended June 30, 2015 Six Months Ended June 30, 2014 Derivative Instruments Pension and Other Postretirement Benefits Total Derivative Instruments Pension and Other Postretirement Benefits Total Beginning balance, January 1 $ (10,385 ) $ (37,948 ) $ (48,333 ) $ (23,059 ) $ (30,313 ) $ (53,372 ) OCI (loss) before reclassifications (775 ) (927 ) (1,702 ) (381 ) (2,041 ) (2,422 ) Amounts reclassified from accumulated other comprehensive loss 2,850 (a) 1,534 (b) 4,384 5,070 (a) 1,324 (b) 6,394 Net current period OCI (loss) 2,075 607 2,682 4,689 (717 ) 3,972 Ending balance, June 30 $ (8,310 ) $ (37,341 ) $ (45,651 ) $ (18,370 ) $ (31,030 ) $ (49,400 ) (a) 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. (b) These amounts primarily represent amortization of actuarial loss and are included in the computation of net periodic pension cost. See Note 4. |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Change in asset retirement obligations | The following schedule shows the change in our asset retirement obligations for the six months ended June 30, 2015 (dollars in millions): Asset retirement obligations at January 1, 2015 $ 391 Changes attributable to: Accretion expense 12 Settlements (18 ) Estimated cash flow revisions 24 Newly incurred liabilities 39 Asset retirement obligations at June 30, 2015 $ 448 |
Consolidation and Nature of O37
Consolidation and Nature of Operations (Details) - USD ($) $ in Thousands | 6 Months Ended | |
Jun. 30, 2015 | Jun. 30, 2014 | |
Cash paid (received) during the period for: | ||
Income taxes, net of refunds | $ 1,834 | $ (131,154) |
Interest, net of amounts capitalized | 84,008 | 90,707 |
Significant non-cash investing and financing activities: | ||
Accrued capital expenditures | 38,985 | 19,668 |
Dividends accrued but not yet paid | $ 65,933 | $ 62,656 |
Long-Term Debt and Liquidity 38
Long-Term Debt and Liquidity Matters - Narrative (Details) | May. 19, 2015USD ($) | Jun. 30, 2015USD ($)Facility | Jun. 26, 2015USD ($) | May. 28, 2015USD ($) | Jan. 12, 2015USD ($) | Dec. 31, 2014USD ($) |
Debt Provisions | ||||||
Total shareholder equity | $ 4,392,836,000 | $ 4,367,493,000 | ||||
Pinnacle West | Letter of Credit [Member] | Revolving credit facility that matures in May 2019 | ||||||
Long-Term Debt and Liquidity Matters | ||||||
Outstanding letters of credit | 0 | |||||
Pinnacle West | Revolving Credit Facility | Revolving credit facility that matures in May 2019 | ||||||
Long-Term Debt and Liquidity Matters | ||||||
Current borrowing capacity on credit facility | 200,000,000 | |||||
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders | 300,000,000 | |||||
Outstanding borrowings | 0 | |||||
Pinnacle West | Commercial paper | Revolving credit facility that matures in May 2019 | ||||||
Long-Term Debt and Liquidity Matters | ||||||
Maximum commercial paper support available under credit facility | 200,000,000 | |||||
Commercial paper | 0 | |||||
APS | ||||||
Debt Provisions | ||||||
Total shareholder equity | 4,494,357,000 | $ 4,478,243,000 | ||||
APS | ACC | ||||||
Debt Provisions | ||||||
Total shareholder equity | 4,500,000,000 | |||||
Total capitalization | 8,200,000,000 | |||||
Dividend restrictions, shareholder equity required | $ 3,300,000,000 | |||||
APS | ACC | Minimum | ||||||
Debt Provisions | ||||||
Required common equity ratio ordered by ACC (as a percent) | 40.00% | |||||
APS | Arizona pollution control revenue refunding bond, 2009 series B, due 2029 | ||||||
Long-Term Debt and Liquidity Matters | ||||||
Repurchased debt | $ 32,000,000 | |||||
APS | Letter of Credit [Member] | ||||||
Long-Term Debt and Liquidity Matters | ||||||
Outstanding letters of credit | $ 76,000,000 | |||||
APS | Letter of Credit [Member] | Revolving credit facilities maturing in 2018 and 2019 | ||||||
Long-Term Debt and Liquidity Matters | ||||||
Outstanding letters of credit | 0 | |||||
APS | Revolving Credit Facility | Revolving credit facilities maturing in 2018 and 2019 | ||||||
Long-Term Debt and Liquidity Matters | ||||||
Current borrowing capacity on credit facility | 1,000,000,000 | |||||
Outstanding borrowings | $ 0 | |||||
Number of line of credit facilities | Facility | 2 | |||||
APS | Revolving Credit Facility | Revolving credit facility maturing April 2018 | ||||||
Long-Term Debt and Liquidity Matters | ||||||
Current borrowing capacity on credit facility | $ 500,000,000 | |||||
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders | 700,000,000 | |||||
APS | Revolving Credit Facility | Revolving credit facility maturing May 2019 | ||||||
Long-Term Debt and Liquidity Matters | ||||||
Current borrowing capacity on credit facility | 500,000,000 | |||||
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders | 700,000,000 | |||||
APS | Commercial paper | ||||||
Long-Term Debt and Liquidity Matters | ||||||
Maximum commercial paper support available under credit facility | 250,000,000 | |||||
Commercial paper | $ 158,000,000 | |||||
APS | Secured debt | Term loan facility maturing June 26, 2018 | ||||||
Long-Term Debt and Liquidity Matters | ||||||
Debt issued | $ 50,000,000 | |||||
APS | Senior Notes | 2.20% unsecured senior notes that mature on January 15, 2020 | ||||||
Long-Term Debt and Liquidity Matters | ||||||
Debt issued | $ 250,000,000 | |||||
Interest rate (as a percent) | 2.20% | |||||
APS | Senior Notes | 3.15% unsecured senior notes that mature on May 15, 2025 | ||||||
Long-Term Debt and Liquidity Matters | ||||||
Debt issued | $ 300,000,000 | |||||
Interest rate (as a percent) | 3.15% | |||||
Extinguishment of Debt, Amount | $ 300,000,000 | |||||
APS | Senior Notes | 4.65% unsecured senior notes that mature on May 15, 2015 | ||||||
Long-Term Debt and Liquidity Matters | ||||||
Interest rate (as a percent) | 4.65% |
Long-Term Debt and Liquidity 39
Long-Term Debt and Liquidity Matters - Estimated Fair Value of Long-Term Debt (Details) - USD ($) $ in Millions | Jun. 30, 2015 | Dec. 31, 2014 |
Estimated fair value of long-term debt, including current maturities | ||
Carrying Amount | $ 3,669 | $ 3,415 |
Fair Value | 3,943 | 3,839 |
Pinnacle West | ||
Estimated fair value of long-term debt, including current maturities | ||
Carrying Amount | 125 | 125 |
Fair Value | 125 | 125 |
Arizona Public Service Company | ||
Estimated fair value of long-term debt, including current maturities | ||
Carrying Amount | 3,544 | 3,290 |
Fair Value | $ 3,818 | $ 3,714 |
Regulatory Matters (Details)
Regulatory Matters (Details) | Jun. 01, 2015USD ($) | Apr. 02, 2015USD ($)$ / kWh | Mar. 02, 2015USD ($) | Feb. 01, 2015$ / kWh | Jun. 01, 2014USD ($) | Apr. 15, 2014CustomerMW | Mar. 01, 2014USD ($) | Feb. 01, 2014$ / kWh | Jan. 01, 2014USD ($)$ / kWh | Jan. 06, 2012USD ($)$ / kWh | Jun. 01, 2011USD ($) | Jun. 30, 2015USD ($)$ / kWh | Jun. 30, 2014USD ($) | Jul. 01, 2015USD ($) | Mar. 20, 2015USD ($)project | Dec. 31, 2014USD ($) | Jul. 01, 2014USD ($) | Mar. 11, 2014USD ($) | Jul. 12, 2013USD ($) | Dec. 31, 2012USD ($) | Jun. 01, 2012 |
Change in regulatory asset | |||||||||||||||||||||
Deferred fuel and purchased power costs-current period | $ (11,711,000) | $ (1,315,000) | |||||||||||||||||||
Amounts charged to customers | (11,424,000) | (18,399,000) | |||||||||||||||||||
APS | |||||||||||||||||||||
Change in regulatory asset | |||||||||||||||||||||
Deferred fuel and purchased power costs-current period | (11,711,000) | (1,315,000) | |||||||||||||||||||
Amounts charged to customers | $ (11,424,000) | (18,399,000) | |||||||||||||||||||
APS | Filing with the Arizona Corporation Commission | ACC | Retail rate case filing | |||||||||||||||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||||||||||||||
Net retail rate increase | $ 95,500,000 | ||||||||||||||||||||
Approximate percentage of increase in the average retail customer bill | 6.60% | ||||||||||||||||||||
Settlement Agreement | |||||||||||||||||||||
Net change in base rates | $ 0 | ||||||||||||||||||||
Non-fuel base rate increase | 116,300,000 | ||||||||||||||||||||
Fuel-related base rate decrease | $ 153,100,000 | ||||||||||||||||||||
Current base fuel rate (in dollars per kWh) | $ / kWh | 0.03757 | ||||||||||||||||||||
Approved base fuel rate (in dollars per kWh) | $ / kWh | 0.03207 | ||||||||||||||||||||
Estimated amount of transfer of cost recovery for certain renewable energy projects from the RES surcharge to base rates | $ 36,800,000 | ||||||||||||||||||||
Authorized return on common equity (as a percent) | 10.00% | ||||||||||||||||||||
Percentage of debt in capital structure | 46.10% | ||||||||||||||||||||
Percentage of common equity in capital structure | 53.90% | ||||||||||||||||||||
Deferral of property taxes in 2012, if Arizona property tax rates increase (as a percent) | 25.00% | ||||||||||||||||||||
Deferral of property taxes in 2013, if Arizona property tax rates increase (as a percent) | 50.00% | ||||||||||||||||||||
Deferral of property taxes for 2014 and subsequent years, if Arizona property tax rates increase (as a percent) | 75.00% | ||||||||||||||||||||
Deferral of property taxes in all years, if Arizona property tax rates decrease (as a percent) | 100.00% | ||||||||||||||||||||
Elimination of the sharing provision of fuel and purchased power costs | 9 | ||||||||||||||||||||
Period to process the subsequent rate cases | 12 months | ||||||||||||||||||||
ACC staff sufficiency findings, general period of time | 30 days | ||||||||||||||||||||
APS | Filing with the Arizona Corporation Commission | ACC | Retail rate case filing | Maximum | |||||||||||||||||||||
Settlement Agreement | |||||||||||||||||||||
Annual cost recovery due to modifications to the Environmental Improvement Surcharge | $ 5,000,000 | ||||||||||||||||||||
APS | RES | Cost Recovery Mechanisms | ACC | |||||||||||||||||||||
Settlement Agreement | |||||||||||||||||||||
Plan term | 5 years | ||||||||||||||||||||
APS | 2014 RES | Cost Recovery Mechanisms | ACC | |||||||||||||||||||||
Settlement Agreement | |||||||||||||||||||||
Amount of proposed budget | $ 143,000,000 | ||||||||||||||||||||
APS | 2014 RES | AZ Sun Program | Filing with the Arizona Corporation Commission | |||||||||||||||||||||
Settlement Agreement | |||||||||||||||||||||
Request to build additional utility scale solar, capacity | MW | 20 | ||||||||||||||||||||
APS | 2014 RES | Alternative to AZ Sun Program | Filing with the Arizona Corporation Commission | |||||||||||||||||||||
Settlement Agreement | |||||||||||||||||||||
Request to build additional utility scale solar, capacity | MW | 10 | ||||||||||||||||||||
Additional capacity from APS-owned non AZ Sun projects, impacted customers | Customer | 1,500 | ||||||||||||||||||||
APS | 2014 RES | Alternative to AZ Sun Program, Phase 1 | Filing with the Arizona Corporation Commission | |||||||||||||||||||||
Settlement Agreement | |||||||||||||||||||||
Request to build additional utility scale solar, capacity | MW | 8 | ||||||||||||||||||||
APS | 2014 RES | Alternative to AZ Sun Program Phase 2 | Filing with the Arizona Corporation Commission | |||||||||||||||||||||
Settlement Agreement | |||||||||||||||||||||
Request to build additional utility scale solar, capacity | MW | 2 | ||||||||||||||||||||
APS | 2015 RES | Cost Recovery Mechanisms | ACC | |||||||||||||||||||||
Settlement Agreement | |||||||||||||||||||||
Amount of proposed budget | $ 154,000,000 | ||||||||||||||||||||
Amount of approved budget | $ 152,000,000 | ||||||||||||||||||||
APS | 2016 RES | Cost Recovery Mechanisms | ACC | |||||||||||||||||||||
Settlement Agreement | |||||||||||||||||||||
Amount of proposed budget | $ 148,000,000 | ||||||||||||||||||||
APS | 2013 DSMAC | Cost Recovery Mechanisms | |||||||||||||||||||||
Settlement Agreement | |||||||||||||||||||||
Amount of approved budget | $ 68,900,000 | ||||||||||||||||||||
APS | 2013 DSMAC | Cost Recovery Mechanisms | ACC | |||||||||||||||||||||
Settlement Agreement | |||||||||||||||||||||
Amount of proposed budget | $ 87,600,000 | ||||||||||||||||||||
Percentage of cumulative energy savings for current year | 5.00% | ||||||||||||||||||||
APS | 2014 DSMAC | Cost Recovery Mechanisms | ACC | |||||||||||||||||||||
Settlement Agreement | |||||||||||||||||||||
Amount of approved budget | $ 68,900,000 | ||||||||||||||||||||
APS | 2015 DSMAC | Cost Recovery Mechanisms | ACC | |||||||||||||||||||||
Settlement Agreement | |||||||||||||||||||||
Amount of proposed budget | $ 68,900,000 | ||||||||||||||||||||
Number of resource savings projects | project | 3 | ||||||||||||||||||||
APS | 2016 DSMAC | Cost Recovery Mechanisms | ACC | |||||||||||||||||||||
Settlement Agreement | |||||||||||||||||||||
Amount of proposed budget | $ 68,900,000 | ||||||||||||||||||||
Proposed rate reduction percentage | 12.00% | ||||||||||||||||||||
APS | Power Supply Adjustor (PSA) | Cost Recovery Mechanisms | ACC | |||||||||||||||||||||
Change in regulatory asset | |||||||||||||||||||||
Beginning balance | $ 21,000,000 | $ 7,000,000 | 21,000,000 | ||||||||||||||||||
Deferred fuel and purchased power costs-current period | (12,000,000) | (1,000,000) | |||||||||||||||||||
Amounts charged to customers | (11,000,000) | (19,000,000) | |||||||||||||||||||
Ending balance | $ (16,000,000) | $ 1,000,000 | |||||||||||||||||||
PSA rate (in dollars per kWh) | $ / kWh | 0.000887 | ||||||||||||||||||||
PSA rate for prior year (in dollars per kWh) | $ / kWh | 0.001557 | ||||||||||||||||||||
Forward component of increase in PSA (in dollars per kWh) | $ / kWh | 0.001131 | ||||||||||||||||||||
Historical component of increase in PSA (in dollars per kWh) | $ / kWh | (0.000244) | ||||||||||||||||||||
APS | Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters | Cost Recovery Mechanisms | FERC | |||||||||||||||||||||
Change in regulatory asset | |||||||||||||||||||||
Increase in annual wholesale transmission rates | $ 17,600,000 | $ 5,900,000 | |||||||||||||||||||
APS | Lost Fixed Cost Recovery Mechanism | |||||||||||||||||||||
Change in regulatory asset | |||||||||||||||||||||
Percentage of retail revenues | 1.00% | ||||||||||||||||||||
APS | Lost Fixed Cost Recovery Mechanism | Cost Recovery Mechanisms | |||||||||||||||||||||
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 | ||||||||||||||||||||
Amount of adjustment approved representing prorated sales losses | $ 38,500,000 | $ 25,300,000 | |||||||||||||||||||
APS | Net Metering | ACC | |||||||||||||||||||||
Change in regulatory asset | |||||||||||||||||||||
Charge on future customers who install rooftop solar panels (in dollars per kWh) | $ / kWh | 0.70 | 0.70 | 0.70 | ||||||||||||||||||
Estimated monthly collection due to charge on future customers who install rooftop solar panels | $ 4.90 | ||||||||||||||||||||
Proposed fixed grid access charge on new residential solar customers (in dollars per KWh) | $ / kWh | 3 | ||||||||||||||||||||
Estimated monthly collection due to charge on new residential solar customers | $ 21 |
Regulatory Matters - Four Corne
Regulatory Matters - Four Corners and Cholla (Details) - APS $ in Millions | Dec. 23, 2014USD ($) | Dec. 30, 2013USD ($)MW | Jun. 30, 2015USD ($) |
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 | ||
Net receipt due to negotiation of alternate arrangement | $ 40 | ||
Capacity rights over the Arizona Transmission System assign to third-parties | MW | 1,555 | ||
Capacity rights related to marketing and trading group for transmission of the additional power received assign to third-parties | MW | 300 | ||
Four Corners cost deferral | SCE | Four Corners Units 4 and 5 | |||
Business Acquisition [Line Items] | |||
Regulatory assets, non-current | $ 74 | ||
Regulatory noncurrent asset amortization period | 10 years | ||
Retired power plant costs | |||
Business Acquisition [Line Items] | |||
Net book value | $ 125 |
Regulatory Matters - Schedule o
Regulatory Matters - Schedule of Regulatory Assets (Details) - USD ($) $ in Thousands | Jun. 30, 2015 | Dec. 31, 2014 |
Detail of regulatory assets | ||
Regulatory assets, current | $ 135,000 | $ 138,000 |
Regulatory assets, non-current | 1,081,113 | 1,054,087 |
Pension benefits | ||
Detail of regulatory assets | ||
Regulatory assets, current | 0 | 0 |
Regulatory assets, non-current | 505,000 | 485,000 |
Income taxes — allowance for funds used during construction (AFUDC) equity | ||
Detail of regulatory assets | ||
Regulatory assets, current | 5,000 | 5,000 |
Regulatory assets, non-current | 122,000 | 118,000 |
Deferred fuel and purchased power — mark-to-market (Note 7) | ||
Detail of regulatory assets | ||
Regulatory assets, current | 53,000 | 51,000 |
Regulatory assets, non-current | 62,000 | 46,000 |
Transmission vegetation management | ||
Detail of regulatory assets | ||
Regulatory assets, current | 9,000 | 9,000 |
Regulatory assets, non-current | 0 | 5,000 |
Coal reclamation | ||
Detail of regulatory assets | ||
Regulatory assets, current | 0 | 0 |
Regulatory assets, non-current | 6,000 | 7,000 |
Palo Verde VIEs (Note 6) | ||
Detail of regulatory assets | ||
Regulatory assets, current | 0 | 0 |
Regulatory assets, non-current | 26,000 | 35,000 |
Deferred compensation | ||
Detail of regulatory assets | ||
Regulatory assets, current | 0 | 0 |
Regulatory assets, non-current | 36,000 | 34,000 |
Deferred fuel and purchased power | ||
Detail of regulatory assets | ||
Regulatory assets, current | 0 | 7,000 |
Regulatory assets, non-current | 0 | 0 |
Tax expense of Medicare subsidy | ||
Detail of regulatory assets | ||
Regulatory assets, current | 2,000 | 2,000 |
Regulatory assets, non-current | 13,000 | 14,000 |
Loss on reacquired debt | ||
Detail of regulatory assets | ||
Regulatory assets, current | 1,000 | 1,000 |
Regulatory assets, non-current | 16,000 | 16,000 |
Income taxes — investment tax credit basis adjustment | ||
Detail of regulatory assets | ||
Regulatory assets, current | 2,000 | 2,000 |
Regulatory assets, non-current | 46,000 | 46,000 |
Pension and other postretirement benefits deferral | ||
Detail of regulatory assets | ||
Regulatory assets, current | 0 | 4,000 |
Regulatory assets, non-current | 0 | 0 |
Four Corners cost deferral | ||
Detail of regulatory assets | ||
Regulatory assets, current | 7,000 | 7,000 |
Regulatory assets, non-current | 67,000 | 70,000 |
Lost fixed cost recovery | ||
Detail of regulatory assets | ||
Regulatory assets, current | 45,000 | 38,000 |
Regulatory assets, non-current | 0 | 0 |
Retired power plant costs | ||
Detail of regulatory assets | ||
Regulatory assets, current | 10,000 | 10,000 |
Regulatory assets, non-current | 131,000 | 136,000 |
Deferred property taxes | ||
Detail of regulatory assets | ||
Regulatory assets, current | 0 | 0 |
Regulatory assets, non-current | 40,000 | 30,000 |
Other | ||
Detail of regulatory assets | ||
Regulatory assets, current | 1,000 | 2,000 |
Regulatory assets, non-current | 11,000 | 12,000 |
Arizona Public Service Company | ||
Detail of regulatory assets | ||
Regulatory assets, non-current | $ 1,081,113 | $ 1,054,087 |
Regulatory Matters - Schedule43
Regulatory Matters - Schedule of Regulatory Liabilities (Details) - USD ($) $ in Thousands | Jun. 30, 2015 | Dec. 31, 2014 |
Detail of regulatory liabilities | ||
Regulatory liabilities, current | $ 152,000 | $ 131,000 |
Regulatory liabilities, non-current | 1,016,991 | 1,051,196 |
Removal costs | ||
Detail of regulatory liabilities | ||
Regulatory liabilities, current | 44,000 | 31,000 |
Regulatory liabilities, non-current | 245,000 | 273,000 |
Asset retirement obligations | ||
Detail of regulatory liabilities | ||
Regulatory liabilities, current | 0 | 0 |
Regulatory liabilities, non-current | 272,000 | 296,000 |
Renewable energy standard | ||
Detail of regulatory liabilities | ||
Regulatory liabilities, current | 29,000 | 25,000 |
Regulatory liabilities, non-current | 20,000 | 23,000 |
Income taxes — change in rates | ||
Detail of regulatory liabilities | ||
Regulatory liabilities, current | 1,000 | 0 |
Regulatory liabilities, non-current | 71,000 | 72,000 |
Spent nuclear fuel | ||
Detail of regulatory liabilities | ||
Regulatory liabilities, current | 3,000 | 5,000 |
Regulatory liabilities, non-current | 68,000 | 66,000 |
Deferred gains on utility property | ||
Detail of regulatory liabilities | ||
Regulatory liabilities, current | 2,000 | 2,000 |
Regulatory liabilities, non-current | 7,000 | 8,000 |
Income taxes — deferred investment tax credit | ||
Detail of regulatory liabilities | ||
Regulatory liabilities, current | 3,000 | 4,000 |
Regulatory liabilities, non-current | 92,000 | 93,000 |
Deferred fuel and purchased power | ||
Detail of regulatory liabilities | ||
Regulatory liabilities, current | 16,000 | 0 |
Regulatory liabilities, non-current | 0 | 0 |
Demand side management | ||
Detail of regulatory liabilities | ||
Regulatory liabilities, current | 8,000 | 31,000 |
Regulatory liabilities, non-current | 27,000 | 0 |
Other postretirement benefits | ||
Detail of regulatory liabilities | ||
Regulatory liabilities, current | 33,000 | 32,000 |
Regulatory liabilities, non-current | 189,000 | 199,000 |
Other | ||
Detail of regulatory liabilities | ||
Regulatory liabilities, current | 13,000 | 1,000 |
Regulatory liabilities, non-current | $ 26,000 | $ 21,000 |
Retirement Plans and Other Be44
Retirement Plans and Other Benefits - Narrative (Details) - USD ($) | 1 Months Ended | 3 Months Ended | 6 Months Ended | ||
Jul. 31, 2012 | Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | |
Regulatory Assets | |||||
Regulatory asset amortization period | 3 years | ||||
Amortization of regulatory asset | $ 2,000,000 | $ 2,000,000 | $ 4,000,000 | $ 4,000,000 | |
Pension Benefits | |||||
Contributions | |||||
Voluntary employer contributions to pension plan | 80,000,000 | ||||
Minimum employer contributions for the next three years | 0 | ||||
Maximum employer contributions for the next three years | 300,000,000 | ||||
Other Benefits | |||||
Other Postretirement Benefit Plan Remeasurement | |||||
Other postretirement plan benefit remeasurement, amount seeking approval to move to separate account to Pay Union employee medical costs | 100,000,000 | ||||
Contributions | |||||
2,015 | 1,000,000 | ||||
2,016 | 1,000,000 | ||||
2,017 | 1,000,000 | ||||
Maximum | Pension Benefits | |||||
Contributions | |||||
2,015 | 100,000,000 | ||||
2,016 | 100,000,000 | ||||
2,017 | $ 100,000,000 |
Retirement Plans and Other Be45
Retirement Plans and Other Benefits - Schedule of Net Benefit Cost (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | |
Pension Benefits | ||||
Retirement Plans and Other Benefits | ||||
Service cost — benefits earned during the period | $ 14 | $ 12 | $ 30 | $ 27 |
Interest cost on benefit obligation | 31 | 33 | 62 | 65 |
Expected return on plan assets | (45) | (39) | (90) | (79) |
Amortization of: | ||||
Prior service cost | 0 | 0 | 0 | 0 |
Net actuarial loss | 8 | 3 | 16 | 5 |
Net periodic benefit cost | 8 | 9 | 18 | 18 |
Portion of cost charged to expense | 5 | 5 | 11 | 11 |
Other postretirement benefits | ||||
Retirement Plans and Other Benefits | ||||
Service cost — benefits earned during the period | 4 | 5 | 8 | 9 |
Interest cost on benefit obligation | 7 | 11 | 14 | 23 |
Expected return on plan assets | (9) | (13) | (18) | (25) |
Amortization of: | ||||
Prior service cost | (9) | 0 | (19) | 0 |
Net actuarial loss | 0 | 0 | 2 | 0 |
Net periodic benefit cost | (7) | 3 | (13) | 7 |
Portion of cost charged to expense | $ (2) | $ 3 | $ (4) | $ 5 |
Income Taxes (Details)
Income Taxes (Details) - USD ($) | Sep. 13, 2013 | Jun. 30, 2015 |
Income Taxes | ||
Increase (decrease) in deferred income taxes due to adoption of regulations | $ 82,000,000 | |
Consolidation of VIEs | ||
Income Taxes | ||
Income tax expense associates with the VIE's | $ 0 |
Palo Verde Sale Leaseback Var47
Palo Verde Sale Leaseback Variable Interest Entities - Schedule of VIEs (Details) - USD ($) $ in Thousands | Jun. 30, 2015 | Dec. 31, 2014 |
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets | ||
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation | $ 119,320 | $ 121,255 |
Current maturities of long-term debt | 102,723 | 383,570 |
Equity — Noncontrolling interests | 132,807 | 151,609 |
Arizona Public Service Company | ||
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets | ||
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation | 119,320 | 121,255 |
Current maturities of long-term debt | 102,723 | 383,570 |
Equity — Noncontrolling interests | 132,807 | 151,609 |
Arizona Public Service Company | 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 | 119,000 | 121,000 |
Current maturities of long-term debt | 1,000 | 13,000 |
Equity — Noncontrolling interests | $ 133,000 | $ 152,000 |
Palo Verde Sale Leaseback Var48
Palo Verde Sale Leaseback Variable Interest Entities - Narrative (Details) $ in Thousands | Jul. 07, 2014Lease | Jun. 30, 2015USD ($)power_plant | Jun. 30, 2014USD ($) | Jun. 30, 2015USD ($)power_plant | Jun. 30, 2014USD ($) | Dec. 31, 1986Trust |
Palo Verde Sale Leaseback Variable Interest Entities | ||||||
Increase in net income due to consolidation of Palo Verde Sale Leaseback Trusts | $ 4,605 | $ 8,926 | $ 9,210 | $ 17,851 | ||
Arizona Public Service Company | ||||||
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 | $ 4,605 | 8,926 | $ 9,210 | 17,851 | ||
Arizona Public Service Company | 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 | $ 9,000 | 9,000 | $ 18,000 | ||
Maximum payment to the VIEs' noncontrolling equity participants upon the occurrence of certain unlikely events | 114,000 | |||||
VIE debt to be assumed upon the occurrence of certain unlikely events | 1,000 | |||||
Arizona Public Service Company | Consolidation of VIEs | Through 2023 | ||||||
Palo Verde Sale Leaseback Variable Interest Entities | ||||||
Number of leases under which assets are retained | Lease | 1 | |||||
Arizona Public Service Company | Consolidation of VIEs | Through 2033 | ||||||
Palo Verde Sale Leaseback Variable Interest Entities | ||||||
Number of leases under which assets are retained | Lease | 2 | |||||
Arizona Public Service Company | Consolidation of VIEs | 2015 | ||||||
Palo Verde Sale Leaseback Variable Interest Entities | ||||||
Annual lease payments | 49,000 | |||||
Arizona Public Service Company | Consolidation of VIEs | Period 2016 through 2023 | ||||||
Palo Verde Sale Leaseback Variable Interest Entities | ||||||
Annual lease payments | 23,000 | |||||
Arizona Public Service Company | Consolidation of VIEs | Period 2024 through 2033 | ||||||
Palo Verde Sale Leaseback Variable Interest Entities | ||||||
Annual lease payments | $ 16,000 | |||||
Arizona Public Service Company | Consolidation of VIEs | Period 2024 through 2033 | Maximum | ||||||
Palo Verde Sale Leaseback Variable Interest Entities | ||||||
Lease period | 2 years |
Derivative Accounting - Narrati
Derivative Accounting - Narrative (Details) $ in Thousands | 6 Months Ended | |
Jun. 30, 2015USD ($)Counterparty | Dec. 31, 2014USD ($) | |
Derivative Accounting | ||
Percentage of deferred unrealized gains (losses) on contracts due to PSA recovery | 100.00% | |
Designated as Hedging Instruments | ||
Derivative Accounting | ||
Gross recognized derivatives | $ 4,000 | $ 4,000 |
Commodity Contracts | ||
Derivative Accounting | ||
Gross recognized derivatives | $ 175,678 | 169,052 |
Concentration of credit risk, number of counterparties | Counterparty | 1 | |
Concentration of risk with two counterparties, as a percentage of risk management assets | 81.00% | |
Risk management activities-derivative instruments: Commodity Contracts | $ 33,235 | $ 31,405 |
Additional collateral to counterparties for energy related non-derivative instrument contracts | 161,000 | |
Commodity Contracts | Designated as Hedging Instruments | ||
Derivative Accounting | ||
Estimated net gain (loss) before income taxes to be reclassified from accumulated other comprehensive income | $ (4,000) | |
Arizona Public Service Company | ||
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) - 6 months ended Jun. 30, 2015 - Commodity Contracts MMcf in Thousands | GWhMMcf |
Outstanding gross notional amount of derivatives | |
Power | GWh | 3,808 |
Gas | 188 |
Derivative Accounting - Gains a
Derivative Accounting - Gains and Losses from Derivative Instruments (Details) - Commodity Contracts - USD ($) | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | |
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) | (1,430,000) | (3,216,000) | (3,773,000) | (7,654,000) |
Not Designated as Hedging Instruments | ||||
Gains and losses from derivative instruments | ||||
Net gain (loss) recognized in income | 10,547,000 | 4,960,000 | (34,304,000) | 22,975,000 |
Not Designated as Hedging Instruments | Revenue | ||||
Gains and losses from derivative instruments | ||||
Net gain (loss) recognized in income | (66,000) | 155,000 | (114,000) | 63,000 |
Not Designated as Hedging Instruments | Fuel and purchased power | ||||
Gains and losses from derivative instruments | ||||
Net gain (loss) recognized in income | 10,613,000 | 4,805,000 | (34,190,000) | 22,912,000 |
Other comprehensive income | Designated as Hedging Instruments | ||||
Gains and losses from derivative instruments | ||||
Gain (loss) recognized in OCI on derivative instruments (effective portion) | $ 41,000 | $ 66,000 | $ (286,000) | $ 243,000 |
Derivative Accounting - Derivat
Derivative Accounting - Derivative Instruments in the Balance Sheets (Details) - USD ($) $ in Thousands | Jun. 30, 2015 | Dec. 31, 2014 |
Commodity Contracts | ||
Assets | ||
Gross Recognized Derivatives | $ 46,045 | $ 53,372 |
Amounts Offset | (17,712) | (22,317) |
Net Recognized Derivatives | 28,333 | 31,055 |
Other | 4,902 | 350 |
Amount Reported on Balance Sheet | 33,235 | 31,405 |
Liabilities | ||
Gross Recognized Derivatives | (175,678) | (169,052) |
Amounts Offset | 35,412 | 66,217 |
Net Recognized Derivatives | (140,266) | (102,835) |
Other | (8,096) | (7,443) |
Amount Reported on Balance Sheet | (148,362) | (110,278) |
Assets and Liabilities | ||
Gross Recognized Derivatives | (129,633) | (115,680) |
Amounts Offset | 17,700 | 43,900 |
Net Recognized Derivatives | (111,933) | (71,780) |
Other | (3,194) | (7,093) |
Amount Reported on Balance Sheet | (115,127) | (78,873) |
Commodity Contracts | Current Assets | ||
Assets | ||
Gross Recognized Derivatives | 25,485 | 28,562 |
Amounts Offset | (12,925) | (15,127) |
Net Recognized Derivatives | 12,560 | 13,435 |
Other | 2,162 | 350 |
Amount Reported on Balance Sheet | 14,722 | 13,785 |
Commodity Contracts | Investments and Other Assets | ||
Assets | ||
Gross Recognized Derivatives | 20,560 | 24,810 |
Amounts Offset | (4,787) | (7,190) |
Net Recognized Derivatives | 15,773 | 17,620 |
Other | 2,740 | 0 |
Amount Reported on Balance Sheet | 18,513 | 17,620 |
Commodity Contracts | Current Liabilities | ||
Liabilities | ||
Gross Recognized Derivatives | (83,203) | (86,062) |
Amounts Offset | 30,626 | 33,829 |
Net Recognized Derivatives | (52,577) | (52,233) |
Other | (8,096) | (7,443) |
Amount Reported on Balance Sheet | (60,673) | (59,676) |
Assets and Liabilities | ||
Amounts Offset | 43,900 | |
Commodity Contracts | Deferred Credits and Other | ||
Liabilities | ||
Gross Recognized Derivatives | (92,475) | (82,990) |
Amounts Offset | 4,786 | 32,388 |
Net Recognized Derivatives | (87,689) | (50,602) |
Other | 0 | 0 |
Amount Reported on Balance Sheet | (87,689) | (50,602) |
Designated as Hedging Instruments | ||
Liabilities | ||
Gross Recognized Derivatives | $ (4,000) | $ (4,000) |
Derivative Accounting - Credit
Derivative Accounting - Credit Risk and Credit Related Contingent Features (Details) - Commodity Contracts $ in Millions | Jun. 30, 2015USD ($) |
Credit Risk and Credit-Related Contingent Features | |
Aggregate fair value of derivative instruments in a net liability position | $ 176 |
Cash collateral posted | 18 |
Additional cash collateral in the event credit-risk-related contingent features were fully triggered | $ 89 |
Commitments and Contingencies -
Commitments and Contingencies - Palo Verde Nuclear Generating Station and Contractual Obligations (Details) | Jun. 01, 2015USD ($) | Mar. 11, 2015USD ($) | Aug. 18, 2014USD ($) | Jun. 30, 2015USD ($)power_plant | Jun. 30, 2015USD ($)power_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 | $ 42,000,000 | $ 57,400,000 | ||||
Arizona Public Service Company | ||||||
Commitments and Contingencies | ||||||
Maximum insurance against public liability per occurrence for a nuclear incident | $ 13,400,000,000 | |||||
Maximum available nuclear liability insurance | 375,000,000 | |||||
Remaining nuclear liability insurance through mandatory industry wide retrospective assessment program | 12,980,000,000 | |||||
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 | $ 111,000,000 | |||||
Annual payment limitation with respect to maximum potential retrospective premium assessment | 16,500,000 | |||||
Amount of "all risk" (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde | 2,750,000,000 | |||||
Maximum amount that APS could incur under the current NEIL policies for each retrospective assessment | 23,100,000 | |||||
Collateral assurance provided based on rating triggers | $ 61,700,000 | |||||
Period to provide collateral assurance based on rating triggers | 20 days | |||||
Arizona Public Service Company | Gas Generation Projects | ||||||
Commitments and Contingencies | ||||||
Increase in contractual obligations | $ 170,000,000 | |||||
Contractual Obligations | ||||||
2,015 | 26,000,000 | $ 26,000,000 | ||||
2,016 | 89,000,000 | 89,000,000 | ||||
2,017 | 46,000,000 | 46,000,000 | ||||
2,018 | $ 9,000,000 | $ 9,000,000 | ||||
Arizona Public Service Company | Breach of Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste | ||||||
Commitments and Contingencies | ||||||
Litigation settlement amount | $ 12,200,000 | $ 16,700,000 | ||||
Arizona Public Service Company | Breach of Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste | Regulatory Liability | ||||||
Commitments and Contingencies | ||||||
Proceeds from legal settlements | $ 12,200,000 |
Commitments and Contingencies55
Commitments and Contingencies - Superfund-Related Matters, Southwest Power Outage and Clean Air Act (Details) $ in Millions | Jun. 24, 2015USD ($)power_plant | Aug. 06, 2013Defendant | Sep. 08, 2011kVCustomer | Jun. 30, 2015USD ($) |
Arizona Public Service Company | ||||
Loss Contingencies [Line Items] | ||||
Capacity of transmission line that tripped out of service (in kV) | kV | 500 | |||
Period, after the transmission line went off-line, over which generation and transmission resources for the Yuma area were lost | 10 minutes | |||
Number of customers losing service in Yuma area | Customer | 69,700 | |||
Arizona Public Service Company | Contaminated groundwater wells | ||||
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 | |||
Arizona Public Service Company | Clean Air Act Citizen Lawsuit | ||||
Loss Contingencies [Line Items] | ||||
Public comment period | 30 days | |||
Number of power plants in lawsuit | power_plant | 2 | |||
Litigation settlement percent | 15.00% | |||
Four Corners | Clean Air Act Citizen Lawsuit | ||||
Loss Contingencies [Line Items] | ||||
Civil penalty amount | $ 1.5 | |||
Environmental mitigation project cost | $ 6.2 |
Commitments and Contingencies56
Commitments and Contingencies - Environmental Matters and Financial Assurances (Details) $ in Millions | May. 23, 2013USD ($) | Jun. 30, 2015USD ($)Letter_of_credit |
Four Corners | New Mexico Tax Matter | ||
Environmental Matters | ||
Coal severance surtax, penalty, and interest | $ 30 | |
Arizona Public Service Company | Letters of Credit Expiring in 2016 | ||
Financial Assurances | ||
Number of letters of credit expiring | Letter_of_credit | 2 | |
Arizona Public Service Company | Letters of Credit Expiring in 2017 | ||
Financial Assurances | ||
Number of letters of credit expiring | Letter_of_credit | 1 | |
Arizona Public Service Company | Letter of Credit | ||
Financial Assurances | ||
Outstanding letters of credit | $ 76 | |
Arizona Public Service Company | Equity Lessors in Palo Verde sale leaseback transactions | ||
Financial Assurances | ||
Outstanding letters of credit | 20 | |
Arizona Public Service Company | Natural gas tolling contract obligations | ||
Financial Assurances | ||
Outstanding letters of credit | $ 35 | |
Arizona Public Service Company | Four Corners | New Mexico Tax Matter | ||
Environmental Matters | ||
Share of the assessment | $ 12 | |
Regional Haze Rules | Arizona Public Service Company | Four Corners Units 4 and 5 | ||
Environmental Matters | ||
Percentage of share of cost of control | 63.00% | |
Expected environmental cost | $ 400 | |
Regional Haze Rules | Arizona Public Service Company | 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 | Arizona Public Service Company | Four Corners | Four Corners Units 4 and 5 | ||
Environmental Matters | ||
Site contingency increase in loss exposure not accrued, best estimate | $ 45 | |
Regional Haze Rules | Arizona Public Service Company | Navajo Plant | ||
Environmental Matters | ||
Expected environmental cost | 200 | |
Regional Haze Rules | Arizona Public Service Company | Cholla | ||
Environmental Matters | ||
Expected environmental cost | 200 | |
Mercury and air toxic standards (MATS) | Arizona Public Service Company | Navajo Plant | ||
Environmental Matters | ||
Expected environmental cost | 1 | |
Mercury and air toxic standards (MATS) | Arizona Public Service Company | Cholla Units 2 And 3 | ||
Environmental Matters | ||
Expected environmental cost | 130 | |
Coal combustion waste | Arizona Public Service Company | Four Corners | ||
Environmental Matters | ||
Site contingency increase in loss exposure not accrued, best estimate | 15 | |
Coal combustion waste | Arizona Public Service Company | Navajo Plant | ||
Environmental Matters | ||
Site contingency increase in loss exposure not accrued, best estimate | 1 | |
Coal combustion waste | Arizona Public Service Company | Cholla | ||
Environmental Matters | ||
Site contingency increase in loss exposure not accrued, best estimate | $ 85 |
Other Income and Other Expens57
Other Income and Other Expense (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | |
Other income: | ||||
Interest income | $ 184 | $ 495 | $ 294 | $ 746 |
Miscellaneous | (9) | 2,286 | 116 | 4,402 |
Total other income | 175 | 2,781 | 410 | 5,148 |
Other expense: | ||||
Non-operating costs | (1,952) | (2,620) | (4,200) | (4,992) |
Investment losses — net | (650) | (105) | (1,145) | (246) |
Miscellaneous | (7) | 2,217 | (1,550) | 46 |
Total other expense | (2,609) | (508) | (6,895) | (5,192) |
Arizona Public Service Company | ||||
Other income: | ||||
Interest income | 6 | 417 | 73 | 554 |
Gain on disposition of property | 478 | 328 | 685 | 645 |
Miscellaneous | 226 | 2,476 | 591 | 4,784 |
Total other income | 710 | 3,221 | 1,349 | 5,983 |
Other expense: | ||||
Non-operating costs | (1,878) | (2,868) | (4,395) | (5,455) |
Loss on disposition of property | (251) | (285) | (894) | (468) |
Miscellaneous | (320) | 1,676 | (2,514) | (610) |
Total other expense | $ (2,449) | $ (1,477) | $ (7,803) | $ (6,533) |
Earnings Per Share (Details)
Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | |
Earnings Per Share [Abstract] | ||||
Net income attributable to common shareholders | $ 122,902 | $ 132,458 | $ 139,024 | $ 148,224 |
Weighted average common shares outstanding - basic | 110,986 | 110,565 | 110,958 | 110,546 |
Net effect of dilutive securities: | ||||
Contingently issuable performance shares and restricted stock units | 474 | 437 | 468 | 379 |
Weighted average common shares outstanding — diluted | 111,460 | 111,002 | 111,426 | 110,925 |
Earnings per average common share attributable to common shareholders -basic (in dollars per share) | $ 1.11 | $ 1.20 | $ 1.25 | $ 1.34 |
Earnings per average common share attributable to common shareholders -diluted (in dollars per share) | $ 1.10 | $ 1.19 | $ 1.25 | $ 1.34 |
Fair Value Measurements - Asset
Fair Value Measurements - Assets and Liabilities Measured on a Recurring Basis (Details) - USD ($) $ in Thousands | Jun. 30, 2015 | Dec. 31, 2014 |
Assets | ||
Nuclear decommissioning trust | $ 723,582 | $ 713,866 |
Total assets | 30,000 | 33,000 |
Recurring | ||
Assets | ||
Derivative instruments, other | (13,000) | (23,000) |
Derivative assets | 33,000 | 31,000 |
Nuclear decommissioning trust, other | (4,000) | (7,000) |
Nuclear decommissioning trust | 724,000 | 714,000 |
Total, other | (17,000) | (30,000) |
Total assets | 757,000 | 745,000 |
Liabilities | ||
Derivative instruments, other | 28,000 | 59,000 |
Derivative liability | (148,000) | (110,000) |
Recurring | US commingled equity funds | ||
Assets | ||
Nuclear decommissioning trust | 314,000 | 310,000 |
Recurring | U.S. Treasury | ||
Assets | ||
Nuclear decommissioning trust | 95,000 | 119,000 |
Recurring | Cash and cash equivalent funds | ||
Assets | ||
Nuclear decommissioning trust, other | (4,000) | (7,000) |
Nuclear decommissioning trust | 7,000 | 4,000 |
Recurring | Corporate debt | ||
Assets | ||
Nuclear decommissioning trust | 116,000 | 109,000 |
Recurring | Mortgage-backed securities | ||
Assets | ||
Nuclear decommissioning trust | 87,000 | 89,000 |
Recurring | Municipality bonds | ||
Assets | ||
Nuclear decommissioning trust | 86,000 | 69,000 |
Recurring | Other | ||
Assets | ||
Nuclear decommissioning trust | 19,000 | 14,000 |
Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | ||
Assets | ||
Decommissioning fund investments, gross fair value | 93,000 | 119,000 |
Gross assets, fair value disclosure | 93,000 | 119,000 |
Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | U.S. Treasury | ||
Assets | ||
Decommissioning fund investments, gross fair value | 93,000 | 119,000 |
Recurring | Significant Other Observable Inputs (Level 2) | ||
Assets | ||
Gross derivative assets | 16,000 | 21,000 |
Decommissioning fund investments, gross fair value | 635,000 | 602,000 |
Gross assets, fair value disclosure | 651,000 | 623,000 |
Liabilities | ||
Gross derivative liability | (103,000) | (95,000) |
Recurring | Significant Other Observable Inputs (Level 2) | US commingled equity funds | ||
Assets | ||
Decommissioning fund investments, gross fair value | 314,000 | 310,000 |
Recurring | Significant Other Observable Inputs (Level 2) | U.S. Treasury | ||
Assets | ||
Decommissioning fund investments, gross fair value | 2,000 | |
Recurring | Significant Other Observable Inputs (Level 2) | Cash and cash equivalent funds | ||
Assets | ||
Decommissioning fund investments, gross fair value | 11,000 | 11,000 |
Recurring | Significant Other Observable Inputs (Level 2) | Corporate debt | ||
Assets | ||
Decommissioning fund investments, gross fair value | 116,000 | 109,000 |
Recurring | Significant Other Observable Inputs (Level 2) | Mortgage-backed securities | ||
Assets | ||
Decommissioning fund investments, gross fair value | 87,000 | 89,000 |
Recurring | Significant Other Observable Inputs (Level 2) | Municipality bonds | ||
Assets | ||
Decommissioning fund investments, gross fair value | 86,000 | 69,000 |
Recurring | Significant Other Observable Inputs (Level 2) | Other | ||
Assets | ||
Decommissioning fund investments, gross fair value | 19,000 | 14,000 |
Recurring | Significant Unobservable Inputs (Level 3) | ||
Assets | ||
Gross derivative assets | 30,000 | 33,000 |
Gross assets, fair value disclosure | 30,000 | 33,000 |
Liabilities | ||
Gross derivative liability | $ (73,000) | $ (74,000) |
Fair Value Measurements - Signi
Fair Value Measurements - Significant Unobservable Inputs Used to Value Level 3 Instruments (Details 2) $ in Millions | 6 Months Ended | 12 Months Ended |
Jun. 30, 2015USD ($)$ / MMBTU$ / MWh | Dec. 31, 2014USD ($)$ / MMBTU$ / MWh | |
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments | ||
Assets | $ 30 | $ 33 |
Liabilities | 73 | 74 |
Electricity forward contracts | ||
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments | ||
Assets | 28 | 30 |
Liabilities | $ 57 | $ 56 |
Electricity forward contracts | Minimum | Discounted cash flows | ||
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments | ||
Electricity forward price (per MWh) | $ / MWh | 21.07 | 19.51 |
Electricity forward contracts | Maximum | Discounted cash flows | ||
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments | ||
Electricity forward price (per MWh) | $ / MWh | 67.74 | 56.72 |
Electricity forward contracts | Weighted Average | Discounted cash flows | ||
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments | ||
Electricity forward price (per MWh) | $ / MWh | 31.46 | 35.27 |
Option Contracts | ||
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments | ||
Assets | $ 0 | $ 0 |
Liabilities | $ 12 | $ 15 |
Option Contracts | Minimum | Option model | ||
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments | ||
Electricity forward price (per MWh) | $ / MWh | 32.85 | 32.14 |
Natural gas forward price (per MMbtu) | $ / MMBTU | 3.18 | |
Electricity price volatilities (as a percent) | 26.00% | 23.00% |
Natural gas price volatilities (as a percent) | 27.00% | 23.00% |
Option Contracts | Maximum | Option model | ||
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments | ||
Electricity forward price (per MWh) | $ / MWh | 67.74 | 66.09 |
Natural gas forward price (per MMbtu) | $ / MMBTU | 3.29 | |
Electricity price volatilities (as a percent) | 115.00% | 63.00% |
Natural gas price volatilities (as a percent) | 42.00% | 41.00% |
Option Contracts | Weighted Average | Option model | ||
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments | ||
Electricity forward price (per MWh) | $ / MWh | 46.13 | 45.83 |
Natural gas forward price (per MMbtu) | $ / MMBTU | 3.25 | |
Electricity price volatilities (as a percent) | 68.00% | 41.00% |
Natural gas price volatilities (as a percent) | 31.00% | 31.00% |
Natural gas forward contracts | ||
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments | ||
Assets | $ 2 | $ 3 |
Liabilities | $ 4 | $ 3 |
Natural gas forward contracts | Minimum | Discounted cash flows | ||
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments | ||
Natural gas forward price (per MMbtu) | $ / MMBTU | 2.69 | 2.98 |
Natural gas forward contracts | Maximum | Discounted cash flows | ||
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments | ||
Natural gas forward price (per MMbtu) | $ / MMBTU | 3.61 | 4.13 |
Natural gas forward contracts | Weighted Average | Discounted cash flows | ||
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments | ||
Natural gas forward price (per MMbtu) | $ / MMBTU | 3.23 | 3.45 |
Fair Value Measurements - Level
Fair Value Measurements - Level 3 Rollforward Derivatives (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | |
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward] | ||||
Net derivative beginning balance | $ (49,000) | $ (49,000) | $ (41,000) | $ (49,000) |
Deferred as a regulatory asset or liability | 6,000 | 3,000 | (5,000) | 6,000 |
Settlements | 5,000 | 4,000 | 5,000 | 5,000 |
Transfers into Level 3 from Level 2 | (4,000) | 1,000 | (4,000) | (2,000) |
Transfers from Level 3 into Level 2 | (1,000) | 0 | 2,000 | (1,000) |
Net derivative ending balance | (43,000) | (41,000) | (43,000) | (41,000) |
Net unrealized gains included in earnings related to instruments still held at end of period | $ 0 | $ 0 | $ 0 | $ 0 |
Nuclear Decommissioning Trust62
Nuclear Decommissioning Trusts (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | |||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | Dec. 31, 2014 | |
Nuclear decommissioning trust fund assets | |||||
Fair Value | $ 723,582 | $ 723,582 | $ 713,866 | ||
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds | |||||
Proceeds from the sale of securities | 225,779 | $ 199,224 | |||
Fair value of fixed income securities, summarized by contractual maturities | |||||
Total | 723,582 | 723,582 | 713,866 | ||
Arizona Public Service Company | |||||
Nuclear decommissioning trust fund assets | |||||
Fair Value | 723,582 | 723,582 | 713,866 | ||
Unrealized Gains | 173,000 | 173,000 | 176,000 | ||
Unrealized Losses | (3,000) | (3,000) | (1,000) | ||
Net payables for securities purchases | (4,000) | (4,000) | (7,000) | ||
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds | |||||
Realized gains | 1,000 | $ 1,000 | 2,000 | 2,000 | |
Realized losses | (1,000) | (1,000) | (2,000) | (3,000) | |
Proceeds from the sale of securities | 110,000 | $ 96,000 | 225,779 | $ 199,224 | |
Fair value of fixed income securities, summarized by contractual maturities | |||||
Total | 723,582 | 723,582 | 713,866 | ||
Arizona Public Service Company | Equity Securities | |||||
Nuclear decommissioning trust fund assets | |||||
Fair Value | 314,000 | 314,000 | 310,000 | ||
Unrealized Gains | 160,000 | 160,000 | 159,000 | ||
Fair value of fixed income securities, summarized by contractual maturities | |||||
Total | 314,000 | 314,000 | 310,000 | ||
Arizona Public Service Company | Fixed income securities. | |||||
Nuclear decommissioning trust fund assets | |||||
Fair Value | 414,000 | 414,000 | 411,000 | ||
Unrealized Gains | 13,000 | 13,000 | 17,000 | ||
Unrealized Losses | (3,000) | (3,000) | (1,000) | ||
Fair value of fixed income securities, summarized by contractual maturities | |||||
Less than one year | 13,000 | 13,000 | |||
1 year - 5 years | 111,000 | 111,000 | |||
5 years - 10 years | 123,000 | 123,000 | |||
Greater than 10 years | 167,000 | 167,000 | |||
Total | $ 414,000 | $ 414,000 | $ 411,000 |
Changes in Accumulated Other 63
Changes in Accumulated Other Comprehensive Loss (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | |
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||||
Beginning balance | $ (66,382) | $ (74,902) | $ (68,141) | $ (78,053) |
OCI (loss) before reclassifications | (944) | (2,032) | (1,744) | (2,453) |
Amounts reclassified from accumulated other comprehensive loss | 1,726 | 2,717 | 4,285 | 6,289 |
Total other comprehensive income | 782 | 685 | 2,541 | 3,836 |
Ending balance | (65,600) | (74,217) | (65,600) | (74,217) |
Derivative Instruments | ||||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||||
Beginning balance | (9,209) | (20,364) | (10,385) | (23,058) |
OCI (loss) before reclassifications | 25 | 40 | (775) | (381) |
Amounts reclassified from accumulated other comprehensive loss | 874 | 1,955 | 2,850 | 5,070 |
Total other comprehensive income | 899 | 1,995 | 2,075 | 4,689 |
Ending balance | (8,310) | (18,369) | (8,310) | (18,369) |
Pension and other postretirement benefits | ||||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||||
Beginning balance | (57,173) | (54,538) | (57,756) | (54,995) |
OCI (loss) before reclassifications | (969) | (2,072) | (969) | (2,072) |
Amounts reclassified from accumulated other comprehensive loss | 852 | 762 | 1,435 | 1,219 |
Total other comprehensive income | (117) | (1,310) | 466 | (853) |
Ending balance | (57,290) | (55,848) | (57,290) | (55,848) |
Arizona Public Service Company | ||||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||||
Beginning balance | (46,476) | (50,111) | (48,333) | (53,372) |
OCI (loss) before reclassifications | (902) | (2,001) | (1,702) | (2,422) |
Amounts reclassified from accumulated other comprehensive loss | 1,727 | 2,712 | 4,384 | 6,394 |
Total other comprehensive income | 825 | 711 | 2,682 | 3,972 |
Ending balance | (45,651) | (49,400) | (45,651) | (49,400) |
Arizona Public Service Company | Derivative Instruments | ||||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||||
Beginning balance | (9,209) | (20,364) | (10,385) | (23,059) |
OCI (loss) before reclassifications | 25 | 40 | (775) | (381) |
Amounts reclassified from accumulated other comprehensive loss | 874 | 1,954 | 2,850 | 5,070 |
Total other comprehensive income | 899 | 1,994 | 2,075 | 4,689 |
Ending balance | (8,310) | (18,370) | (8,310) | (18,370) |
Arizona Public Service Company | Pension and other postretirement benefits | ||||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||||
Beginning balance | (37,267) | (29,747) | (37,948) | (30,313) |
OCI (loss) before reclassifications | (927) | (2,041) | (927) | (2,041) |
Amounts reclassified from accumulated other comprehensive loss | 853 | 758 | 1,534 | 1,324 |
Total other comprehensive income | (74) | (1,283) | 607 | (717) |
Ending balance | $ (37,341) | $ (31,030) | $ (37,341) | $ (31,030) |
Asset Retirement Obligations Na
Asset Retirement Obligations Narrative (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2015 | Mar. 31, 2015 | Jun. 30, 2015 | Dec. 31, 2014 | |
Asset Retirement Obligations | ||||
Asset retirement obligation, current | $ 28,543 | $ 28,543 | $ 32,462 | |
Arizona Public Service Company | ||||
Asset Retirement Obligations | ||||
Estimated cash flow revisions | 24,000 | |||
Newly incurred liabilities | 39,000 | |||
Asset retirement obligation, current | 28,543 | 28,543 | 32,462 | |
Asset retirement obligation | 448,000 | $ 448,000 | $ 391,000 | |
Arizona Public Service Company | Four Corners | ||||
Asset Retirement Obligations | ||||
Estimated cash flow revisions | 6,000 | $ 18,000 | ||
Arizona Public Service Company | Cholla | ||||
Asset Retirement Obligations | ||||
Newly incurred liabilities | 39,000 | |||
Newly incurred liabilities, increase in plant services | 23,000 | |||
Newly incurred liabilities, decrease in regulatory liabilities | $ 16,000 |
Asset Retirement Obligations Ro
Asset Retirement Obligations Roll-Forward (Details) - Arizona Public Service Company - USD ($) $ in Millions | 6 Months Ended |
Jun. 30, 2015 | |
Change in asset retirement obligations | |
Asset retirement obligations at the beginning of year | $ 391 |
Changes attributable to: | |
Accretion expense | 12 |
Settlements | (18) |
Estimated cash flow revisions | 24 |
Newly incurred liabilities | 39 |
Asset retirement obligations at the end of year | $ 448 |