Document and Entity Information
Document and Entity Information - shares | 3 Months Ended | |
Mar. 31, 2017 | Apr. 25, 2017 | |
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 | Mar. 31, 2017 | |
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 | 111,560,427 | |
Document Fiscal Year Focus | 2,017 | |
Document Fiscal Period Focus | Q1 | |
APS | ||
Entity Information [Line Items] | ||
Entity Registrant Name | ARIZONA PUBLIC SERVICE COMPANY | |
Entity Central Index Key | 7,286 | |
Document Type | 10-Q | |
Document Period End Date | Mar. 31, 2017 | |
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 | 2,017 | |
Document Fiscal Period Focus | Q1 |
CONDENSED CONSOLIDATED STATEMEN
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited) - USD ($) shares in Thousands, $ in Thousands | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
OPERATING REVENUES | $ 677,728 | $ 677,167 |
OPERATING EXPENSES | ||
Fuel and purchased power | 212,395 | 221,285 |
Operations and maintenance | 219,976 | 243,195 |
Depreciation and amortization | 127,627 | 119,476 |
Taxes other than income taxes | 43,836 | 42,501 |
Other expenses | 388 | 548 |
Total | 604,222 | 627,005 |
OPERATING INCOME | 73,506 | 50,162 |
OTHER INCOME (DEDUCTIONS) | ||
Allowance for equity funds used during construction | 9,482 | 10,516 |
Other income (Note 8) | 480 | 117 |
Other expense (Note 8) | (3,680) | (4,038) |
Total | 6,282 | 6,595 |
INTEREST EXPENSE | ||
Interest charges | 51,864 | 50,744 |
Allowance for borrowed funds used during construction | (4,472) | (5,227) |
Total | 47,392 | 45,517 |
INCOME BEFORE INCOME TAXES | 32,396 | 11,240 |
INCOME TAXES | 4,211 | 1,914 |
NET INCOME | 28,185 | 9,326 |
Less: Net income attributable to noncontrolling interests (Note 5) | 4,873 | 4,873 |
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS | $ 23,312 | $ 4,453 |
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING | ||
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - BASIC (in shares) | 111,728 | 111,296 |
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - DILUTED (in shares) | 112,195 | 111,847 |
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING | ||
Net income attributable to common shareholders - basic (in dollars per share) | $ 0.21 | $ 0.04 |
Net income attributable to common shareholders - diluted (in dollars per share) | $ 0.21 | $ 0.04 |
APS | ||
ELECTRIC OPERATING REVENUES | $ 676,869 | $ 676,632 |
OPERATING EXPENSES | ||
Fuel and purchased power | 217,104 | 221,285 |
Operations and maintenance | 212,218 | 238,711 |
Depreciation and amortization | 127,208 | 119,446 |
Income taxes | 11,373 | 5,850 |
Taxes other than income taxes | 43,498 | 42,410 |
Total | 611,401 | 627,702 |
OPERATING INCOME | 65,468 | 48,930 |
OTHER INCOME (DEDUCTIONS) | ||
Income taxes | 2,725 | 1,815 |
Allowance for equity funds used during construction | 9,482 | 10,516 |
Other income (Note 8) | 1,062 | 610 |
Other expense (Note 8) | (4,378) | (4,750) |
Total | 8,891 | 8,191 |
INTEREST EXPENSE | ||
Interest on long-term debt | 47,491 | 46,819 |
Interest on short-term borrowings | 2,128 | 2,077 |
Debt discount, premium and expense | 1,177 | 1,139 |
Allowance for borrowed funds used during construction | (4,472) | (5,040) |
Total | 46,324 | 44,995 |
NET INCOME | 28,035 | 12,126 |
Less: Net income attributable to noncontrolling interests (Note 5) | 4,873 | 4,873 |
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS | $ 23,162 | $ 7,253 |
CONDENSED CONSOLIDATED STATEME3
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
NET INCOME | $ 28,185 | $ 9,326 |
Derivative instruments: | ||
Net unrealized gain (loss), net of tax expense | (770) | (693) |
Reclassification of net realized loss, net of tax expense | 1,207 | 1,141 |
Pension and other postretirement benefits activity, net of tax expense | 522 | 530 |
Total other comprehensive income | 959 | 978 |
COMPREHENSIVE INCOME | 29,144 | 10,304 |
Less: Comprehensive income attributable to noncontrolling interests | 4,873 | 4,873 |
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS | 24,271 | 5,431 |
APS | ||
NET INCOME | 28,035 | 12,126 |
Derivative instruments: | ||
Net unrealized gain (loss), net of tax expense | (770) | (693) |
Reclassification of net realized loss, net of tax expense | 1,207 | 1,141 |
Pension and other postretirement benefits activity, net of tax expense | 611 | 611 |
Total other comprehensive income | 1,048 | 1,059 |
COMPREHENSIVE INCOME | 29,083 | 13,185 |
Less: Comprehensive income attributable to noncontrolling interests | 4,873 | 4,873 |
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS | $ 24,210 | $ 8,312 |
CONDENSED CONSOLIDATED STATEME4
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) (Parenthetical) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
Net unrealized loss, tax expense | $ 674 | $ 546 |
Reclassification of net realized loss, tax expense | 356 | 200 |
Pension and other postretirement benefits activity, tax expense | 704 | 645 |
Arizona Public Service Company | ||
Net unrealized loss, tax expense | 674 | 546 |
Reclassification of net realized loss, tax expense | 356 | 200 |
Pension and other postretirement benefits activity, tax expense | $ 590 | $ 558 |
CONDENSED CONSOLIDATED BALANCE
CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($) $ in Thousands | Mar. 31, 2017 | Dec. 31, 2016 |
CURRENT ASSETS | ||
Cash and cash equivalents | $ 3,028 | $ 8,881 |
Customer and other receivables | 191,175 | 250,491 |
Accrued unbilled revenues | 101,226 | 107,949 |
Allowance for doubtful accounts | (1,946) | (3,037) |
Materials and supplies (at average cost) | 252,598 | 253,979 |
Fossil fuel (at average cost) | 30,656 | 28,608 |
Income tax receivable | 9,531 | 3,751 |
Assets from risk management activities (Note 6) | 4,222 | 19,694 |
Deferred fuel and purchased power regulatory asset (Note 3) | 17,625 | 12,465 |
Other regulatory assets (Note 3) | 138,316 | 94,410 |
Other current assets | 48,565 | 45,028 |
Total current assets | 794,996 | 822,219 |
INVESTMENTS AND OTHER ASSETS | ||
Assets from risk management activities (Note 6) | 0 | 1 |
Nuclear decommissioning trust (Note 11) | 805,048 | 779,586 |
Other assets | 70,025 | 69,063 |
Total investments and other assets | 875,073 | 848,650 |
PROPERTY, PLANT AND EQUIPMENT | ||
Plant in service and held for future use | 17,436,720 | 17,341,888 |
Accumulated depreciation and amortization | (6,060,254) | (5,970,100) |
Net | 11,376,466 | 11,371,788 |
Construction work in progress | 1,005,797 | 1,019,947 |
Palo Verde sale leaseback, net of accumulated depreciation (Note 5) | 112,548 | 113,515 |
Intangible assets, net of accumulated amortization | 251,208 | 90,022 |
Nuclear fuel, net of accumulated amortization | 135,821 | 119,004 |
Total property, plant and equipment | 12,881,840 | 12,714,276 |
DEFERRED DEBITS | ||
Regulatory assets (Note 3) | 1,321,473 | 1,313,428 |
Assets for other postretirement benefits (Note 4) | 175,414 | 166,206 |
Other | 144,029 | 139,474 |
Total deferred debits | 1,640,916 | 1,619,108 |
TOTAL ASSETS | 16,192,825 | 16,004,253 |
CURRENT LIABILITIES | ||
Accounts payable | 250,197 | 264,631 |
Accrued taxes | 182,812 | 138,964 |
Accrued interest | 48,576 | 52,835 |
Common dividends payable | 0 | 72,926 |
Short-term borrowings (Note 2) | 207,297 | 177,200 |
Current maturities of long-term debt (Note 2) | 125,000 | 125,000 |
Customer deposits | 76,149 | 82,520 |
Liabilities from risk management activities (Note 6) | 41,932 | 25,836 |
Liabilities for asset retirements | 8,627 | 9,135 |
Regulatory liabilities (Note 3) | 101,208 | 99,899 |
Other current liabilities | 152,015 | 244,000 |
Total current liabilities | 1,193,813 | 1,292,946 |
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 2) | 4,273,890 | 4,021,785 |
DEFERRED CREDITS AND OTHER | ||
Deferred income taxes | 2,955,441 | 2,945,232 |
Regulatory liabilities (Note 3) | 948,293 | 948,916 |
Liabilities for asset retirements | 623,394 | 615,340 |
Liabilities for pension benefits (Note 4) | 469,746 | 509,310 |
Liabilities from risk management activities (Note 6) | 63,213 | 47,238 |
Customer advances | 92,113 | 88,672 |
Coal mine reclamation | 224,516 | 221,910 |
Deferred investment tax credit | 209,818 | 210,162 |
Unrecognized tax benefits | 10,172 | 10,046 |
Other | 162,476 | 156,784 |
Total deferred credits and other | 5,759,182 | 5,753,610 |
COMMITMENTS AND CONTINGENCIES (SEE NOTE 7) | ||
EQUITY | ||
Common stock, no par value; authorized 150,000,000 shares, 111,587,048 and 111,392,053 issued at respective dates | 2,595,042 | 2,596,030 |
Treasury stock at cost; 29,195 and 55,317 shares at respective dates | (2,270) | (4,133) |
Total common stock | 2,592,772 | 2,591,897 |
Retained earnings | 2,278,867 | 2,255,547 |
Accumulated other comprehensive loss: | ||
Pension and other postretirement benefits | (38,548) | (39,070) |
Derivative instruments | (4,315) | (4,752) |
Total accumulated other comprehensive loss | (42,863) | (43,822) |
Total shareholders’ equity | 4,828,776 | 4,803,622 |
Noncontrolling interests (Note 5) | 137,164 | 132,290 |
Total equity | 4,965,940 | 4,935,912 |
TOTAL LIABILITIES AND EQUITY | 16,192,825 | 16,004,253 |
Arizona Public Service Company | ||
CURRENT ASSETS | ||
Cash and cash equivalents | 2,933 | 8,840 |
Customer and other receivables | 190,898 | 262,611 |
Accrued unbilled revenues | 101,226 | 107,949 |
Allowance for doubtful accounts | (1,946) | (3,037) |
Materials and supplies (at average cost) | 251,360 | 252,777 |
Fossil fuel (at average cost) | 30,656 | 28,608 |
Income tax receivable | 11,195 | 11,174 |
Assets from risk management activities (Note 6) | 4,222 | 19,694 |
Deferred fuel and purchased power regulatory asset (Note 3) | 17,625 | 12,465 |
Other regulatory assets (Note 3) | 138,316 | 94,410 |
Other current assets | 43,040 | 41,849 |
Total current assets | 789,525 | 837,340 |
INVESTMENTS AND OTHER ASSETS | ||
Assets from risk management activities (Note 6) | 0 | 1 |
Nuclear decommissioning trust (Note 11) | 805,048 | 779,586 |
Other assets | 49,094 | 48,320 |
Total investments and other assets | 854,142 | 827,907 |
PROPERTY, PLANT AND EQUIPMENT | ||
Plant in service and held for future use | 17,324,182 | 17,228,787 |
Accumulated depreciation and amortization | (5,974,360) | (5,881,941) |
Net | 11,349,822 | 11,346,846 |
Construction work in progress | 970,880 | 989,497 |
Palo Verde sale leaseback, net of accumulated depreciation (Note 5) | 112,548 | 113,515 |
Intangible assets, net of accumulated amortization | 251,045 | 89,868 |
Nuclear fuel, net of accumulated amortization | 135,821 | 119,004 |
Total property, plant and equipment | 12,820,116 | 12,658,730 |
DEFERRED DEBITS | ||
Regulatory assets (Note 3) | 1,321,473 | 1,313,428 |
Assets for other postretirement benefits (Note 4) | 172,071 | 162,911 |
Other | 130,327 | 130,859 |
Total deferred debits | 1,623,871 | 1,607,198 |
TOTAL ASSETS | 16,087,654 | 15,931,175 |
CURRENT LIABILITIES | ||
Accounts payable | 245,774 | 259,161 |
Accrued taxes | 178,393 | 130,576 |
Accrued interest | 48,349 | 52,525 |
Common dividends payable | 0 | 72,900 |
Short-term borrowings (Note 2) | 116,497 | 135,500 |
Customer deposits | 76,149 | 82,520 |
Liabilities from risk management activities (Note 6) | 41,932 | 25,836 |
Liabilities for asset retirements | 8,182 | 8,703 |
Regulatory liabilities (Note 3) | 101,208 | 99,899 |
Other current liabilities | 149,486 | 226,417 |
Total current liabilities | 965,970 | 1,094,037 |
DEFERRED CREDITS AND OTHER | ||
Deferred income taxes | 3,008,075 | 2,999,295 |
Regulatory liabilities (Note 3) | 948,293 | 948,916 |
Liabilities for asset retirements | 615,230 | 607,234 |
Liabilities for pension benefits (Note 4) | 449,222 | 488,253 |
Liabilities from risk management activities (Note 6) | 63,213 | 47,238 |
Customer advances | 92,113 | 88,672 |
Coal mine reclamation | 209,126 | 206,645 |
Deferred investment tax credit | 209,818 | 210,162 |
Unrecognized tax benefits | 37,534 | 37,408 |
Other | 148,118 | 143,560 |
Total deferred credits and other | 5,780,742 | 5,777,383 |
COMMITMENTS AND CONTINGENCIES (SEE NOTE 7) | ||
EQUITY | ||
Total common stock | 178,162 | 178,162 |
Additional paid-in capital | 2,421,696 | 2,421,696 |
Retained earnings | 2,354,405 | 2,331,245 |
Accumulated other comprehensive loss: | ||
Pension and other postretirement benefits | (20,060) | (20,671) |
Derivative instruments | (4,315) | (4,752) |
Total accumulated other comprehensive loss | (24,375) | (25,423) |
Total shareholders’ equity | 4,929,888 | 4,905,680 |
Noncontrolling interests (Note 5) | 137,164 | 132,290 |
Total equity | 5,067,052 | 5,037,970 |
Long-term debt less current maturities (Note 2) | 4,273,890 | 4,021,785 |
Total capitalization | 9,340,942 | 9,059,755 |
TOTAL LIABILITIES AND EQUITY | $ 16,087,654 | $ 15,931,175 |
CONDENSED CONSOLIDATED BALANCE6
CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical) - $ / shares | Mar. 31, 2017 | Dec. 31, 2016 |
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest [Abstract] | ||
Common stock, par value (in dollars per share) | ||
Common stock, authorized shares (in shares) | 150,000,000 | 150,000,000 |
Common stock, issued shares (in shares) | 111,587,048 | 111,392,053 |
Treasury stock at cost, shares (in shares) | 29,195 | 55,317 |
CONDENSED CONSOLIDATED STATEME7
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
CASH FLOWS FROM OPERATING ACTIVITIES | ||
NET INCOME | $ 28,185 | $ 9,326 |
Adjustments to reconcile net income to net cash provided by operating activities: | ||
Depreciation and amortization including nuclear fuel | 147,861 | 140,759 |
Deferred fuel and purchased power | (988) | 1,007 |
Deferred fuel and purchased power amortization | (4,172) | 2,388 |
Allowance for equity funds used during construction | (9,482) | (10,516) |
Deferred income taxes | 10,357 | 3,468 |
Deferred investment tax credit | (344) | (114) |
Change in derivative instruments fair value | (101) | (111) |
Stock compensation | 9,997 | 16,687 |
Changes in current assets and liabilities: | ||
Customer and other receivables | 47,007 | 47,282 |
Accrued unbilled revenues | 6,723 | 6,445 |
Materials, supplies and fossil fuel | (667) | 1,525 |
Income tax receivable | (5,780) | (4,048) |
Other current assets | (17,353) | (8,131) |
Accounts payable | 22,147 | (38,443) |
Accrued taxes | 43,706 | 43,289 |
Other current liabilities | (101,801) | (38,040) |
Change in margin and collateral accounts — assets | (12) | 681 |
Change in margin and collateral accounts — liabilities | 0 | 410 |
Change in other long-term assets | (36,836) | (17,504) |
Change in other long-term liabilities | 1,604 | (12,151) |
Net cash flow provided by operating activities | 140,051 | 144,209 |
CASH FLOWS FROM INVESTING ACTIVITIES | ||
Capital expenditures | (348,824) | (378,500) |
Contributions in aid of construction | 5,975 | 12,464 |
Allowance for borrowed funds used during construction | (4,472) | (5,227) |
Proceeds from nuclear decommissioning trust sales | 151,126 | 141,809 |
Investment in nuclear decommissioning trust | (151,696) | (142,379) |
Other | (793) | (472) |
Net cash flow used for investing activities | (348,684) | (372,305) |
CASH FLOWS FROM FINANCING ACTIVITIES | ||
Issuance of long-term debt | 255,441 | 0 |
Short-term borrowing and payments — net | 22,097 | 261,800 |
Short-term debt borrowings under revolving credit facility | 8,000 | 0 |
Dividends paid on common stock | (71,177) | (67,611) |
Common stock equity issuance - net of purchases | (11,580) | 8,902 |
Other | (1) | 1 |
Net cash flow provided by financing activities | 202,780 | 203,092 |
NET DECREASE IN CASH AND CASH EQUIVALENTS | (5,853) | (25,004) |
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD | 8,881 | 39,488 |
CASH AND CASH EQUIVALENTS AT END OF PERIOD | 3,028 | 14,484 |
Cash paid during the period for: | ||
Income taxes, net of refunds | (2) | 2,502 |
Interest, net of amounts capitalized | 54,280 | 56,139 |
Significant non-cash investing and financing activities: | ||
Accrued capital expenditures | 79,306 | 59,707 |
Arizona Public Service Company | ||
CASH FLOWS FROM OPERATING ACTIVITIES | ||
NET INCOME | 28,035 | 12,126 |
Adjustments to reconcile net income to net cash provided by operating activities: | ||
Depreciation and amortization including nuclear fuel | 147,443 | 140,729 |
Deferred fuel and purchased power | (988) | 1,007 |
Deferred fuel and purchased power amortization | (4,172) | 2,388 |
Allowance for equity funds used during construction | (9,482) | (10,516) |
Deferred income taxes | 8,899 | 3,394 |
Deferred investment tax credit | (344) | (114) |
Change in derivative instruments fair value | (101) | (111) |
Changes in current assets and liabilities: | ||
Customer and other receivables | 60,782 | 47,575 |
Accrued unbilled revenues | 6,723 | 6,445 |
Materials, supplies and fossil fuel | (631) | 1,525 |
Other current assets | (15,007) | (8,172) |
Accounts payable | 22,847 | (34,999) |
Accrued taxes | 47,817 | 38,784 |
Other current liabilities | (88,990) | (28,748) |
Change in margin and collateral accounts — assets | (12) | 681 |
Change in margin and collateral accounts — liabilities | 0 | 410 |
Change in other long-term assets | (31,172) | (17,375) |
Change in other long-term liabilities | 1,888 | (1,102) |
Net cash flow provided by operating activities | 173,535 | 153,927 |
CASH FLOWS FROM INVESTING ACTIVITIES | ||
Capital expenditures | (343,139) | (369,861) |
Contributions in aid of construction | 5,975 | 12,464 |
Allowance for borrowed funds used during construction | (4,472) | (5,040) |
Proceeds from nuclear decommissioning trust sales | 151,126 | 141,809 |
Investment in nuclear decommissioning trust | (151,696) | (142,379) |
Other | (774) | (472) |
Net cash flow used for investing activities | (342,980) | (363,479) |
CASH FLOWS FROM FINANCING ACTIVITIES | ||
Issuance of long-term debt | 255,441 | 0 |
Short-term borrowing and payments — net | (19,003) | 261,800 |
Dividends paid on common stock | (72,900) | (69,400) |
Net cash flow provided by financing activities | 163,538 | 192,400 |
NET DECREASE IN CASH AND CASH EQUIVALENTS | (5,907) | (17,152) |
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD | 8,840 | 22,056 |
CASH AND CASH EQUIVALENTS AT END OF PERIOD | 2,933 | 4,904 |
Cash paid during the period for: | ||
Income taxes, net of refunds | 0 | 8,772 |
Interest, net of amounts capitalized | 53,129 | 55,580 |
Significant non-cash investing and financing activities: | ||
Accrued capital expenditures | $ 78,977 | $ 59,707 |
CONDENSED CONSOLIDATED STATEME8
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Unaudited) - USD ($) $ in Thousands | Total | Common Stock | Treasury Stock | Retained Earnings | Accumulated Other Comprehensive Income (Loss) | Noncontrolling Interests | 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, 2015 | 111,095,402 | 115,030 | 71,264,947 | ||||||||||
Balance at beginning of period at Dec. 31, 2015 | $ 4,719,457 | $ 2,541,668 | $ (5,806) | $ 2,092,803 | $ (44,748) | $ 135,540 | $ 4,814,794 | $ 178,162 | $ 2,379,696 | $ 2,148,493 | $ (27,097) | $ 135,540 | |
Increase (Decrease) in Shareholders' Equity | |||||||||||||
Net income | 9,326 | 4,453 | 4,873 | 12,126 | 7,253 | 4,873 | |||||||
Other comprehensive income | 978 | 978 | 1,059 | 1,059 | |||||||||
Other | 1 | 0 | 1 | ||||||||||
Issuance of common stock (in shares) | 52,122 | ||||||||||||
Issuance of common stock | 5,397 | $ 5,397 | |||||||||||
Purchase of treasury stock (in shares) | [1] | (71,962) | |||||||||||
Purchase of treasury stock | [1] | (4,880) | $ (4,880) | ||||||||||
Reissuance of treasury stock for stock-based compensation and other (in shares) | 179,056 | ||||||||||||
Reissuance of treasury stock for stock-based compensation and other | 10,135 | $ 10,144 | (10) | 1 | |||||||||
Ending balance (in shares) at Mar. 31, 2016 | 111,147,524 | 7,936 | 71,264,947 | ||||||||||
Balance at end of period at Mar. 31, 2016 | $ 4,740,413 | $ 2,547,065 | $ (542) | 2,097,246 | (43,770) | 140,414 | 4,827,980 | $ 178,162 | 2,379,696 | 2,155,746 | (26,038) | 140,414 | |
Beginning balance (in shares) at Dec. 31, 2016 | 111,392,053 | 111,392,053 | 55,317 | 71,264,947 | |||||||||
Balance at beginning of period at Dec. 31, 2016 | $ 4,935,912 | $ 2,596,030 | $ (4,133) | 2,255,547 | (43,822) | 132,290 | 5,037,970 | $ 178,162 | 2,421,696 | 2,331,245 | (25,423) | 132,290 | |
Increase (Decrease) in Shareholders' Equity | |||||||||||||
Net income | 28,185 | 23,312 | 4,873 | 28,035 | 23,162 | 4,873 | |||||||
Other comprehensive income | 959 | 959 | 1,048 | 1,048 | |||||||||
Other | (1) | (2) | 1 | ||||||||||
Issuance of common stock (in shares) | 194,995 | ||||||||||||
Issuance of common stock | (988) | $ (988) | |||||||||||
Purchase of treasury stock (in shares) | [1] | (153,470) | |||||||||||
Purchase of treasury stock | [1] | (12,141) | $ (12,141) | ||||||||||
Reissuance of treasury stock for stock-based compensation and other (in shares) | 179,592 | ||||||||||||
Reissuance of treasury stock for stock-based compensation and other | $ 14,013 | $ 14,004 | 8 | 1 | |||||||||
Ending balance (in shares) at Mar. 31, 2017 | 111,587,048 | 111,587,048 | 29,195 | 71,264,947 | |||||||||
Balance at end of period at Mar. 31, 2017 | $ 4,965,940 | $ 2,595,042 | $ (2,270) | $ 2,278,867 | $ (42,863) | $ 137,164 | $ 5,067,052 | $ 178,162 | $ 2,421,696 | $ 2,354,405 | $ (24,375) | $ 137,164 | |
[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 | 3 Months Ended |
Mar. 31, 2017 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Consolidation and Nature of Operations | Consolidation and Nature of Operations The unaudited condensed consolidated financial statements include the accounts of Pinnacle West and our subsidiaries: APS, 4C Acquisition, LLC ("4CA"), Bright Canyon Energy Corporation ("BCE") and El Dorado Investment Company ("El Dorado"). 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 5 for further discussion). Our accounting records are maintained in accordance with accounting principles generally accepted in the United States of America ("GAAP"). The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Amounts reported in our interim Condensed Consolidated Statements of Income are not necessarily indicative of amounts expected for the respective annual periods, due to the effects of seasonal temperature variations on energy consumption, timing of maintenance on electric generating units, and other factors. Our condensed consolidated financial statements reflect all adjustments (consisting only of normal recurring adjustments except as otherwise disclosed in the notes) that we believe are necessary for the fair presentation of our financial position, results of operations, and cash flows for the periods presented. Certain information and footnote disclosures normally included in financial statements prepared in conformity with GAAP have been condensed or omitted pursuant to such regulations, although we believe that the disclosures provided are adequate to make the interim information presented not misleading. The accompanying condensed consolidated financial statements and these notes should be read in conjunction with the audited consolidated financial statements and notes included in our 2016 Form 10-K. Certain line items are presented in more detail on the Condensed Consolidated Statements of Cash Flows than was presented in the prior years. The prior year amounts were reclassified to conform to the current year presentation. These reclassifications have no impact on net cash flows provided by operating activities. The following tables show the impacts of the reclassifications of the prior year's (previously reported) amounts (dollars in thousands): Statements of Cash Flows for the As previously Reclassifications to conform to current year presentation Amount reported after reclassification to conform to current year presentation Cash Flows from Operating Activities Stock compensation $ — $ 16,687 $ 16,687 Change in other long-term liabilities 4,536 (16,687 ) (12,151 ) Supplemental Cash Flow Information The following table summarizes supplemental Pinnacle West cash flow information (dollars in thousands): Three Months Ended 2017 2016 Cash paid (received) during the period for: Income taxes, net of refunds $ (2 ) $ 2,502 Interest, net of amounts capitalized 54,280 56,139 Significant non-cash investing and financing activities: Accrued capital expenditures $ 79,306 $ 59,707 |
Long-Term Debt and Liquidity Ma
Long-Term Debt and Liquidity Matters | 3 Months Ended |
Mar. 31, 2017 | |
Debt Disclosure [Abstract] | |
Long-Term Debt and Liquidity Matters | Long-Term Debt and Liquidity Matters Pinnacle West and APS maintain committed revolving credit facilities in order to enhance liquidity and provide credit support for their commercial paper programs, to refinance indebtedness, and for other general corporate purposes. Pinnacle West At March 31, 2017 , Pinnacle West had a $200 million facility that matures in May 2021. Pinnacle West has the option to increase the amount of the facility up to a maximum of $300 million upon the satisfaction of certain conditions and with the consent of the lenders. At March 31, 2017 , Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding and $42.8 million of commercial paper borrowings. At March 31, 2017 , Pinnacle West had a $75 million 364 -day unsecured revolving credit facility that matures in August 2017. Borrowings under the facility will bear interest at LIBOR plus 0.80% per annum. At March 31, 2017 , Pinnacle West had $48 million outstanding under the facility. APS On March 21, 2017 , APS issued an additional $250 million par amount of its outstanding 4.35% unsecured senior notes that mature on November 15, 2045. The net proceeds from the sale were used to refinance commercial paper borrowings and to replenish cash temporarily used to fund capital expenditures. At March 31, 2017 , APS had two revolving credit facilities totaling $1 billion , including a $500 million credit facility that matures in September 2020 and a $500 million facility that matures in May 2021. APS may increase the amount of each facility up to a maximum of $700 million , for a total of $1.4 billion , upon the satisfaction of certain conditions and with the consent of the lenders. Interest rates are based on APS’s senior unsecured debt credit ratings. These facilities are available to support APS’s $500 million commercial paper program, for bank borrowings or for issuances of letters of credit. At March 31, 2017 , APS had $116.5 million of commercial paper outstanding and no outstanding borrowings or letters of credit under its revolving credit facilities. See "Financial Assurances" in Note 7 for a discussion of APS’s other 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 presents the estimated fair value of our long-term debt, including current maturities (dollars in thousands): As of March 31, 2017 As of December 31, 2016 Carrying Amount Fair Value Carrying Amount Fair Value Pinnacle West $ 125,000 $ 125,000 $ 125,000 $ 125,000 APS 4,273,890 4,558,285 4,021,785 4,300,789 Total $ 4,398,890 $ 4,683,285 $ 4,146,785 $ 4,425,789 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 March 31, 2017 , APS was in compliance with this common equity ratio requirement. Its total shareholder equity was approximately $4.9 billion , and total capitalization was approximately $9.4 billion . APS would be prohibited from paying dividends if the payment would reduce its total shareholder equity below approximately $3.8 billion , assuming APS’s total capitalization remains the same. |
Regulatory Matters
Regulatory Matters | 3 Months Ended |
Mar. 31, 2017 | |
Regulated Operations [Abstract] | |
Regulatory Matters | Regulatory Matters Retail Rate Case Filing with the Arizona Corporation Commission On June 1, 2016, APS filed an application with the ACC for an annual increase in retail base rates of $165.9 million . This amount excludes amounts that are currently collected on customer bills through adjustor mechanisms. The application requests that some of the balances in these adjustor accounts (aggregating to approximately $267.6 million as of December 31, 2015) be transferred into base rates through the ratemaking process. This transfer would not have an incremental effect on average customer bills. The average annual customer bill impact of APS’s request is an increase of 5.74% (the average annual bill impact for a typical APS residential customer is 7.96% ) . The principal provisions of the application are described in detail in Note 3 of our 2016 Form 10-K. On March 1, 2017, the ACC Staff filed with the ACC a settlement term sheet. The settlement term sheet was agreed to by a majority of the formal stakeholders in the rate case, including the ACC Staff, the Residential Utility Consumer Office, limited income advocates and private rooftop solar organizations. The settlement term sheet was converted into a definitive settlement agreement (the "2017 Settlement Agreement"), was signed by the supporting parties and was filed with the ACC on March 27, 2017. The 2017 Settlement Agreement was submitted to the administrative law judge ("ALJ"), whose decision regarding whether the settlement should be approved will be reviewed by the ACC. Hearings on the proposed settlement began on April 24, 2017. In its original filing, the Company requested that the rate increase become effective July 1, 2017. In July 2016, the ALJ set a procedural schedule for the rate proceeding, which supported completing the case within 12 months. On January 13, 2017, the ALJ issued a procedural order delaying hearings on the case for approximately one month to allow parties to prepare testimony on the distributed generation ("DG") rate design issues addressed in the value and cost of DG decision. In light of this delay in the start of the hearings on the settlement, we currently expect a moderate delay in the scheduling of a final ACC vote on the settlement beyond the originally-anticipated July 1, 2017 date. On April 27, 2017, Commissioner Burns filed a motion requesting that the ALJ suspend and continue the rate case proceedings and facilitate an investigation to determine whether certain commissioners should be disqualified from further participation in the matter. The 2017 Settlement Agreement provides for a net retail base rate increase of $94.6 million , excluding the transfer of adjustor balances, consisting of: (1) a non-fuel, non-depreciation, base rate increase of $87.2 million per year; (2) a base rate decrease of $53.6 million attributable to reduced fuel and purchased power costs; and (3) a base rate increase of $61 million due to changes in depreciation schedules. Other key provisions of the agreement include the following: • an agreement by APS not to file another general rate case application before June 1, 2019; • an authorized return on common equity of 10.0% ; • a capital structure comprised of 44.2% debt and 55.8% common equity; • a cost deferral order for potential future recovery in APS’s next general rate case for the construction and operating costs APS incurs for its Ocotillo modernization project; • a cost deferral and procedure to allow APS to request rate adjustments prior to its next general rate case related to its share of the construction costs associated with installing selective catalytic reduction ("SCR") equipment at the Four Corners Power Plant ("Four Corners"); • a deferral for future recovery (or credit to customers) of the Arizona property tax expense above or below a specified test year level caused by changes to the applicable Arizona property tax rate; • an expansion of the Power Supply Adjustor (“PSA”) to include certain environmental chemical costs and third-party battery storage costs; • a new AZ Sun II program for utility-owned solar distributed generation with the purpose of expanding access to rooftop solar for low and moderate income Arizonans, recoverable through the Arizona Renewable Energy Standard and Tariff ("RES"), to be no less than $10 million per year, and not more than $15 million per year; • an environmental improvement surcharge cumulative per kilowatt-hour (“kWh”) cap rate increase from $0.00016 to a new rate of $0.00050 , which includes a balancing account; • rate design changes, including: ▪ a change in the on-peak time of use period from noon - 7 p.m. to 3 p.m. - 8 p.m. Monday through Friday, excluding holidays; ▪ non-grandfathered distributed generation customers would be required to select a rate option that has time of use rates and either a new grid access charge or demand component; ▪ a Resource Comparison Proxy (“RCP”) for exported energy of 12.9 cents per kWh in year one; and • an agreement by APS not to pursue any new self-build generation (with certain exceptions) having an in-service date prior to January 1, 2022 (extended to December 31, 2027 for combined-cycle generating units), unless expressly authorized by the ACC. Through a separate agreement, APS, industry representatives, and solar advocates commit to stand by the settlement agreement and refrain from seeking to undermine it through ballot initiatives, legislation or advocacy at the ACC. APS cannot predict whether the 2017 Settlement Agreement will ultimately be approved by the ACC, or the exact timing of the ACC's consideration of the matter. Prior Rate Case Filing 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. 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 kWh; and (3) the transfer of cost recovery for certain renewable energy projects from the RES surcharge to base rates in an estimated amount of $36.8 million . Other key provisions of the 2012 Settlement Agreement are described in detail in Note 3 of our 2016 Form 10-K. 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. In December 2014, the ACC voted that it had no objection to APS implementing an APS-owned rooftop solar research and development program aimed at learning how to efficiently enable the integration of rooftop solar and battery storage with the grid. The first stage of the program, called the "Solar Partner Program," placed 8 MW of residential rooftop solar on strategically selected distribution feeders in an effort to maximize potential system benefits, as well as made systems available to limited-income customers who could not easily install solar through transactions with third parties. The second stage of the program, which included an additional 2 MW of rooftop solar and energy storage, placed two energy storage systems sized at 2 MW on two different high solar penetration feeders to test various grid-related operation improvements and system interoperability, and was in operation by the end of 2016. The ACC expressly reserved that any determination of prudency of the residential rooftop solar program for rate making purposes would not be made until the project was fully in service, and APS has requested cost recovery for the project in its currently pending rate case. On September 30, 2016, APS presented its preliminary findings from the residential rooftop solar program in a filing with the ACC. On July 1, 2015, APS filed its 2016 RES Implementation Plan and proposed a RES budget of approximately $148 million . On January 12, 2016, the ACC approved APS’s plan and requested budget. On July 1, 2016, APS filed its 2017 RES Implementation Plan and proposed a budget of approximately $150 million . APS’s budget request included additional funding to process the high volume of residential rooftop solar interconnection requests and also requested a permanent waiver of the residential distributed energy requirement for 2017 contained in the RES rules. On April 7, 2017, APS filed an amended 2017 RES Implementation Plan and updated budget request which includes the revenue neutral transfer of specific revenue requirements in accordance with the 2017 Settlement Agreement. The ACC has not yet ruled on the Company’s 2017 RES Implementation Plan. In September 2016, the ACC initiated a proceeding which will examine the possible modernization and expansion of the RES. The ACC noted that many of the provisions of the original rule may no longer be appropriate, and the underlying economic assumptions associated with the rule have changed dramatically. The proceeding will review such issues as the rapidly declining cost of solar generation, an increased interest in community solar projects, energy storage options, and the decline in fossil fuel generation due to stringent regulations of the United States Environmental Protection Agency ("EPA"). The proceeding will also examine the feasibility of increasing the standard to 30% of retail sales by 2030, in contrast to the current standard of 15% of retail sales by 2025. APS cannot predict the outcome of this proceeding. Demand Side Management Adjustor Charge ("DSMAC") . 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. In March 2014, the ACC approved a Resource Savings Initiative that allows APS to count towards compliance with the ACC Electric Energy Efficiency Standards, savings from 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. The ACC approved APS’s 2015 DSM budget on November 25, 2015. In its decision, the ACC also approved that verified energy savings from APS's resource savings projects could be counted toward compliance with the Electric Energy Efficiency Standard, however, the ACC ruled that APS was not allowed to count savings from systems savings projects toward determination of its achievement tier level for its performance incentive, nor may APS include savings from conservation voltage reduction in the calculation of its Lost Fixed Cost Recovery Mechanism (“LFCR”) mechanism. 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. On April 1, 2016, APS filed an amended 2016 DSM Plan that sought minor modifications to its existing DSM Plan and requested to continue the current DSMAC and current budget of $68.9 million . On July 12, 2016, the ACC approved APS’s amended DSM Plan and directed APS to spend up to an additional $4 million on a new residential demand response or load management program that facilitates energy storage technology. On December 5, 2016, APS filed for ACC approval of a $4 million Residential Demand Response, Energy Storage and Load Management Program. On June 1, 2016, the Company filed its 2017 DSM Implementation Plan, in which APS proposes programs and measures that specifically focus on reducing peak demand, shifting load to off-peak periods and educating customers about strategies to manage their energy and demand. The requested budget in the 2017 DSM Implementation Plan is $62.6 million . On January 27, 2017, APS filed an updated and modified 2017 DSM Implementation Plan that incorporated the proposed Residential Demand Response, Energy Storage and Load Management Program and the requested budget increased to $66.6 million . The ACC has not yet ruled on the Company’s 2017 DSM Plan. 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. On July 12, 2016, the ACC ordered that ACC staff convene a workshop within 120 days to discuss a number of issues related to the Electric Energy Efficiency Standards, including the process of determining the cost effectiveness of DSM programs and the treatment of peak demand and capacity reductions, among others. ACC staff convened the workshop on November 29, 2016 and sought public comment on potential revisions to the Electric Energy Efficiency Standards. APS cannot predict the outcome of this proceeding. 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 2017 and 2016 (dollars in thousands): Three Months Ended 2017 2016 Beginning balance $ 12,465 $ (9,688 ) Deferred fuel and purchased power costs — current period 988 (1,007 ) Amounts charged to customers 4,172 (2,388 ) Ending balance $ 17,625 $ (13,083 ) The PSA rate for the PSA year beginning February 1, 2017 is $(0.001348) per kWh, as compared to $0.001678 per kWh for the prior year. This new rate is comprised of a forward component of $(0.001027) per kWh and a historical component of $(0.000321) per kWh. Transmission Rates, Transmission Cost Adjustor ("TCA") 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 Charges because any adjustment, though applied prospectively, may be calculated to account for previously over- or under-collected amounts. 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. Effective June 1, 2016, APS's annual wholesale transmission rates for all users of its transmission system increased by approximately $24.9 million for the twelve-month period beginning June 1, 2016 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, 2016. On January 31, 2017, APS made a filing to reduce the Post-Employment Benefits Other than Pension expense reflected in its FERC transmission formula rate calculation to recognize certain savings resulting from plan design changes to the other postretirement benefit plans. A transmission customer intervened and protested certain aspects of APS’s filing. FERC initiated a proceeding under Section 206 of the Federal Power Act to evaluate the justness and reasonableness of the revised formula rate filing APS proposed. At this time, APS is unable to predict the outcome of this proceeding. APS's formula rate implementation protocols have been in effect since 2008. Recent FERC orders suggest that FERC is examining the structure of formula rate implementation protocols and may require companies to make changes to their protocols in the future. As a result, APS made an administrative filing to update its formula rate implementation protocols on March 3, 2017, which was accepted by FERC with an effective date of May 1, 2017. 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. APS files for a LFCR adjustment every January. APS filed its 2015 annual LFCR adjustment on January 15, 2015, requesting an LFCR adjustment of $38.5 million , which was approved on March 16, 2015, effective for the first billing cycle of March. APS filed its 2016 annual LFCR adjustment on January 15, 2016, requesting an LFCR adjustment of $46.4 million (a $7.9 million annual increase), to be effective for the first billing cycle of March 2016. The ACC approved the 2016 annual LFCR to be effective in May 2016. APS filed its 2017 LFCR adjustment on January 13, 2017 requesting an LFCR adjustment of $63.7 million (a $17.3 million per year increase over 2016 levels), to be effective for the first billing cycle of March 2017. On April 5, 2017, the ACC approved the 2017 annual LFCR adjustment as filed, to be effective with the first billing cycle of April 2017. Because the LFCR mechanism has a balancing account that trues up any under or over recoveries, a one or two month delay in implementation does not have an adverse effect on APS. Net Metering In 2015, the ACC voted to conduct a generic evidentiary hearing on the value and cost of distributed generation to gather information that will inform the ACC on net metering issues and cost of service studies in upcoming utility rate cases. A hearing was held in April 2016. On October 7, 2016, the ALJ issued a recommendation in the docket concerning the value and cost of DG solar installations. On December 20, 2016, the ACC completed its open meeting to consider the recommended decision by the ALJ. After making several amendments, the ACC approved the recommended decision by a 4-1 vote. As a result of the ACC’s action, effective following APS’s pending rate case, the current net metering tariff that governs payments for energy exported to the grid from rooftop solar systems will be replaced by a more formula-driven approach that will utilize inputs from historical wholesale solar power costs and eventually an avoided cost methodology. As amended, the decision provides that payments by utilities for energy exported to the grid from DG solar facilities will be determined using a resource comparison proxy methodology, a method that is based on the price that APS pays for utility-scale solar projects on a five year rolling average, while a forecasted avoided cost methodology is being developed. The price established by this resource comparison proxy method will be updated annually (between rate cases) but will not be decreased by more than 10% per year. Once the avoided cost methodology is developed, the ACC will determine in APS's subsequent rate cases which method (or a combination of methods) is appropriate to determine the actual price to be paid by that utility for exported distributed energy. In addition, the ACC made the following determinations: • Customers who have interconnected a DG system or submitted an application for interconnection for DG systems prior to the date new rates are effective based on APS' pending rate case will be grandfathered for a period of 20 years from the date of interconnection; • Customers with DG solar systems are to be considered a separate class of customers for ratemaking purposes; and • Once an export price is set for APS, no netting or banking of retail credits will be available for new DG customers, and the then-applicable export price will be guaranteed for new customers for a period of 10 years. This decision of the ACC addresses policy determinations only. The decision states that its principles will be applied in future rate cases, and the policy determinations themselves may be subject to future change as are all ACC policies. The determination of the initial export energy price to be paid by APS will be made in APS’s currently pending rate case. APS cannot predict the outcome of this determination. The ACC’s decision did not make any policy determinations as to any specific costs to be charged to DG solar system customers for their use of the grid. The determination of any such costs will be made in APS's future rate cases. On January 23, 2017, The Alliance for Solar Choice ("TASC") sought rehearing of the ACC's decision regarding the value and cost of DG. TASC asserts that the ACC improperly ignored the Administrative Procedure Act, failed to give adequate notice regarding the scope of the proceedings, and relied on information that was not submitted as evidence, among other alleged defects. Consistent with Arizona statute, TASC filed a Notice of Appeal in the Court of Appeals and filed a Complaint and Statutory Appeal in the Maricopa County Superior Court on March 10, 2017. In accordance with the 2017 Settlement Agreement described above, in the event the ACC approves the 2017 Settlement Agreement, these appeals will be withdrawn by TASC. The ACC's decision is expected to remain in effect during any legal challenge. Appellate Review of Third-Party Regulatory Decision ("System Improvement Benefits" or "SIB") In a recent appellate challenge to an ACC rate decision involving a water company, the Arizona Court of Appeals considered the question of how the ACC should determine the “fair value” of a utility’s property, as specified in the Arizona Constitution, in connection with authorizing the recovery of costs through rate adjustors outside of a rate case. The Court of Appeals reversed the ACC’s method of finding fair value in that case, and raised questions concerning the relationship between the need for fair value findings and the recovery of capital and certain other utility costs through adjustors. The ACC sought review by the Arizona Supreme Court of this decision, and APS filed a brief supporting the ACC’s petition to the Arizona Supreme Court for review of the Court of Appeals’ decision. On February 9, 2016, the Arizona Supreme Court granted review of the decision and on August 8, 2016, the Arizona Supreme Court vacated the Court of Appeals opinion and affirmed the ACC’s orders approving the water company’s SIB adjustor. System Benefits Charge The 2012 Settlement Agreement provided that once APS achieved full funding of its decommissioning obligation under the sale leaseback agreements covering Unit 2 of Palo Verde, APS was required to implement a reduced System Benefits charge effective January 1, 2016. Beginning on January 1, 2016, APS began implementing a reduced System Benefits charge. The impact on APS retail revenues from the new System Benefits charge is an overall reduction of approximately $14.6 million per year with a corresponding reduction in depreciation and amortization expense. This adjustment is subsumed within the 2017 Settlement Agreement. Subpoena from Arizona Corporation Commissioner Robert Burns On August 25, 2016, Commissioner Burns, individually and not by action of the ACC as a whole, filed subpoenas in APS’s current retail rate proceeding to APS and Pinnacle West for the production of records and information relating to a range of expenditures from 2011 through 2016. The subpoenas requested information concerning marketing and advertising expenditures, charitable donations, lobbying expenses, contributions to 501(c)(3) and (c)(4) nonprofits and political contributions. The return date for the production of information was set as September 15, 2016. The subpoenas also sought testimony from Company personnel having knowledge of the material, including the Chief Executive Officer. On September 9, 2016, APS filed with the ACC a motion to quash the subpoenas or, alternatively to stay APS's obligations to comply with the subpoenas and decline to decide APS's motion pending court proceedings. Contemporaneously with the filing of this motion, APS and Pinnacle West filed a complaint for special action and declaratory judgment in the Superior Court of Arizona for Maricopa County, seeking a declaratory judgment that Commissioner Burns’ subpoenas are contrary to law. On September 15, 2016, APS produced all non-confidential and responsive documents and offered to produce any remaining responsive documents that are confidential after an appropriate confidentiality agreement is signed. On February 7, 2017, Commissioner Burns opened a new ACC docket and indicated that its purpose is to study and rectify problems with transparency and disclosure regarding financial contributions from regulated monopolies or other stakeholders who may appear before the ACC that may directly or indirectly benefit an ACC Commissioner, a candidate for ACC Commissioner, or key ACC staff. As part of this docket, Commissioner Burns set March 24, 2017 as a deadline for APS to produce all information previously requested through the subpoenas. APS did not produce the information requested and instead objected to the subpoena. Also, as part of the docket a workshop was held on March 24, 2017. On March 10, 2017, Commissioner Burns filed suit against APS and PNW in an effort to enforce his subpoenas. On March 30, 2017, APS filed a motion to dismiss Commissioner Burns suit against APS and PNW. APS and Pinnacle West cannot predict the outcome of this matter. 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 $62 million as of March 31, 2017 and is being amortized in rates over a total of 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 is actively participating in the proceeding. The Arizona Court of Appeals suspended the appeal pending the Arizona Supreme Court's decision in the SIB matter discussed above. On August 8, 2016, the Arizona Supreme Court issued its opinion in the SIB matter, and the Arizona Court of Appeals has now ordered supplemental briefing on how that SIB decision should affect the challenge to the Four Corners rate adjustment. We cannot predict when or how this matter 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. On December 22, 2015, APS and SCE agreed to terminate the Transmission Termination Agreement and allow for the Transmission Agreement to expire according to its terms, which includes settling obligations in accordance with the terms of the Transmission Agreement. APS established a regulatory asset of $12 million in 2015 in connection with the payment required under the terms of the Transmission Agreement. On July 1, 2016, FERC issued an order denying APS’s request to recover the regulatory asset through its FERC-jurisdictional rates. APS and SCE completed the termination of the Transmission Agreement on July 6, 2016. APS made the required payment to SCE and wrote-off the $12 million regulatory asset and charged operating revenues to reflect the effects of this order in the second quarter of 2016. On July 29, 2016, APS filed a request for rehearing with FERC. In its order denying recovery FERC also referred to its enforcement division a question of whether the agreement bet |
Retirement Plans and Other Post
Retirement Plans and Other Postretirement Benefits | 3 Months Ended |
Mar. 31, 2017 | |
Compensation and Retirement Disclosure [Abstract] | |
Retirement Plans and Other Postretirement Benefits | Retirement Plans and Other Postretirement Benefits Pinnacle West sponsors a qualified defined benefit and account balance pension plan, a non-qualified supplemental excess benefit retirement plan, and an other postretirement benefit plan for the employees of Pinnacle West and our subsidiaries. Pinnacle West uses a December 31 measurement date for its pension and other postretirement benefit plans. The market-related value of our plan assets is their fair value at the measurement dates. Because of plan changes in September 2014, the Company is currently in the process of seeking IRS approval to move approximately $145 million of the other postretirement benefit trust assets into a new trust account to pay for active union employee medical costs. In December 2016, FERC approved a methodology for determining the amount of other postretirement benefit trust assets to transfer into a new trust account to pay for active union employee medical costs. While we do not expect to transfer any funds prior to 2018, as of March 31, 2017, such methodology would result in an amount of approximately $145 million being transferred to the new trust account. 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 to the regulatory asset or liability) (dollars in thousands): Pension Benefits Other Benefits Three Months Ended Three Months Ended 2017 2016 2017 2016 Service cost — benefits earned during the period $ 13,760 $ 14,266 $ 4,358 $ 3,937 Interest cost on benefit obligation 32,701 32,945 7,565 7,341 Expected return on plan assets (43,710 ) (43,792 ) (13,350 ) (9,122 ) Amortization of: Prior service cost (credit) 20 132 (9,461 ) (9,471 ) Net actuarial loss 12,489 9,731 1,454 946 Net periodic benefit cost $ 15,260 $ 13,282 $ (9,434 ) $ (6,369 ) Portion of cost charged to expense $ 7,568 $ 6,519 $ (4,678 ) $ (3,126 ) Contributions We have made voluntary contributions of $60 million to our pension plan year-to-date in 2017. The minimum required contributions for the pension plan are zero for the next three years. We expect to make voluntary contributions up to a total of $300 million during the 2017-2019 period. We expect to make contributions of less than $1 million in total for the next three years to our other postretirement benefit plans. |
Palo Verde Sale Leaseback Varia
Palo Verde Sale Leaseback Variable Interest Entities | 3 Months Ended |
Mar. 31, 2017 | |
Variable Interest Entities [Abstract] | |
Palo Verde Sale Leaseback Variable Interest Entities | Palo Verde Sale Leaseback Variable Interest Entities In 1986, APS entered into agreements with three separate VIE lessor trust entities in order to sell and lease back interests in Palo Verde Unit 2 and related common facilities. APS will retain the assets through 2023 under one lease and 2033 under the other two leases. APS will be required to make payments relating to these leases of approximately $23 million annually through 2023, and $16 million annually for the period 2024 through 2033. At the end of the lease period, APS will have the option to purchase the leased assets at their fair market value, extend the leases for up to two years , or return the assets to the lessors. The leases' terms give APS the ability to utilize the assets for a significant portion of the assets’ economic life, and therefore provide APS with the power to direct activities of the VIEs that most significantly impact the VIEs’ economic performance. Predominantly due to the lease terms, APS has been deemed the primary beneficiary of these VIEs and therefore consolidates the VIEs. As a result of consolidation, we eliminate lease accounting and instead recognize depreciation expense, resulting in an increase in net income for the three months ended March 31, 2017 and 2016 of $5 million, entirely attributable to the noncontrolling interests. Income attributable to Pinnacle West shareholders is not impacted by the consolidation. Our Condensed Consolidated Balance Sheets at March 31, 2017 and December 31, 2016 include the following amounts relating to the VIEs (dollars in thousands): March 31, 2017 December 31, 2016 Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation $ 112,548 $ 113,515 Equity — Noncontrolling interests 137,164 132,290 Assets of the VIEs are restricted and may only be used for payment to the noncontrolling interest holders. These assets are reported on our condensed consolidated financial statements. APS is exposed to losses relating to these VIEs upon the occurrence of certain events that APS does not consider to be reasonably likely to occur. Under certain circumstances (for example, the NRC issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), APS would be required to make specified payments to the VIEs’ noncontrolling equity participants and take title to the leased Unit 2 interests, which, if appropriate, may be required to be written down in value. If such an event were to occur during the lease periods, APS may be required to pay the noncontrolling equity participants approximately $291 million beginning in 2017, and up to $456 million over the lease terms. For regulatory ratemaking purposes, the agreements continue to be treated as operating leases and, as a result, we have recorded a regulatory asset relating to the arrangements. |
Derivative Accounting
Derivative Accounting | 3 Months Ended |
Mar. 31, 2017 | |
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. 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 10 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 March 31, 2017 , we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position): Commodity Quantity Power 1,123 GWh Gas 226 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 months ended March 31, 2017 and 2016 (dollars in thousands): Financial Statement Location Three Months Ended Commodity Contracts 2017 2016 Loss Recognized in OCI on Derivative Instruments (Effective Portion) OCI — derivative instruments $ (96 ) $ (147 ) Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a) Fuel and purchased power (b) (851 ) (941 ) (a) During the three months ended March 31, 2017 and 2016 , we had no losses reclassified from accumulated OCI to earnings related to discontinued cash flow hedges. (b) Amounts are before the effect of PSA deferrals. During the next twelve months, we estimate that a net loss of $3 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 months ended March 31, 2017 and 2016 (dollars in thousands): Financial Statement Location Three Months Ended Commodity Contracts 2017 2016 Net Loss Recognized in Income Operating revenues $ (288 ) $ (102 ) Net Loss Recognized in Income Fuel and purchased power (a) (52,627 ) (30,936 ) Total $ (52,915 ) $ (31,038 ) (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 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 March 31, 2017 and December 31, 2016 , include gross liabilities of $1 million and $2 million , respectively, 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 March 31, 2017 and December 31, 2016 . 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 March 31, 2017: Gross Recognized Derivatives (a) Amounts Offset (b) Net Recognized Derivatives Other (c) Amount Reported on Balance Sheet Current assets $ 28,193 $ (23,983 ) $ 4,210 $ 12 $ 4,222 Investments and other assets 1,654 (1,654 ) — — — Total assets 29,847 (25,637 ) 4,210 12 4,222 Current liabilities (61,861 ) 23,983 (37,878 ) (4,054 ) (41,932 ) Deferred credits and other (64,867 ) 1,654 (63,213 ) — (63,213 ) Total liabilities (126,728 ) 25,637 (101,091 ) (4,054 ) (105,145 ) Total $ (96,881 ) $ — $ (96,881 ) $ (4,042 ) $ (100,923 ) (a) All of our gross recognized derivative instruments were subject to master netting arrangements. (b) No cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting. (c) Represents cash collateral and cash margin that is not subject to offsetting. Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument. Includes cash collateral received from counterparties of $4,054 . As of December 31, 2016: Gross Recognized Derivatives (a) Amounts Offset (b) Net Recognized Derivatives Other (c) Amount Reported on Balance Sheet Current assets $ 48,094 $ (28,400 ) $ 19,694 $ — $ 19,694 Investments and other assets 6,704 (6,703 ) 1 — 1 Total assets 54,798 (35,103 ) 19,695 — 19,695 Current liabilities (50,182 ) 28,400 (21,782 ) (4,054 ) (25,836 ) Deferred credits and other (53,941 ) 6,703 (47,238 ) — (47,238 ) Total liabilities (104,123 ) 35,103 (69,020 ) (4,054 ) (73,074 ) Total $ (49,325 ) $ — $ (49,325 ) $ (4,054 ) $ (53,379 ) (a) All of our gross recognized derivative instruments were subject to master netting arrangements. (b) No cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting. (c) Represents cash collateral and cash margin that is not subject to offsetting. Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument. Includes cash collateral received from counterparties of $4,054 . Credit Risk and Credit Related Contingent Features We are exposed to losses in the event of nonperformance or nonpayment by counterparties and have risk management contracts with many counterparties. As of March 31, 2017 , we have no counterparties with positive exposures of greater than 10% of risk management assets. Our risk management process assesses and monitors the financial exposure of all counterparties. Despite the fact that the great majority of 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 March 31, 2017 (dollars in thousands): March 31, 2017 Aggregate fair value of derivative instruments in a net liability position $ 126,728 Cash collateral posted — Additional cash collateral in the event credit-risk-related contingent features were fully triggered (a) 63,646 (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 $130 million if our debt credit ratings were to fall below investment grade. |
Commitments and Contingencies
Commitments and Contingencies | 3 Months Ended |
Mar. 31, 2017 | |
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 second breach of contract lawsuit against the United States Department of Energy ("DOE") in the United States Court of Federal Claims ("Court of Federal Claims"). The lawsuit sought to recover damages incurred due to DOE’s breach of the Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste ("Standard Contract") for failing to accept Palo Verde's spent nuclear fuel and high level waste from January 1, 2007 through June 30, 2011, as it was required to do pursuant to the terms of the Standard Contract and the Nuclear Waste Policy Act. On August 18, 2014, APS and DOE entered into a settlement agreement, stipulating to a dismissal of the lawsuit and payment of $57.4 million by DOE to the Palo Verde owners for certain specified costs incurred by Palo Verde during the period January 1, 2007 through June 30, 2011. APS’s share of this amount is $16.7 million . Amounts recovered in the lawsuit and settlement were recorded as adjustments to a regulatory liability and had no impact on the amount of reported net income. In addition, the settlement agreement, as amended, provides APS with a method for submitting claims and getting recovery for costs incurred through December 31, 2019. APS has submitted three claims pursuant to the terms of the August 18, 2014 settlement agreement, for three separate time periods during July 1, 2011 through June 30, 2016. The DOE has approved and paid $65.2 million for these claims (APS’s share is $19 million ). The amounts recovered were primarily recorded as adjustments to a regulatory liability and had no impact on reported net income. Nuclear Insurance Public liability for incidents at nuclear power plants is governed by the Price-Anderson Nuclear Industries Indemnity Act ("Price-Anderson Act"), which limits the liability of nuclear reactor owners to the amount of insurance available from both commercial sources and an industry-wide retrospective payment plan. In accordance with the Price-Anderson Act, the Palo Verde participants are insured against public liability for a nuclear incident up to approximately $13.4 billion per occurrence. Palo Verde maintains the maximum available nuclear liability insurance in the amount of $450 million , which is provided by American Nuclear Insurers ("ANI"). The remaining balance of approximately $13.0 billion of liability coverage is provided through a mandatory industry-wide retrospective premium program. If losses at any nuclear power plant covered by the program exceed the accumulated funds, APS could be responsible for retrospective premiums. The maximum retrospective premium per reactor under the program for each nuclear liability incident is approximately $127.3 million , subject to a maximum annual premium of $19 million per incident. Based on APS’s ownership interest in the three Palo Verde units, APS’s maximum retrospective premium per incident for all three units is approximately $111.1 million , with a maximum annual retrospective premium of approximately $16.6 million . The Palo Verde participants maintain insurance for property damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.8 billion . APS has also secured accidental outage insurance for a sudden and unforeseen accidental outage of any of the three units. The property damage, decontamination, and accidental outage insurance are provided by Nuclear Electric Insurance Limited ("NEIL"). APS is subject to retrospective premium adjustments under all NEIL policies if NEIL’s losses in any policy year exceed accumulated funds. The maximum amount APS could incur under the current NEIL policies totals approximately $24 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 $64.8 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 first quarter of 2017 our fuel and purchased power commitments decreased approximately $600 million primarily due to updated estimated renewable energy purchases. The majority of these changes relate to the years 2022 and thereafter. Other than the items described above, there have been no material changes, as of March 31, 2017 , outside the normal course of business in contractual obligations from the information provided in our 2016 Form 10-K. See Note 2 for discussion regarding changes in our long-term debt obligations. 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 ("RI/FS"). The OU3 working group parties have agreed to a schedule with EPA that calls for the submission of a revised draft RI/FS by November 2017. We estimate that our costs related to this investigation and study will be approximately $2 million . We anticipate incurring additional expenditures in the future, but because the overall investigation is not complete and ultimate remediation requirements are not yet finalized, at the present time expenditures related to this matter cannot be reasonably estimated. On August 6, 2013, the Roosevelt Irrigation District ("RID") filed a lawsuit in Arizona District Court against APS and 24 other defendants, alleging that RID’s groundwater wells were contaminated by the release of hazardous substances from facilities owned or operated by the defendants. The lawsuit also alleges that, under Superfund laws, the defendants are jointly and severally liable to RID. The allegations against APS arise out of APS’s current and former ownership of facilities in and around OU3. As part of a state governmental investigation into groundwater contamination in this area, on January 25, 2015, the Arizona Department of Environmental Quality ("ADEQ") sent a letter to APS seeking information concerning the degree to which, if any, APS’s current and former ownership of these facilities may have contributed to groundwater contamination in this area. APS responded to ADEQ on May 4, 2015. On December 16, 2016, two RID contractors filed ancillary lawsuits for recovery of costs against APS and the other defendants. In addition, on March 15, 2017, the Arizona District Court granted partial summary judgment to RID for one element of RID's lawsuit against APS and the other defendants. The court's order is interlocutory and subject to a pending motion for reconsideration. We are unable to predict the outcome of these matters; however, we do not expect the outcome to have a material impact on our financial position, results of operations or cash flows. Environmental Matters APS is subject to numerous environmental laws and regulations affecting many aspects of its present and future operations, including air emissions of both conventional pollutants and greenhouse gases, water quality, wastewater discharges, solid waste, hazardous waste, and coal combustion residuals ("CCRs"). These laws and regulations can change from time to time, imposing new obligations on APS resulting in increased capital, operating, and other costs. Associated capital expenditures or operating costs could be material. APS intends to seek recovery of any such environmental compliance costs through our rates, but cannot predict whether it will obtain such recovery. The following proposed and final rules involve material compliance costs to APS. Regional Haze Rules. APS has received the final rulemaking imposing new requirements on Four Corners and the Navajo Plant. EPA will require these plants to install pollution control equipment that constitutes best available retrofit technology ("BART") to lessen the impacts of emissions on visibility surrounding the plants. EPA recently approved a proposed rule for Regional Haze compliance at Cholla that does not involve the installation of new pollution controls and that will replace an earlier BART determination for this facility. See below for details of the recent Cholla rule approval. Four Corners. Based on EPA’s final standards, APS estimates that its 63% share of the cost of required controls for Four Corners Units 4 and 5 would be approximately $400 million . In addition, APS and El Paso Electric Company ("El Paso") entered into an asset purchase agreement providing for the purchase by APS, or an affiliate of APS, of El Paso's 7% interest in Four Corners Units 4 and 5. 4CA purchased the El Paso interest on July 6, 2016. Navajo Transitional Energy Company, LLC ("NTEC") has the option to purchase the interest within a certain timeframe pursuant to an option granted to NTEC. In December 2015, NTEC notified APS of its intent to exercise the option. The cost of the pollution controls related to the 7% interest is approximately $45 million , which will be assumed by the ultimate owner of the 7% interest. Navajo Plant. APS estimates that its share of costs for upgrades at the Navajo Plant, based on EPA’s Federal Implementation Plan ("FIP"), could be up to approximately $200 million . 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. On March 20, 2017, the Court denied this petition for review and upheld the legality of EPA's final BART rule for the Navajo Plant. See "Navajo Plant" in Note 3 for information regarding future plans for the Navajo Plant. Cholla . APS believes that EPA’s original 2012 final rule establishing controls constituting BART for Cholla, which would require installation of SCR controls with a cost to APS of approximately $100 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. Pending certain regulatory approvals, APS would permanently close Cholla Unit 2 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/or converting the units as contemplated in the proposal is more cost effective than, and will result in increased visibility improvement over, the current BART requirements for NOx imposed on the Cholla units under EPA's BART FIP. APS’s proposal involves state and federal rulemaking 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 October 16, 2015, ADEQ issued a revised operating permit for Cholla, which incorporates APS's proposal, and subsequently submitted a proposed revision to the SIP to the EPA, which would incorporate the new permit terms. On June 30, 2016, EPA issued a proposed rule approving a revision to the Arizona SIP that incorporates APS’s compromise approach for compliance with the Regional Haze program. EPA signed the final rule approving the Agency's proposal on January 13, 2017. Under the terms of an executive memorandum issued on January 20, 2017, this final rule was held back from publication in the Federal Register pending review by incoming EPA leadership. On March 16, 2017, the new EPA Administrator re-signed the final rule, thereby allowing for publication in the Federal Register, which occurred on March 27, 2017. Parties have until May 26, 2017 (60 days from publication in the Federal Register) to file a petition for review in the Ninth Circuit Court of Appeals. APS cannot predict whether such actions will be filed or if they will be successful. 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. 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. On December 16, 2016, President Obama signed the Water Infrastructure Improvements for the Nation ("WIIN") Act into law, which contains a number of provisions requiring EPA to modify the self-implementing provisions of the Agency's current CCR rules under Subtitle D. Such modifications include new EPA authority to directly enforce the CCR rules through the use of administrative orders and providing states, like Arizona, where the Cholla facility is located, the option of developing CCR disposal unit permitting programs, subject to EPA approval. For facilities in states that do not develop state-specific permitting programs, EPA is required to develop a federal permit program, pending the availability of congressional appropriations. By contrast, for facilities located within the boundaries of Native American tribal reservations, such as the Navajo Nation, where the Navajo Plant and Four Corners facilities are located, EPA is required to develop a federal permit program regardless of appropriated funds. Because EPA has yet to undertake rulemaking proceedings to implement the CCR provisions of the WIIN Act, and Arizona has yet to determine whether it will develop a state-specific permitting program, it is unclear what effects the CCR provisions of the WIIN Act will have on APS's management of CCR. 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 . APS is currently evaluating compliance alternatives for Cholla and estimates that its share of incremental costs to comply with the CCR rule for this plant is in the range of $5 million to $40 million based upon which compliance alternatives are ultimately selected. 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 , the majority of which has already been incurred. Additionally, the CCR rule requires ongoing, phased groundwater monitoring. By October 17, 2017, electric utility companies that own or operate CCR disposal units, such as APS, must collect sufficient groundwater sampling data to initiate a detection monitoring program. To the extent that certain threshold constituents are identified through this initial detection monitoring at levels above the CCR rule’s standards, the rule requires the initiation of an assessment monitoring program by April 15, 2018. If this assessment monitoring program reveals concentrations of certain constituents above the CCR rule standards that trigger remedial obligations, a corrective measures evaluation must be completed by October 12, 2018. Depending upon the results of such groundwater monitoring and data evaluations at each of Cholla, Four Corners and the Navajo Plant, we may be required to take corrective actions, the costs of which we are unable to reasonably estimate at this time. Pursuant to a June 24, 2016 order by the D.C. Circuit Court of Appeals in the litigation by industry- and environmental-groups challenging EPA’s CCR regulations, within the next three years EPA is required to complete a rulemaking proceeding concerning whether or not boron must be included on the list of groundwater constituents that might trigger corrective action under EPA’s CCR rules. EPA is not required to take final action approving the inclusion of boron, but EPA must propose and consider its inclusion. Should EPA take final action adding boron to the list of groundwater constituents that might trigger corrective action, any resulting corrective action measures may increase APS's costs of compliance with the CCR rule at our coal-fired generating facilities. At this time, though, APS cannot predict when EPA will commence its rulemaking concerning boron or the eventual results of those proceedings. Clean Power Plan. On August 3, 2015, EPA finalized carbon pollution standards for electric generating units ("EGUs"). Shortly thereafter, a coalition of states, industry groups and electric utilities challenged the legality of these standards, including EPA's Clean Power Plan for existing EGUs, in the U.S. Court of Appeals for the D.C. Circuit. On February 9, 2016, the U.S. Supreme Court granted a stay of the Clean Power Plan pending judicial review of the rule, which temporarily delays compliance obligations under the Clean Power Plan. On March 28, 2017, President Trump issued an Executive Order that, among other things, instructs EPA to reevaluate Agency regulations concerning carbon emissions from EGUs and take appropriate action to suspend, revise or rescind the August 2015 carbon pollution standards for EGUs, including the Clean Power Plan. Also on March 28, 2017, the U.S. Department of Justice, on behalf of EPA, filed a motion with the U.S. Court of Appeals for the D.C. Circuit to hold the ongoing litigation over the August 2015 pollution standards in abeyance pending EPA action in accordance with the Executive Order. At this time we cannot predict the outcome of EPA's review of the August 2015 carbon pollution standards and whether EPA will take action to suspend, rescind or revise these regulations. The carbon pollution standards for EGUs on state and tribal lands are described in detail in Note 10 of our 2016 Form 10-K. Other environmental rules that could involve material compliance costs include those related to effluent limitations, the ozone national ambient air quality standard and other rules or matters involving the Clean Air Act, Clean Water Act, Endangered Species Act, RCRA, Superfund, the Navajo Nation, and water supplies for our power plants. The financial impact of complying with current and future environmental rules could jeopardize the economic viability of our coal plants or the willingness or ability of power plant participants to fund any required equipment upgrades or continue their participation in these plants. The economics of continuing to own certain resources, particularly our coal plants, may deteriorate, warranting early retirement of those plants, which may result in asset impairments. APS would seek recovery in rates for the book value of any remaining investments in the plants as well as other costs related to early retirement, but cannot predict whether it would obtain such recovery. Federal Agency Environmental Lawsuit Related to Four Corners On April 20, 2016, several environmental groups filed a lawsuit against the Office of Surface Mining Reclamation and Enforcement ("OSM") and other federal agencies in the District of Arizona in connection with their issuance of the approvals that extended the life of Four Corners and the adjacent mine. The lawsuit alleges that these federal agencies violated both the Endangered Species Act ("ESA") and the National Environmental Policy Act ("NEPA") in providing the federal approvals necessary to extend operations at the Four Corners Power Plant and the adjacent Navajo Mine past July 6, 2016. APS filed a motion to intervene in the proceedings, which was granted on August 3, 2016. Briefing on the merits of this litigation is expected to extend through May 2017. On September 15, 2016, NTEC, the company that owns the adjacent mine, filed a motion to intervene for the purpose of dismissing the lawsuit based on NTEC's tribal sovereign immunity. Because the court has placed a stay on all litigation deadlines pending its decision regarding NTEC's motion to dismiss, the schedule for briefing and the anticipated timeline for completion of this litigation will likely be extended. We cannot predict the outcome of this matter or its potential effect on Four Corners. Financial Assurances In the normal course of business, we obtain standby letters of credit and surety bonds from financial institutions and other third parties. These instruments guarantee our own future performance and provide third parties with financial and performance assurance in the event we do not perform. These instruments support certain debt arrangements, commodity contract collateral obligations, and other transactions. As of March 31, 2017 , standby letters of credit totaled $35 million and will expire in 2017. As of March 31, 2017 , surety bonds expiring through 2019 totaled $61 million . The underlying liabilities insured by these instruments are reflected on our balance sheets, where applicable. Therefore, no additional liability is reflected for the letters of credit and surety bonds themselves. We enter into agreements that include indemnification provisions relating to liabilities arising from or related to certain of our agreements. Most significantly, APS has agreed to indemnify the equity participants and other parties in the Palo Verde sale leaseback transactions with respect to certain tax matters. Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnification provisions cannot be reasonably estimated. Based on historical experience and evaluation of the specific indemnities, we do not believe that any material loss related to such indemnification provisions is likely. Pinnacle West has issued parental guarantees and has provided indemnification under certain surety bonds for APS which were not material at March 31, 2017 . Effective July 6, 2016, Pinnacle West has issued two parental guarantees for 4CA relating to payment obligations arising from 4CA’s acquisition of El Paso’s 7% interest in Four Corners, and pursuant to the Four Corners participation agreement payment obligations arising from 4CA’s ownership interest in Four Corners. |
Other Income and Other Expense
Other Income and Other Expense | 3 Months Ended |
Mar. 31, 2017 | |
Component of Other Income and Other Expense Nonoperating [Line Items] | |
Other Income and Other Expense | Other Income and Other Expense The following table provides detail of Pinnacle West's Consolidated other income and other expense for the three months ended March 31, 2017 and 2016 (dollars in thousands): Three Months Ended 2017 2016 Other income: Interest income $ 477 $ 117 Miscellaneous 3 — Total other income $ 480 $ 117 Other expense: Non-operating costs $ (1,959 ) $ (2,049 ) Investment losses — net (301 ) (518 ) Miscellaneous (1,420 ) (1,471 ) Total other expense $ (3,680 ) $ (4,038 ) |
Arizona Public Service Company | |
Component of Other Income and Other Expense Nonoperating [Line Items] | |
Other Income and Other Expense | The following table provides detail of APS’s other income and other expense for the three months ended March 31, 2017 and 2016 (dollars in thousands): Three Months Ended 2017 2016 Other income: Interest income $ 338 $ 73 Gain on disposition of property 308 332 Miscellaneous 416 205 Total other income $ 1,062 $ 610 Other expense: Non-operating costs (a) $ (2,166 ) $ (1,966 ) Loss on disposition of property (88 ) (426 ) Miscellaneous (2,124 ) (2,358 ) Total other expense $ (4,378 ) $ (4,750 ) (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 | 3 Months Ended |
Mar. 31, 2017 | |
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 months ended March 31, 2017 and 2016 (in thousands, except per share amounts): Three Months Ended 2017 2016 Net income attributable to common shareholders $ 23,312 $ 4,453 Weighted average common shares outstanding — basic 111,728 111,296 Net effect of dilutive securities: Contingently issuable performance shares and restricted stock units 467 551 Weighted average common shares outstanding — diluted 112,195 111,847 Earnings per weighted-average common share outstanding Net income attributable to common shareholders — basic $ 0.21 $ 0.04 Net income attributable to common shareholders — diluted $ 0.21 $ 0.04 |
Fair Value Measurements
Fair Value Measurements | 3 Months Ended |
Mar. 31, 2017 | |
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, exchange traded mutual funds, 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. Level 3 — Valuation models with significant unobservable inputs that are supported by little or no market activity. Instruments in this category include long-dated derivative transactions where valuations are unobservable due to the length of the transaction, options, and transactions in locations where observable market data does not exist. The valuation models we employ utilize spot prices, forward prices, historical market data and other factors to forecast future prices. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Thus, a valuation may be classified in Level 3 even though the valuation may include significant inputs that are readily observable. We maximize the use of observable inputs and minimize the use of unobservable inputs. We rely primarily on the market approach of using prices and other market information for identical and/or comparable assets and liabilities. If market data is not readily available, inputs may reflect our own assumptions about the inputs market participants would use. Our assessment of the inputs and the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities as well as their placement within the fair value hierarchy levels. We assess whether a market is active by obtaining observable broker quotes, reviewing actual market activity, and assessing the volume of transactions. We consider broker quotes observable inputs when the quote is binding on the broker, we can validate the quote with market activity, or we can determine that the inputs the broker used to arrive at the quoted price are observable. Certain instruments have been valued using the concept of Net Asset Value (“NAV”), as a practical expedient. These instruments are typically structured as investment companies offering shares or units to multiple investors for the purpose of providing a return. These instruments are similar to mutual funds; however, they are not traded on an exchange. Instruments valued using NAV, as a practical expedient, are included in our fair value disclosures however, in accordance with GAAP are not classified within the fair value hierarchy levels. Recurring Fair Value Measurements We apply recurring fair value measurements to certain cash equivalents, derivative instruments, investments held in our nuclear decommissioning trust, plan assets held in our retirement and other benefit plans and coal reclamation trust investments. See Note 7 in the 2016 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. Coal Reclamation Trust Investments The coal reclamation trust holds cash equivalent investments in money market funds that are valued using quoted prices in active markets, and are reported within Level 1. 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. 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 using the funds' NAV as a practical expedient. The funds' NAV is primarily derived from the quoted active market prices of the underlying equity securities held by the funds. We may transact in these commingled funds on a semi-monthly basis at the NAV. The commingled funds are maintained by a bank and hold investments in accordance with the stated objective of tracking the performance of the S&P 500 Index. Because the commingled funds' shares are offered to a limited group of investors, they are not considered to be traded in an active market. As these instruments are valued using NAV, as a practical expedient, they have not been classified within the fair value hierarchy. Cash equivalents reported within Level 1 represent investments held in a short-term investment exchange-traded mutual fund, 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. 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 11 for additional discussion about our nuclear decommissioning trust. Fair Value Tables The following table presents the fair value at March 31, 2017 , of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands): Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (a) (Level 3) Other Balance at March 31, 2017 Assets Coal reclamation trust - cash equivalents (b) $ 14,801 $ — $ — $ — $ 14,801 Risk management activities — derivative instruments: Commodity contracts — 20,431 9,416 (25,625 ) (c) 4,222 Nuclear decommissioning trust: U.S. commingled equity funds — — — 374,695 (d) 374,695 Fixed income securities: Cash and cash equivalent funds — — — 336 (e) 336 U.S. Treasury 94,709 — — — 94,709 Corporate debt — 115,329 — — 115,329 Mortgage-backed securities — 115,332 — — 115,332 Municipal bonds — 81,932 — — 81,932 Other — 22,715 — — 22,715 Subtotal nuclear decommissioning trust 94,709 335,308 — 375,031 805,048 Total $ 109,510 $ 355,739 $ 9,416 $ 349,406 $ 824,071 Liabilities Risk management activities — derivative instruments: Commodity contracts $ — $ (75,627 ) $ (51,101 ) $ 21,583 (c) $ (105,145 ) (a) Primarily consists of long-dated electricity contracts. (b) Represents investments restricted for coal mine reclamation funding related to Four Corners. These assets are included in the Other Assets line item, reported under the Investments and Other Assets section of our Condensed Consolidated Balance Sheets. (c) Represents counterparty netting, margin and collateral. See Note 6 . (d) Valued using NAV as a practical expedient and, therefore, are not classified in the fair value hierarchy. (e) Represents nuclear decommissioning trust net pending securities sales and purchases. The following table presents the fair value at December 31, 2016 , of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands): Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (a) (Level 3) Other Balance at December 31, 2016 Assets Coal reclamation trust - cash equivalents (b) $ 14,521 $ — $ — $ — $ 14,521 Risk management activities — derivative instruments: Commodity contracts — 43,722 11,076 (35,103 ) (c) 19,695 Nuclear decommissioning trust: U.S. commingled equity funds — — — 353,261 (d) 353,261 Fixed income securities: Cash and cash equivalent funds — — — 795 (e) 795 U.S. Treasury 95,441 — — — 95,441 Corporate debt — 111,623 — — 111,623 Mortgage-backed securities — 115,337 — — 115,337 Municipal bonds — 80,997 — — 80,997 Other — 22,132 — — 22,132 Subtotal nuclear decommissioning trust 95,441 330,089 — 354,056 779,586 Total $ 109,962 $ 373,811 $ 11,076 $ 318,953 $ 813,802 Liabilities Risk management activities — derivative instruments: Commodity contracts $ — $ (45,641 ) $ (58,482 ) $ 31,049 (c) $ (73,074 ) (a) Primarily consists of long-dated electricity contracts. (b) Represents investments restricted for coal mine reclamation funding related to Four Corners. These assets are included in the Other Assets line item, reported under the Investments and Other Assets section of our Condensed Consolidated Balance Sheets. (c) Represents counterparty netting, margin and collateral. See Note 6. (d) Valued using NAV as a practical expedient and, therefore, are not classified in the fair value hierarchy. (e) 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. 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. 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 March 31, 2017 and December 31, 2016 : March 31, 2017 Valuation Technique Significant Unobservable Input Weighted-Average Commodity Contracts Assets Liabilities Range Electricity: Forward Contracts (a) $ 8,805 $ 30,313 Discounted cash flows Electricity forward price (per MWh) $16.65 - $36.64 $ 27.96 Natural Gas: Forward Contracts (a) 611 20,788 Discounted cash flows Natural gas forward price (per MMBtu) $2.07 - $2.80 $ 2.42 Total $ 9,416 $ 51,101 (a) Includes swaps and physical and financial contracts. December 31, 2016 Valuation Technique Significant Unobservable Input Weighted-Average Commodity Contracts Assets Liabilities Range Electricity: Forward Contracts (a) $ 10,648 $ 32,042 Discounted cash flows Electricity forward price (per MWh) $16.43 - $41.07 $ 29.86 Natural Gas: Forward Contracts (a) 428 26,440 Discounted cash flows Natural gas forward price (per MMBtu) $2.32 - $3.60 $ 2.81 Total $ 11,076 $ 58,482 (a) Includes swaps and physical and financial contracts. The following table shows the changes in fair value for our risk management activities' assets and liabilities that are measured at fair value on a recurring basis using Level 3 inputs for the three months ended March 31, 2017 and 2016 (dollars in thousands): Three Months Ended Commodity Contracts 2017 2016 Net derivative balance at beginning of period $ (47,406 ) $ (32,979 ) Total net gains (losses) realized/unrealized: Included in OCI — — Deferred as a regulatory asset or liability (11,755 ) (9,103 ) Settlements 1,423 1,765 Transfers into Level 3 from Level 2 (38 ) 262 Transfers from Level 3 into Level 2 16,091 548 Net derivative balance at end of period $ (41,685 ) $ (39,507 ) 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. See Note 2 for our long-term debt fair values. |
Nuclear Decommissioning Trusts
Nuclear Decommissioning Trusts | 3 Months Ended |
Mar. 31, 2017 | |
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 10 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 March 31, 2017 and December 31, 2016 (dollars in thousands): Fair Value Total Unrealized Gains Total Unrealized Losses March 31, 2017 Equity securities $ 374,695 $ 207,708 $ — Fixed income securities 430,016 10,022 (3,963 ) Net receivables (a) 337 — — Total $ 805,048 $ 217,730 $ (3,963 ) Fair Value Total Unrealized Gains Total Unrealized Losses December 31, 2016 Equity securities $ 353,261 $ 188,091 $ — Fixed income securities 425,530 9,820 (4,962 ) Net receivables (a) 795 — — Total $ 779,586 $ 197,911 $ (4,962 ) (a) Net receivables/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 thousands): Three Months Ended 2017 2016 Realized gains $ 2,367 $ 2,438 Realized losses (2,453 ) (1,786 ) Proceeds from the sale of securities (a) 151,126 141,809 (a) Proceeds are reinvested in the trust. The fair value of fixed income securities, summarized by contractual maturities, at March 31, 2017 is as follows (dollars in thousands): Fair Value Less than one year $ 12,143 1 year – 5 years 117,217 5 years – 10 years 114,131 Greater than 10 years 186,525 Total $ 430,016 |
New Accounting Standards
New Accounting Standards | 3 Months Ended |
Mar. 31, 2017 | |
New Accounting Pronouncements and Changes in Accounting Principles [Abstract] | |
New Accounting Standards | New Accounting Standards Accounting Standards Update ("ASU") 2014-09, Revenue from Contracts with Customers In May 2014, a new revenue recognition accounting standard was issued. This standard provides a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance. Since the issuance of the new revenue standard, additional guidance was issued to clarify certain aspects of the new revenue standard, including principal versus agent considerations, identifying performance obligations, and other narrow scope improvements. The new revenue standard, and related amendments, will be effective for us on January 1, 2018. The standard may be adopted using a full retrospective application or a simplified transition method that allows entities to record a cumulative effect adjustment in retained earnings at the date of initial application. We will adopt this standard on January 1, 2018, and expect to adopt the guidance using the modified retrospective transition approach. Our revenues are derived primarily from sales of electricity to our regulated retail customers, and based on our assessment we do not expect the adoption of this guidance will impact the timing of our revenue recognition relating to these customers. However, our evaluation is on-going and we continue to monitor certain industry related topics being addressed by the American Institute of Certified Public Accountants Revenue Recognition Working Group and the Financial Accounting Standards Board’s Transition Resource Group. Conclusions reached by these groups could impact our application of the standard. Furthermore, the adoption of the new standard may impact our presentation of revenues and will impact our disclosures relating to revenue. ASU 2016-01, Financial Instruments: Recognition and Measurement In January 2016, a new accounting standard was issued relating to the recognition and measurement of financial instruments. The new guidance will require certain investments in equity securities to be measured at fair value with changes in fair value recognized in net income, and modifies the impairment assessment of certain equity securities. The new standard is effective for us on January 1, 2018. Certain aspects of the standard may require a cumulative effect adjustment and other aspects of the standard are required to be adopted prospectively. We plan on adopting this standard on January 1, 2018, and continue to evaluate the impacts the new guidance may have on our financial statements. As of March 31, 2017 we do not have significant equity investments that would be impacted by this standard. ASU 2016-02, Leases In February 2016, a new lease accounting standard was issued. This new standard supersedes the existing lease accounting model, and modifies both lessee and lessor accounting. The new standard will require a lessee to reflect most operating lease arrangements on the balance sheet by recording a right-of-use asset and a lease liability that will initially be measured at the present value of lease payments. Among other changes, the new standard also modifies the definition of a lease, and requires expanded lease disclosures. The new standard will be effective for us on January 1, 2019, with early application permitted. The standard must be adopted using a modified retrospective approach, with various optional practical expedients provided to facilitate transition. We are currently evaluating this new accounting standard and the impacts it may have on our financial statements. ASU 2016-13, Financial Instruments: Measurement of Credit Losses In June 2016, a new accounting standard was issued that amends the measurement of credit losses on certain financial instruments. The new standard will require entities to use a current expected credit loss model to measure impairment of certain investments in debt securities, trade accounts receivables, and other financial instruments. The new standard is effective for us on January 1, 2020 and must be adopted using a modified retrospective approach for certain aspects of the standard, and a prospective approach for other aspects of the standard. We are currently evaluating this new accounting standard and the impacts it may have on our financial statements. ASU 2017-01, Business Combinations: Clarifying the Definition of a Business In January 2017, a new accounting standard was issued that clarifies the definition of a business. This standard is intended to assist entities with evaluating whether a transaction should be accounted for as an acquisition (or disposal) of assets or a business. The definition of a business affects many areas of accounting including acquisitions, disposals, goodwill, and consolidation. The new standard is effective for us on January 1, 2018 using a prospective approach. We are currently evaluating this new accounting standard and the impacts it may have on our financial statements. ASU 2017-05, Other Income: Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets In February 2017, a new accounting standard was issued intended to clarify the scope of accounting guidance pertaining to gains and losses from the derecognition of nonfinancial assets, and to add guidance for partial sales of nonfinancial assets. The new standard is effective for us on January 1, 2018. The guidance may be applied using either a retrospective or modified retrospective transition approach. We are currently evaluating this new accounting standard and the impacts it may have on our financial statements. ASU 2017-07, Compensation-Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost In March 2017, a new accounting standard was issued that modifies how plan sponsors present net periodic pension cost and net periodic postretirement benefit cost (net benefit costs). The presentation changes will require net benefit costs to be disaggregated on the income statement by the various components that comprise these costs. Specifically, only the service cost component will be eligible for presentation as an operating income item, and all other cost components will be presented as non-operating items. This presentation change must be applied retrospectively. Furthermore, the new standard only allows the service cost component to be eligible for capitalization. The change in capitalization requirements must be applied prospectively. The new guidance is effective for us on January 1, 2018. We are currently evaluating this new accounting standard and the impacts it will have on our financial statements. The adoption of this guidance will change our financial statement presentation of net benefit costs and amounts eligible for capitalization; however due to regulatory accounting we do not expect these changes will have a significant impact on our results of operations. |
Changes in Accumulated Other Co
Changes in Accumulated Other Comprehensive Loss | 3 Months Ended |
Mar. 31, 2017 | |
Accumulated Other Comprehensive Income (Loss) [Line Items] | |
Changes in Accumulated Other Comprehensive Loss | Changes in Accumulated Other Comprehensive Loss The following table shows the changes in Pinnacle West's consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the three months ended March 31, 2017 and 2016 (dollars in thousands): Three Months Ended March 31, 2017 2016 Balance at beginning of period $ (43,822 ) $ (44,748 ) Derivative Instruments OCI (loss) before reclassifications (770 ) (693 ) Amounts reclassified from accumulated other comprehensive loss (a) 1,207 1,141 Net current period OCI (loss) 437 448 Pension and Other Postretirement Benefits Amounts reclassified from accumulated other comprehensive loss (b) 522 530 Net current period OCI (loss) 522 530 Balance at end of period $ (42,863 ) $ (43,770 ) (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 6 . (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 | The following table shows the changes in APS's consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the three months ended March 31, 2017 and 2016 (dollars in thousands): Three Months Ended March 31, 2017 2016 Balance at beginning of period $ (25,423 ) $ (27,097 ) Derivative Instruments OCI (loss) before reclassifications (770 ) (693 ) Amounts reclassified from accumulated other comprehensive loss (a) 1,207 1,141 Net current period OCI (loss) 437 448 Pension and Other Postretirement Benefits Amounts reclassified from accumulated other comprehensive loss (b) 611 611 Net current period OCI (loss) 611 611 Balance at end of period $ (24,375 ) $ (26,038 ) (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 6 . (b) These amounts primarily represent amortization of actuarial loss and are included in the computation of net periodic pension cost. See Note 4 . |
New Accounting Standards (Polic
New Accounting Standards (Policies) | 3 Months Ended |
Mar. 31, 2017 | |
New Accounting Pronouncements and Changes in Accounting Principles [Abstract] | |
New Accounting Standards | Accounting Standards Update ("ASU") 2014-09, Revenue from Contracts with Customers In May 2014, a new revenue recognition accounting standard was issued. This standard provides a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance. Since the issuance of the new revenue standard, additional guidance was issued to clarify certain aspects of the new revenue standard, including principal versus agent considerations, identifying performance obligations, and other narrow scope improvements. The new revenue standard, and related amendments, will be effective for us on January 1, 2018. The standard may be adopted using a full retrospective application or a simplified transition method that allows entities to record a cumulative effect adjustment in retained earnings at the date of initial application. We will adopt this standard on January 1, 2018, and expect to adopt the guidance using the modified retrospective transition approach. Our revenues are derived primarily from sales of electricity to our regulated retail customers, and based on our assessment we do not expect the adoption of this guidance will impact the timing of our revenue recognition relating to these customers. However, our evaluation is on-going and we continue to monitor certain industry related topics being addressed by the American Institute of Certified Public Accountants Revenue Recognition Working Group and the Financial Accounting Standards Board’s Transition Resource Group. Conclusions reached by these groups could impact our application of the standard. Furthermore, the adoption of the new standard may impact our presentation of revenues and will impact our disclosures relating to revenue. ASU 2016-01, Financial Instruments: Recognition and Measurement In January 2016, a new accounting standard was issued relating to the recognition and measurement of financial instruments. The new guidance will require certain investments in equity securities to be measured at fair value with changes in fair value recognized in net income, and modifies the impairment assessment of certain equity securities. The new standard is effective for us on January 1, 2018. Certain aspects of the standard may require a cumulative effect adjustment and other aspects of the standard are required to be adopted prospectively. We plan on adopting this standard on January 1, 2018, and continue to evaluate the impacts the new guidance may have on our financial statements. As of March 31, 2017 we do not have significant equity investments that would be impacted by this standard. ASU 2016-02, Leases In February 2016, a new lease accounting standard was issued. This new standard supersedes the existing lease accounting model, and modifies both lessee and lessor accounting. The new standard will require a lessee to reflect most operating lease arrangements on the balance sheet by recording a right-of-use asset and a lease liability that will initially be measured at the present value of lease payments. Among other changes, the new standard also modifies the definition of a lease, and requires expanded lease disclosures. The new standard will be effective for us on January 1, 2019, with early application permitted. The standard must be adopted using a modified retrospective approach, with various optional practical expedients provided to facilitate transition. We are currently evaluating this new accounting standard and the impacts it may have on our financial statements. ASU 2016-13, Financial Instruments: Measurement of Credit Losses In June 2016, a new accounting standard was issued that amends the measurement of credit losses on certain financial instruments. The new standard will require entities to use a current expected credit loss model to measure impairment of certain investments in debt securities, trade accounts receivables, and other financial instruments. The new standard is effective for us on January 1, 2020 and must be adopted using a modified retrospective approach for certain aspects of the standard, and a prospective approach for other aspects of the standard. We are currently evaluating this new accounting standard and the impacts it may have on our financial statements. ASU 2017-01, Business Combinations: Clarifying the Definition of a Business In January 2017, a new accounting standard was issued that clarifies the definition of a business. This standard is intended to assist entities with evaluating whether a transaction should be accounted for as an acquisition (or disposal) of assets or a business. The definition of a business affects many areas of accounting including acquisitions, disposals, goodwill, and consolidation. The new standard is effective for us on January 1, 2018 using a prospective approach. We are currently evaluating this new accounting standard and the impacts it may have on our financial statements. ASU 2017-05, Other Income: Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets In February 2017, a new accounting standard was issued intended to clarify the scope of accounting guidance pertaining to gains and losses from the derecognition of nonfinancial assets, and to add guidance for partial sales of nonfinancial assets. The new standard is effective for us on January 1, 2018. The guidance may be applied using either a retrospective or modified retrospective transition approach. We are currently evaluating this new accounting standard and the impacts it may have on our financial statements. ASU 2017-07, Compensation-Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost In March 2017, a new accounting standard was issued that modifies how plan sponsors present net periodic pension cost and net periodic postretirement benefit cost (net benefit costs). The presentation changes will require net benefit costs to be disaggregated on the income statement by the various components that comprise these costs. Specifically, only the service cost component will be eligible for presentation as an operating income item, and all other cost components will be presented as non-operating items. This presentation change must be applied retrospectively. Furthermore, the new standard only allows the service cost component to be eligible for capitalization. The change in capitalization requirements must be applied prospectively. The new guidance is effective for us on January 1, 2018. We are currently evaluating this new accounting standard and the impacts it will have on our financial statements. The adoption of this guidance will change our financial statement presentation of net benefit costs and amounts eligible for capitalization; however due to regulatory accounting we do not expect these changes will have a significant impact on our results of operations. |
Consolidation and Nature of O23
Consolidation and Nature of Operations (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Schedule of reclassifications of the prior year | The following tables show the impacts of the reclassifications of the prior year's (previously reported) amounts (dollars in thousands): Statements of Cash Flows for the As previously Reclassifications to conform to current year presentation Amount reported after reclassification to conform to current year presentation Cash Flows from Operating Activities Stock compensation $ — $ 16,687 $ 16,687 Change in other long-term liabilities 4,536 (16,687 ) (12,151 ) |
Summary of supplemental cash flow information | The following table summarizes supplemental Pinnacle West cash flow information (dollars in thousands): Three Months Ended 2017 2016 Cash paid (received) during the period for: Income taxes, net of refunds $ (2 ) $ 2,502 Interest, net of amounts capitalized 54,280 56,139 Significant non-cash investing and financing activities: Accrued capital expenditures $ 79,306 $ 59,707 |
Long-Term Debt and Liquidity 24
Long-Term Debt and Liquidity Matters (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
Debt Disclosure [Abstract] | |
Schedule of estimated fair value of long-term debt, including current maturities | The following table presents the estimated fair value of our long-term debt, including current maturities (dollars in thousands): As of March 31, 2017 As of December 31, 2016 Carrying Amount Fair Value Carrying Amount Fair Value Pinnacle West $ 125,000 $ 125,000 $ 125,000 $ 125,000 APS 4,273,890 4,558,285 4,021,785 4,300,789 Total $ 4,398,890 $ 4,683,285 $ 4,146,785 $ 4,425,789 |
Regulatory Matters (Tables)
Regulatory Matters (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
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 2017 and 2016 (dollars in thousands): Three Months Ended 2017 2016 Beginning balance $ 12,465 $ (9,688 ) Deferred fuel and purchased power costs — current period 988 (1,007 ) Amounts charged to customers 4,172 (2,388 ) Ending balance $ 17,625 $ (13,083 ) |
Schedule of regulatory assets | The detail of regulatory assets is as follows (dollars in thousands): Amortization Through March 31, 2017 December 31, 2016 Current Non-Current Current Non-Current Pension (a) $ — $ 699,817 $ — $ 711,059 Retired power plant costs 2033 9,913 115,110 9,913 117,591 Income taxes — allowance for funds used during construction ("AFUDC") equity 2047 6,202 150,629 6,305 152,118 Deferred fuel and purchased power — mark-to-market (Note 6) 2020 30,203 59,428 — 42,963 Deferred fuel and purchased power (b) (e) 2018 17,625 — 12,465 — Four Corners cost deferral 2024 6,689 55,221 6,689 56,894 Income taxes — investment tax credit basis adjustment 2046 2,120 54,265 2,120 54,356 Lost fixed cost recovery (b) 2018 70,762 — 61,307 — Palo Verde VIEs (Note 5) 2046 — 18,930 — 18,775 Deferred compensation 2036 — 36,846 — 35,595 Deferred property taxes (c) — 79,447 — 73,200 Loss on reacquired debt 2038 1,637 16,533 1,637 16,942 Tax expense of Medicare subsidy 2024 1,503 10,458 1,513 10,589 Demand Side Management 2018 5,491 — 3,744 — AG-1 deferral 2018 — 6,976 — 5,868 Mead-Phoenix transmission line CIAC 2050 332 10,625 332 10,708 Transmission cost adjustor (b) 2018 2,071 2,460 — 1,588 Coal reclamation 2026 418 4,728 418 5,182 Other Various 975 — 432 — Total regulatory assets (d) $ 155,941 $ 1,321,473 $ 106,875 $ 1,313,428 (a) See Note 4 for further discussion. (b) See "Cost Recovery Mechanisms" discussion above. (c) Per the provision of the 2012 Settlement Agreement. (d) There are no regulatory assets for which the ACC has allowed recovery of costs, but not allowed a return by exclusion from rate base. FERC rates are set using a formula rate as described in "Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters." (e) Subject to a carrying charge. |
Schedule of regulatory liabilities | The detail of regulatory liabilities is as follows (dollars in thousands): Amortization Through March 31, 2017 December 31, 2016 Current Non-Current Current Non-Current Asset retirement obligations 2057 $ — $ 298,796 $ — $ 279,976 Removal costs (a) 37,194 211,348 29,899 223,145 Other postretirement benefits (c) 32,662 115,950 32,662 123,913 Income taxes — deferred investment tax credit 2046 4,315 108,691 4,368 108,827 Income taxes — change in rates 2046 2,565 69,497 1,771 70,898 Spent nuclear fuel 2047 — 72,755 — 71,726 Renewable energy standard (b) 2018 22,367 — 26,809 — Demand side management (b) 2019 — 19,921 — 20,472 Sundance maintenance 2030 — 15,690 — 15,287 Deferred gains on utility property 2019 2,062 8,439 2,063 8,895 Four Corners coal reclamation 2031 — 19,684 — 18,248 Other Various 43 7,522 2,327 7,529 Total regulatory liabilities $ 101,208 $ 948,293 $ 99,899 $ 948,916 (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) See Note 4 . |
Retirement Plans and Other Po26
Retirement Plans and Other Postretirement Benefits (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
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 to the regulatory asset or liability) (dollars in thousands): Pension Benefits Other Benefits Three Months Ended Three Months Ended 2017 2016 2017 2016 Service cost — benefits earned during the period $ 13,760 $ 14,266 $ 4,358 $ 3,937 Interest cost on benefit obligation 32,701 32,945 7,565 7,341 Expected return on plan assets (43,710 ) (43,792 ) (13,350 ) (9,122 ) Amortization of: Prior service cost (credit) 20 132 (9,461 ) (9,471 ) Net actuarial loss 12,489 9,731 1,454 946 Net periodic benefit cost $ 15,260 $ 13,282 $ (9,434 ) $ (6,369 ) Portion of cost charged to expense $ 7,568 $ 6,519 $ (4,678 ) $ (3,126 ) |
Palo Verde Sale Leaseback Var27
Palo Verde Sale Leaseback Variable Interest Entities (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
Variable Interest Entities [Abstract] | |
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets | Our Condensed Consolidated Balance Sheets at March 31, 2017 and December 31, 2016 include the following amounts relating to the VIEs (dollars in thousands): March 31, 2017 December 31, 2016 Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation $ 112,548 $ 113,515 Equity — Noncontrolling interests 137,164 132,290 |
Derivative Accounting (Tables)
Derivative Accounting (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
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 March 31, 2017 , we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position): Commodity Quantity Power 1,123 GWh Gas 226 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 months ended March 31, 2017 and 2016 (dollars in thousands): Financial Statement Location Three Months Ended Commodity Contracts 2017 2016 Loss Recognized in OCI on Derivative Instruments (Effective Portion) OCI — derivative instruments $ (96 ) $ (147 ) Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a) Fuel and purchased power (b) (851 ) (941 ) (a) During the three months ended March 31, 2017 and 2016 , we had no losses reclassified from accumulated OCI to earnings related to discontinued cash flow hedges. (b) Amounts are before the effect of PSA deferrals. |
Gains and losses from derivative instruments not designated as accounting hedges instruments | The following table provides information about gains and losses from derivative instruments not designated as accounting hedging instruments during the three months ended March 31, 2017 and 2016 (dollars in thousands): Financial Statement Location Three Months Ended Commodity Contracts 2017 2016 Net Loss Recognized in Income Operating revenues $ (288 ) $ (102 ) Net Loss Recognized in Income Fuel and purchased power (a) (52,627 ) (30,936 ) Total $ (52,915 ) $ (31,038 ) (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 March 31, 2017 and December 31, 2016 . 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 March 31, 2017: Gross Recognized Derivatives (a) Amounts Offset (b) Net Recognized Derivatives Other (c) Amount Reported on Balance Sheet Current assets $ 28,193 $ (23,983 ) $ 4,210 $ 12 $ 4,222 Investments and other assets 1,654 (1,654 ) — — — Total assets 29,847 (25,637 ) 4,210 12 4,222 Current liabilities (61,861 ) 23,983 (37,878 ) (4,054 ) (41,932 ) Deferred credits and other (64,867 ) 1,654 (63,213 ) — (63,213 ) Total liabilities (126,728 ) 25,637 (101,091 ) (4,054 ) (105,145 ) Total $ (96,881 ) $ — $ (96,881 ) $ (4,042 ) $ (100,923 ) (a) All of our gross recognized derivative instruments were subject to master netting arrangements. (b) No cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting. (c) Represents cash collateral and cash margin that is not subject to offsetting. Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument. Includes cash collateral received from counterparties of $4,054 . As of December 31, 2016: Gross Recognized Derivatives (a) Amounts Offset (b) Net Recognized Derivatives Other (c) Amount Reported on Balance Sheet Current assets $ 48,094 $ (28,400 ) $ 19,694 $ — $ 19,694 Investments and other assets 6,704 (6,703 ) 1 — 1 Total assets 54,798 (35,103 ) 19,695 — 19,695 Current liabilities (50,182 ) 28,400 (21,782 ) (4,054 ) (25,836 ) Deferred credits and other (53,941 ) 6,703 (47,238 ) — (47,238 ) Total liabilities (104,123 ) 35,103 (69,020 ) (4,054 ) (73,074 ) Total $ (49,325 ) $ — $ (49,325 ) $ (4,054 ) $ (53,379 ) (a) All of our gross recognized derivative instruments were subject to master netting arrangements. (b) No cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting. (c) Represents cash collateral and cash margin that is not subject to offsetting. Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument. Includes cash collateral received from counterparties of $4,054 . |
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 March 31, 2017 and December 31, 2016 . 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 March 31, 2017: Gross Recognized Derivatives (a) Amounts Offset (b) Net Recognized Derivatives Other (c) Amount Reported on Balance Sheet Current assets $ 28,193 $ (23,983 ) $ 4,210 $ 12 $ 4,222 Investments and other assets 1,654 (1,654 ) — — — Total assets 29,847 (25,637 ) 4,210 12 4,222 Current liabilities (61,861 ) 23,983 (37,878 ) (4,054 ) (41,932 ) Deferred credits and other (64,867 ) 1,654 (63,213 ) — (63,213 ) Total liabilities (126,728 ) 25,637 (101,091 ) (4,054 ) (105,145 ) Total $ (96,881 ) $ — $ (96,881 ) $ (4,042 ) $ (100,923 ) (a) All of our gross recognized derivative instruments were subject to master netting arrangements. (b) No cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting. (c) Represents cash collateral and cash margin that is not subject to offsetting. Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument. Includes cash collateral received from counterparties of $4,054 . As of December 31, 2016: Gross Recognized Derivatives (a) Amounts Offset (b) Net Recognized Derivatives Other (c) Amount Reported on Balance Sheet Current assets $ 48,094 $ (28,400 ) $ 19,694 $ — $ 19,694 Investments and other assets 6,704 (6,703 ) 1 — 1 Total assets 54,798 (35,103 ) 19,695 — 19,695 Current liabilities (50,182 ) 28,400 (21,782 ) (4,054 ) (25,836 ) Deferred credits and other (53,941 ) 6,703 (47,238 ) — (47,238 ) Total liabilities (104,123 ) 35,103 (69,020 ) (4,054 ) (73,074 ) Total $ (49,325 ) $ — $ (49,325 ) $ (4,054 ) $ (53,379 ) (a) All of our gross recognized derivative instruments were subject to master netting arrangements. (b) No cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting. (c) Represents cash collateral and cash margin that is not subject to offsetting. Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument. Includes cash collateral received from counterparties of |
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 March 31, 2017 (dollars in thousands): March 31, 2017 Aggregate fair value of derivative instruments in a net liability position $ 126,728 Cash collateral posted — Additional cash collateral in the event credit-risk-related contingent features were fully triggered (a) 63,646 (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) | 3 Months Ended |
Mar. 31, 2017 | |
Component of Other Income and Other Expense Nonoperating [Line Items] | |
Detail of other income and other expense | The following table provides detail of Pinnacle West's Consolidated other income and other expense for the three months ended March 31, 2017 and 2016 (dollars in thousands): Three Months Ended 2017 2016 Other income: Interest income $ 477 $ 117 Miscellaneous 3 — Total other income $ 480 $ 117 Other expense: Non-operating costs $ (1,959 ) $ (2,049 ) Investment losses — net (301 ) (518 ) Miscellaneous (1,420 ) (1,471 ) Total other expense $ (3,680 ) $ (4,038 ) |
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 months ended March 31, 2017 and 2016 (dollars in thousands): Three Months Ended 2017 2016 Other income: Interest income $ 338 $ 73 Gain on disposition of property 308 332 Miscellaneous 416 205 Total other income $ 1,062 $ 610 Other expense: Non-operating costs (a) $ (2,166 ) $ (1,966 ) Loss on disposition of property (88 ) (426 ) Miscellaneous (2,124 ) (2,358 ) Total other expense $ (4,378 ) $ (4,750 ) (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) | 3 Months Ended |
Mar. 31, 2017 | |
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 months ended March 31, 2017 and 2016 (in thousands, except per share amounts): Three Months Ended 2017 2016 Net income attributable to common shareholders $ 23,312 $ 4,453 Weighted average common shares outstanding — basic 111,728 111,296 Net effect of dilutive securities: Contingently issuable performance shares and restricted stock units 467 551 Weighted average common shares outstanding — diluted 112,195 111,847 Earnings per weighted-average common share outstanding Net income attributable to common shareholders — basic $ 0.21 $ 0.04 Net income attributable to common shareholders — diluted $ 0.21 $ 0.04 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
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 March 31, 2017 , of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands): Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (a) (Level 3) Other Balance at March 31, 2017 Assets Coal reclamation trust - cash equivalents (b) $ 14,801 $ — $ — $ — $ 14,801 Risk management activities — derivative instruments: Commodity contracts — 20,431 9,416 (25,625 ) (c) 4,222 Nuclear decommissioning trust: U.S. commingled equity funds — — — 374,695 (d) 374,695 Fixed income securities: Cash and cash equivalent funds — — — 336 (e) 336 U.S. Treasury 94,709 — — — 94,709 Corporate debt — 115,329 — — 115,329 Mortgage-backed securities — 115,332 — — 115,332 Municipal bonds — 81,932 — — 81,932 Other — 22,715 — — 22,715 Subtotal nuclear decommissioning trust 94,709 335,308 — 375,031 805,048 Total $ 109,510 $ 355,739 $ 9,416 $ 349,406 $ 824,071 Liabilities Risk management activities — derivative instruments: Commodity contracts $ — $ (75,627 ) $ (51,101 ) $ 21,583 (c) $ (105,145 ) (a) Primarily consists of long-dated electricity contracts. (b) Represents investments restricted for coal mine reclamation funding related to Four Corners. These assets are included in the Other Assets line item, reported under the Investments and Other Assets section of our Condensed Consolidated Balance Sheets. (c) Represents counterparty netting, margin and collateral. See Note 6 . (d) Valued using NAV as a practical expedient and, therefore, are not classified in the fair value hierarchy. (e) Represents nuclear decommissioning trust net pending securities sales and purchases. The following table presents the fair value at December 31, 2016 , of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands): Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (a) (Level 3) Other Balance at December 31, 2016 Assets Coal reclamation trust - cash equivalents (b) $ 14,521 $ — $ — $ — $ 14,521 Risk management activities — derivative instruments: Commodity contracts — 43,722 11,076 (35,103 ) (c) 19,695 Nuclear decommissioning trust: U.S. commingled equity funds — — — 353,261 (d) 353,261 Fixed income securities: Cash and cash equivalent funds — — — 795 (e) 795 U.S. Treasury 95,441 — — — 95,441 Corporate debt — 111,623 — — 111,623 Mortgage-backed securities — 115,337 — — 115,337 Municipal bonds — 80,997 — — 80,997 Other — 22,132 — — 22,132 Subtotal nuclear decommissioning trust 95,441 330,089 — 354,056 779,586 Total $ 109,962 $ 373,811 $ 11,076 $ 318,953 $ 813,802 Liabilities Risk management activities — derivative instruments: Commodity contracts $ — $ (45,641 ) $ (58,482 ) $ 31,049 (c) $ (73,074 ) (a) Primarily consists of long-dated electricity contracts. (b) Represents investments restricted for coal mine reclamation funding related to Four Corners. These assets are included in the Other Assets line item, reported under the Investments and Other Assets section of our Condensed Consolidated Balance Sheets. (c) Represents counterparty netting, margin and collateral. See Note 6. (d) Valued using NAV as a practical expedient and, therefore, are not classified in the fair value hierarchy. (e) 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 March 31, 2017 and December 31, 2016 : March 31, 2017 Valuation Technique Significant Unobservable Input Weighted-Average Commodity Contracts Assets Liabilities Range Electricity: Forward Contracts (a) $ 8,805 $ 30,313 Discounted cash flows Electricity forward price (per MWh) $16.65 - $36.64 $ 27.96 Natural Gas: Forward Contracts (a) 611 20,788 Discounted cash flows Natural gas forward price (per MMBtu) $2.07 - $2.80 $ 2.42 Total $ 9,416 $ 51,101 (a) Includes swaps and physical and financial contracts. December 31, 2016 Valuation Technique Significant Unobservable Input Weighted-Average Commodity Contracts Assets Liabilities Range Electricity: Forward Contracts (a) $ 10,648 $ 32,042 Discounted cash flows Electricity forward price (per MWh) $16.43 - $41.07 $ 29.86 Natural Gas: Forward Contracts (a) 428 26,440 Discounted cash flows Natural gas forward price (per MMBtu) $2.32 - $3.60 $ 2.81 Total $ 11,076 $ 58,482 (a) Includes swaps and physical and financial contracts. |
Changes in fair value for assets and liabilities that are measured at fair value on a recurring basis using Level 3 inputs | The following table shows the changes in fair value for our risk management activities' assets and liabilities that are measured at fair value on a recurring basis using Level 3 inputs for the three months ended March 31, 2017 and 2016 (dollars in thousands): Three Months Ended Commodity Contracts 2017 2016 Net derivative balance at beginning of period $ (47,406 ) $ (32,979 ) Total net gains (losses) realized/unrealized: Included in OCI — — Deferred as a regulatory asset or liability (11,755 ) (9,103 ) Settlements 1,423 1,765 Transfers into Level 3 from Level 2 (38 ) 262 Transfers from Level 3 into Level 2 16,091 548 Net derivative balance at end of period $ (41,685 ) $ (39,507 ) Net unrealized gains included in earnings related to instruments still held at end of period $ — $ — |
Nuclear Decommissioning Trusts
Nuclear Decommissioning Trusts (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
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 March 31, 2017 and December 31, 2016 (dollars in thousands): Fair Value Total Unrealized Gains Total Unrealized Losses March 31, 2017 Equity securities $ 374,695 $ 207,708 $ — Fixed income securities 430,016 10,022 (3,963 ) Net receivables (a) 337 — — Total $ 805,048 $ 217,730 $ (3,963 ) Fair Value Total Unrealized Gains Total Unrealized Losses December 31, 2016 Equity securities $ 353,261 $ 188,091 $ — Fixed income securities 425,530 9,820 (4,962 ) Net receivables (a) 795 — — Total $ 779,586 $ 197,911 $ (4,962 ) (a) Net receivables/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 thousands): Three Months Ended 2017 2016 Realized gains $ 2,367 $ 2,438 Realized losses (2,453 ) (1,786 ) Proceeds from the sale of securities (a) 151,126 141,809 (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 March 31, 2017 is as follows (dollars in thousands): Fair Value Less than one year $ 12,143 1 year – 5 years 117,217 5 years – 10 years 114,131 Greater than 10 years 186,525 Total $ 430,016 |
Changes in Accumulated Other 33
Changes in Accumulated Other Comprehensive Loss (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
Accumulated Other Comprehensive Income (Loss) [Line Items] | |
Schedule of changes in accumulated other comprehensive loss including reclassification adjustments, net of tax, by component | The following table shows the changes in Pinnacle West's consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the three months ended March 31, 2017 and 2016 (dollars in thousands): Three Months Ended March 31, 2017 2016 Balance at beginning of period $ (43,822 ) $ (44,748 ) Derivative Instruments OCI (loss) before reclassifications (770 ) (693 ) Amounts reclassified from accumulated other comprehensive loss (a) 1,207 1,141 Net current period OCI (loss) 437 448 Pension and Other Postretirement Benefits Amounts reclassified from accumulated other comprehensive loss (b) 522 530 Net current period OCI (loss) 522 530 Balance at end of period $ (42,863 ) $ (43,770 ) (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 6 . (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 table shows the changes in APS's consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the three months ended March 31, 2017 and 2016 (dollars in thousands): Three Months Ended March 31, 2017 2016 Balance at beginning of period $ (25,423 ) $ (27,097 ) Derivative Instruments OCI (loss) before reclassifications (770 ) (693 ) Amounts reclassified from accumulated other comprehensive loss (a) 1,207 1,141 Net current period OCI (loss) 437 448 Pension and Other Postretirement Benefits Amounts reclassified from accumulated other comprehensive loss (b) 611 611 Net current period OCI (loss) 611 611 Balance at end of period $ (24,375 ) $ (26,038 ) (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 6 . (b) These amounts primarily represent amortization of actuarial loss and are included in the computation of net periodic pension cost. See Note 4 . |
Consolidated and Nature of Oper
Consolidated and Nature of Operations - Schedule of Reclassification of Prior Period Adjustments (Details) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
Error Corrections and Prior Period Adjustments Restatement [Line Items] | ||
Stock compensation | $ 9,997 | $ 16,687 |
Change in other long-term liabilities | $ 1,604 | (12,151) |
As previously reported | ||
Error Corrections and Prior Period Adjustments Restatement [Line Items] | ||
Stock compensation | 0 | |
Change in other long-term liabilities | 4,536 | |
Reclassifications to conform to current year presentation | ||
Error Corrections and Prior Period Adjustments Restatement [Line Items] | ||
Stock compensation | 16,687 | |
Change in other long-term liabilities | $ (16,687) |
Consolidation and Nature of O35
Consolidation and Nature of Operations (Details) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
Cash paid (received) during the period for: | ||
Income taxes, net of refunds | $ (2) | $ 2,502 |
Interest, net of amounts capitalized | 54,280 | 56,139 |
Significant non-cash investing and financing activities: | ||
Accrued capital expenditures | $ 79,306 | $ 59,707 |
Long-Term Debt and Liquidity 36
Long-Term Debt and Liquidity Matters - Narrative (Details) | 3 Months Ended | ||
Mar. 31, 2017USD ($)Facility | Mar. 21, 2017USD ($) | Dec. 31, 2016USD ($) | |
Long-Term Debt and Liquidity Matters | |||
Shot-term debt | $ 207,297,000 | $ 177,200,000 | |
Debt Provisions | |||
Total shareholder equity | 4,828,776,000 | 4,803,622,000 | |
Pinnacle West | Revolving Credit Facility | Revolving credit facility maturing May 2021 | |||
Long-Term Debt and Liquidity Matters | |||
Current borrowing capacity on credit facility | 200,000,000 | ||
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders (up to) | 300,000,000 | ||
Long-term line of credit | 0 | ||
Pinnacle West | Revolving Credit Facility | Revolving credit facility maturing in August 2017 | |||
Long-Term Debt and Liquidity Matters | |||
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders (up to) | $ 75,000,000 | ||
Debt instrument, term | 364 days | ||
Shot-term debt | $ 48,000,000 | ||
Pinnacle West | Letter of Credit | Revolving credit facility maturing May 2021 | |||
Long-Term Debt and Liquidity Matters | |||
Outstanding letters of credit | 0 | ||
Pinnacle West | Commercial paper | Revolving credit facility maturing May 2021 | |||
Long-Term Debt and Liquidity Matters | |||
Commercial paper | 42,800,000 | ||
APS | |||
Long-Term Debt and Liquidity Matters | |||
Shot-term debt | 116,497,000 | 135,500,000 | |
Debt Provisions | |||
Total shareholder equity | 4,929,888,000 | $ 4,905,680,000 | |
APS | ACC | |||
Debt Provisions | |||
Total shareholder equity | 4,900,000,000 | ||
Total capitalization | 9,400,000,000 | ||
Dividend restrictions, shareholder equity required | $ 3,800,000,000 | ||
APS | ACC | Minimum | |||
Debt Provisions | |||
Required common equity ratio ordered by ACC (as a percent) (at least) | 40.00% | ||
APS | Revolving Credit Facility | Revolving Credit Facilities Maturing in 2020 and 2021 | |||
Long-Term Debt and Liquidity Matters | |||
Current borrowing capacity on credit facility | $ 1,000,000,000 | ||
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders (up to) | 1,400,000,000 | ||
Long-term line of credit | $ 0 | ||
Number of line of credit facilities | Facility | 2 | ||
APS | Revolving Credit Facility | Revolving credit facility maturing May 2021 | |||
Long-Term Debt and Liquidity Matters | |||
Current borrowing capacity on credit facility | $ 500,000,000 | ||
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders (up to) | 700,000,000 | ||
APS | Revolving Credit Facility | Revolving credit facility maturing September 2020 | |||
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 (up to) | 700,000,000 | ||
APS | Letter of Credit | Revolving Credit Facilities Maturing in 2020 and 2021 | |||
Long-Term Debt and Liquidity Matters | |||
Outstanding letters of credit | 0 | ||
APS | Commercial paper | |||
Long-Term Debt and Liquidity Matters | |||
Maximum commercial paper support available under credit facility | 500,000,000 | ||
APS | Commercial paper | Revolving Credit Facilities Maturing in 2020 and 2021 | |||
Long-Term Debt and Liquidity Matters | |||
Commercial paper | $ 116,500,000 | ||
Senior Notes | APS | Unsecured senior notes maturing November 2045 | |||
Long-Term Debt and Liquidity Matters | |||
Debt issued | $ 250,000,000 | ||
Debt instrument, stated interest rate | 4.35% | ||
LIBOR | Pinnacle West | Revolving Credit Facility | Revolving credit facility maturing in August 2017 | |||
Long-Term Debt and Liquidity Matters | |||
Debt instrument, basis spread on variable rate | 0.80% |
Long-Term Debt and Liquidity 37
Long-Term Debt and Liquidity Matters - Estimated Fair Value of Long-Term Debt (Details) - USD ($) $ in Thousands | Mar. 31, 2017 | Dec. 31, 2016 |
Estimated fair value of long-term debt, including current maturities | ||
Carrying Amount | $ 4,398,890 | $ 4,146,785 |
Fair Value | 4,683,285 | 4,425,789 |
Pinnacle West | ||
Estimated fair value of long-term debt, including current maturities | ||
Carrying Amount | 125,000 | 125,000 |
Fair Value | 125,000 | 125,000 |
Arizona Public Service Company | ||
Estimated fair value of long-term debt, including current maturities | ||
Carrying Amount | 4,273,890 | 4,021,785 |
Fair Value | $ 4,558,285 | $ 4,300,789 |
Regulatory Matters - Retail Rat
Regulatory Matters - Retail Rate Case Filing (Details) - Retail Rate Case Filing with Arizona Corporation Commission - ACC - APS - USD ($) $ in Millions | Jun. 01, 2016 | Dec. 31, 2015 | Jun. 01, 2011 |
Public Utilities, General Disclosures [Line Items] | |||
Net retail rate increase | $ 165.9 | $ 95.5 | |
Adjustor account balance transferred into base rates, amount | $ 267.6 | ||
Approximate percentage of increase in average customer bill | 5.74% | ||
Approximate percentage of increase in average residential customer bill | 7.96% |
Regulatory Matters - Settlement
Regulatory Matters - Settlement Agreement, Cost Recovery Mechanism and Net Metering (Details) | Mar. 27, 2017USD ($)$ / kWh | Mar. 26, 2017$ / kWh | Feb. 01, 2017$ / kWh | Jan. 13, 2017USD ($) | Dec. 20, 2016 | Jun. 01, 2016USD ($) | Feb. 01, 2016$ / kWh | Jan. 15, 2016USD ($) | Jan. 01, 2016USD ($) | Jun. 01, 2015USD ($) | Mar. 02, 2015USD ($) | Nov. 04, 2014 | Jan. 06, 2012USD ($)$ / kWh | Jun. 01, 2011USD ($) | Sep. 30, 2016 | Dec. 31, 2014storage_systempenetration_feederMW | Apr. 30, 2014workshop | Mar. 31, 2017USD ($)$ / kWh | Mar. 31, 2016USD ($) | Jan. 27, 2017USD ($) | Dec. 05, 2016USD ($) | Jul. 12, 2016USD ($) | Jul. 01, 2016USD ($) | Apr. 01, 2016USD ($) | Jan. 12, 2016USD ($) | Nov. 25, 2015USD ($) | Mar. 20, 2015project |
Change in regulatory asset | |||||||||||||||||||||||||||
Deferred fuel and purchased power costs — current period | $ 988,000 | $ (1,007,000) | |||||||||||||||||||||||||
Amounts charged to customers | 4,172,000 | (2,388,000) | |||||||||||||||||||||||||
APS | |||||||||||||||||||||||||||
Change in regulatory asset | |||||||||||||||||||||||||||
Deferred fuel and purchased power costs — current period | 988,000 | (1,007,000) | |||||||||||||||||||||||||
Amounts charged to customers | $ 4,172,000 | (2,388,000) | |||||||||||||||||||||||||
RES 2014 | APS | Alternative to AZ Sun Program, Phase 1 | |||||||||||||||||||||||||||
Settlement Agreement | |||||||||||||||||||||||||||
Request to build additional utility scale solar, capacity | MW | 8 | ||||||||||||||||||||||||||
RES 2014 | APS | Alternative to AZ Sun Program Phase 2 | |||||||||||||||||||||||||||
Settlement Agreement | |||||||||||||||||||||||||||
Request to build additional utility scale solar, capacity | MW | 2 | ||||||||||||||||||||||||||
Number of energy storage systems | storage_system | 2 | ||||||||||||||||||||||||||
Number of high solar penetration feeders | penetration_feeder | 2 | ||||||||||||||||||||||||||
Lost Fixed Cost Recovery Mechanisms | APS | |||||||||||||||||||||||||||
Change in regulatory asset | |||||||||||||||||||||||||||
Fixed costs recoverable per residential power lost (in dollars per kWh) | $ / kWh | 0.031 | ||||||||||||||||||||||||||
Fixed costs recoverable per non-residential power lost (in dollars per kWh) | $ / kWh | 0.023 | ||||||||||||||||||||||||||
Percentage of retail revenues | 1.00% | ||||||||||||||||||||||||||
Amount of adjustment representing prorated sales losses approval | $ 46,400,000 | $ 38,500,000 | |||||||||||||||||||||||||
Increase in amount of adjustment representing prorated sales losses | $ 7,900,000 | ||||||||||||||||||||||||||
ACC | Retail Rate Case Filing with Arizona Corporation Commission | APS | |||||||||||||||||||||||||||
Settlement Agreement | |||||||||||||||||||||||||||
Net retail base rate, increase | $ 94,600,000 | ||||||||||||||||||||||||||
Non-fuel and non-depreciation base rate, increase | 87,200,000 | ||||||||||||||||||||||||||
Fuel-related base rate decrease | 53,600,000 | $ 153,100,000 | |||||||||||||||||||||||||
Base rate increase, changes in depreciation schedules | $ 61,000,000 | ||||||||||||||||||||||||||
Authorized return on common equity (as a percent) | 10.00% | ||||||||||||||||||||||||||
Percentage of debt in capital structure | 44.20% | ||||||||||||||||||||||||||
Percentage of common equity in capital structure | 55.80% | ||||||||||||||||||||||||||
Rate matter, environmental surcharge cap rate (in dollars per kWh) | $ / kWh | 0.00050 | 0.00016 | |||||||||||||||||||||||||
Rate matter, resource comparison proxy for exported energy (in dollars per kWh) | $ / kWh | 0.129 | ||||||||||||||||||||||||||
Net retail rate increase | $ 165,900,000 | $ 95,500,000 | |||||||||||||||||||||||||
Approximate percentage of increase in average retail customer bill | 6.60% | ||||||||||||||||||||||||||
Net change in base rates | 0 | ||||||||||||||||||||||||||
Non-fuel base rate increase | $ 116,300,000 | ||||||||||||||||||||||||||
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 | ||||||||||||||||||||||||||
Change in regulatory asset | |||||||||||||||||||||||||||
Reduced system benefits charge, amount | $ 14,600,000 | ||||||||||||||||||||||||||
ACC | Retail Rate Case Filing with Arizona Corporation Commission | APS | AZ Sun Program Phase 2 | |||||||||||||||||||||||||||
Settlement Agreement | |||||||||||||||||||||||||||
Public utilities, minimum annual renewable energy standard and tariff | $ 10,000,000 | ||||||||||||||||||||||||||
Public utilities, maximum annual renewable energy standard and tariff | $ 15,000,000 | ||||||||||||||||||||||||||
ACC | RES | APS | |||||||||||||||||||||||||||
Settlement Agreement | |||||||||||||||||||||||||||
Plan term | 5 years | ||||||||||||||||||||||||||
ACC | RES 2016 | APS | |||||||||||||||||||||||||||
Settlement Agreement | |||||||||||||||||||||||||||
Amount of approved budget | $ 148,000,000 | ||||||||||||||||||||||||||
ACC | RES 2017 | APS | |||||||||||||||||||||||||||
Settlement Agreement | |||||||||||||||||||||||||||
Amount of proposed budget | $ 150,000,000 | ||||||||||||||||||||||||||
ACC | Modernization and Expansion of the Renewal Energy Standard | APS | |||||||||||||||||||||||||||
Settlement Agreement | |||||||||||||||||||||||||||
Proposed renewal energy standard, percent of retail sales | 30.00% | ||||||||||||||||||||||||||
Current renewal energy standard, percent of retail sales | 15.00% | ||||||||||||||||||||||||||
ACC | DSMAC 2015 | APS | |||||||||||||||||||||||||||
Settlement Agreement | |||||||||||||||||||||||||||
Amount of approved budget | $ 68,900,000 | $ 68,900,000 | |||||||||||||||||||||||||
Number of resource savings projects | project | 3 | ||||||||||||||||||||||||||
Additional budget approved | $ 4,000,000 | ||||||||||||||||||||||||||
ACC | DSMC 2016 | APS | |||||||||||||||||||||||||||
Settlement Agreement | |||||||||||||||||||||||||||
Amount of approved budget | $ 68,900,000 | ||||||||||||||||||||||||||
ACC | Electric energy efficiency standard | APS | |||||||||||||||||||||||||||
Settlement Agreement | |||||||||||||||||||||||||||
Number of workshops | workshop | 3 | ||||||||||||||||||||||||||
Number of days to convene a workshop | 120 days | ||||||||||||||||||||||||||
ACC | Power Supply Adjustor (PSA) | APS | |||||||||||||||||||||||||||
Change in regulatory asset | |||||||||||||||||||||||||||
Beginning balance | $ (9,688,000) | $ 12,465,000 | (9,688,000) | ||||||||||||||||||||||||
Deferred fuel and purchased power costs — current period | 988,000 | (1,007,000) | |||||||||||||||||||||||||
Amounts charged to customers | 4,172,000 | (2,388,000) | |||||||||||||||||||||||||
Ending balance | $ 17,625,000 | $ (13,083,000) | |||||||||||||||||||||||||
PSA rate (in dollars per kWh) | $ / kWh | (0.001348) | ||||||||||||||||||||||||||
Forward component of increase in PSA (in dollars per kWh) | $ / kWh | (0.001027) | ||||||||||||||||||||||||||
Historical component of increase in PSA (in dollars per kWh) | $ / kWh | (0.000321) | ||||||||||||||||||||||||||
ACC | Net Metering | APS | |||||||||||||||||||||||||||
Change in regulatory asset | |||||||||||||||||||||||||||
Cost of service, resource comparison proxy method, maximum annual percentage decrease | 10.00% | ||||||||||||||||||||||||||
Cost of service for interconnected DG system customers, grandfathered period | 20 years | ||||||||||||||||||||||||||
Cost of service for new customers, guaranteed export price period | 10 years | ||||||||||||||||||||||||||
ACC | Residential Demand Response, Energy Storage and Load Management Program | APS | |||||||||||||||||||||||||||
Settlement Agreement | |||||||||||||||||||||||||||
Additional budget approved | $ 4,000,000 | ||||||||||||||||||||||||||
ACC | Demand Side Management Adjustor Charge 2017 | APS | |||||||||||||||||||||||||||
Settlement Agreement | |||||||||||||||||||||||||||
Amount of proposed budget | 62,600,000 | $ 66,600,000 | |||||||||||||||||||||||||
United States Federal Energy Regulatory Commission | Open Access Transmission Tariff | APS | |||||||||||||||||||||||||||
Change in regulatory asset | |||||||||||||||||||||||||||
Decrease in annual wholesale transmission rates | $ 17,600,000 | ||||||||||||||||||||||||||
Increase in annual wholesale transmission rates | $ 24,900,000 | ||||||||||||||||||||||||||
Cost Recovery Mechanisms | Lost Fixed Cost Recovery Mechanisms | APS | |||||||||||||||||||||||||||
Change in regulatory asset | |||||||||||||||||||||||||||
Increase in amount of adjustment representing prorated sales losses | $ 17,300,000 | ||||||||||||||||||||||||||
Amount of adjustment representing prorated sales losses pending approval | $ 63,700,000 | ||||||||||||||||||||||||||
Cost Recovery Mechanisms | ACC | Power Supply Adjustor (PSA) | APS | |||||||||||||||||||||||||||
Change in regulatory asset | |||||||||||||||||||||||||||
PSA rate for prior year (in dollars per kWh) | $ / kWh | 0.001678 |
Regulatory Matters - Four Corne
Regulatory Matters - Four Corners and Cholla (Details) - APS - USD ($) $ in Millions | Dec. 23, 2014 | Dec. 30, 2013 | Mar. 31, 2017 | Jun. 30, 2016 | Dec. 31, 2015 |
SCE | Four Corners Units 4 and 5 | |||||
Business Acquisition [Line Items] | |||||
Ownership interest acquired | 48.00% | ||||
Settlement agreement, ACC approved rate adjustment, annualized customer impact | $ 57.1 | ||||
Net receipt due to negotiation of alternate arrangement | $ 40 | ||||
Four Corners cost deferral | SCE | Four Corners Units 4 and 5 | |||||
Business Acquisition [Line Items] | |||||
Regulatory assets, non-current | $ 62 | ||||
Regulatory noncurrent asset amortization period | 10 years | ||||
Retired power plant costs | |||||
Business Acquisition [Line Items] | |||||
Net book value | $ 114 | ||||
Navajo Plant | |||||
Business Acquisition [Line Items] | |||||
Asset book value | $ 106 | ||||
Four Corners | SCE | |||||
Business Acquisition [Line Items] | |||||
Regulatory assets, non-current | $ 12 | ||||
Regulatory asset, write off amount | $ 12 |
Regulatory Matters - Schedule o
Regulatory Matters - Schedule of Regulatory Assets (Details) - USD ($) $ in Thousands | Mar. 31, 2017 | Dec. 31, 2016 |
Detail of regulatory assets | ||
Regulatory assets, current | $ 155,941 | $ 106,875 |
Regulatory assets, non-current | 1,321,473 | 1,313,428 |
Pension | ||
Detail of regulatory assets | ||
Regulatory assets, current | 0 | 0 |
Regulatory assets, non-current | 699,817 | 711,059 |
Retired power plant costs | ||
Detail of regulatory assets | ||
Regulatory assets, current | 9,913 | 9,913 |
Regulatory assets, non-current | 115,110 | 117,591 |
Income taxes — allowance for funds used during construction (AFUDC) equity | ||
Detail of regulatory assets | ||
Regulatory assets, current | 6,202 | 6,305 |
Regulatory assets, non-current | 150,629 | 152,118 |
Deferred fuel and purchased power — mark-to-market (Note 6) | ||
Detail of regulatory assets | ||
Regulatory assets, current | 30,203 | 0 |
Regulatory assets, non-current | 59,428 | 42,963 |
Deferred fuel and purchased power (b) (e) | ||
Detail of regulatory assets | ||
Regulatory assets, current | 17,625 | 12,465 |
Regulatory assets, non-current | 0 | 0 |
Four Corners cost deferral | ||
Detail of regulatory assets | ||
Regulatory assets, current | 6,689 | 6,689 |
Regulatory assets, non-current | 55,221 | 56,894 |
Income taxes — investment tax credit basis adjustment | ||
Detail of regulatory assets | ||
Regulatory assets, current | 2,120 | 2,120 |
Regulatory assets, non-current | 54,265 | 54,356 |
Lost fixed cost recovery (b) | ||
Detail of regulatory assets | ||
Regulatory assets, current | 70,762 | 61,307 |
Regulatory assets, non-current | 0 | 0 |
Palo Verde VIEs (Note 5) | ||
Detail of regulatory assets | ||
Regulatory assets, current | 0 | 0 |
Regulatory assets, non-current | 18,930 | 18,775 |
Deferred compensation | ||
Detail of regulatory assets | ||
Regulatory assets, current | 0 | 0 |
Regulatory assets, non-current | 36,846 | 35,595 |
Deferred property taxes | ||
Detail of regulatory assets | ||
Regulatory assets, current | 0 | 0 |
Regulatory assets, non-current | 79,447 | 73,200 |
Loss on reacquired debt | ||
Detail of regulatory assets | ||
Regulatory assets, current | 1,637 | 1,637 |
Regulatory assets, non-current | 16,533 | 16,942 |
Tax expense of Medicare subsidy | ||
Detail of regulatory assets | ||
Regulatory assets, current | 1,503 | 1,513 |
Regulatory assets, non-current | 10,458 | 10,589 |
Demand side management (b) | ||
Detail of regulatory assets | ||
Regulatory assets, current | 5,491 | 3,744 |
Regulatory assets, non-current | 0 | 0 |
AG-1 deferral | ||
Detail of regulatory assets | ||
Regulatory assets, current | 0 | 0 |
Regulatory assets, non-current | 6,976 | 5,868 |
Mead-Phoenix transmission line CIAC | ||
Detail of regulatory assets | ||
Regulatory assets, current | 332 | 332 |
Regulatory assets, non-current | 10,625 | 10,708 |
Transmission cost adjustor (b) | ||
Detail of regulatory assets | ||
Regulatory assets, current | 2,071 | 0 |
Regulatory assets, non-current | 2,460 | 1,588 |
Coal reclamation | ||
Detail of regulatory assets | ||
Regulatory assets, current | 418 | 418 |
Regulatory assets, non-current | 4,728 | 5,182 |
Other | ||
Detail of regulatory assets | ||
Regulatory assets, current | 975 | 432 |
Regulatory assets, non-current | $ 0 | $ 0 |
Regulatory Matters - Schedule42
Regulatory Matters - Schedule of Regulatory Liabilities (Details) - USD ($) $ in Thousands | Mar. 31, 2017 | Dec. 31, 2016 |
Detail of regulatory liabilities | ||
Regulatory liabilities, current | $ 101,208 | $ 99,899 |
Regulatory liabilities, non-current | 948,293 | 948,916 |
Asset retirement obligations | ||
Detail of regulatory liabilities | ||
Regulatory liabilities, current | 0 | 0 |
Regulatory liabilities, non-current | 298,796 | 279,976 |
Removal costs | ||
Detail of regulatory liabilities | ||
Regulatory liabilities, current | 37,194 | 29,899 |
Regulatory liabilities, non-current | 211,348 | 223,145 |
Other postretirement benefits | ||
Detail of regulatory liabilities | ||
Regulatory liabilities, current | 32,662 | 32,662 |
Regulatory liabilities, non-current | 115,950 | 123,913 |
Income taxes — deferred investment tax credit | ||
Detail of regulatory liabilities | ||
Regulatory liabilities, current | 4,315 | 4,368 |
Regulatory liabilities, non-current | 108,691 | 108,827 |
Income taxes — change in rates | ||
Detail of regulatory liabilities | ||
Regulatory liabilities, current | 2,565 | 1,771 |
Regulatory liabilities, non-current | 69,497 | 70,898 |
Spent nuclear fuel | ||
Detail of regulatory liabilities | ||
Regulatory liabilities, current | 0 | 0 |
Regulatory liabilities, non-current | 72,755 | 71,726 |
Renewable energy standard (b) | ||
Detail of regulatory liabilities | ||
Regulatory liabilities, current | 22,367 | 26,809 |
Regulatory liabilities, non-current | 0 | 0 |
Demand side management (b) | ||
Detail of regulatory liabilities | ||
Regulatory liabilities, current | 0 | 0 |
Regulatory liabilities, non-current | 19,921 | 20,472 |
Sundance maintenance | ||
Detail of regulatory liabilities | ||
Regulatory liabilities, current | 0 | 0 |
Regulatory liabilities, non-current | 15,690 | 15,287 |
Deferred gains on utility property | ||
Detail of regulatory liabilities | ||
Regulatory liabilities, current | 2,062 | 2,063 |
Regulatory liabilities, non-current | 8,439 | 8,895 |
Four Corners coal reclamation | ||
Detail of regulatory liabilities | ||
Regulatory liabilities, current | 0 | 0 |
Regulatory liabilities, non-current | 19,684 | 18,248 |
Other | ||
Detail of regulatory liabilities | ||
Regulatory liabilities, current | 43 | 2,327 |
Regulatory liabilities, non-current | $ 7,522 | $ 7,529 |
Retirement Plans and Other Po43
Retirement Plans and Other Postretirement Benefits - Narrative (Details) | 3 Months Ended |
Mar. 31, 2017USD ($) | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Amount of other postretirement benefit trust assets for union employee medical costs | $ 145,000,000 |
Pension Benefits | |
Contributions | |
Voluntary employer contributions to pension plan | 60,000,000 |
Minimum employer contributions for the next three years | 0 |
Maximum employer contributions for the next two years (up to) | 300,000,000 |
Other Benefits | |
Contributions | |
Estimated future employer contributions in next three years | $ 1,000,000 |
Retirement Plans and Other Po44
Retirement Plans and Other Postretirement Benefits - Schedule of Net Benefit Cost (Details) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
Pension Benefits | ||
Retirement Plans and Other Benefits | ||
Service cost — benefits earned during the period | $ 13,760 | $ 14,266 |
Interest cost on benefit obligation | 32,701 | 32,945 |
Expected return on plan assets | (43,710) | (43,792) |
Amortization of: | ||
Prior service cost (credit) | 20 | 132 |
Net actuarial loss | 12,489 | 9,731 |
Net periodic benefit cost | 15,260 | 13,282 |
Portion of cost charged to expense | 7,568 | 6,519 |
Other Benefits | ||
Retirement Plans and Other Benefits | ||
Service cost — benefits earned during the period | 4,358 | 3,937 |
Interest cost on benefit obligation | 7,565 | 7,341 |
Expected return on plan assets | (13,350) | (9,122) |
Amortization of: | ||
Prior service cost (credit) | (9,461) | (9,471) |
Net actuarial loss | 1,454 | 946 |
Net periodic benefit cost | (9,434) | (6,369) |
Portion of cost charged to expense | $ (4,678) | $ (3,126) |
Palo Verde Sale Leaseback Var45
Palo Verde Sale Leaseback Variable Interest Entities - Narrative (Details) | 3 Months Ended | ||
Mar. 31, 2017USD ($)power_plantLease | Mar. 31, 2016USD ($) | Dec. 31, 1986Trust | |
Palo Verde Sale Leaseback Variable Interest Entities | |||
Increase in net income due to consolidation of Palo Verde Sale Leaseback Trusts | $ 4,873,000 | $ 4,873,000 | |
Arizona Public Service Company | |||
Palo Verde Sale Leaseback Variable Interest Entities | |||
Number of VIE lessor trusts | 3 | 3 | |
Increase in net income due to consolidation of Palo Verde Sale Leaseback Trusts | $ 4,873,000 | 4,873,000 | |
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 | 5,000,000 | $ 5,000,000 | |
Initial loss exposure to the VIE's noncontrolling equity participants during lease extension period | 291,000,000 | ||
Maximum loss exposure to the VIE's noncontrolling equity participants during lease extension period | $ 456,000,000 | ||
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 | Period 2017 through 2023 | |||
Palo Verde Sale Leaseback Variable Interest Entities | |||
Annual lease payments | $ 23,000,000 | ||
Arizona Public Service Company | Consolidation of VIEs | Period 2024 through 2033 | |||
Palo Verde Sale Leaseback Variable Interest Entities | |||
Annual lease payments | $ 16,000,000 | ||
Arizona Public Service Company | Consolidation of VIEs | Period 2024 through 2033 | Maximum | |||
Palo Verde Sale Leaseback Variable Interest Entities | |||
Lease period (up to) | 2 years |
Palo Verde Sale Leaseback Var46
Palo Verde Sale Leaseback Variable Interest Entities - Schedule of VIEs (Details) - USD ($) $ in Thousands | Mar. 31, 2017 | Dec. 31, 2016 |
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets | ||
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation | $ 112,548 | $ 113,515 |
Equity — Noncontrolling interests | 137,164 | 132,290 |
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 | 112,548 | 113,515 |
Equity — Noncontrolling interests | 137,164 | 132,290 |
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 | 112,548 | 113,515 |
Equity — Noncontrolling interests | $ 137,164 | $ 132,290 |
Derivative Accounting - Narrati
Derivative Accounting - Narrative (Details) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2017 | Dec. 31, 2016 | |
Designated as Hedging Instruments | ||
Derivative Accounting | ||
Gross recognized derivatives | $ 1,000 | $ 2,000 |
Commodity Contracts | ||
Derivative Accounting | ||
Gross recognized derivatives | 126,728 | $ 104,123 |
Additional collateral to counterparties for energy related non-derivative instrument contracts | 130,000 | |
Commodity Contracts | Designated as Hedging Instruments | ||
Derivative Accounting | ||
Estimated net gain (loss) before income taxes to be reclassified from accumulated other comprehensive income | $ (3,000) | |
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) - Commodity Contracts MMcf in Thousands | 3 Months Ended |
Mar. 31, 2017GWhMMcf | |
Outstanding gross notional amount of derivatives | |
Power | GWh | 1,123 |
Gas | MMcf | 0 |
Derivative Accounting - Gains a
Derivative Accounting - Gains and Losses from Derivative Instruments (Details) - Commodity Contracts - USD ($) | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
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 |
Designated as Hedging Instruments | Fuel and purchased power | ||
Gains and losses from derivative instruments | ||
Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) | (851,000) | (941,000) |
Not Designated as Hedging Instruments | ||
Gains and losses from derivative instruments | ||
Net loss recognized in income | (52,915,000) | (31,038,000) |
Not Designated as Hedging Instruments | Operating revenues | ||
Gains and losses from derivative instruments | ||
Net loss recognized in income | (288,000) | (102,000) |
Not Designated as Hedging Instruments | Fuel and purchased power | ||
Gains and losses from derivative instruments | ||
Net loss recognized in income | (52,627,000) | (30,936,000) |
Other comprehensive income | Designated as Hedging Instruments | ||
Gains and losses from derivative instruments | ||
Loss Recognized in OCI on Derivative Instruments (Effective Portion) | $ (96,000) | $ (147,000) |
Derivative Accounting - Derivat
Derivative Accounting - Derivative Instruments in the Balance Sheets (Details) - Commodity Contracts - USD ($) | Mar. 31, 2017 | Dec. 31, 2016 |
Assets | ||
Gross Recognized Derivatives | $ 29,847,000 | $ 54,798,000 |
Amounts Offset | (25,637,000) | (35,103,000) |
Net Recognized Derivatives | 4,210,000 | 19,695,000 |
Other | 12,000 | 0 |
Derivative assets | 4,222,000 | 19,695,000 |
Liabilities | ||
Gross Recognized Derivatives | (126,728,000) | (104,123,000) |
Amounts Offset | 25,637,000 | 35,103,000 |
Other | (4,054,000) | (4,054,000) |
Net Recognized Derivatives | (101,091,000) | (69,020,000) |
Amount Reported on Balance Sheet | (105,145,000) | (73,074,000) |
Assets and Liabilities | ||
Gross Recognized Derivatives | (96,881,000) | (49,325,000) |
Amounts Offset | 0 | 0 |
Net Recognized Derivatives | (96,881,000) | (49,325,000) |
Other | (4,042,000) | (4,054,000) |
Amount Reported on Balance Sheet | (100,923,000) | (53,379,000) |
Current Assets | ||
Assets | ||
Gross Recognized Derivatives | 28,193,000 | 48,094,000 |
Amounts Offset | (23,983,000) | (28,400,000) |
Net Recognized Derivatives | 4,210,000 | 19,694,000 |
Other | 12,000 | 0 |
Derivative assets | 4,222,000 | 19,694,000 |
Investments and Other Assets | ||
Assets | ||
Gross Recognized Derivatives | 1,654,000 | 6,704,000 |
Amounts Offset | (1,654,000) | (6,703,000) |
Net Recognized Derivatives | 0 | 1,000 |
Other | 0 | 0 |
Derivative assets | 0 | 1,000 |
Current Liabilities | ||
Liabilities | ||
Gross Recognized Derivatives | (61,861,000) | (50,182,000) |
Amounts Offset | 23,983,000 | 28,400,000 |
Other | (4,054,000) | (4,054,000) |
Net Recognized Derivatives | (37,878,000) | (21,782,000) |
Amount Reported on Balance Sheet | (41,932,000) | (25,836,000) |
Deferred Credits and Other | ||
Liabilities | ||
Gross Recognized Derivatives | (64,867,000) | (53,941,000) |
Amounts Offset | 1,654,000 | 6,703,000 |
Other | 0 | 0 |
Net Recognized Derivatives | (63,213,000) | (47,238,000) |
Amount Reported on Balance Sheet | $ (63,213,000) | $ (47,238,000) |
Derivative Accounting - Credit
Derivative Accounting - Credit Risk and Credit Related Contingent Features (Details) - Commodity Contracts $ in Thousands | Mar. 31, 2017USD ($) |
Credit Risk and Credit-Related Contingent Features | |
Aggregate fair value of derivative instruments in a net liability position | $ 126,728 |
Cash collateral posted | 0 |
Additional cash collateral in the event credit-risk-related contingent features were fully triggered | $ 63,646 |
Commitments and Contingencies -
Commitments and Contingencies - Palo Verde Nuclear Generating Station and Contractual Obligations (Details) | Aug. 18, 2014USD ($) | Mar. 31, 2017USD ($)time_periodpower_plantclaim | Dec. 31, 1986Trust |
Commitments and Contingencies | |||
Purchase obligation, increase (decrease) as a result of variable components | $ 600,000,000 | ||
Breach of Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste | |||
Commitments and Contingencies | |||
Litigation settlement amount | $ 57,400,000 | ||
Proceeds from legal settlements | 65,200,000 | ||
Arizona Public Service Company | |||
Commitments and Contingencies | |||
Maximum insurance against public liability per occurrence for a nuclear incident (up to) | 13,400,000,000 | ||
Maximum available nuclear liability insurance (up to) | 450,000,000 | ||
Remaining nuclear liability insurance through mandatory industry wide retrospective assessment program | 13,000,000,000 | ||
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 | |
Maximum potential retrospective assessment per incident of APS | $ 111,100,000 | ||
Annual payment limitation with respect to maximum potential retrospective premium assessment | 16,600,000 | ||
Amount of "all risk" (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde | 2,800,000,000 | ||
Maximum amount that APS could incur under the current NEIL policies for each retrospective assessment | 24,000,000 | ||
Collateral assurance provided based on rating triggers | $ 64,800,000 | ||
Period to provide collateral assurance based on rating triggers | 20 days | ||
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 | $ 16,700,000 | ||
Number of claims submitted | claim | 3 | ||
Number of settlement agreement time periods | time_period | 3 | ||
Proceeds from legal settlements | $ 19,000,000 |
Commitments and Contingencies53
Commitments and Contingencies - Superfund-Related Matters, Southwest Power Outage and Clean Air Act (Details) - Arizona Public Service Company - Contaminated groundwater wells $ in Millions | Dec. 16, 2016plaintiff | Aug. 06, 2013Defendant | Mar. 31, 2017USD ($) |
Loss Contingencies [Line Items] | |||
Costs related to investigation and study under Superfund site | $ | $ 2 | ||
Number of defendants against whom Roosevelt Irrigation District (RID) filed lawsuit | Defendant | 24 | ||
Number of plaintiffs | plaintiff | 2 |
Commitments and Contingencies54
Commitments and Contingencies - Environmental Matters and Financial Assurances (Details) $ in Millions | Jul. 06, 2016guarantee | Jun. 24, 2016 | Mar. 31, 2017USD ($) |
Arizona Public Service Company | Letter of Credit Expiring in 2016 and 2017 | |||
Financial Assurances | |||
Outstanding letters of credit | $ 35 | ||
Arizona Public Service Company | Letters of Credit Expiring in 2017 | |||
Financial Assurances | |||
Surety bonds expiring, amount | $ 61 | ||
4C Acquisition, LLC | Four Corners Units 4 and 5 | |||
Environmental Matters | |||
Percentage of share of cost of control | 7.00% | ||
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 | 100 | ||
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 | Navajo Plant | Boron Inclusion on List of Groundwater Constituents | |||
Environmental Matters | |||
Industry litigation, period to complete rulemaking proceeding | 3 years | ||
Payment Guarantee | |||
Financial Assurances | |||
Number of parental guarantees | guarantee | 2 | ||
Minimum | Coal combustion waste | Arizona Public Service Company | Cholla | |||
Environmental Matters | |||
Site contingency increase in loss exposure not accrued, best estimate | 5 | ||
Maximum | Coal combustion waste | Arizona Public Service Company | Cholla | |||
Environmental Matters | |||
Site contingency increase in loss exposure not accrued, best estimate | $ 40 |
Other Income and Other Expens55
Other Income and Other Expense (Details) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
Other income: | ||
Interest income | $ 477 | $ 117 |
Miscellaneous | 3 | 0 |
Total other income | 480 | 117 |
Other expense: | ||
Non-operating costs | (1,959) | (2,049) |
Investment losses — net | (301) | (518) |
Miscellaneous | (1,420) | (1,471) |
Total other expense | (3,680) | (4,038) |
Arizona Public Service Company | ||
Other income: | ||
Interest income | 338 | 73 |
Gain on disposition of property | 308 | 332 |
Miscellaneous | 416 | 205 |
Total other income | 1,062 | 610 |
Other expense: | ||
Non-operating costs | (2,166) | (1,966) |
Loss on disposition of property | (88) | (426) |
Miscellaneous | (2,124) | (2,358) |
Total other expense | $ (4,378) | $ (4,750) |
Earnings Per Share (Details)
Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
Earnings Per Share [Abstract] | ||
Net income attributable to common shareholders | $ 23,312 | $ 4,453 |
Weighted average common shares outstanding - basic (in shares) | 111,728 | 111,296 |
Net effect of dilutive securities: | ||
Contingently issuable performance shares and restricted stock units (in shares) | 467 | 551 |
Weighted average common shares outstanding — diluted (in shares) | 112,195 | 111,847 |
Earnings per weighted-average common share outstanding | ||
Net income attributable to common shareholders - basic (in dollars per share) | $ 0.21 | $ 0.04 |
Net income attributable to common shareholders - diluted (in dollars per share) | $ 0.21 | $ 0.04 |
Fair Value Measurements - Asset
Fair Value Measurements - Assets and Liabilities Measured on a Recurring Basis (Details) - USD ($) $ in Thousands | Mar. 31, 2017 | Dec. 31, 2016 |
Assets | ||
Total | $ 805,048 | $ 779,586 |
Total assets | 9,416 | 11,076 |
Recurring | ||
Assets | ||
Coal reclamation trust - cash equivalents (b) | 14,801 | 14,521 |
Derivative instruments, other | (25,625) | (35,103) |
Derivative assets | 4,222 | 19,695 |
Nuclear decommissioning trust, other | 375,031 | 354,056 |
Total | 805,048 | 779,586 |
Total, other | 349,406 | 318,953 |
Total assets | 824,071 | 813,802 |
Liabilities | ||
Total, other | 21,583 | 31,049 |
Amount Reported on Balance Sheet | (105,145) | (73,074) |
Recurring | US commingled equity funds | ||
Assets | ||
Nuclear decommissioning trust, other | 374,695 | 353,261 |
Total | 374,695 | 353,261 |
Recurring | Cash and cash equivalent funds | ||
Assets | ||
Nuclear decommissioning trust, other | 336 | 795 |
Total | 336 | 795 |
Recurring | U.S. Treasury | ||
Assets | ||
Total | 94,709 | 95,441 |
Recurring | Corporate debt | ||
Assets | ||
Total | 115,329 | 111,623 |
Recurring | Mortgage-backed securities | ||
Assets | ||
Total | 115,332 | 115,337 |
Recurring | Municipality bonds | ||
Assets | ||
Total | 81,932 | 80,997 |
Recurring | Other | ||
Assets | ||
Total | 22,715 | 22,132 |
Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | ||
Assets | ||
Coal reclamation trust - cash equivalents (b) | 14,801 | 14,521 |
Decommissioning fund investments, gross fair value | 94,709 | 95,441 |
Gross assets, fair value disclosure | 109,510 | 109,962 |
Liabilities | ||
Gross derivative liability | 0 | 0 |
Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Cash and cash equivalent funds | ||
Assets | ||
Decommissioning fund investments, gross fair value | 0 | 0 |
Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | U.S. Treasury | ||
Assets | ||
Decommissioning fund investments, gross fair value | 94,709 | 95,441 |
Recurring | Significant Other Observable Inputs (Level 2) | ||
Assets | ||
Gross derivative assets | 20,431 | 43,722 |
Decommissioning fund investments, gross fair value | 335,308 | 330,089 |
Gross assets, fair value disclosure | 355,739 | 373,811 |
Liabilities | ||
Gross derivative liability | (75,627) | (45,641) |
Recurring | Significant Other Observable Inputs (Level 2) | Corporate debt | ||
Assets | ||
Decommissioning fund investments, gross fair value | 115,329 | 111,623 |
Recurring | Significant Other Observable Inputs (Level 2) | Mortgage-backed securities | ||
Assets | ||
Decommissioning fund investments, gross fair value | 115,332 | 115,337 |
Recurring | Significant Other Observable Inputs (Level 2) | Municipality bonds | ||
Assets | ||
Decommissioning fund investments, gross fair value | 81,932 | 80,997 |
Recurring | Significant Other Observable Inputs (Level 2) | Other | ||
Assets | ||
Decommissioning fund investments, gross fair value | 22,715 | 22,132 |
Recurring | Significant Unobservable Inputs (a) (Level 3) | ||
Assets | ||
Gross derivative assets | 9,416 | 11,076 |
Gross assets, fair value disclosure | 9,416 | 11,076 |
Liabilities | ||
Gross derivative liability | $ (51,101) | $ (58,482) |
Fair Value Measurements - Signi
Fair Value Measurements - Significant Unobservable Inputs Used to Value Level 3 Instruments (Details 2) $ in Thousands | 3 Months Ended | 12 Months Ended |
Mar. 31, 2017USD ($)$ / MMBTU$ / MWh | Dec. 31, 2016USD ($)$ / MMBTU$ / MWh | |
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments | ||
Assets | $ 9,416 | $ 11,076 |
Liabilities | 51,101 | 58,482 |
Electricity forward contracts | ||
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments | ||
Assets | 8,805 | 10,648 |
Liabilities | $ 30,313 | $ 32,042 |
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 | 16.65 | 16.43 |
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 | 36.64 | 41.07 |
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 | 27.96 | 29.86 |
Natural gas forward contracts | ||
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments | ||
Assets | $ 611 | $ 428 |
Liabilities | $ 20,788 | $ 26,440 |
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 | 2.07 | 2.32 |
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 | 2.80 | 3.60 |
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 | 2.42 | 2.81 |
Fair Value Measurements - Level
Fair Value Measurements - Level 3 Rollforward Derivatives (Details) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward] | ||
Net derivative balance at beginning of period | $ (47,406) | $ (32,979) |
Included in OCI | 0 | 0 |
Deferred as a regulatory asset or liability | (11,755) | (9,103) |
Settlements | 1,423 | 1,765 |
Transfers into Level 3 from Level 2 | (38) | 262 |
Transfers from Level 3 into Level 2 | 16,091 | 548 |
Net derivative balance at end of period | (41,685) | (39,507) |
Net unrealized gains included in earnings related to instruments still held at end of period | $ 0 | $ 0 |
Nuclear Decommissioning Trust60
Nuclear Decommissioning Trusts (Details) - USD ($) $ in Thousands | 3 Months Ended | ||
Mar. 31, 2017 | Mar. 31, 2016 | Dec. 31, 2016 | |
Nuclear decommissioning trust fund assets | |||
Fair Value | $ 805,048 | $ 779,586 | |
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds | |||
Proceeds from the sale of securities | 151,126 | $ 141,809 | |
Fair value of fixed income securities, summarized by contractual maturities | |||
Total | 805,048 | 779,586 | |
Arizona Public Service Company | |||
Nuclear decommissioning trust fund assets | |||
Fair Value | 805,048 | 779,586 | |
Unrealized Gains | 217,730 | 197,911 | |
Unrealized Losses | (3,963) | (4,962) | |
Net receivables for securities purchases | 337 | 795 | |
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds | |||
Realized gains | 2,367 | 2,438 | |
Realized losses | (2,453) | (1,786) | |
Proceeds from the sale of securities | 151,126 | $ 141,809 | |
Fair value of fixed income securities, summarized by contractual maturities | |||
Total | 805,048 | 779,586 | |
Arizona Public Service Company | Equity Securities | |||
Nuclear decommissioning trust fund assets | |||
Fair Value | 374,695 | 353,261 | |
Unrealized Gains | 207,708 | 188,091 | |
Unrealized Losses | 0 | 0 | |
Fair value of fixed income securities, summarized by contractual maturities | |||
Total | 374,695 | 353,261 | |
Arizona Public Service Company | Fixed income securities. | |||
Nuclear decommissioning trust fund assets | |||
Fair Value | 430,016 | 425,530 | |
Unrealized Gains | 10,022 | 9,820 | |
Unrealized Losses | (3,963) | (4,962) | |
Fair value of fixed income securities, summarized by contractual maturities | |||
Less than one year | 12,143 | ||
1 year – 5 years | 117,217 | ||
5 years – 10 years | 114,131 | ||
Greater than 10 years | 186,525 | ||
Total | $ 430,016 | $ 425,530 |
Changes in Accumulated Other 61
Changes in Accumulated Other Comprehensive Loss (Details) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | ||
Balance at beginning of period | $ 4,935,912 | $ 4,719,457 |
Total other comprehensive income | 959 | 978 |
Balance at end of period | 4,965,940 | 4,740,413 |
AOCI Including Portion Attributable to Noncontrolling Interest | ||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | ||
Balance at beginning of period | (43,822) | (44,748) |
Balance at end of period | (42,863) | (43,770) |
Accumulated Net Gain (Loss) from Cash Flow Hedges Including Portion Attributable to Noncontrolling Interest | ||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | ||
OCI (loss) before reclassifications | (770) | (693) |
Amounts reclassified from accumulated other comprehensive loss | 1,207 | 1,141 |
Total other comprehensive income | 437 | 448 |
Accumulated Defined Benefit Plans Adjustment Including Portion Attributable to Noncontrolling Interest | ||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | ||
Amounts reclassified from accumulated other comprehensive loss | 522 | 530 |
Total other comprehensive income | 522 | 530 |
Arizona Public Service Company | ||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | ||
Balance at beginning of period | 5,037,970 | 4,814,794 |
Total other comprehensive income | 1,048 | 1,059 |
Balance at end of period | 5,067,052 | 4,827,980 |
Arizona Public Service Company | AOCI Including Portion Attributable to Noncontrolling Interest | ||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | ||
Balance at beginning of period | (25,423) | (27,097) |
Balance at end of period | (24,375) | (26,038) |
Arizona Public Service Company | Accumulated Net Gain (Loss) from Cash Flow Hedges Including Portion Attributable to Noncontrolling Interest | ||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | ||
OCI (loss) before reclassifications | (770) | (693) |
Amounts reclassified from accumulated other comprehensive loss | 1,207 | 1,141 |
Total other comprehensive income | 437 | 448 |
Arizona Public Service Company | Accumulated Defined Benefit Plans Adjustment Including Portion Attributable to Noncontrolling Interest | ||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | ||
Amounts reclassified from accumulated other comprehensive loss | 611 | 611 |
Total other comprehensive income | $ 611 | $ 611 |