Document and Entity Information
Document and Entity Information - shares | 6 Months Ended | |
Jun. 30, 2016 | Aug. 01, 2016 | |
Document and Entity Information [Abstract] | ||
Entity Registrant Name | XCEL ENERGY INC | |
Entity Central Index Key | 72,903 | |
Current Fiscal Year End Date | --12-31 | |
Entity Well-known Seasoned Issuer | Yes | |
Entity Voluntary Filers | No | |
Entity Current Reporting Status | Yes | |
Entity Filer Category | Large Accelerated Filer | |
Entity Common Stock, Shares Outstanding | 507,952,795 | |
Document Fiscal Year Focus | 2,016 | |
Document Fiscal Period Focus | Q2 | |
Document Type | 10-Q | |
Amendment Flag | false | |
Document Period End Date | Jun. 30, 2016 |
CONSOLIDATED STATEMENTS OF INCO
CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) - USD ($) shares in Thousands, $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2016 | Jun. 30, 2015 | Jun. 30, 2016 | Jun. 30, 2015 | |
Operating revenues | ||||
Electric | $ 2,224,142 | $ 2,213,460 | $ 4,409,261 | $ 4,438,323 |
Natural gas | 258,899 | 284,131 | 824,588 | 1,000,127 |
Other | 16,808 | 17,543 | 38,273 | 38,903 |
Total operating revenues | 2,499,849 | 2,515,134 | 5,272,122 | 5,477,353 |
Operating expenses | ||||
Electric fuel and purchased power | 855,968 | 904,705 | 1,717,820 | 1,854,837 |
Cost of natural gas sold and transported | 90,071 | 126,667 | 402,188 | 599,038 |
Cost of sales — other | 8,332 | 8,164 | 16,577 | 18,213 |
Operating and maintenance expenses | 596,978 | 594,279 | 1,174,388 | 1,180,109 |
Conservation and demand side management program expenses | 55,916 | 54,141 | 113,352 | 107,946 |
Depreciation and amortization | 322,534 | 274,602 | 642,554 | 547,700 |
Taxes (other than income taxes) | 138,469 | 129,731 | 283,792 | 266,357 |
Loss on Monticello life cycle management/extended power uprate project | 0 | 0 | 0 | 129,463 |
Total operating expenses | 2,068,268 | 2,092,289 | 4,350,671 | 4,703,663 |
Operating income | 431,581 | 422,845 | 921,451 | 773,690 |
Other income, net | 1,560 | 961 | 5,810 | 4,122 |
Equity earnings of unconsolidated subsidiaries | 9,617 | 8,422 | 22,799 | 16,198 |
Allowance for funds used during construction — equity | 14,730 | 12,641 | 27,843 | 25,301 |
Interest charges and financing costs | ||||
Interest charges — includes other financing costs of $6,630 $5,861, $12,966 and $11,559, respectively | 162,980 | 144,222 | 319,423 | 289,162 |
Allowance for funds used during construction — debt | (6,684) | (6,165) | (12,674) | (12,309) |
Total interest charges and financing costs | 156,296 | 138,057 | 306,749 | 276,853 |
Income before income taxes | 301,192 | 306,812 | 671,154 | 542,458 |
Income taxes | 104,397 | 109,881 | 233,047 | 193,461 |
Net income | $ 196,795 | $ 196,931 | $ 438,107 | $ 348,997 |
Weighted average common shares outstanding: | ||||
Basic (in shares) | 508,930 | 507,707 | 508,789 | 507,359 |
Diluted (in shares) | 509,490 | 508,074 | 509,311 | 507,747 |
Earnings per average common share: | ||||
Basic (in dollars per share) | $ 0.39 | $ 0.39 | $ 0.86 | $ 0.69 |
Diluted (in dollars per share) | 0.39 | 0.39 | 0.86 | 0.69 |
Cash dividends declared per common share (in dollars per share) | $ 0.34 | $ 0.32 | $ 0.68 | $ 0.64 |
CONSOLIDATED STATEMENTS OF INC3
CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) (Parenthetical) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2016 | Jun. 30, 2015 | Jun. 30, 2016 | Jun. 30, 2015 | |
Interest charges and financing costs | ||||
Other financing costs | $ 6,630 | $ 5,861 | $ 12,966 | $ 11,559 |
CONSOLIDATED STATEMENTS OF COMP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2016 | Jun. 30, 2015 | Jun. 30, 2016 | Jun. 30, 2015 | |
Comprehensive income: | ||||
Net income | $ 196,795 | $ 196,931 | $ 438,107 | $ 348,997 |
Pension and retiree medical benefits: | ||||
Amortization of losses included in net periodic benefit cost, net of tax of $550, $561, $407 and $1,130, respectively | 865 | 883 | 1,076 | 1,759 |
Derivative instruments: | ||||
Net fair value increase, net of tax of $7, $11, $5 and $4, respectively | 12 | 18 | 8 | 7 |
Reclassification of losses to net income, net of tax of $594, $382, $1,198 and $764, respectively | 936 | 600 | 1,874 | 1,185 |
Total derivative instruments, net of tax | 948 | 618 | 1,882 | 1,192 |
Marketable securities: | ||||
Net fair value increase, net of tax of $0, $1, $0 and $1, respectively | 0 | 1 | 0 | 2 |
Other comprehensive income | 1,813 | 1,502 | 2,958 | 2,953 |
Comprehensive income | $ 198,608 | $ 198,433 | $ 441,065 | $ 351,950 |
CONSOLIDATED STATEMENTS OF COM5
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) (Parenthetical) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2016 | Jun. 30, 2015 | Jun. 30, 2016 | Jun. 30, 2015 | |
Pension and retiree medical benefits: | ||||
Amortization of losses included in net periodic benefit cost, tax | $ 550 | $ 561 | $ 407 | $ 1,130 |
Derivative instruments: | ||||
Net fair value increase (decrease), tax | 7 | 11 | 5 | 4 |
Reclassification of losses to net income, tax | 594 | 382 | 1,198 | 764 |
Marketable securities: | ||||
Net fair value increase (decrease), tax | $ 0 | $ 1 | $ 0 | $ 1 |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) - USD ($) $ in Thousands | 6 Months Ended | |
Jun. 30, 2016 | Jun. 30, 2015 | |
Operating activities | ||
Net income | $ 438,107 | $ 348,997 |
Adjustments to reconcile net income to cash provided by operating activities: | ||
Depreciation and amortization | 650,336 | 556,420 |
Conservation and demand side management program amortization | 2,323 | 2,901 |
Nuclear fuel amortization | 58,267 | 49,454 |
Deferred income taxes | 252,889 | 191,164 |
Amortization of investment tax credits | (2,613) | (2,768) |
Allowance for equity funds used during construction | (27,843) | (25,301) |
Equity earnings of unconsolidated subsidiaries | (22,799) | (16,198) |
Dividends from unconsolidated subsidiaries | 22,910 | 19,754 |
Share-based compensation expense | 24,454 | 21,420 |
Loss on Monticello life cycle management/extended power uprate project | 0 | 129,463 |
Net realized and unrealized hedging and derivative transactions | 3,903 | 13,450 |
Other | (388) | 0 |
Changes in operating assets and liabilities: | ||
Accounts receivable | 35,042 | 150,283 |
Accrued unbilled revenues | 65,159 | 145,781 |
Inventories | 81,880 | 64,561 |
Other current assets | 69,493 | 69,080 |
Accounts payable | 27,805 | (132,032) |
Net regulatory assets and liabilities | 34,264 | 129,595 |
Other current liabilities | (164,076) | (92,108) |
Pension and other employee benefit obligations | (108,562) | (78,681) |
Change in other noncurrent assets | (6,363) | 684 |
Change in other noncurrent liabilities | (21,649) | (36,874) |
Net cash provided by operating activities | 1,412,539 | 1,509,045 |
Investing activities | ||
Utility capital/construction expenditures | (1,413,129) | (1,477,959) |
Proceeds from insurance recoveries | 1,595 | 27,237 |
Allowance for equity funds used during construction | 27,843 | 25,301 |
Purchases of investment securities | (319,880) | (640,100) |
Proceeds from the sale of investment securities | 262,321 | 636,669 |
Investments in WYCO Development LLC and other | (2,170) | (764) |
Other, net | 100 | (1,407) |
Net cash used in investing activities | (1,443,320) | (1,431,023) |
Financing activities | ||
Repayments of short-term borrowings, net | (399,000) | (568,500) |
Proceeds from issuance of long-term debt | 1,337,430 | 841,534 |
Repayments of long-term debt | (579,976) | (454) |
Proceeds from issuance of common stock | 0 | 3,409 |
Purchase of common stock for settlement of equity awards | (789) | 0 |
Dividends paid | (335,113) | (298,022) |
Net cash provided by (used in) financing activities | 22,552 | (22,033) |
Net change in cash and cash equivalents | (8,229) | 55,989 |
Cash and cash equivalents at beginning of period | 84,940 | 79,608 |
Cash and cash equivalents at end of period | 76,711 | 135,597 |
Supplemental disclosure of cash flow information: | ||
Cash paid for interest (net of amounts capitalized) | (293,954) | (266,840) |
Cash received for income taxes, net | 61,345 | 58,598 |
Supplemental disclosure of non-cash investing and financing transactions: | ||
Property, plant and equipment additions in accounts payable | 252,370 | 206,540 |
Issuance of common stock for reinvested dividends and 401(k) plans | $ 13,497 | $ 30,498 |
CONSOLIDATED BALANCE SHEETS (UN
CONSOLIDATED BALANCE SHEETS (UNAUDITED) - USD ($) $ in Thousands | Jun. 30, 2016 | Dec. 31, 2015 |
Current assets | ||
Cash and cash equivalents | $ 76,711 | $ 84,940 |
Accounts receivable, net | 689,564 | 724,606 |
Accrued unbilled revenues | 589,708 | 654,867 |
Inventories | 526,785 | 608,584 |
Regulatory assets | 325,690 | 344,630 |
Derivative instruments | 46,953 | 33,842 |
Deferred income taxes | 206,644 | 140,219 |
Prepaid taxes | 115,898 | 163,023 |
Prepayments and other | 126,146 | 155,734 |
Total current assets | 2,704,099 | 2,910,445 |
Property, plant and equipment, net | 31,823,282 | 31,205,851 |
Other assets | ||
Nuclear decommissioning fund and other investments | 1,987,474 | 1,902,995 |
Regulatory assets | 2,886,250 | 2,858,741 |
Derivative instruments | 50,644 | 51,083 |
Other | 38,415 | 32,581 |
Total other assets | 4,962,783 | 4,845,400 |
Total assets | 39,490,164 | 38,961,696 |
Current liabilities | ||
Current portion of long-term debt | 710,151 | 657,021 |
Short-term debt | 447,000 | 846,000 |
Accounts payable | 921,973 | 960,982 |
Regulatory liabilities | 279,755 | 306,830 |
Taxes accrued | 330,398 | 438,189 |
Accrued interest | 169,309 | 166,829 |
Dividends payable | 172,704 | 162,410 |
Derivative instruments | 26,542 | 29,839 |
Other | 448,549 | 490,197 |
Total current liabilities | 3,506,381 | 4,058,297 |
Deferred credits and other liabilities | ||
Deferred income taxes | 6,619,681 | 6,293,661 |
Deferred investment tax credits | 65,806 | 68,419 |
Regulatory liabilities | 1,343,889 | 1,332,889 |
Asset retirement obligations | 2,671,320 | 2,608,562 |
Derivative instruments | 156,357 | 168,311 |
Customer advances | 212,565 | 228,999 |
Pension and employee benefit obligations | 825,614 | 941,002 |
Other | 280,647 | 261,756 |
Total deferred credits and other liabilities | 12,175,879 | 11,903,599 |
Commitments and contingencies | ||
Capitalization | ||
Long-term debt | 13,104,770 | 12,398,880 |
Common stock — 1,000,000,000 shares authorized of $2.50 par value; 507,952,795 and 507,535,523 shares outstanding at June 30, 2016 and Dec. 31, 2015, respectively | 1,269,882 | 1,268,839 |
Additional paid in capital | 5,896,394 | 5,889,106 |
Retained earnings | 3,643,653 | 3,552,728 |
Accumulated other comprehensive loss | (106,795) | (109,753) |
Total common stockholders’ equity | 10,703,134 | 10,600,920 |
Total liabilities and equity | $ 39,490,164 | $ 38,961,696 |
CONSOLIDATED BALANCE SHEETS (U8
CONSOLIDATED BALANCE SHEETS (UNAUDITED) (Parenthetical) - $ / shares | Jun. 30, 2016 | Dec. 31, 2015 |
Capitalization | ||
Common stock, shares authorized (in shares) | 1,000,000,000 | 1,000,000,000 |
Common stock, par value (in dollars per share) | $ 2.50 | $ 2.50 |
Common stock, shares outstanding (in shares) | 507,952,795 | 507,535,523 |
CONSOLIDATED STATEMENTS OF COMM
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY (UNAUDITED) - USD ($) $ in Thousands | Total | Common Stock | Additional Paid In Capital | Retained Earnings | Accumulated Other Comprehensive Loss |
Beginning balance at Dec. 31, 2014 | $ 10,214,482 | $ 1,264,333 | $ 5,837,330 | $ 3,220,958 | $ (108,139) |
Balance (in shares) at Dec. 31, 2014 | 505,733,000 | ||||
Increase (Decrease) in Stockholders' Equity | |||||
Net income | 348,997 | 348,997 | |||
Other comprehensive income | 2,953 | 2,953 | |||
Dividends declared on common stock | (326,310) | (326,310) | |||
Issuances of common stock | 13,274 | $ 3,065 | 10,209 | ||
Issuances of common stock (in shares) | 1,226,000 | ||||
Share-based compensation | 15,670 | 15,670 | |||
Ending balance at Jun. 30, 2015 | 10,269,066 | $ 1,267,398 | 5,863,209 | 3,243,645 | (105,186) |
Balance (in shares) at Jun. 30, 2015 | 506,959,000 | ||||
Beginning balance at Mar. 31, 2015 | 10,214,870 | $ 1,266,659 | 5,844,995 | 3,209,904 | (106,688) |
Balance (in shares) at Mar. 31, 2015 | 506,664,000 | ||||
Increase (Decrease) in Stockholders' Equity | |||||
Net income | 196,931 | 196,931 | |||
Other comprehensive income | 1,502 | 1,502 | |||
Dividends declared on common stock | (163,190) | (163,190) | |||
Issuances of common stock | 10,055 | $ 739 | 9,316 | ||
Issuances of common stock (in shares) | 295,000 | ||||
Share-based compensation | 8,898 | 8,898 | |||
Ending balance at Jun. 30, 2015 | 10,269,066 | $ 1,267,398 | 5,863,209 | 3,243,645 | (105,186) |
Balance (in shares) at Jun. 30, 2015 | 506,959,000 | ||||
Beginning balance at Dec. 31, 2015 | $ 10,600,920 | $ 1,268,839 | 5,889,106 | 3,552,728 | (109,753) |
Balance (in shares) at Dec. 31, 2015 | 507,535,523 | 507,536,000 | |||
Increase (Decrease) in Stockholders' Equity | |||||
Net income | $ 438,107 | 438,107 | |||
Other comprehensive income | 2,958 | 2,958 | |||
Dividends declared on common stock | (347,182) | (347,182) | |||
Issuances of common stock | (2,899) | $ 1,043 | (3,942) | ||
Purchase of common stock for settlement of equity awards | (789) | (789) | |||
Issuances of common stock (in shares) | 417,000 | ||||
Share-based compensation | 12,019 | 12,019 | |||
Ending balance at Jun. 30, 2016 | $ 10,703,134 | $ 1,269,882 | 5,896,394 | 3,643,653 | (106,795) |
Balance (in shares) at Jun. 30, 2016 | 507,952,795 | 507,953,000 | |||
Beginning balance at Mar. 31, 2016 | $ 10,671,634 | $ 1,269,882 | 5,889,939 | 3,620,421 | (108,608) |
Balance (in shares) at Mar. 31, 2016 | 507,953,000 | ||||
Increase (Decrease) in Stockholders' Equity | |||||
Net income | 196,795 | 196,795 | |||
Other comprehensive income | 1,813 | 1,813 | |||
Dividends declared on common stock | (173,563) | (173,563) | |||
Issuances of common stock | (187) | $ 0 | (187) | ||
Issuances of common stock (in shares) | 0 | ||||
Share-based compensation | 6,642 | 6,642 | |||
Ending balance at Jun. 30, 2016 | $ 10,703,134 | $ 1,269,882 | $ 5,896,394 | $ 3,643,653 | $ (106,795) |
Balance (in shares) at Jun. 30, 2016 | 507,952,795 | 507,953,000 |
Management's Opinion
Management's Opinion | 6 Months Ended |
Jun. 30, 2016 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Management's Opinion | In the opinion of management, the accompanying unaudited consolidated financial statements contain all adjustments necessary to present fairly, in accordance with accounting principles generally accepted in the United States of America (GAAP), the financial position of Xcel Energy Inc. and its subsidiaries as of June 30, 2016 and Dec. 31, 2015 ; the results of its operations, including the components of net income and comprehensive income, and changes in stockholders’ equity for the three and six months ended June 30, 2016 and 2015 ; and its cash flows for the six months ended June 30, 2016 and 2015 . All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after June 30, 2016 up to the date of issuance of these consolidated financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation. The Dec. 31, 2015 balance sheet information has been derived from the audited 2015 consolidated financial statements included in the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, 2015 . These notes to the consolidated financial statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with GAAP on an annual basis have been condensed or omitted pursuant to such rules and regulations. For further information, refer to the consolidated financial statements and notes thereto, included in the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, 2015 , filed with the SEC on Feb. 19, 2016. Due to the seasonality of Xcel Energy’s electric and natural gas sales, interim results are not necessarily an appropriate base from which to project annual results. |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 6 Months Ended |
Jun. 30, 2016 | |
Accounting Policies [Abstract] | |
Summary of Significant Accounting Policies | Summary of Significant Accounting Policies The significant accounting policies set forth in Note 1 to the consolidated financial statements in the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, 2015 , appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference. |
Accounting Pronouncements
Accounting Pronouncements | 6 Months Ended |
Jun. 30, 2016 | |
New Accounting Pronouncements and Changes in Accounting Principles [Abstract] | |
Accounting Pronouncements | Accounting Pronouncements Recently Issued Revenue Recognition — In May 2014, the Financial Accounting Standards Board (FASB) issued Revenue from Contracts with Customers, Topic 606 (Accounting Standards Update (ASU) No. 2014-09) , which provides a framework for the recognition of revenue, with the objective that recognized revenues properly reflect amounts an entity is entitled to receive in exchange for goods and services. The new guidance also includes additional disclosure requirements regarding revenue, cash flows and obligations related to contracts with customers. The guidance is effective for interim and annual reporting periods beginning after Dec. 15, 2017. Xcel Energy is currently evaluating the impact of adopting ASU 2014-09 on its consolidated financial statements. Presentation of Deferred Taxes — In November 2015, the FASB issued Balance Sheet Classification of Deferred Taxes, Topic 740 (ASU No 2015-17) , which eliminates the requirement to present deferred tax assets and liabilities as current and noncurrent on the balance sheet based on the classification of the related asset or liability, and instead requires classification of all deferred tax assets and liabilities as noncurrent. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2016, and early adoption is permitted. Other than the prescribed classification of all deferred tax assets and liabilities as noncurrent, Xcel Energy does not expect the implementation of ASU 2015-17 to have a material impact on its consolidated financial statements. Classification and Measurement of Financial Instruments — In January 2016, the FASB issued Recognition and Measurement of Financial Assets and Financial Liabilities, Subtopic 825-10 (ASU No. 2016-01) , which among other changes in accounting and disclosure requirements, replaces the cost method of accounting for non-marketable equity securities with a model for recognizing impairments and observable price changes, and also eliminates the available-for-sale classification for marketable equity securities. Under the new guidance, other than when the consolidation or equity method of accounting is utilized, changes in the fair value of equity securities are to be recognized in earnings. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2017. Xcel Energy is currently evaluating the impact of adopting ASU 2016-01 on its consolidated financial statements. Leases — In February 2016, the FASB issued Leases, Topic 842 (ASU No. 2016-02) , which, for lessees, requires balance sheet recognition of right-of-use assets and lease liabilities for all leases. Additionally, for leases that qualify as finance leases, the guidance requires expense recognition consisting of amortization of the right-of-use asset as well as interest on the related lease liability using the effective interest method. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2018, and early adoption is permitted. Xcel Energy is currently evaluating the impact of adopting ASU 2016-02 on its consolidated financial statements. Stock Compensation — In March 2016, the FASB issued Improvements to Employee Share-Based Payment Accounting, Topic 718 (ASU 2016-09), which amends existing guidance to simplify several aspects of accounting and presentation for share-based payment transactions, including the accounting for income taxes and forfeitures, as well as presentation in the statement of cash flows. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2016, and early adoption is permitted. Xcel Energy does not expect the implementation of ASU 2016-09 to have a material impact on its consolidated financial statements. Recently Adopted Consolidation — In February 2015, the FASB issued Amendments to the Consolidation Analysis, Topic 810 (ASU No. 2015-02) , which reduces the number of consolidation models and amends certain consolidation principles related to variable interest entities. Xcel Energy implemented the guidance on Jan. 1, 2016, and other than the classification of certain real estate investments held within the Nuclear Decommissioning Trust as non-consolidated variable interest entities, the implementation did not have a significant impact on its consolidated financial statements. Presentation of Debt Issuance Costs — In April 2015, the FASB issued Simplifying the Presentation of Debt Issuance Costs, Subtopic 835-30 (ASU No. 2015-03) , which requires the presentation of debt issuance costs on the balance sheet as a deduction from the carrying amount of the related debt, instead of presentation as an asset. Xcel Energy implemented the new guidance as required on Jan. 1, 2016, and as a result, $94.5 million of deferred debt issuance costs were presented as a deduction from the carrying amount of long-term debt on the consolidated balance sheet as of March 31, 2016, and $91.8 million of such deferred costs were retrospectively reclassified from other non-current assets to long-term debt on the consolidated balance sheet as of Dec. 31, 2015. Fair Value Measurement — In May 2015, the FASB issued Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share (or Its Equivalent), Topic 820 (ASU No. 2015-07), which eliminates the requirement to categorize fair value measurements using a net asset value (NAV) methodology in the fair value hierarchy. Xcel Energy implemented the guidance on Jan. 1, 2016, and the implementation did not have a material impact on its consolidated financial statements. For related disclosures, see Note 8 to the consolidated financial statements. |
Selected Balance Sheet Data
Selected Balance Sheet Data | 6 Months Ended |
Jun. 30, 2016 | |
Balance Sheet Related Disclosures [Abstract] | |
Selected Balance Sheet Data | Selected Balance Sheet Data (Thousands of Dollars) June 30, 2016 Dec. 31, 2015 Accounts receivable, net Accounts receivable $ 735,586 $ 776,494 Less allowance for bad debts (46,022 ) (51,888 ) $ 689,564 $ 724,606 (Thousands of Dollars) June 30, 2016 Dec. 31, 2015 Inventories Materials and supplies $ 304,055 $ 290,690 Fuel 164,054 202,271 Natural gas 58,676 115,623 $ 526,785 $ 608,584 (Thousands of Dollars) June 30, 2016 Dec. 31, 2015 Property, plant and equipment, net Electric plant $ 36,990,529 $ 36,464,050 Natural gas plant 5,065,218 4,944,757 Common and other property 1,746,789 1,709,508 Plant to be retired (a) 29,853 38,249 Construction work in progress 1,687,397 1,256,949 Total property, plant and equipment 45,519,786 44,413,513 Less accumulated depreciation (14,035,591 ) (13,591,259 ) Nuclear fuel 2,461,008 2,447,251 Less accumulated amortization (2,121,921 ) (2,063,654 ) $ 31,823,282 $ 31,205,851 (a) In 2017, PSCo expects to both early retire Valmont Unit 5 and convert Cherokee Unit 4 from a coal-fueled generating facility to natural gas, as approved by the Colorado Public Utilities Commission (CPUC). Amounts are presented net of accumulated depreciation. |
Income Taxes
Income Taxes | 6 Months Ended |
Jun. 30, 2016 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | Income Taxes Except to the extent noted below, Note 6 to the consolidated financial statements included in Xcel Energy Inc.’s Annual Report on Form 10-K for the year ended Dec. 31, 2015 appropriately represents, in all material respects, the current status of other income tax matters, and are incorporated herein by reference. Federal Tax Loss Carryback Claims — In 2012, 2013, 2014 and 2015, Xcel Energy identified certain expenses related to 2009, 2010, 2011, 2013, 2014 and 2015 that qualify for an extended carryback beyond the typical two -year carryback period. As a result of a higher tax rate in prior years, Xcel Energy recognized a tax benefit of approximately $5 million in 2015, $17 million in 2014, $12 million in 2013 and $15 million in 2012. Federal Audit — Xcel Energy files a consolidated federal income tax return. In 2012, the Internal Revenue Service (IRS) commenced an examination of tax years 2010 and 2011 , including the 2009 carryback claim. As of June 30, 2016, the IRS had proposed an adjustment to the federal tax loss carryback claims that would result in $14 million of income tax expense for the 2009 through 2011 and 2013 claims, the recently filed 2014 claim, and the anticipated claim for 2015. In the fourth quarter of 2015, the IRS forwarded the issue to the Office of Appeals (Appeals). In the second quarter of 2016 the IRS audit team presented their case to Appeals; however, the outcome and timing of a resolution is uncertain. The statute of limitations applicable to Xcel Energy’s 2009 through 2011 federal income tax returns expires in December 2016 following an extension to allow additional time for the Appeals process. In the third quarter of 2015, the IRS commenced an examination of tax years 2012 and 2013 . As of June 30, 2016, the IRS had not proposed any material adjustments to tax years 2012 and 2013. State Audits — Xcel Energy files consolidated state tax returns based on income in its major operating jurisdictions of Colorado, Minnesota, Texas, and Wisconsin, and various other state income-based tax returns. As of June 30, 2016, Xcel Energy’s earliest open tax years that are subject to examination by state taxing authorities in its major operating jurisdictions were as follows: State Year Colorado 2009 Minnesota 2009 Texas 2009 Wisconsin 2011 In February 2016, Texas began an audit of years 2009 and 2010 . As of June 30, 2016, Texas had not proposed any adjustments. In June 2016, Minnesota began an audit of years 2010 through 2014 . As of June 30, 2016, Minnesota had not proposed any adjustments. As of June 30, 2016, there were no other state income tax audits in progress. Unrecognized Tax Benefits — The unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the annual effective tax rate (ETR). In addition, the unrecognized tax benefit balance includes temporary tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. A change in the period of deductibility would not affect the ETR but would accelerate the payment of cash to the taxing authority to an earlier period. A reconciliation of the amount of unrecognized tax benefit is as follows: (Millions of Dollars) June 30, 2016 Dec. 31, 2015 Unrecognized tax benefit — Permanent tax positions $ 26.8 $ 25.8 Unrecognized tax benefit — Temporary tax positions 97.6 94.9 Total unrecognized tax benefit $ 124.4 $ 120.7 The unrecognized tax benefit amounts were reduced by the tax benefits associated with net operating loss (NOL) and tax credit carryforwards. The amounts of tax benefits associated with NOL and tax credit carryforwards are as follows: (Millions of Dollars) June 30, 2016 Dec. 31, 2015 NOL and tax credit carryforwards $ (40.4 ) $ (36.7 ) It is reasonably possible that Xcel Energy’s amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS Appeals and audit progress, the Minnesota and Texas audits progress, and other state audits resume. As the IRS Appeals and IRS, Minnesota, and Texas audits progress, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $58 million . The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. The payables for interest related to unrecognized tax benefits at June 30, 2016 and Dec. 31, 2015 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of June 30, 2016 or Dec. 31, 2015. |
Rate Matters
Rate Matters | 6 Months Ended |
Jun. 30, 2016 | |
Public Utilities, General Disclosures [Abstract] | |
Rate Matters | Rate Matters Except to the extent noted below, the circumstances set forth in Note 12 to the consolidated financial statements included in Xcel Energy Inc.’s Annual Report on Form 10-K for the year ended Dec. 31, 2015 and in Note 5 to Xcel Energy Inc.’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2016, appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference. NSP-Minnesota Pending and Recently Concluded Regulatory Proceedings — Minnesota Public Utilities Commission ( MPUC) Minnesota 2016 Multi-Year Electric Rate Case — In November 2015, NSP-Minnesota filed a three -year electric rate case with the MPUC. The rate case is based on a requested return on equity (ROE) of 10.0 percent and a 52.50 percent equity ratio. The request is detailed in the table below: Request (Millions of Dollars) 2016 2017 2018 Rate request $ 194.6 $ 52.1 $ 50.4 Increase percentage 6.4 % 1.7 % 1.7 % Interim request $ 163.7 $ 44.9 N/A Rate base $ 7,800 $ 7,700 $ 7,700 In December 2015, the MPUC approved interim rates for 2016. Intervenor Testimony: In June 2016, intervening parties filed direct testimony proposing modifications to NSP-Minnesota’s rate request. The Minnesota Department of Commerce (DOC) subsequently filed revised testimony recommending an increase of approximately $45.6 million in 2016, a step increase of $53.8 million for 2017, and a step decrease of $5.0 million for 2018, based on a recommended ROE of 9.06 percent and an equity ratio of 52.50 percent . Based on NSP-Minnesota’s interpretation of the DOC’s testimony, certain recommended adjustments of approximately $72.7 million would not be expected to impact earnings, assuming MPUC approval. The following table summarizes NSP-Minnesota’s estimate of the DOC’s recommendations: (Millions of Dollars) 2016 2017 Step 2018 Step Total Filed rate request $ 194.6 $ 52.1 $ 50.4 $ 297.1 DOC recommended adjustments: ROE (65.0 ) 0.3 1.0 (63.7 ) Sales forecast (39.4 ) — — (39.4 ) Property tax (5.2 ) (0.3 ) (0.1 ) (5.6 ) Depreciation life (8.0 ) 0.4 (2.2 ) (9.8 ) Purchased demand timing changes — — (19.4 ) (19.4 ) Nuclear capital costs (3.6 ) 0.8 (11.2 ) (14.0 ) Tax related items (12.2 ) 18.4 (6.9 ) (0.7 ) Operating and maintenance (O&M) (15.5 ) (17.8 ) (16.7 ) (50.0 ) Other, net (0.1 ) (0.1 ) 0.1 (0.1 ) Total DOC Adjustments (149.0 ) 1.7 (55.4 ) (202.7 ) Total DOC recommended rate increase $ 45.6 $ 53.8 $ (5.0 ) $ 94.4 Estimated non-earnings DOC adjustments: Depreciation life 8.0 (0.4 ) 2.2 9.8 Sales forecast 37.4 — — 37.4 Property tax 5.2 0.3 0.1 5.6 Purchased demand timing changes — — 19.4 19.4 Other 0.5 — — 0.5 Total estimated non-earnings adjustments 51.1 (0.1 ) 21.7 72.7 Total pre-tax earnings impact $ 96.7 $ 53.7 $ 16.7 $ 167.1 The DOC also presented several nuclear recommendations related to capital recovery for spent fuel storage investments and Prairie Island LCM projects. • The use of certificate of need estimates as a recovery cap, and/or provisionally exclude recovery of amounts in excess of the cap unless the costs are deemed reasonable by the DOC’s nuclear consultant and/or the MPUC. • No recovery of a portion of capital costs associated with Monticello fuel storage Cask 16, representing the amount beyond the originally anticipated project cost, or approximately $15 million . The additional costs incurred were for testing of cask lid welds to demonstrate compliance with Nuclear Regulatory Commission requirements. Settlement Agreement In August 2016, NSP-Minnesota reached a settlement in principal with several of the parties, which resolves all revenue requirement issues in dispute. The terms and conditions of the agreement are still subject to final documentation. The settlement agreement requires the approval of the MPUC. The next steps in the procedural schedule are expected to be as follows: • Rebuttal testimony — Aug. 9, 2016; • Surrebuttal testimony — Sept. 16, 2016; • Settlement conference — Sept. 26, 2016; • Evidentiary hearing — Oct. 4-7, 2016; • Administrative Law Judge report — Feb. 21, 2017; and • MPUC order — June 1, 2017. A current liability representing NSP-Minnesota’s best estimate of a refund obligation for 2016 associated with interim rates was recorded as of June 30, 2016. NSP-Minnesota – Gas Utility Infrastructure Costs (GUIC) Rider — In July 2016, the MPUC verbally approved NSP-Minnesota’s request to recover approximately $15 million in natural gas infrastructure costs through the GUIC Rider, based on NSP-Minnesota’s proposed capital structure and a ROE of 9.64 percent , as proposed by the DOC. Recovery was approved for the 15 -month period from January 2016 to March 2017. Annual Automatic Adjustment (AAA) of Charges — In June 2016, the DOC recommended the MPUC should hold utilities responsible for incremental costs of replacement power incurred due to unplanned outages at nuclear facilities under certain circumstances. As it pertains to NSP-Minnesota, the DOC’s recommendation could impact replacement power cost recovery for the Prairie Island (PI) nuclear facility outages allocated to the Minnesota jurisdiction during the 2015 AAA fiscal year. NSP-Minnesota expects a MPUC decision in mid-2017. Nuclear Project Prudence Investigation — In 2013, NSP-Minnesota completed the Monticello LCM/extended power uprate (EPU) project. The multi-year project extended the life of the facility and increased the capacity from 600 to 671 megawatts (MW) in 2015. The Monticello LCM/EPU project expenditures were approximately $665 million . Total capitalized costs were approximately $748 million , which includes allowance for funds used during construction (AFUDC). In 2008, project expenditures were initially estimated at approximately $320 million , excluding AFUDC. In 2013, the MPUC initiated an investigation to determine whether the final costs for the Monticello LCM/EPU project were prudent. In March 2015, the MPUC voted to allow for full recovery, including a return, on approximately $415 million of the total plant costs (inclusive of AFUDC), but only allow recovery of the remaining $333 million of costs with no return on this portion of the investment over the remaining life of the plant. Further, the MPUC determined that only 50 percent of the investment was considered used-and-useful for 2014. As a result of these determinations, Xcel Energy recorded an estimated pre-tax loss of $129 million in the first quarter of 2015, after which the remaining book value of the Monticello project represented the present value of the estimated future cash flows. NSP-Wisconsin Pending Regulatory Proceedings — Public Service Commission of Wisconsin (PSCW) Wisconsin 2017 Electric and Gas Rate Case — In April 2016, NSP-Wisconsin filed a request with the PSCW for an increase in annual electric rates of $17.4 million , or 2.4 percent , and an increase in natural gas rates by $4.8 million , or 3.9 percent , effective January 2017. The following table outlines the filed request: Electric Rate Request (Millions of Dollars) Request Rate base investments $ 11.0 Generation and transmission expenses (excluding fuel and purchased power) 6.8 Fuel and purchased power expenses 11.0 Subtotal 28.8 2015 fuel refund (a) (9.5 ) DOE settlement refund (1.9 ) Total electric rate increase $ 17.4 (a) In July 2016, the PSCW required NSP-Wisconsin to return the 2015 fuel refund directly to customers, rather than using it to offset the proposed 2017 rate increase, as originally proposed by NSP-Wisconsin. This decision effectively increases NSP-Wisconsin’s requested electric rate increase to $26.9 million , or 3.8 percent . The electric rate request is for the limited purpose of recovering increases in (1) generation and transmission fixed charges and fuel and purchased power expenses related to the interchange agreement with NSP-Minnesota, and (2) costs associated with forecasted average rate base of $1.188 billion in 2017. The natural gas rate request is for the limited purpose of recovering expenses related to the ongoing environmental remediation of a former manufactured gas plant (MGP) site and adjacent area in Ashland, Wis. No changes are being requested to the capital structure or the 10.0 percent ROE authorized by the PSCW in the 2016 rate case. As part of an agreement with stakeholders to limit the size and scope of the case, NSP-Wisconsin also agreed to an earnings cap, solely for 2017, in which 100 percent of the earnings in excess of the authorized ROE would be refunded to customers. Key dates in the procedural schedule are as follows: • Staff and intervenor direct testimony — Aug. 12, 2016; • Rebuttal testimony — Aug. 26, 2016; • Surrebuttal testimony — Sept. 2, 2016; • Hearing — Sept. 7, 2016; • Initial brief due — Sept. 21, 2016; • Reply brief due — Sept. 28, 2016; and • A final PSCW decision is anticipated in the fourth quarter of 2016 with final rates effective in January 2017. PSCo Pending Regulatory Proceedings — CPUC Annual Electric Earnings Tests — As part of an annual earnings test, PSCo must share with customers earnings that exceed the authorized ROE threshold of 9.83 percent for 2015 through 2017. In April 2016, PSCo filed the 2015 earnings test, proposing an electric customer refund obligation of $14.9 million , which was approved by the CPUC in July 2016. The proposed refund obligation related to the 2015 earnings test was accrued for as of June 30, 2016. The current estimate of the 2016 earnings test, based on annual forecasted information, did not result in the recognition of a liability as of June 30, 2016. SPS Pending Regulatory Proceedings — Public Utility Commission of Texas (PUCT) Appeal of the Texas 2015 Electric Rate Case Decision — In April 2016, SPS filed an appeal, with the Texas State District Court, of the PUCT’s order that had denied SPS’ request for rehearing on certain items in SPS’ Texas 2015 electric rate case related to capital structure, incentive compensation and wholesale load reductions. In 2014, SPS had requested an overall retail electric revenue rate increase of $64.8 million , which it subsequently revised to $42.1 million . In 2015, the PUCT approved an overall rate decrease of approximately $4.0 million , net of rate case expenses. The hearing in the appeal is scheduled for February 2017. Texas 2015 Electric Rate Net Refund Case — Under an agreement in the Texas 2015 electric rate case, the final rates were retroactively applied to June 11, 2015. In June 2016, SPS filed an application to provide a net refund of approximately $1.25 million to reflect the difference in revenue SPS would have received for usage had SPS been charging the final rates approved by the PUCT from June 11, 2015 through Jan. 31, 2016. SPS has proposed to make the net refund over a six -month period beginning October 2016. The application is pending before the PUCT. Texas 2016 Electric Rate Case — In February 2016, SPS filed a retail electric, non-fuel rate case in Texas with each of its Texas municipalities and the PUCT requesting an overall increase in annual base rate revenue of approximately $71.9 million , or 14.4 percent . The filing is based on a historic test year (HTY) ended Sept. 30, 2015, a requested ROE of 10.25 percent , an electric rate base of approximately $1.7 billion , and an equity ratio of 53.97 percent . In April 2016, SPS revised its requested rate increase to $68.6 million . The following table summarizes the revised net request: (Millions of Dollars) Request Capital expenditure investments $ 38.9 Change in jurisdictional allocation factors 9.8 Changes in ROE and capital structure 11.6 Estimated rate case expenses 4.5 Other, net 3.8 Total $ 68.6 Key dates in the procedural schedule are as follows: • Intervenor direct testimony — Aug. 16, 2016; • PUCT Staff direct testimony — Aug. 23, 2016; • PUCT Staff and Intervenors’ cross-rebuttal testimony — Sept. 7, 2016; • SPS’ rebuttal testimony — Sept. 9, 2016; and • Hearings — Sept. 27 - Oct. 7, 2016. SPS and various parties are having discussions regarding a potential settlement of the rate case. The final rates established at the end of the case are expected to be effective retroactive to July 20, 2016. A PUCT decision is expected in the first quarter of 2017. Pending Regulatory Proceedings — New Mexico Public Regulation Commission (NMPRC) New Mexico 2015 Electric Rate Case — In October 2015, SPS filed an electric rate case with the NMPRC seeking an increase in non-fuel base rates of $45.4 million . The proposed increase would be offset by a decrease in base fuel revenue of approximately $21.1 million . The rate filing is based on a June 30, 2015 HTY adjusted for known and measurable changes, a requested ROE of 10.25 percent , an electric rate base of approximately $734 million and an equity ratio of 53.97 percent . In May 2016, SPS, the NMPRC Staff and all other parties filed a unanimous black-box stipulation that resolves all issues in the case. Under the stipulation, SPS will implement a non-fuel base rate increase of $23.5 million and a decrease in base fuel revenue of approximately $21.1 million . The decrease in base fuel revenue will be reflected in adjustments collected through the fuel and purchased power cost adjustment clause. The stipulation places no restriction on when SPS may file its next base rate case. In July 2016, the hearing examiner issued a recommendation that the NMPRC approve the stipulation. The stipulation is subject to approval by the NMPRC and a decision on the settlement and implementation of final rates is expected in fall of 2016. Pending Regulatory Proceedings — FERC Midcontinent Independent System Operator, Inc. (MISO) ROE Complaints/ROE Adder — In November 2013, a group of customers filed a complaint at the FERC against MISO transmission owners (TOs), including NSP-Minnesota and NSP-Wisconsin. The complaint argued for a reduction in the ROE in transmission formula rates in the MISO region from 12.38 percent to 9.15 percent , a prohibition on capital structures in excess of 50 percent equity, and the removal of ROE adders (including those for regional transmission organization (RTO) membership and being an independent transmission company), effective Nov. 12, 2013. In December 2015, an ALJ initial decision recommended the FERC approve a ROE of 10.32 percent . A FERC order is expected to be issued in late 2016 or in 2017. In February 2015, a second complaint was filed seeking to reduce the MISO region ROE from 12.38 percent to 8.67 percent , prior to any adder. The FERC set the second complaint for hearings, and established a refund effective date of Feb. 12, 2015. The MPUC, the North Dakota Public Service Commission (NDPSC), the South Dakota Public Utilities Commission and the DOC joined a joint complainant/intervenor initial brief recommending an ROE of either 8.82 percent or 8.81 percent . FERC staff recommended a ROE of 8.78 percent . The MISO TOs recommended a ROE of 10.92 percent . On June 30, 2016, the ALJ issued an initial decision recommending a ROE of 9.7 percent , the midpoint of the upper half of the discounted cash flow (DCF) range, with refunds for the 15 month period beginning Feb.12, 2015. A FERC decision is expected in 2017. FERC approved of a 50 basis point ROE adder for RTO membership, effective Jan. 6, 2015, subject to the outcome of the ROE complaint. Under FERC policy, the total ROE including the RTO membership adder cannot exceed the top of the DCF range. NSP-Minnesota has recorded a current liability representing the best estimate of a refund obligation associated with the new ROE, including the RTO membership adder, as of June 30, 2016. The new FERC ROE methodology is estimated to reduce transmission revenue, net of expense, between $8 million and $10 million , annually, for the NSP System. Southwest Power Pool, Inc. (SPP) Open Access Transmission Tariff (OATT) Upgrade Costs — Under the SPP OATT, costs of participant-funded, or “sponsored,” transmission upgrades may be recovered, in part, from other SPP customers whose transmission service depends on capacity enabled by the upgrade. The SPP OATT has allowed SPP to collect charges since 2008, but to date SPP has not charged its customers any amounts attributable to these upgrades. In April 2016, SPP filed a request with the FERC for a waiver that would allow SPP to recover the charges not billed since 2008. The FERC approved the waiver request in July 2016. SPS is considering whether to seek clarification or rehearing of the FERC order. SPP has indicated it anticipates completing its process and invoicing customers during the fourth quarter of 2016. SPS estimates the charges to be $5 million to $10 million , based on preliminary information. SPS anticipates these costs would be recoverable through regulatory mechanisms. |
Commitments and Contingencies
Commitments and Contingencies | 6 Months Ended |
Jun. 30, 2016 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | Commitments and Contingencies Except to the extent noted below and in Note 5 above, the circumstances set forth in Notes 12, 13 and 14 to the consolidated financial statements included in Xcel Energy Inc.’s Annual Report on Form 10-K for the year ended Dec. 31, 2015 , and in Notes 5 and 6 to the consolidated financial statements included in Xcel Energy Inc.’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2016, appropriately represent, in all material respects, the current status of commitments and contingent liabilities, and are incorporated herein by reference. The following include commitments, contingencies and unresolved contingencies that are material to Xcel Energy’s financial position. Purchased Power Agreements (PPAs) Under certain PPAs, NSP-Minnesota, PSCo and SPS purchase power from independent power producing entities for which the utility subsidiaries are required to reimburse natural gas or biomass fuel costs, or to participate in tolling arrangements under which the utility subsidiaries procure the natural gas required to produce the energy that they purchase. These specific PPAs create a variable interest in the associated independent power producing entity. The Xcel Energy utility subsidiaries had approx imate ly 3,467 MW and 3,698 MW of capacity under long-term PPAs as of June 30, 2016 and Dec. 31, 2015 , with entities that have been determined to be variable interest entities. Xcel Energy has concluded that these entities are not required to be consolidated in its consolidated financial statements because it does not have the power to direct the activities that most significantly impact the entities’ economic performance. These agreements have expiration dates through 2033 . Guarantees and Bond Indemnifications Xcel Energy Inc. and its subsidiaries provide guarantees and bond indemnities under specified agreements or transactions. The guarantees and bond indemnities issued by Xcel Energy Inc. guarantee payment or performance by its subsidiaries. As a result, Xcel Energy Inc.’s exposure under the guarantees and bond indemnities is based upon the net liability of the relevant subsidiary under the specified agreements or transactions. Most of the guarantees and bond indemnities issued by Xcel Energy Inc. and its subsidiaries limit the exposure to a maximum amount stated in the guarantees and bond indemnities. As of June 30, 2016 and Dec. 31, 2015 , Xcel Energy Inc. and its subsidiaries had no assets held as collateral related to their guarantees, bond indemnities and indemnification agreements. The following table presents guarantees and bond indemnities issued and outstanding for Xcel Energy: (Millions of Dollars) June 30, 2016 Dec. 31, 2015 Guarantees issued and outstanding $ 15.9 $ 12.5 Current exposure under these guarantees 0.1 0.1 Bonds with indemnity protection 43.0 41.3 Other Indemnification Agreements Xcel Energy Inc. and its subsidiaries provide indemnifications through contracts entered into in the normal course of business. These are primarily indemnifications against adverse litigation outcomes in connection with underwriting agreements, as well as breaches of representations and warranties, including corporate existence, transaction authorization and income tax matters with respect to assets sold. Xcel Energy Inc.’s and its subsidiaries’ obligations under these agreements may be limited in terms of duration and amount. The maximum potential amount of future payments under these indemnifications cannot be reasonably estimated as the obligated amounts of these indemnifications often are not explicitly stated. Environmental Contingencies Ashland MGP Site — NSP-Wisconsin has been named a potentially responsible party (PRP) for contamination at a site in Ashland, Wis. The Ashland/Northern States Power Lakefront Superfund Site (the Site) includes property owned by NSP-Wisconsin, previously operated as a MGP facility (the Upper Bluff), and two other properties: an adjacent city lakeshore park area (Kreher Park); and an area of Lake Superior’s Chequamegon Bay adjoining the park (the Sediments). In 2010, the United States Environmental Protection Agency (EPA) issued its Record of Decision (ROD), including their preferred remedy for the Sediments which is a hybrid remedy involving both dry excavation and wet conventional dredging methodologies (the Hybrid Remedy). A wet conventional dredging only remedy (the Wet Dredge), contingent upon the completion of a successful Wet Dredge pilot study, is another potential remedy. In 2012, under a settlement agreement, NSP-Wisconsin agreed to perform the remediation of the Phase I Project Area (which includes the Upper Bluff and Kreher Park areas of the Site). The excavation and containment remedies are complete, and a long-term groundwater pump and treatment program is now underway. The final design was approved by the EPA in 2015. The current cost estimate for the cleanup of the Phase I Project Area is approximately $71.4 million , of which approximately $51.8 million has already been spent. Negotiations are ongoing between the EPA and NSP-Wisconsin regarding who will pay for or perform the cleanup of the Sediments and which remedy will be implemented. The EPA’s ROD includes estimates that the cost of the Hybrid Remedy is between $63 million and $77 million , with a potential deviation in such estimated costs of up to 50 percent higher or 30 percent lower. NSP-Wisconsin believes the Hybrid Remedy is not safe or feasible to implement. In 2015, NSP-Wisconsin constructed a breakwater at the site to serve as wave attenuation and containment for a wet dredge pilot study and full scale sediment remedy at the site. Equipment mobilization for the wet dredge pilot study commenced in April 2016. The pilot study is expected to conclude in late summer of 2016. The EPA will then determine whether NSP-Wisconsin can perform extended pilot work into early fall of 2016 and whether a full scale wet dredge remedy of the Sediments may be performed beginning as early as 2017. At June 30, 2016 and Dec. 31, 2015, NSP-Wisconsin had recorded a liability of $95.0 million and $94.4 million , respectively, for the Site based upon potential remediation and design costs together with estimated outside legal and consultant costs; of which $18.7 million and $17.0 million , respectively, were considered a current liability. NSP-Wisconsin’s potential liability, the actual cost of remediation and the timing of expenditures are subject to change. NSP-Wisconsin also continues to work to identify and access state and federal funds to apply to the remediation cost of the entire site. NSP-Wisconsin has deferred the estimated site remediation costs as a regulatory asset. The PSCW has consistently authorized NSP-Wisconsin rate recovery for all remediation costs incurred at the Site. In a December 2012 decision, the PSCW agreed to allow NSP-Wisconsin to pre-collect certain costs, to amortize costs over a ten -year period, and to apply a three percent carrying cost to the unamortized regulatory asset. In April 2016, NSP-Wisconsin filed a limited natural gas rate case for recovering additional expenses associated with remediating the Site. If approved, the annual recovery of MGP clean-up costs would increase from $7.6 million in 2016 to $12.4 million in 2017. Fargo, N.D. MGP Site — In May 2015, underground pipes, tars and impacted soils were discovered in Fargo, N.D., which may be related to a former MGP site operated by NSP-Minnesota or a prior company. NSP-Minnesota has removed the impacted soils and other materials from the project area. NSP-Minnesota is undertaking further investigation of the location of the historic MGP site and nearby properties. In October 2015, NSP-Minnesota initiated insurance recovery litigation in North Dakota. The U.S. District Court for the District of North Dakota agreed to the parties’ request for a stay of the litigation until November 2016 to allow NSP-Minnesota time to further investigate site conditions. As of June 30, 2016 and Dec. 31, 2015, NSP-Minnesota had recorded a liability of $1.6 million and $2.7 million , respectively, related to further investigation and additional planned activities. Uncertainties include the nature and cost of the additional remediation efforts that may be necessary, the ability to recover costs from insurance carriers and the potential for contributions from entities that may be identified as PRPs. Therefore, the total cost of remediation, NSP-Minnesota’s potential liability and amounts allocable to the North Dakota and Minnesota jurisdictions related to the site cannot currently be reasonably estimated. In December 2015, the NDPSC approved NSP-Minnesota’s request to defer the portion of investigation and response costs allocable to the North Dakota jurisdiction. Environmental Requirements Water and Waste Coal Ash Regulation — Xcel Energy’s operations are subject to federal and state laws that impose requirements for handling, storage, treatment and disposal of solid waste. In April 2015, the EPA published a final rule regulating the management and disposal of coal combustion byproducts (coal ash) as a nonhazardous waste. Under the final rule, Xcel Energy’s costs to manage and dispose of coal ash has not significantly increased. In 2015, industry and environmental non-governmental organizations sought judicial review of the final rule. In June 2016, the D.C Circuit issued an order remanding and vacating certain elements of the rule as a result of partial settlements with these parties. Oral arguments are expected to be heard in the second half of 2016 and a final decision is anticipated in early 2017. Until a final decision is reached in the case, it is uncertain whether the litigation or partial settlements will have any significant impact on results of operations, financial position or cash flows on Xcel Energy. Air Regional Haze Rules — The regional haze program is designed to address widespread haze that results from emissions from a multitude of sources. In 2005, the EPA amended the best available retrofit technology (BART) requirements of its regional haze rules, which require the installation and operation of emission controls for industrial facilities emitting air pollutants that reduce visibility in national parks and wilderness areas. Under BART, regional haze plans identify facilities that will have to reduce sulfur dioxide (SO 2 ), nitrogen oxide (NOx) and particulate matter (PM) emissions and set emission limits for those facilities. BART requirements can also be met through participation in interstate emission trading programs such as the Clean Air Interstate Rule (CAIR) and its successor, Cross-State Air Pollution Rule (CSAPR). Texas developed a state implementation plan (SIP) that finds the CAIR equal to BART for electric generating units (EGUs). As a result, no additional controls beyond CAIR compliance would be required. In December 2014, the EPA proposed to approve the BART portion of the SIP, with the exception that the EPA would substitute the CSAPR compliance for Texas’ reliance on CAIR. In January 2016, the EPA adopted a final rule that defers its approval of CSAPR compliance as BART until the EPA considers further adjustments to CSAPR emission budgets under the United States Court of Appeals for the District of Columbia Circuit’s (D.C. Circuit) remand of the Texas SO 2 emission budgets. In March 2016, the EPA requested information under the Clean Air Act (CAA) related to EGUs at SPS’ plants. SPS identified Harrington Units 1 and 2, Jones Units 1 and 2, Nichols Unit 3 and Plant X Unit 4 as BART-eligible units. These units will be evaluated based on their impact on visibility. Additional emission control equipment under the EPA’s BART guidelines for PM, SO 2 and NOx could be required if a unit is determined to “cause or contribute” to visibility impairment. SPS cannot evaluate the impact of additional emission controls until the EPA concludes its evaluation of BART. The EPA is expected to issue a proposed rule in December 2016. In June 2016, the EPA issued a memorandum which allows Texas to voluntarily adopt the CSAPR emission budgets limiting annual SO 2 and NOx emissions and rely on those emission budgets to satisfy Texas’ BART obligations under the regional haze rules. It is not yet known whether the Texas Commission on Environmental Quality (TCEQ) intends to utilize this option. In December 2014, the EPA proposed to disapprove the reasonable progress portions of the SIP and instead adopt a federal implementation plan (FIP). In January 2016, the EPA adopted a final rule establishing a FIP for the state of Texas. As part of this final rule, the EPA imposed SO 2 emission limitations that reflect the installation of dry scrubbers on Tolk Units 1 and 2, with compliance required by February 2021. Investment costs associated with dry scrubbers could be approximately $600 million . In March 2016, SPS appealed the EPA’s decision and asked for a stay of the final rule while it is being reviewed. In July 2016, the United States Court of Appeals for the Fifth Circuit (Fifth Circuit) granted the stay motion and decided that the Fifth Circuit, not the D.C. Circuit, is the appropriate venue for this case. In addition, SPS filed a petition with the EPA requesting reconsideration of the final rule. SPS believes these costs would be recoverable through regulatory mechanisms if required, and therefore does not expect a material impact on results of operations, financial position or cash flows. Implementation of the National Ambient Air Quality Standard (NAAQS) for SO 2 — The EPA adopted a more stringent NAAQS for SO 2 in 2010. The EPA is requiring states to evaluate areas in three phases. The first phase includes areas near PSCo’s Pawnee plant and SPS’ Tolk and Harrington plants. The Pawnee plant recently installed an SO 2 scrubber and the Tolk and Harrington Plants utilize low sulfur coal to reduce SO 2 emissions. In June 2016, the EPA issued final designations which found the area near the Tolk plant to be meeting the NAAQS and the areas near the Harrington and Pawnee plants as “unclassifiable.” The area near the Harrington plant is to be monitored for three years and a final designation is expected to be made by December 2020. It is anticipated that the area near the Pawnee plant will be able to show compliance with the NAAQS through air dispersion modeling performed by the Colorado Department of Public Health and Environment. If an area is designated nonattainment in 2020, the respective states will need to evaluate all SO 2 sources in the area. The state would then submit an implementation plan, which would be due by 2022, designed to achieve the NAAQS by 2025. The TCEQ could require additional SO 2 controls at Harrington as part of such a plan. The areas near the remaining Xcel Energy power plants will be evaluated in the next designation phase, ending December 2017. The remaining plants, PSCo’s Comanche and Hayden plants along with NSP-Minnesota’s King and Sherco plants, utilize scrubbers to control SO 2 emissions. Xcel Energy cannot evaluate the impacts until the designation of nonattainment areas is made and any required state plans are developed. Xcel Energy believes that, should SO 2 control systems be required for a plant, compliance costs will be recoverable through regulatory mechanisms and therefore does not expect a material impact on results of operations, financial position or cash flows. Legal Contingencies Xcel Energy is involved in various litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or is a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Management maintains accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss. For current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Xcel Energy’s financial statements. Unless otherwise required by GAAP, legal fees are expensed as incurred. Employment, Tort and Commercial Litigation Pacific Northwest FERC Refund Proceeding — A complaint with the FERC posed that sales made in the Pacific Northwest in 2000 and 2001 through bilateral contracts were unjust and unreasonable under the Federal Power Act. The City of Seattle (the City) alleges between $34 million to $50 million in sales with PSCo is subject to refund. In 2003, the FERC terminated the proceeding, although it was later remanded back to the FERC in 2007 by the U.S. Court of Appeals for the Ninth Circuit (Ninth Circuit). In May 2015, in the remand proceeding, the FERC issued an order rejecting the City’s claim that any of the sales made resulted in an excessive burden and concluded that the City failed to establish a causal link between any contracts and any claimed unlawful market activity. In February 2016, the City appealed this decision to the Ninth Circuit. This appeal is pending review by the Ninth Circuit. Also in December 2015, the Ninth Circuit issued an order and held that the standard of review applied by the FERC to the contracts which the City was challenging is appropriate. The Ninth Circuit dismissed questions concerning whether the FERC properly established the scope of the hearing, and determined that the challenged orders are preliminary and that the Ninth Circuit lacks jurisdiction to review evidentiary decisions until after the FERC’s proceedings are final. The City joined the State of California in its request seeking rehearing of this order, which the Ninth Circuit denied. Preliminary calculations of the City’s claim for refunds from PSCo are approximately $28 million , excluding interest, or approximately $60 million , including interest. PSCo has concluded that a loss is reasonably possible; however, given the surrounding uncertainties, PSCo is currently unable to estimate the amount or range of reasonably possible loss in the event of an adverse outcome of this matter. If a loss were sustained, PSCo would attempt to recover those losses from other PRPs. No accrual has been recorded for this matter. Gas Trading Litigation — e prime, inc. (e prime) is a wholly owned subsidiary of Xcel Energy. e prime was in the business of natural gas trading and marketing, but has not engaged in natural gas trading or marketing activities since 2003. Thirteen lawsuits were commenced against e prime and Xcel Energy (and NSP-Wisconsin, in two instances) between 2003 and 2009 alleging fraud and anticompetitive activities in conspiring to restrain the trade of natural gas and manipulate natural gas prices. Five of the cases have since been settled and seven have been dismissed. One multi-district litigation (MDL) matter remains and it consists of a Colorado class (Breckenridge), a Wisconsin class (NSP-Wisconsin), a Kansas class, and two other cases identified as “Sinclair Oil” and “Farmland.” In May 2016, the MDL judge granted summary judgment dismissing defendants from the Farmland lawsuit. e prime and Xcel Energy have filed a motion seeking clarification that this order includes them. This motion is currently pending. The e prime defendants recently filed a summary judgment motion in the Colorado class lawsuit (Breckenridge) and oppositions to class certifications in all the class actions. Trial dates have not yet been set, but are not expected to occur prior to early 2017. Xcel Energy, NSP-Wisconsin and e prime have concluded that a loss is remote. Line Extension Disputes — In December 2015, Development Recovery Company (DRC) filed a lawsuit in Denver State Court, stating PSCo failed to award proper allowances and refunds for line extensions to new developments pursuant to the terms of electric service agreements entered into by PSCo and various developers. The dispute involves assigned interests in those claims by over fifty developers. In May 2016, the district court granted PSCo’s motion to dismiss the lawsuit, concluding that jurisdiction over this dispute resides with the CPUC. In June 2016, DRC filed a notice of appeal. DRC also brought a proceeding before the CPUC as assignee on behalf of two developers, Ryland Homes and Richmond Homes of Colorado. In March 2016, the ALJ issued an order rejecting DRC’s claims for additional allowances and refunds. In June 2016, the ALJ’s determination was approved by the CPUC. PSCo has concluded that a loss is remote with respect to this matter as the service agreements were developed to implement CPUC approved tariffs and PSCo has complied with the tariff provisions. Also, if a loss were sustained, PSCo believes it would be allowed to recover these costs through traditional regulatory mechanisms. The amount or range in dispute is presently unknown and no accrual has been recorded for this matter. |
Borrowings and Other Financing
Borrowings and Other Financing Instruments | 6 Months Ended |
Jun. 30, 2016 | |
Debt Disclosure [Abstract] | |
Borrowings and Other Financing Instruments | Borrowings and Other Financing Instruments Short-Term Borrowings Money Pool — Xcel Energy Inc. and its utility subsidiaries have established a money pool arrangement that allows for short-term investments in and borrowings between the utility subsidiaries. NSP-Wisconsin does not participate in the money pool. Xcel Energy Inc. may make investments in the utility subsidiaries at market-based interest rates; however, the money pool arrangement does not allow the utility subsidiaries to make investments in Xcel Energy Inc. The money pool balances are eliminated in consolidation. Commercial Paper — Xcel Energy Inc. and its utility subsidiaries meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under their credit facilities. Commercial paper outstanding for Xcel Energy was as follows: (Amounts in Millions, Except Interest Rates) Three Months Ended Year Ended Borrowing limit $ 2,750 $ 2,750 Amount outstanding at period end 447 846 Average amount outstanding 404 601 Maximum amount outstanding 841 1,360 Weighted average interest rate, computed on a daily basis 0.72 % 0.48 % Weighted average interest rate at period end 0.80 0.82 Letters of Credit — Xcel Energy Inc. and its subsidiaries use letters of credit, generally with terms of one year , to provide financial guarantees for certain operating obligations. At June 30, 2016 and Dec. 31, 2015 , there were $28 million and $29 million , respectively, of letters of credit outstanding under the credit facilities. The contract amounts of these letters of credit approximate their fair value and are subject to fees. Credit Facilities — In order to use their commercial paper programs, Xcel Energy Inc. and its utility subsidiaries must have credit facilities in place at least equal to the amount of their commercial paper borrowing limits and cannot issue commercial paper in an aggregate amount exceeding available credit facility capacity. The lines of credit provide short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings. At June 30, 2016 , Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available: (Millions of Dollars) Credit Facility (a) Drawn (b) Available Xcel Energy Inc. $ 1,000 $ 414 $ 586 PSCo 700 3 697 NSP-Minnesota 500 18 482 SPS 400 32 368 NSP-Wisconsin 150 8 142 Total $ 2,750 $ 475 $ 2,275 (a) These credit facilities expire in June 2021 . (b) Includes outstanding commercial paper and letters of credit. All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the respective credit facilities. Xcel Energy Inc. and its subsidiaries had no direct advances on the credit facilities outstanding at June 30, 2016 and Dec. 31, 2015 . Amended Credit Agreements - In June 2016, Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS entered into amended five-year credit agreements with a syndicate of banks. The total borrowing limit under the amended credit agreements remained at $2.75 billion . The amended credit agreements have substantially the same terms and conditions as the prior credit agreements with the following exceptions: • The maturity extended from October 2019 to June 2021 . • The Eurodollar borrowing margins on these lines of credit were reduced to a range of 75 to 150 basis points per year, from a range of 87.5 to 175 basis points per year, based upon applicable long-term credit ratings. • The commitment fees, calculated on the unused portion of the lines of credit, were reduced to a range of 6 to 22.5 basis points per year, from a range of 7.5 to 27.5 basis points per year, also based on applicable long-term credit ratings. Xcel Energy Inc., NSP-Minnesota, PSCo and SPS each have the right to request an extension of the revolving credit facility termination date for two additional one-year periods. NSP-Wisconsin has the right to request an extension of the revolving credit facility termination date for an additional one-year period. All extension requests are subject to majority bank group approval. Long-Term Borrowings During the six months ended June 30, 2016, Xcel Energy Inc. and its utility subsidiaries completed the following bond issuances: • In March, Xcel Energy Inc. issued $400 million of 2.4 percent senior notes due March 15, 2021 and $350 million of 3.3 percent senior notes due June 1, 2025 ; • In May, NSP-Minnesota issued $350 million of 3.6 percent first mortgage bonds due May 15, 2046 ; and • In June, PSCo issued $250 million of 3.55 percent first mortgage bonds due June 15, 2046 . |
Fair Value of Financial Assets
Fair Value of Financial Assets and Liabilities | 6 Months Ended |
Jun. 30, 2016 | |
Fair Value Disclosures [Abstract] | |
Fair Value of Financial Assets and Liabilities | Fair Value of Financial Assets and Liabilities Fair Value Measurements The accounting guidance for fair value measurements and disclosures provides a single definition of fair value and requires certain disclosures about assets and liabilities measured at fair value. A hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value is established by this guidance. The three levels in the hierarchy are as follows: Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices. Level 2 — Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reporting date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, or priced with models using highly observable inputs. Level 3 — Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 are those valued with models requiring significant management judgment or estimation. Specific valuation methods include the following: Cash equivalents — The fair values of cash equivalents are generally based on cost plus accrued interest; money market funds are measured using quoted prices. Investments in equity securities and other funds — Equity securities are valued using quoted prices in active markets. The fair values for commingled funds, international equity funds, private equity investments and real estate investments are measured using a net asset value (NAV) methodology, which takes into consideration the value of underlying fund investments, as well as the other accrued assets and liabilities of a fund, in order to determine a per-share market value. The investments in commingled funds and international equity funds may be redeemed for NAV with proper notice. Proper notice varies by fund and can range from daily with one or two days notice to annually with 90 days notice. Private equity investments require approval of the fund for any unscheduled redemption, and such redemptions may be approved or denied by the fund at its sole discretion. Unscheduled distributions from real estate investments may be redeemed with proper notice, which is typically quarterly with 45 - 90 days notice; however, withdrawals from real estate investments may be delayed or discounted as a result of fund illiquidity. Investments in debt securities — Fair values for debt securities are determined by a third party pricing service using recent trades and observable spreads from benchmark interest rates for similar securities. Interest rate derivatives — The fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts. Commodity derivatives — The methods used to measure the fair value of commodity derivative forwards and options utilize forward prices and volatilities, as well as pricing adjustments for specific delivery locations, and are generally assigned a Level 2. When contractual settlements extend to periods beyond those readily observable on active exchanges or quoted by brokers, the significance of the use of less observable forecasts of long-term forward prices and volatilities on a valuation is evaluated, and may result in Level 3 classification. Electric commodity derivatives held by NSP-Minnesota and SPS include transmission congestion instruments, referred to as financial transmission rights (FTRs). FTRs purchased from a RTO are financial instruments that entitle or obligate the holder to monthly revenues or charges based on transmission congestion across a given transmission path. The value of an FTR is derived from, and designed to offset, the cost of energy congestion, which is caused by transmission load and transmission constraints. Congestion is also influenced by the operating schedules of power plants and the consumption of electricity. Unplanned plant outages, scheduled plant maintenance, changes in the costs of fuels used in generation, weather and changes in demand for electricity can each impact the operating schedules of the power plants and the value of an FTR. The valuation process for FTRs utilizes complex iterative modeling to predict the impacts of forecasted changes in these drivers of transmission system congestion on the historical pricing of FTR purchases. If forecasted costs of electric transmission congestion increase or decrease for a given FTR path, the value of that particular FTR instrument will likewise increase or decrease. Given the limited observability of management’s forecasts for several of the inputs to this complex valuation model fair value measurements for FTRs have been assigned a Level 3. Monthly settlements for non-trading FTRs are included in fuel and purchased energy cost recovery mechanisms as applicable in each jurisdiction, and therefore changes in the fair value of the yet to be settled portions of most FTRs are deferred as a regulatory asset or liability. Given this regulatory treatment and the limited magnitude of FTRs relative to the electric utility operations of NSP-Minnesota and SPS, the numerous unobservable quantitative inputs to the complex model used for valuation of FTRs are insignificant to the consolidated financial statements of Xcel Energy. Non-Derivative Instruments Fair Value Measurements Nuclear Decommissioning Fund The NRC requires NSP-Minnesota to maintain a portfolio of investments to fund the costs of decommissioning its nuclear generating plants. Together with all accumulated earnings or losses, the assets of the nuclear decommissioning fund are legally restricted for the purpose of decommissioning the Monticello and PI nuclear generating plants. The fund contains cash equivalents, debt securities, equity securities and other investments – all classified as available-for-sale. NSP-Minnesota plans to reinvest matured securities until decommissioning begins. NSP-Minnesota uses the MPUC approved asset allocation for the escrow and investment targets by asset class for both the escrow and qualified trust. NSP-Minnesota recognizes the costs of funding the decommissioning of its nuclear generating plants over the lives of the plants, assuming rate recovery of all costs. Realized and unrealized gains on fund investments over the life of the fund are deferred as an offset of NSP-Minnesota’s regulatory asset for nuclear decommissioning costs, given the purpose and legal restrictions on the use of nuclear decommissioning fund assets. Consequently, any realized and unrealized gains and losses on securities in the nuclear decommissioning fund, including any other-than-temporary impairments, are deferred as a component of the regulatory asset for nuclear decommissioning. Unrealized gains for the nuclear decommissioning fund were $336.5 million and $328.8 million at June 30, 2016 and Dec. 31, 2015 , respectively, and unrealized losses and amounts recorded as other-than-temporary impairments were $95.2 million and $100.2 million at June 30, 2016 and Dec. 31, 2015 , respectively. The following tables present the cost and fair value of Xcel Energy’s non-derivative instruments with recurring fair value measurements in the nuclear decommissioning fund at June 30, 2016 and Dec. 31, 2015 : June 30, 2016 Fair Value (Thousands of Dollars) Cost Level 1 Level 2 Level 3 Investments Measured at NAV (b) Total Nuclear decommissioning fund (a) Cash equivalents $ 15,749 $ 15,749 $ — $ — $ — $ 15,749 Commingled funds 389,700 — — — 411,788 411,788 International equity funds 259,090 — — — 236,087 236,087 Private equity investments 119,370 — — — 166,054 166,054 Real estate 72,956 — — — 102,144 102,144 Debt securities: Government securities 35,199 — 35,828 — — 35,828 U.S. corporate bonds 96,110 — 91,350 — — 91,350 International corporate bonds 19,959 — 19,394 — — 19,394 Municipal bonds 11,966 — 12,826 — — 12,826 Asset-backed securities 2,844 — 2,881 — — 2,881 Mortgage-backed securities 10,708 — 11,180 — — 11,180 Equity securities: Common stock 479,865 649,521 — — — 649,521 Total $ 1,513,516 $ 665,270 $ 173,459 $ — $ 916,073 $ 1,754,802 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $133.7 million of equity investments in unconsolidated subsidiaries and $99.0 million of rabbi trust assets and miscellaneous investments. (b) Based on the requirements of ASU 2015-07, investments measured at fair value using a NAV methodology have not been classified in the fair value hierarchy. See Note 2 for further information on the adoption of ASU 2015-07. Dec. 31, 2015 Fair Value (Thousands of Dollars) Cost Level 1 Level 2 Level 3 Investments Measured at NAV (b) Total Nuclear decommissioning fund (a) Cash equivalents $ 27,484 $ 27,484 $ — $ — $ — $ 27,484 Commingled funds 392,838 — — — 410,634 410,634 International equity funds 259,114 — — — 231,122 231,122 Private equity investments 105,965 — — — 157,528 157,528 Real estate 61,816 — — — 84,750 84,750 Debt securities: Government securities 24,444 — 21,356 — — 21,356 U.S. corporate bonds 73,061 — 65,276 — — 65,276 International corporate bonds 13,726 — 12,801 — — 12,801 Municipal bonds 49,255 — 51,589 — — 51,589 Asset-backed securities 2,837 — 2,830 — — 2,830 Mortgage-backed securities 11,444 — 11,621 — — 11,621 Equity securities: Common stock 473,615 647,159 — — — 647,159 Total $ 1,495,599 $ 674,643 $ 165,473 $ — $ 884,034 $ 1,724,150 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $130.0 million of equity investments in unconsolidated subsidiaries and $48.9 million of miscellaneous investments. (b) Based on the requirements of ASU 2015-07, investments measured at fair value using a NAV methodology have not been classified in the fair value hierarchy. See Note 2 for further information on the adoption of ASU 2015-07. For the six months ended June 30, 2016 and 2015 there were no Level 3 nuclear decommissioning fund investments and no transfers of amounts between levels. The following table summarizes the final contractual maturity dates of the debt securities in the nuclear decommissioning fund, by asset class, at June 30, 2016 : Final Contractual Maturity (Thousands of Dollars) Due in 1 Year or Less Due in 1 to 5 Years Due in 5 to 10 Years Due after 10 Years Total Government securities $ — $ 10,659 $ 982 $ 24,187 $ 35,828 U.S. corporate bonds 261 26,988 59,368 4,733 91,350 International corporate bonds — 3,966 12,368 3,060 19,394 Municipal bonds — 212 4,248 8,366 12,826 Asset-backed securities — — 2,881 — 2,881 Mortgage-backed securities — — — 11,180 11,180 Debt securities $ 261 $ 41,825 $ 79,847 $ 51,526 $ 173,459 Rabbi Trusts In June 2016, Xcel Energy established rabbi trusts to provide funding for future distributions of its supplemental executive retirement plan and nonqualified pension plans. The following table presents the cost and fair value of the assets held in rabbi trusts at June 30, 2016: June 30, 2016 Fair Value (Thousands of Dollars) Cost Level 1 Level 2 Level 3 Total Rabbi Trusts (a) Cash equivalents $ 47,762 $ 47,762 $ — $ — $ 47,762 Mutual funds 1,593 1,778 — — 1,778 Total $ 49,355 $ 49,540 $ — $ — $ 49,540 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet. An immaterial amount of mutual funds were held in rabbi trusts at Dec. 31, 2015. Derivative Instruments Fair Value Measurements Xcel Energy enters into derivative instruments, including forward contracts, futures, swaps and options, for trading purposes and to manage risk in connection with changes in interest rates, utility commodity prices and vehicle fuel prices. Interest Rate Derivatives — Xcel Energy enters into various instruments that effectively fix the interest payments on certain floating rate debt obligations or effectively fix the yield or price on a specified benchmark interest rate for an anticipated debt issuance for a specific period. These derivative instruments are generally designated as cash flow hedges for accounting purposes. At June 30, 2016 , accumulated other comprehensive losses related to interest rate derivatives included $3.4 million of net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings, including forecasted amounts for unsettled hedges, as applicable. Wholesale and Commodity Trading Risk — Xcel Energy Inc.’s utility subsidiaries conduct various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy and energy-related instruments. Xcel Energy’s risk management policy allows management to conduct these activities within guidelines and limitations as approved by its risk management committee. Commodity Derivatives — Xcel Energy enters into derivative instruments to manage variability of future cash flows from changes in commodity prices in its electric and natural gas operations, as well as for trading purposes. This could include the purchase or sale of energy or energy-related products, natural gas to generate electric energy, natural gas for resale, FTRs, vehicle fuel and weather derivatives. At June 30, 2016 , Xcel Energy had various vehicle fuel contracts designated as cash flow hedges extending through December 2016. Xcel Energy also enters into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers but are not designated as qualifying hedging transactions. Changes in the fair value of non-trading commodity derivative instruments are recorded in other comprehensive income or deferred as a regulatory asset or liability. The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. Xcel Energy recorded immaterial amounts to income related to the ineffectiveness of cash flow hedges for the three and six months ended June 30, 2016 and 2015 . At June 30, 2016 , net losses related to commodity derivative cash flow hedges recorded as a component of accumulated other comprehensive losses included $0.1 million of net losses expected to be reclassified into earnings during the next 12 months as the hedged transactions occur. Additionally, Xcel Energy enters into commodity derivative instruments for trading purposes not directly related to commodity price risks associated with serving its electric and natural gas customers. Changes in the fair value of these commodity derivatives are recorded in electric operating revenues, net of amounts credited to customers under margin-sharing mechanisms. The following table details the gross notional amounts of commodity forwards, options and FTRs at June 30, 2016 and Dec. 31, 2015 : (Amounts in Thousands) (a)(b) June 30, 2016 Dec. 31, 2015 Megawatt hours of electricity 81,667 50,487 Million British thermal units of natural gas 84,578 20,874 Gallons of vehicle fuel 70 141 (a) Amounts are not reflective of net positions in the underlying commodities. (b) Notional amounts for options are included on a gross basis, but are weighted for the probability of exercise. The following tables detail the impact of derivative activity during the three and six months ended June 30, 2016 and 2015, on accumulated other comprehensive loss, regulatory assets and liabilities, and income: Three Months Ended June 30, 2016 Pre-Tax Fair Value Gains (Losses) Recognized During the Period in: Pre-Tax Losses Reclassified into Income During the Period from: Pre-Tax Gains Recognized (Thousands of Dollars) Accumulated Other Regulatory Accumulated Other Regulatory Assets and (Liabilities) Derivatives designated as cash flow hedges Interest rate $ — $ — $ 1,483 (a) $ — $ — Vehicle fuel and other commodity 19 — 47 (b) — — Total $ 19 $ — $ 1,530 $ — $ — Other derivative instruments Commodity trading $ — $ — $ — $ — $ 481 (c) Electric commodity — (705 ) — 16,642 (d) — Natural gas commodity — 6,063 — — 25 (e) Total $ — $ 5,358 $ — $ 16,642 $ 506 Six Months Ended June 30, 2016 Pre-Tax Fair Value Gains (Losses) Recognized During the Period in: Pre-Tax Losses Reclassified into Income During the Period from: Pre-Tax Gains (Losses) Recognized (Thousands of Dollars) Accumulated Other Regulatory Accumulated Other Regulatory Assets and (Liabilities) Derivatives designated as cash flow hedges Interest rate $ — $ — $ 2,968 (a) $ — $ — Vehicle fuel and other commodity 13 — 104 (b) — — Total $ 13 $ — $ 3,072 $ — $ — Other derivative instruments Commodity trading $ — $ — $ — $ — $ 1,490 (c) Electric commodity — (970 ) — 27,533 (d) — Natural gas commodity — 3,361 — 11,666 (e) (4,999 ) (e) Total $ — $ 2,391 $ — $ 39,199 $ (3,509 ) Three Months Ended June 30, 2015 Pre-Tax Fair Value Gains (Losses) Recognized During the Period in: Pre-Tax (Gains) Losses Reclassified into Income During the Period from: Pre-Tax Gains Recognized (Thousands of Dollars) Accumulated Other Regulatory Accumulated Other Regulatory Assets and (Liabilities) Derivatives designated as cash flow hedges Interest rate $ — $ — $ 954 (a) $ — $ — Vehicle fuel and other commodity 29 — 28 (b) — — Total $ 29 $ — $ 982 $ — $ — Other derivative instruments Commodity trading $ — $ — $ — $ — $ 4,401 (c) Electric commodity — (4,737 ) — (8,037 ) (d) — Natural gas commodity — (232 ) — (22 ) (e) — Total $ — $ (4,969 ) $ — $ (8,059 ) $ 4,401 Six Months Ended June 30, 2015 Pre-Tax Fair Value Gains (Losses) Recognized During the Period in: Pre-Tax (Gains) Losses Reclassified into Income During the Period from: Pre-Tax Gains Recognized (Thousands of Dollars) Accumulated Other Regulatory Accumulated Other Regulatory Derivatives designated as cash flow hedges Interest rate $ — $ — $ 1,894 (a) $ — $ — Vehicle fuel and other commodity 11 — 55 (b) — — Total $ 11 $ — $ 1,949 $ — $ — Other derivative instruments Commodity trading $ — $ — $ — $ — $ 8,281 (c) Electric commodity — (14,208 ) — (13,160 ) (d) — Natural gas commodity — (448 ) — (8,852 ) (e) 8,991 (e) Total $ — $ (14,656 ) $ — $ (22,012 ) $ 17,272 (a) Amounts are recorded to interest charges. (b) Amounts are recorded to O&M expenses. (c) Amounts are recorded to electric operating revenues. Portions of these gains and losses are subject to sharing with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate. (d) Amounts are recorded to electric fuel and purchased power. These derivative settlement gain and loss amounts are shared with electric customers through fuel and purchased energy cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate. (e) Amounts for the three and six months ended June 30, 2016 and 2015 included an immaterial amount of settlement losses on derivatives entered to mitigate natural gas price risk for electric generation, recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate. The remaining derivative settlement gains and losses for the three and six months ended June 30, 2016 and 2015 relate to natural gas operations and are recorded to cost of natural gas sold and transported. These gains and losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset or liability, as appropriate. Xcel Energy had no derivative instruments designated as fair value hedges during the three and six months ended June 30, 2016 and 2015 . Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for these periods. Consideration of Credit Risk and Concentrations — Xcel Energy monitors the creditworthiness of the counterparties to its interest rate derivatives and commodity derivative contracts prior to settlement, and assesses each counterparty’s ability to perform on the transactions. Given this assessment, as well as an assessment of the impact of Xcel Energy’s own credit risk when determining the fair value of derivative liabilities, the impact of considering credit risk was immaterial to the fair value of unsettled commodity derivatives presented in the consolidated balance sheets. Xcel Energy Inc. and its subsidiaries employ additional credit risk control mechanisms, such as letters of credit, parental guarantees, standardized master netting agreements and termination provisions that allow for offsetting of positive and negative exposures. Credit exposure is monitored and, when necessary, the activity with a specific counterparty is limited until credit enhancement is provided. Xcel Energy’s utility subsidiaries’ most significant concentrations of credit risk are contracts with counterparties to their wholesale, trading and non-trading commodity activities. At June 30, 2016 , one of Xcel Energy’s 10 most significant counterparties for these activities, comprising $13.5 million or 6 percent of this credit exposure, had investment grade credit ratings from Standard & Poor’s Ratings Services, Moody’s Investor Services or Fitch Ratings. Seven of the 10 most significant counterparties, comprising $55.6 million or 25 percent of this credit exposure, were not rated by these external agencies, but based on Xcel Energy’s internal analysis, had credit quality consistent with investment grade. The remaining two most significant counterparties, comprising $12.2 million or 6 percent of this credit exposure, had credit quality less than investment grade, based on ratings from external and internal analysis. Nine of these significant counterparties are RTOs, municipal or cooperative electric entities or other utilities. Credit Related Contingent Features — Contract provisions for derivative instruments that the utility subsidiaries enter, including those recorded to the consolidated balance sheet at fair value, as well as those accounted for as normal purchase-normal sale contracts and therefore not reflected on the balance sheet, may require the posting of collateral or settlement of the contracts for various reasons, including if the applicable utility subsidiary is unable to maintain its credit ratings. At June 30, 2016 and Dec. 31, 2015, there were no derivative instruments in a liability position that would have required the posting of collateral or settlement of applicable outstanding contracts if the credit ratings of Xcel Energy Inc.’s utility subsidiaries were downgraded below investment grade. Certain derivative instruments are also subject to contract provisions that contain adequate assurance clauses. These provisions allow counterparties to seek performance assurance, including cash collateral, in the event that a utility subsidiary’s ability to fulfill its contractual obligations is reasonably expected to be impaired. Xcel Energy had no collateral posted related to adequate assurance clauses in derivative contracts as of June 30, 2016 and Dec. 31, 2015 . Recurring Fair Value Measurements — The following table presents for each of the fair value hierarchy levels, Xcel Energy’s derivative assets and liabilities measured at fair value on a recurring basis at June 30, 2016 : June 30, 2016 Fair Value Fair Value Total Counterparty Netting (b) Total (Thousands of Dollars) Level 1 Level 2 Level 3 Current derivative assets Other derivative instruments: Commodity trading $ 5,384 $ 14,675 $ — $ 20,059 $ (14,017 ) $ 6,042 Electric commodity — — 28,151 28,151 (3,593 ) 24,558 Natural gas commodity — 8,525 — 8,525 (31 ) 8,494 Total current derivative assets $ 5,384 $ 23,200 $ 28,151 $ 56,735 $ (17,641 ) 39,094 PPAs (a) 7,859 Current derivative instruments $ 46,953 Noncurrent derivative assets Other derivative instruments: Commodity trading $ 1,037 $ 28,058 $ — $ 29,095 $ (6,986 ) $ 22,109 Natural gas commodity — 1,355 — 1,355 — 1,355 Total noncurrent derivative assets $ 1,037 $ 29,413 $ — $ 30,450 $ (6,986 ) 23,464 PPAs (a) 27,180 Noncurrent derivative instruments $ 50,644 June 30, 2016 Fair Value Fair Value Total Counterparty Netting (b) Total (Thousands of Dollars) Level 1 Level 2 Level 3 Current derivative liabilities Derivatives designated as cash flow hedges: Vehicle fuel and other commodity $ — $ 82 $ — $ 82 $ — $ 82 Other derivative instruments: Commodity trading 5,407 12,740 41 18,188 (14,575 ) 3,613 Electric commodity — — 3,593 3,593 (3,593 ) — Natural gas commodity — 31 — 31 (31 ) — Total current derivative liabilities $ 5,407 $ 12,853 $ 3,634 $ 21,894 $ (18,199 ) 3,695 PPAs (a) 22,847 Current derivative instruments $ 26,542 Noncurrent derivative liabilities Other derivative instruments: Commodity trading $ 1,086 $ 19,786 $ — $ 20,872 $ (11,162 ) $ 9,710 Total noncurrent derivative liabilities $ 1,086 $ 19,786 $ — $ 20,872 $ (11,162 ) 9,710 PPAs (a) 146,647 Noncurrent derivative instruments $ 156,357 (a) In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, Xcel Energy began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, Xcel Energy qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities. (b) Xcel Energy nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at June 30, 2016 . At June 30, 2016 , derivative assets and liabilities include no obligations to return cash collateral and the rights to reclaim cash collateral of $4.7 million . The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements. The following table presents for each of the fair value hierarchy levels, Xcel Energy’s derivative assets and liabilities measured at fair value on a recurring basis at Dec. 31, 2015 : Dec. 31, 2015 Fair Value Fair Value Total Counterparty Netting (b) Total (Thousands of Dollars) Level 1 Level 2 Level 3 Current derivative assets Other derivative instruments: Commodity trading $ 225 $ 10,620 $ 1,250 $ 12,095 $ (5,865 ) $ 6,230 Electric commodity — — 21,421 21,421 (4,088 ) 17,333 Natural gas commodity — 496 — 496 (303 ) 193 Total current derivative assets $ 225 $ 11,116 $ 22,671 $ 34,012 $ (10,256 ) 23,756 PPAs (a) 10,086 Current derivative instruments $ 33,842 Noncurrent derivative assets Other derivative instruments: Commodity trading $ — $ 27,416 $ — $ 27,416 $ (6,555 ) $ 20,861 Total noncurrent derivative assets $ — $ 27,416 $ — $ 27,416 $ (6,555 ) 20,861 PPAs (a) 30,222 Noncurrent derivative instruments $ 51,083 Dec. 31, 2015 Fair Value Fair Value Total Counterparty Netting (b) Total (Thousands of Dollars) Level 1 Level 2 Level 3 Current derivative liabilities Derivatives designated as cash flow hedges: Vehicle fuel and other commodity $ — $ 205 $ — $ 205 $ — $ 205 Other derivative instruments: Commodity trading 152 7,866 555 8,573 (6,904 ) 1,669 Electric commodity — — 4,088 4,088 (4,088 ) — Natural gas commodity — 5,407 — 5,407 (303 ) 5,104 Total current derivative liabilities $ 152 $ 13,478 $ 4,643 $ 18,273 $ (11,295 ) 6,978 PPAs (a) 22,861 Current derivative instruments $ 29,839 Noncurrent derivative liabilities Other derivative instruments: Commodity trading $ — $ 19,898 $ — $ 19,898 $ (9,780 ) $ 10,118 Total noncurrent derivative liabilities $ — $ 19,898 $ — $ 19,898 $ (9,780 ) 10,118 PPAs (a) 158,193 Noncurrent derivative instruments $ 168,311 (a) In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, Xcel Energy began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, Xcel Energy qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities. (b) Xcel Energy nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2015 . At Dec. 31, 2015 , derivative assets and liabilities include no obligations to return cash collateral and rights to reclaim cash collateral of $4.3 million . The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements. The following table presents the changes in Level 3 commodity derivatives for the three and six months ended June 30, 2016 and 2015 : Three Months Ended June 30 (Thousands of Dollars) 2016 2015 Balance at April 1 $ 6,854 $ 17,429 Purchases 29,826 57,446 Settlements (14,111 ) (17,315 ) Net transactions recorded during the period: (Losses) gains recognized in earnings (a) (18 ) 1,220 Gains (losses) recognized as regulatory assets and liabilities 1,966 (11,953 ) Balance at June 30 $ 24,517 $ 46,827 Six Months Ended June 30 (Thousands of Dollars) 2016 2015 Balance at Jan. 1 $ 18,028 $ 56,155 Purchases 31,670 63,238 Settlements (26,161 ) (37,246 ) Net transactions recorded during the period: (Losses) gains recognized in earnings (a) (43 ) 1,280 Gains (losses) recognized as regulatory assets and liabilities 1,023 (36,600 ) Balance at June 30 $ 24,517 $ 46,827 (a) These amounts relate to commodity derivatives held at the end of the period. Xcel Energy recognizes transfers between levels as of the beginning of each period. There were no transfers of amounts between levels for derivative instruments for the three and six months ended June 30, 2016 and 2015. Fair Value of Long-Term Debt As of June 30, 2016 and Dec. 31, 2015 , other financial instruments for which the carrying amount did not equal fair value were as follows: June 30, 2016 Dec. 31, 2015 (Thousands of Dollars) Carrying Amount Fair Value Carrying Amount Fair Value Long-term debt, including current portion (a) $ 13,814,921 $ 15,935,100 $ 13,055,901 $ 14,094,744 (a) Amounts reflect the classification of debt issuance costs as a deduction from the carrying amount of the related debt. See Note 2, Accounting Pronouncements for more information on the adoption of ASU 2015-03. The fair value of Xcel Energy’s long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities. The fair value estimates are based on information available to management as of June 30, 2016 and Dec. 31, 2015 , and given the observability of the inputs to these estimates, the fair values presented for long-term debt have been assigned a Level 2. |
Other Income, Net
Other Income, Net | 6 Months Ended |
Jun. 30, 2016 | |
Other Income and Expenses [Abstract] | |
Other Income, Net | Other Income, Net Other income, net consisted of the following: Three Months Ended June 30 Six Months Ended June 30 (Thousands of Dollars) 2016 2015 2016 2015 Interest income $ 984 $ 389 $ 5,054 $ 4,627 Other nonoperating income 1,496 794 2,176 1,762 Insurance policy expense (920 ) (222 ) (1,420 ) (2,267 ) Other income, net $ 1,560 $ 961 $ 5,810 $ 4,122 |
Segment Information
Segment Information | 6 Months Ended |
Jun. 30, 2016 | |
Segment Reporting [Abstract] | |
Segment Information | Segment Information The regulated electric utility operating results of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS, as well as the regulated natural gas utility operating results of NSP-Minnesota, NSP-Wisconsin and PSCo are each separately and regularly reviewed by Xcel Energy’s chief operating decision maker. Xcel Energy evaluates performance by each utility subsidiary based on profit or loss generated from the product or service provided. These segments are managed separately because the revenue streams are dependent upon regulated rate recovery, which is separately determined for each segment. Xcel Energy has the following reportable segments: regulated electric utility, regulated natural gas utility and all other. • Xcel Energy’s regulated electric utility segment generates, transmits and distributes electricity primarily in portions of Minnesota, Wisconsin, Michigan, North Dakota, South Dakota, Colorado, Texas and New Mexico. In addition, this segment includes sales for resale and provides wholesale transmission service to various entities in the United States. Regulated electric utility also includes commodity trading operations. • Xcel Energy’s regulated natural gas utility segment transports, stores and distributes natural gas primarily in portions of Minnesota, Wisconsin, North Dakota, Michigan and Colorado. • Revenues from operating segments not included above are below the necessary quantitative thresholds and are therefore included in the all other category. Those primarily include steam revenue, appliance repair services, nonutility real estate activities, revenues associated with processing solid waste into refuse-derived fuel and investments in rental housing projects that qualify for low-income housing tax credits. Xcel Energy had equity investments in unconsolidated subsidiaries of $133.7 million and $130.0 million as of June 30, 2016 and Dec. 31, 2015 , respectively, included in the regulated natural gas utility segment. Asset and capital expenditure information is not provided for Xcel Energy’s reportable segments because as an integrated electric and natural gas utility, Xcel Energy operates significant assets that are not dedicated to a specific business segment, and reporting assets and capital expenditures by business segment would require arbitrary and potentially misleading allocations which may not necessarily reflect the assets that would be required for the operation of the business segments on a stand-alone basis. To report income from operations for regulated electric and regulated natural gas utility segments, the majority of costs are directly assigned to each segment. However, some costs, such as common depreciation, common O&M expenses and interest expense are allocated based on cost causation allocators. A general allocator is used for certain general and administrative expenses, including office supplies, rent, property insurance and general advertising. (Thousands of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total Three Months Ended June 30, 2016 Operating revenues from external customers $ 2,224,142 $ 258,899 $ 16,808 $ — $ 2,499,849 Intersegment revenues 421 241 — (662 ) — Total revenues $ 2,224,563 $ 259,140 $ 16,808 $ (662 ) $ 2,499,849 Net income (loss) $ 205,440 $ 11,933 $ (20,578 ) $ — $ 196,795 (Thousands of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total Three Months Ended June 30, 2015 Operating revenues from external customers $ 2,213,460 $ 284,131 $ 17,543 $ — $ 2,515,134 Intersegment revenues 420 172 — (592 ) — Total revenues $ 2,213,880 $ 284,303 $ 17,543 $ (592 ) $ 2,515,134 Net income (loss) $ 214,955 $ (6,883 ) $ (11,141 ) $ — $ 196,931 (Thousands of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total Six Months Ended June 30, 2016 Operating revenues from external customers $ 4,409,261 $ 824,588 $ 38,273 $ — $ 5,272,122 Intersegment revenues 756 528 — (1,284 ) — Total revenues $ 4,410,017 $ 825,116 $ 38,273 $ (1,284 ) $ 5,272,122 Net income (loss) $ 383,677 $ 90,271 $ (35,841 ) $ — $ 438,107 (Thousands of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total Six Months Ended June 30, 2015 Operating revenues from external customers $ 4,438,323 $ 1,000,127 $ 38,903 $ — $ 5,477,353 Intersegment revenues 750 848 — (1,598 ) — Total revenues $ 4,439,073 $ 1,000,975 $ 38,903 $ (1,598 ) $ 5,477,353 Net income (loss) $ 295,976 (a) $ 76,793 $ (23,772 ) $ — $ 348,997 (a) Includes a net of tax charge related to the Monticello LCM/EPU project. See Note 5. |
Earnings Per Share
Earnings Per Share | 6 Months Ended |
Jun. 30, 2016 | |
Earnings Per Share [Abstract] | |
Earnings Per Share | Earnings Per Share Basic earnings per share (EPS) was computed by dividing the earnings available to Xcel Energy Inc.’s common shareholders by the weighted average number of common shares outstanding during the period. Diluted EPS was computed by dividing the earnings available to Xcel Energy Inc.’s common shareholders by the diluted weighted average number of common shares outstanding during the period. Diluted EPS reflects the potential dilution that could occur if securities or other agreements to issue common stock (i.e., common stock equivalents) were settled. The weighted average number of potentially dilutive shares outstanding used to calculate Xcel Energy Inc.’s diluted EPS is calculated using the treasury stock method. Common Stock Equivalents — Xcel Energy Inc. currently has common stock equivalents related to certain equity awards in share-based compensation arrangements. Common stock equivalents causing dilutive impact to EPS include commitments to issue common stock related to time based equity compensation awards and time based employer matching contributions to certain 401(k) plan participants. Stock equivalent units granted to Xcel Energy Inc.’s Board of Directors are included in common shares outstanding upon grant date as there is no further service, performance or market condition associated with these awards. Restricted stock, granted to settle amounts due to certain employees under the Xcel Energy Inc. Executive Annual Incentive Award Plan, is included in common shares outstanding when granted. Share-based compensation arrangements for which there is currently no dilutive impact to EPS include the following: • Equity awards subject to a performance condition; included in common shares outstanding when all necessary conditions for settlement have been satisfied by the end of the reporting period. • Liability awards subject to a performance condition; any portions settled in shares are included in common shares outstanding upon settlement. The dilutive impact of common stock equivalents affecting EPS was as follows: Three Months Ended June 30, 2016 Three Months Ended June 30, 2015 (Amounts in thousands, except per share data) Income Shares Per Share Amount Income Shares Per Share Amount Net income $ 196,795 — — $ 196,931 — — Basic EPS: Earnings available to common shareholders 196,795 508,930 $ 0.39 196,931 507,707 $ 0.39 Effect of dilutive securities: Time based equity awards — 560 — — 367 — Diluted EPS: Earnings available to common shareholders $ 196,795 509,490 $ 0.39 $ 196,931 508,074 $ 0.39 Six Months Ended June 30, 2016 Six Months Ended June 30, 2015 (Amounts in thousands, except per share data) Income Shares Per Share Amount Income Shares Per Share Amount Net income $ 438,107 — — $ 348,997 — — Basic EPS: Earnings available to common shareholders 438,107 508,789 $ 0.86 348,997 507,359 $ 0.69 Effect of dilutive securities: Time based equity awards — 522 — — 388 — Diluted EPS: Earnings available to common shareholders $ 438,107 509,311 $ 0.86 $ 348,997 507,747 $ 0.69 |
Benefit Plans and Other Postret
Benefit Plans and Other Postretirement Benefits | 6 Months Ended |
Jun. 30, 2016 | |
Compensation and Retirement Disclosure [Abstract] | |
Benefit Plans and Other Postretirement Benefits | Benefit Plans and Other Postretirement Benefits Components of Net Periodic Benefit Cost (Credit) Three Months Ended June 30 2016 2015 2016 2015 (Thousands of Dollars) Pension Benefits Postretirement Health Service cost $ 22,945 $ 24,828 $ 431 $ 529 Interest cost 40,028 37,131 6,526 6,324 Expected return on plan assets (52,575 ) (53,472 ) (6,248 ) (6,650 ) Amortization of prior service credit (477 ) (451 ) (2,671 ) (2,671 ) Amortization of net loss 24,385 31,288 1,009 1,351 Net periodic benefit cost (credit) 34,306 39,324 (953 ) (1,117 ) Costs not recognized due to the effects of regulation (4,159 ) (7,523 ) — — Net benefit cost (credit) recognized for financial reporting $ 30,147 $ 31,801 $ (953 ) $ (1,117 ) Six Months Ended June 30 2016 2015 2016 2015 (Thousands of Dollars) Pension Benefits Postretirement Health Service cost $ 45,865 $ 49,656 $ 863 $ 1,058 Interest cost 80,051 74,262 13,053 12,648 Expected return on plan assets (105,150 ) (106,945 ) (12,497 ) (13,300 ) Amortization of prior service credit (961 ) (902 ) (5,343 ) (5,343 ) Amortization of net loss 48,770 62,576 2,020 2,702 Net periodic benefit cost (credit) 68,575 78,647 (1,904 ) (2,235 ) Costs not recognized due to the effects of regulation (8,611 ) (15,019 ) — — Net benefit cost (credit) recognized for financial reporting $ 59,964 $ 63,628 $ (1,904 ) $ (2,235 ) In January 2016, contributions of $125.0 million were made across four of Xcel Energy’s pension plans. Xcel Energy does not expect additional pension contributions during 2016. |
Other Comprehensive Income
Other Comprehensive Income | 6 Months Ended |
Jun. 30, 2016 | |
Stockholders' Equity Note [Abstract] | |
Other Comprehensive Income | Other Comprehensive Income Changes in accumulated other comprehensive (loss) income, net of tax, for the three and six months ended June 30, 2016 and 2015 were as follows: Three Months Ended June 30, 2016 (Thousands of Dollars) Gains and Losses on Cash Flow Hedges Unrealized Gains and Losses on Marketable Securities Defined Benefit Pension and Postretirement Items Total Accumulated other comprehensive (loss) income at April 1 $ (53,928 ) $ 110 $ (54,790 ) $ (108,608 ) Other comprehensive income before reclassifications 12 — — 12 Losses reclassified from net accumulated other comprehensive loss 936 — 865 1,801 Net current period other comprehensive income 948 — 865 1,813 Accumulated other comprehensive (loss) income at June 30 $ (52,980 ) $ 110 $ (53,925 ) $ (106,795 ) Three Months Ended June 30, 2015 (Thousands of Dollars) Gains and Losses on Cash Flow Hedges Unrealized Gains and Losses on Marketable Securities Defined Benefit Pension and Total Accumulated other comprehensive (loss) income at April 1 $ (57,054 ) $ 111 $ (49,745 ) $ (106,688 ) Other comprehensive income before reclassifications 18 1 — 19 Losses reclassified from net accumulated other comprehensive loss 600 — 883 1,483 Net current period other comprehensive income 618 1 883 1,502 Accumulated other comprehensive (loss) income at June 30 $ (56,436 ) $ 112 $ (48,862 ) $ (105,186 ) Six Months Ended June 30, 2016 (Thousands of Dollars) Gains and Losses on Cash Flow Hedges Unrealized Gains and Losses on Marketable Securities Defined Benefit Pension and Postretirement Items Total Accumulated other comprehensive (loss) income at Jan. 1 $ (54,862 ) $ 110 $ (55,001 ) $ (109,753 ) Other comprehensive income (loss) before reclassifications 8 — (653 ) (645 ) Losses reclassified from net accumulated other comprehensive loss 1,874 — 1,729 3,603 Net current period other comprehensive income 1,882 — 1,076 2,958 Accumulated other comprehensive (loss) income at June 30 $ (52,980 ) $ 110 $ (53,925 ) $ (106,795 ) Six Months Ended June 30, 2015 (Thousands of Dollars) Gains and Losses on Cash Flow Hedges Unrealized Gains and Losses on Marketable Securities Defined Benefit Pension and Postretirement Items Total Accumulated other comprehensive (loss) income at Jan. 1 $ (57,628 ) $ 110 $ (50,621 ) $ (108,139 ) Other comprehensive income before reclassifications 7 2 — 9 Losses reclassified from net accumulated other comprehensive loss 1,185 — 1,759 2,944 Net current period other comprehensive income 1,192 2 1,759 2,953 Accumulated other comprehensive (loss) income at June 30 $ (56,436 ) $ 112 $ (48,862 ) $ (105,186 ) Reclassifications from accumulated other comprehensive loss for the three and six months ended June 30, 2016 and 2015 were as follows: Amounts Reclassified from Accumulated Other Comprehensive Loss (Thousands of Dollars) Three Months Ended June 30, 2016 Three Months Ended June 30, 2015 (Gains) losses on cash flow hedges: Interest rate derivatives $ 1,483 (a) $ 954 (a) Vehicle fuel derivatives 47 (b) 28 (b) Total, pre-tax 1,530 982 Tax benefit (594 ) (382 ) Total, net of tax 936 600 Defined benefit pension and postretirement (gains) losses: Amortization of net loss 1,478 (c) 1,533 (c) Prior service credit (64 ) (c) (89 ) (c) Total, pre-tax 1,414 1,444 Tax benefit (549 ) (561 ) Total, net of tax 865 883 Total amounts reclassified, net of tax $ 1,801 $ 1,483 Amounts Reclassified from Accumulated Other Comprehensive Loss (Thousands of Dollars) Six Months Ended June 30, 2016 Six Months Ended June 30, 2015 (Gains) losses on cash flow hedges: Interest rate derivatives $ 2,968 (a) $ 1,894 (a) Vehicle fuel derivatives 104 (b) 55 (b) Total, pre-tax 3,072 1,949 Tax benefit (1,198 ) (764 ) Total, net of tax 1,874 1,185 Defined benefit pension and postretirement (gains) losses: Amortization of net loss 2,956 (c) 3,068 (c) Prior service credit (128 ) (c) (179 ) (c) Total, pre-tax 2,828 2,889 Tax benefit (1,099 ) (1,130 ) Total, net of tax 1,729 1,759 Total amounts reclassified, net of tax $ 3,603 $ 2,944 (a) Included in interest charges. (b) Included in O&M expenses. (c) Included in the computation of net periodic pension and postretirement benefit costs. See Note 12 for details regarding these benefit plans. |
Selected Balance Sheet Data (Ta
Selected Balance Sheet Data (Tables) | 6 Months Ended |
Jun. 30, 2016 | |
Balance Sheet Related Disclosures [Abstract] | |
Accounts Receivable, Net | (Thousands of Dollars) June 30, 2016 Dec. 31, 2015 Accounts receivable, net Accounts receivable $ 735,586 $ 776,494 Less allowance for bad debts (46,022 ) (51,888 ) $ 689,564 $ 724,606 |
Inventories | (Thousands of Dollars) June 30, 2016 Dec. 31, 2015 Inventories Materials and supplies $ 304,055 $ 290,690 Fuel 164,054 202,271 Natural gas 58,676 115,623 $ 526,785 $ 608,584 |
Property, Plant and Equipment, Net | (Thousands of Dollars) June 30, 2016 Dec. 31, 2015 Property, plant and equipment, net Electric plant $ 36,990,529 $ 36,464,050 Natural gas plant 5,065,218 4,944,757 Common and other property 1,746,789 1,709,508 Plant to be retired (a) 29,853 38,249 Construction work in progress 1,687,397 1,256,949 Total property, plant and equipment 45,519,786 44,413,513 Less accumulated depreciation (14,035,591 ) (13,591,259 ) Nuclear fuel 2,461,008 2,447,251 Less accumulated amortization (2,121,921 ) (2,063,654 ) $ 31,823,282 $ 31,205,851 (a) In 2017, PSCo expects to both early retire Valmont Unit 5 and convert Cherokee Unit 4 from a coal-fueled generating facility to natural gas, as approved by the Colorado Public Utilities Commission (CPUC). Amounts are presented net of accumulated depreciation. |
Income Taxes (Tables)
Income Taxes (Tables) | 6 Months Ended |
Jun. 30, 2016 | |
Income Tax Disclosure [Abstract] | |
Earliest Open Tax Years Subject to Examination by State Taxing Authorities in the Major Operating Jurisdictions | State Audits — Xcel Energy files consolidated state tax returns based on income in its major operating jurisdictions of Colorado, Minnesota, Texas, and Wisconsin, and various other state income-based tax returns. As of June 30, 2016, Xcel Energy’s earliest open tax years that are subject to examination by state taxing authorities in its major operating jurisdictions were as follows: State Year Colorado 2009 Minnesota 2009 Texas 2009 Wisconsin 2011 |
Reconciliation of Unrecognized Tax Benefits | A reconciliation of the amount of unrecognized tax benefit is as follows: (Millions of Dollars) June 30, 2016 Dec. 31, 2015 Unrecognized tax benefit — Permanent tax positions $ 26.8 $ 25.8 Unrecognized tax benefit — Temporary tax positions 97.6 94.9 Total unrecognized tax benefit $ 124.4 $ 120.7 |
Tax Benefits Associated with NOL and Tax Credit Carryforwards | The unrecognized tax benefit amounts were reduced by the tax benefits associated with net operating loss (NOL) and tax credit carryforwards. The amounts of tax benefits associated with NOL and tax credit carryforwards are as follows: (Millions of Dollars) June 30, 2016 Dec. 31, 2015 NOL and tax credit carryforwards $ (40.4 ) $ (36.7 ) |
Rate Matters (Tables)
Rate Matters (Tables) | 6 Months Ended |
Jun. 30, 2016 | |
Public Utilities, General Disclosures [Abstract] | |
NSP-Minnesota's 2016 Multi-Year Electric Rate Case - Rate Request [Table Text Block] | The request is detailed in the table below: Request (Millions of Dollars) 2016 2017 2018 Rate request $ 194.6 $ 52.1 $ 50.4 Increase percentage 6.4 % 1.7 % 1.7 % Interim request $ 163.7 $ 44.9 N/A Rate base $ 7,800 $ 7,700 $ 7,700 |
NSP-Minnesota 2016 Electric Rate Case - Intervenor Testimony [Table Text Block] | The following table summarizes NSP-Minnesota’s estimate of the DOC’s recommendations: (Millions of Dollars) 2016 2017 Step 2018 Step Total Filed rate request $ 194.6 $ 52.1 $ 50.4 $ 297.1 DOC recommended adjustments: ROE (65.0 ) 0.3 1.0 (63.7 ) Sales forecast (39.4 ) — — (39.4 ) Property tax (5.2 ) (0.3 ) (0.1 ) (5.6 ) Depreciation life (8.0 ) 0.4 (2.2 ) (9.8 ) Purchased demand timing changes — — (19.4 ) (19.4 ) Nuclear capital costs (3.6 ) 0.8 (11.2 ) (14.0 ) Tax related items (12.2 ) 18.4 (6.9 ) (0.7 ) Operating and maintenance (O&M) (15.5 ) (17.8 ) (16.7 ) (50.0 ) Other, net (0.1 ) (0.1 ) 0.1 (0.1 ) Total DOC Adjustments (149.0 ) 1.7 (55.4 ) (202.7 ) Total DOC recommended rate increase $ 45.6 $ 53.8 $ (5.0 ) $ 94.4 Estimated non-earnings DOC adjustments: Depreciation life 8.0 (0.4 ) 2.2 9.8 Sales forecast 37.4 — — 37.4 Property tax 5.2 0.3 0.1 5.6 Purchased demand timing changes — — 19.4 19.4 Other 0.5 — — 0.5 Total estimated non-earnings adjustments 51.1 (0.1 ) 21.7 72.7 Total pre-tax earnings impact $ 96.7 $ 53.7 $ 16.7 $ 167.1 |
NSP-WI 2017 Electric and Gas Rate Request [Table Text Block] | The following table outlines the filed request: Electric Rate Request (Millions of Dollars) Request Rate base investments $ 11.0 Generation and transmission expenses (excluding fuel and purchased power) 6.8 Fuel and purchased power expenses 11.0 Subtotal 28.8 2015 fuel refund (a) (9.5 ) DOE settlement refund (1.9 ) Total electric rate increase $ 17.4 (a) In July 2016, the PSCW required NSP-Wisconsin to return the 2015 fuel refund directly to customers, rather than using it to offset the proposed 2017 rate increase, as originally proposed by NSP-Wisconsin. This decision effectively increases NSP-Wisconsin’s requested electric rate increase to $26.9 million , or 3.8 percent . |
SPS' Texas 2016 Electric Rate Case [Table Text Block] | The following table summarizes the revised net request: (Millions of Dollars) Request Capital expenditure investments $ 38.9 Change in jurisdictional allocation factors 9.8 Changes in ROE and capital structure 11.6 Estimated rate case expenses 4.5 Other, net 3.8 Total $ 68.6 |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 6 Months Ended |
Jun. 30, 2016 | |
Commitments and Contingencies Disclosure [Abstract] | |
Guarantees and Bond Indemnities Issued and Outstanding | The following table presents guarantees and bond indemnities issued and outstanding for Xcel Energy: (Millions of Dollars) June 30, 2016 Dec. 31, 2015 Guarantees issued and outstanding $ 15.9 $ 12.5 Current exposure under these guarantees 0.1 0.1 Bonds with indemnity protection 43.0 41.3 |
Borrowings and Other Financin28
Borrowings and Other Financing Instruments (Tables) | 6 Months Ended |
Jun. 30, 2016 | |
Debt Disclosure [Abstract] | |
Commercial Paper | Commercial paper outstanding for Xcel Energy was as follows: (Amounts in Millions, Except Interest Rates) Three Months Ended Year Ended Borrowing limit $ 2,750 $ 2,750 Amount outstanding at period end 447 846 Average amount outstanding 404 601 Maximum amount outstanding 841 1,360 Weighted average interest rate, computed on a daily basis 0.72 % 0.48 % Weighted average interest rate at period end 0.80 0.82 |
Credit Facilities | At June 30, 2016 , Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available: (Millions of Dollars) Credit Facility (a) Drawn (b) Available Xcel Energy Inc. $ 1,000 $ 414 $ 586 PSCo 700 3 697 NSP-Minnesota 500 18 482 SPS 400 32 368 NSP-Wisconsin 150 8 142 Total $ 2,750 $ 475 $ 2,275 (a) These credit facilities expire in June 2021 . (b) Includes outstanding commercial paper and letters of credit. |
Fair Value of Financial Asset29
Fair Value of Financial Assets and Liabilities (Tables) | 6 Months Ended |
Jun. 30, 2016 | |
Fair Value Disclosures [Abstract] | |
Cost and Fair Value of Nuclear Decommissioning Fund Investments | The following tables present the cost and fair value of Xcel Energy’s non-derivative instruments with recurring fair value measurements in the nuclear decommissioning fund at June 30, 2016 and Dec. 31, 2015 : June 30, 2016 Fair Value (Thousands of Dollars) Cost Level 1 Level 2 Level 3 Investments Measured at NAV (b) Total Nuclear decommissioning fund (a) Cash equivalents $ 15,749 $ 15,749 $ — $ — $ — $ 15,749 Commingled funds 389,700 — — — 411,788 411,788 International equity funds 259,090 — — — 236,087 236,087 Private equity investments 119,370 — — — 166,054 166,054 Real estate 72,956 — — — 102,144 102,144 Debt securities: Government securities 35,199 — 35,828 — — 35,828 U.S. corporate bonds 96,110 — 91,350 — — 91,350 International corporate bonds 19,959 — 19,394 — — 19,394 Municipal bonds 11,966 — 12,826 — — 12,826 Asset-backed securities 2,844 — 2,881 — — 2,881 Mortgage-backed securities 10,708 — 11,180 — — 11,180 Equity securities: Common stock 479,865 649,521 — — — 649,521 Total $ 1,513,516 $ 665,270 $ 173,459 $ — $ 916,073 $ 1,754,802 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $133.7 million of equity investments in unconsolidated subsidiaries and $99.0 million of rabbi trust assets and miscellaneous investments. (b) Based on the requirements of ASU 2015-07, investments measured at fair value using a NAV methodology have not been classified in the fair value hierarchy. See Note 2 for further information on the adoption of ASU 2015-07. Dec. 31, 2015 Fair Value (Thousands of Dollars) Cost Level 1 Level 2 Level 3 Investments Measured at NAV (b) Total Nuclear decommissioning fund (a) Cash equivalents $ 27,484 $ 27,484 $ — $ — $ — $ 27,484 Commingled funds 392,838 — — — 410,634 410,634 International equity funds 259,114 — — — 231,122 231,122 Private equity investments 105,965 — — — 157,528 157,528 Real estate 61,816 — — — 84,750 84,750 Debt securities: Government securities 24,444 — 21,356 — — 21,356 U.S. corporate bonds 73,061 — 65,276 — — 65,276 International corporate bonds 13,726 — 12,801 — — 12,801 Municipal bonds 49,255 — 51,589 — — 51,589 Asset-backed securities 2,837 — 2,830 — — 2,830 Mortgage-backed securities 11,444 — 11,621 — — 11,621 Equity securities: Common stock 473,615 647,159 — — — 647,159 Total $ 1,495,599 $ 674,643 $ 165,473 $ — $ 884,034 $ 1,724,150 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $130.0 million of equity investments in unconsolidated subsidiaries and $48.9 million of miscellaneous investments. (b) Based on the requirements of ASU 2015-07, investments measured at fair value using a NAV methodology have not been classified in the fair value hierarchy. See Note 2 for further information on the adoption of ASU 2015-07. |
Final Contractual Maturity Dates of Debt Securities in the Nuclear Decommissioning Fund by Asset Class | The following table summarizes the final contractual maturity dates of the debt securities in the nuclear decommissioning fund, by asset class, at June 30, 2016 : Final Contractual Maturity (Thousands of Dollars) Due in 1 Year or Less Due in 1 to 5 Years Due in 5 to 10 Years Due after 10 Years Total Government securities $ — $ 10,659 $ 982 $ 24,187 $ 35,828 U.S. corporate bonds 261 26,988 59,368 4,733 91,350 International corporate bonds — 3,966 12,368 3,060 19,394 Municipal bonds — 212 4,248 8,366 12,826 Asset-backed securities — — 2,881 — 2,881 Mortgage-backed securities — — — 11,180 11,180 Debt securities $ 261 $ 41,825 $ 79,847 $ 51,526 $ 173,459 |
Rabbi Trust Securities Amortized Cost and Fair Value Measured on Recurrring Basis [Table Text Block] | In June 2016, Xcel Energy established rabbi trusts to provide funding for future distributions of its supplemental executive retirement plan and nonqualified pension plans. The following table presents the cost and fair value of the assets held in rabbi trusts at June 30, 2016: June 30, 2016 Fair Value (Thousands of Dollars) Cost Level 1 Level 2 Level 3 Total Rabbi Trusts (a) Cash equivalents $ 47,762 $ 47,762 $ — $ — $ 47,762 Mutual funds 1,593 1,778 — — 1,778 Total $ 49,355 $ 49,540 $ — $ — $ 49,540 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet. |
Gross Notional Amounts of Commodity Forwards, Options, and FTRs | The following table details the gross notional amounts of commodity forwards, options and FTRs at June 30, 2016 and Dec. 31, 2015 : (Amounts in Thousands) (a)(b) June 30, 2016 Dec. 31, 2015 Megawatt hours of electricity 81,667 50,487 Million British thermal units of natural gas 84,578 20,874 Gallons of vehicle fuel 70 141 (a) Amounts are not reflective of net positions in the underlying commodities. (b) Notional amounts for options are included on a gross basis, but are weighted for the probability of exercise. |
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income | The following tables detail the impact of derivative activity during the three and six months ended June 30, 2016 and 2015, on accumulated other comprehensive loss, regulatory assets and liabilities, and income: Three Months Ended June 30, 2016 Pre-Tax Fair Value Gains (Losses) Recognized During the Period in: Pre-Tax Losses Reclassified into Income During the Period from: Pre-Tax Gains Recognized (Thousands of Dollars) Accumulated Other Regulatory Accumulated Other Regulatory Assets and (Liabilities) Derivatives designated as cash flow hedges Interest rate $ — $ — $ 1,483 (a) $ — $ — Vehicle fuel and other commodity 19 — 47 (b) — — Total $ 19 $ — $ 1,530 $ — $ — Other derivative instruments Commodity trading $ — $ — $ — $ — $ 481 (c) Electric commodity — (705 ) — 16,642 (d) — Natural gas commodity — 6,063 — — 25 (e) Total $ — $ 5,358 $ — $ 16,642 $ 506 Six Months Ended June 30, 2016 Pre-Tax Fair Value Gains (Losses) Recognized During the Period in: Pre-Tax Losses Reclassified into Income During the Period from: Pre-Tax Gains (Losses) Recognized (Thousands of Dollars) Accumulated Other Regulatory Accumulated Other Regulatory Assets and (Liabilities) Derivatives designated as cash flow hedges Interest rate $ — $ — $ 2,968 (a) $ — $ — Vehicle fuel and other commodity 13 — 104 (b) — — Total $ 13 $ — $ 3,072 $ — $ — Other derivative instruments Commodity trading $ — $ — $ — $ — $ 1,490 (c) Electric commodity — (970 ) — 27,533 (d) — Natural gas commodity — 3,361 — 11,666 (e) (4,999 ) (e) Total $ — $ 2,391 $ — $ 39,199 $ (3,509 ) Three Months Ended June 30, 2015 Pre-Tax Fair Value Gains (Losses) Recognized During the Period in: Pre-Tax (Gains) Losses Reclassified into Income During the Period from: Pre-Tax Gains Recognized (Thousands of Dollars) Accumulated Other Regulatory Accumulated Other Regulatory Assets and (Liabilities) Derivatives designated as cash flow hedges Interest rate $ — $ — $ 954 (a) $ — $ — Vehicle fuel and other commodity 29 — 28 (b) — — Total $ 29 $ — $ 982 $ — $ — Other derivative instruments Commodity trading $ — $ — $ — $ — $ 4,401 (c) Electric commodity — (4,737 ) — (8,037 ) (d) — Natural gas commodity — (232 ) — (22 ) (e) — Total $ — $ (4,969 ) $ — $ (8,059 ) $ 4,401 Six Months Ended June 30, 2015 Pre-Tax Fair Value Gains (Losses) Recognized During the Period in: Pre-Tax (Gains) Losses Reclassified into Income During the Period from: Pre-Tax Gains Recognized (Thousands of Dollars) Accumulated Other Regulatory Accumulated Other Regulatory Derivatives designated as cash flow hedges Interest rate $ — $ — $ 1,894 (a) $ — $ — Vehicle fuel and other commodity 11 — 55 (b) — — Total $ 11 $ — $ 1,949 $ — $ — Other derivative instruments Commodity trading $ — $ — $ — $ — $ 8,281 (c) Electric commodity — (14,208 ) — (13,160 ) (d) — Natural gas commodity — (448 ) — (8,852 ) (e) 8,991 (e) Total $ — $ (14,656 ) $ — $ (22,012 ) $ 17,272 (a) Amounts are recorded to interest charges. (b) Amounts are recorded to O&M expenses. (c) Amounts are recorded to electric operating revenues. Portions of these gains and losses are subject to sharing with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate. (d) Amounts are recorded to electric fuel and purchased power. These derivative settlement gain and loss amounts are shared with electric customers through fuel and purchased energy cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate. (e) Amounts for the three and six months ended June 30, 2016 and 2015 included an immaterial amount of settlement losses on derivatives entered to mitigate natural gas price risk for electric generation, recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate. The remaining derivative settlement gains and losses for the three and six months ended June 30, 2016 and 2015 relate to natural gas operations and are recorded to cost of natural gas sold and transported. These gains and losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset or liability, as appropriate. |
Derivative Assets and Liabilities Measured at Fair Value on a Recurring Basis by Hierarchy Level | Recurring Fair Value Measurements — The following table presents for each of the fair value hierarchy levels, Xcel Energy’s derivative assets and liabilities measured at fair value on a recurring basis at June 30, 2016 : June 30, 2016 Fair Value Fair Value Total Counterparty Netting (b) Total (Thousands of Dollars) Level 1 Level 2 Level 3 Current derivative assets Other derivative instruments: Commodity trading $ 5,384 $ 14,675 $ — $ 20,059 $ (14,017 ) $ 6,042 Electric commodity — — 28,151 28,151 (3,593 ) 24,558 Natural gas commodity — 8,525 — 8,525 (31 ) 8,494 Total current derivative assets $ 5,384 $ 23,200 $ 28,151 $ 56,735 $ (17,641 ) 39,094 PPAs (a) 7,859 Current derivative instruments $ 46,953 Noncurrent derivative assets Other derivative instruments: Commodity trading $ 1,037 $ 28,058 $ — $ 29,095 $ (6,986 ) $ 22,109 Natural gas commodity — 1,355 — 1,355 — 1,355 Total noncurrent derivative assets $ 1,037 $ 29,413 $ — $ 30,450 $ (6,986 ) 23,464 PPAs (a) 27,180 Noncurrent derivative instruments $ 50,644 June 30, 2016 Fair Value Fair Value Total Counterparty Netting (b) Total (Thousands of Dollars) Level 1 Level 2 Level 3 Current derivative liabilities Derivatives designated as cash flow hedges: Vehicle fuel and other commodity $ — $ 82 $ — $ 82 $ — $ 82 Other derivative instruments: Commodity trading 5,407 12,740 41 18,188 (14,575 ) 3,613 Electric commodity — — 3,593 3,593 (3,593 ) — Natural gas commodity — 31 — 31 (31 ) — Total current derivative liabilities $ 5,407 $ 12,853 $ 3,634 $ 21,894 $ (18,199 ) 3,695 PPAs (a) 22,847 Current derivative instruments $ 26,542 Noncurrent derivative liabilities Other derivative instruments: Commodity trading $ 1,086 $ 19,786 $ — $ 20,872 $ (11,162 ) $ 9,710 Total noncurrent derivative liabilities $ 1,086 $ 19,786 $ — $ 20,872 $ (11,162 ) 9,710 PPAs (a) 146,647 Noncurrent derivative instruments $ 156,357 (a) In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, Xcel Energy began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, Xcel Energy qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities. (b) Xcel Energy nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at June 30, 2016 . At June 30, 2016 , derivative assets and liabilities include no obligations to return cash collateral and the rights to reclaim cash collateral of $4.7 million . The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements. The following table presents for each of the fair value hierarchy levels, Xcel Energy’s derivative assets and liabilities measured at fair value on a recurring basis at Dec. 31, 2015 : Dec. 31, 2015 Fair Value Fair Value Total Counterparty Netting (b) Total (Thousands of Dollars) Level 1 Level 2 Level 3 Current derivative assets Other derivative instruments: Commodity trading $ 225 $ 10,620 $ 1,250 $ 12,095 $ (5,865 ) $ 6,230 Electric commodity — — 21,421 21,421 (4,088 ) 17,333 Natural gas commodity — 496 — 496 (303 ) 193 Total current derivative assets $ 225 $ 11,116 $ 22,671 $ 34,012 $ (10,256 ) 23,756 PPAs (a) 10,086 Current derivative instruments $ 33,842 Noncurrent derivative assets Other derivative instruments: Commodity trading $ — $ 27,416 $ — $ 27,416 $ (6,555 ) $ 20,861 Total noncurrent derivative assets $ — $ 27,416 $ — $ 27,416 $ (6,555 ) 20,861 PPAs (a) 30,222 Noncurrent derivative instruments $ 51,083 Dec. 31, 2015 Fair Value Fair Value Total Counterparty Netting (b) Total (Thousands of Dollars) Level 1 Level 2 Level 3 Current derivative liabilities Derivatives designated as cash flow hedges: Vehicle fuel and other commodity $ — $ 205 $ — $ 205 $ — $ 205 Other derivative instruments: Commodity trading 152 7,866 555 8,573 (6,904 ) 1,669 Electric commodity — — 4,088 4,088 (4,088 ) — Natural gas commodity — 5,407 — 5,407 (303 ) 5,104 Total current derivative liabilities $ 152 $ 13,478 $ 4,643 $ 18,273 $ (11,295 ) 6,978 PPAs (a) 22,861 Current derivative instruments $ 29,839 Noncurrent derivative liabilities Other derivative instruments: Commodity trading $ — $ 19,898 $ — $ 19,898 $ (9,780 ) $ 10,118 Total noncurrent derivative liabilities $ — $ 19,898 $ — $ 19,898 $ (9,780 ) 10,118 PPAs (a) 158,193 Noncurrent derivative instruments $ 168,311 (a) In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, Xcel Energy began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, Xcel Energy qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities. (b) Xcel Energy nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2015 . At Dec. 31, 2015 , derivative assets and liabilities include no obligations to return cash collateral and rights to reclaim cash collateral of $4.3 million . The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements. |
Changes in Level 3 Commodity Derivatives | The following table presents the changes in Level 3 commodity derivatives for the three and six months ended June 30, 2016 and 2015 : Three Months Ended June 30 (Thousands of Dollars) 2016 2015 Balance at April 1 $ 6,854 $ 17,429 Purchases 29,826 57,446 Settlements (14,111 ) (17,315 ) Net transactions recorded during the period: (Losses) gains recognized in earnings (a) (18 ) 1,220 Gains (losses) recognized as regulatory assets and liabilities 1,966 (11,953 ) Balance at June 30 $ 24,517 $ 46,827 Six Months Ended June 30 (Thousands of Dollars) 2016 2015 Balance at Jan. 1 $ 18,028 $ 56,155 Purchases 31,670 63,238 Settlements (26,161 ) (37,246 ) Net transactions recorded during the period: (Losses) gains recognized in earnings (a) (43 ) 1,280 Gains (losses) recognized as regulatory assets and liabilities 1,023 (36,600 ) Balance at June 30 $ 24,517 $ 46,827 (a) These amounts relate to commodity derivatives held at the end of the period. |
Carrying Amount and Fair Value of Long-term Debt | As of June 30, 2016 and Dec. 31, 2015 , other financial instruments for which the carrying amount did not equal fair value were as follows: June 30, 2016 Dec. 31, 2015 (Thousands of Dollars) Carrying Amount Fair Value Carrying Amount Fair Value Long-term debt, including current portion (a) $ 13,814,921 $ 15,935,100 $ 13,055,901 $ 14,094,744 (a) Amounts reflect the classification of debt issuance costs as a deduction from the carrying amount of the related debt. See Note 2, Accounting Pronouncements for more information on the adoption of ASU 2015-03. |
Other Income, Net (Tables)
Other Income, Net (Tables) | 6 Months Ended |
Jun. 30, 2016 | |
Other Income and Expenses [Abstract] | |
Other Income, Net | Other income, net consisted of the following: Three Months Ended June 30 Six Months Ended June 30 (Thousands of Dollars) 2016 2015 2016 2015 Interest income $ 984 $ 389 $ 5,054 $ 4,627 Other nonoperating income 1,496 794 2,176 1,762 Insurance policy expense (920 ) (222 ) (1,420 ) (2,267 ) Other income, net $ 1,560 $ 961 $ 5,810 $ 4,122 |
Segment Information (Tables)
Segment Information (Tables) | 6 Months Ended |
Jun. 30, 2016 | |
Segment Reporting [Abstract] | |
Results from Operations by Reportable Segment | (Thousands of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total Three Months Ended June 30, 2016 Operating revenues from external customers $ 2,224,142 $ 258,899 $ 16,808 $ — $ 2,499,849 Intersegment revenues 421 241 — (662 ) — Total revenues $ 2,224,563 $ 259,140 $ 16,808 $ (662 ) $ 2,499,849 Net income (loss) $ 205,440 $ 11,933 $ (20,578 ) $ — $ 196,795 (Thousands of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total Three Months Ended June 30, 2015 Operating revenues from external customers $ 2,213,460 $ 284,131 $ 17,543 $ — $ 2,515,134 Intersegment revenues 420 172 — (592 ) — Total revenues $ 2,213,880 $ 284,303 $ 17,543 $ (592 ) $ 2,515,134 Net income (loss) $ 214,955 $ (6,883 ) $ (11,141 ) $ — $ 196,931 (Thousands of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total Six Months Ended June 30, 2016 Operating revenues from external customers $ 4,409,261 $ 824,588 $ 38,273 $ — $ 5,272,122 Intersegment revenues 756 528 — (1,284 ) — Total revenues $ 4,410,017 $ 825,116 $ 38,273 $ (1,284 ) $ 5,272,122 Net income (loss) $ 383,677 $ 90,271 $ (35,841 ) $ — $ 438,107 (Thousands of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total Six Months Ended June 30, 2015 Operating revenues from external customers $ 4,438,323 $ 1,000,127 $ 38,903 $ — $ 5,477,353 Intersegment revenues 750 848 — (1,598 ) — Total revenues $ 4,439,073 $ 1,000,975 $ 38,903 $ (1,598 ) $ 5,477,353 Net income (loss) $ 295,976 (a) $ 76,793 $ (23,772 ) $ — $ 348,997 (a) Includes a net of tax charge related to the Monticello LCM/EPU project. See Note 5. |
Earnings Per Share (Tables)
Earnings Per Share (Tables) | 6 Months Ended |
Jun. 30, 2016 | |
Earnings Per Share [Abstract] | |
Dilutive Impact of Common Stock Equivalents | The dilutive impact of common stock equivalents affecting EPS was as follows: Three Months Ended June 30, 2016 Three Months Ended June 30, 2015 (Amounts in thousands, except per share data) Income Shares Per Share Amount Income Shares Per Share Amount Net income $ 196,795 — — $ 196,931 — — Basic EPS: Earnings available to common shareholders 196,795 508,930 $ 0.39 196,931 507,707 $ 0.39 Effect of dilutive securities: Time based equity awards — 560 — — 367 — Diluted EPS: Earnings available to common shareholders $ 196,795 509,490 $ 0.39 $ 196,931 508,074 $ 0.39 Six Months Ended June 30, 2016 Six Months Ended June 30, 2015 (Amounts in thousands, except per share data) Income Shares Per Share Amount Income Shares Per Share Amount Net income $ 438,107 — — $ 348,997 — — Basic EPS: Earnings available to common shareholders 438,107 508,789 $ 0.86 348,997 507,359 $ 0.69 Effect of dilutive securities: Time based equity awards — 522 — — 388 — Diluted EPS: Earnings available to common shareholders $ 438,107 509,311 $ 0.86 $ 348,997 507,747 $ 0.69 |
Benefit Plans and Other Postr33
Benefit Plans and Other Postretirement Benefits (Tables) | 6 Months Ended |
Jun. 30, 2016 | |
Compensation and Retirement Disclosure [Abstract] | |
Components of Net Periodic Benefit Cost (Credit) | Components of Net Periodic Benefit Cost (Credit) Three Months Ended June 30 2016 2015 2016 2015 (Thousands of Dollars) Pension Benefits Postretirement Health Service cost $ 22,945 $ 24,828 $ 431 $ 529 Interest cost 40,028 37,131 6,526 6,324 Expected return on plan assets (52,575 ) (53,472 ) (6,248 ) (6,650 ) Amortization of prior service credit (477 ) (451 ) (2,671 ) (2,671 ) Amortization of net loss 24,385 31,288 1,009 1,351 Net periodic benefit cost (credit) 34,306 39,324 (953 ) (1,117 ) Costs not recognized due to the effects of regulation (4,159 ) (7,523 ) — — Net benefit cost (credit) recognized for financial reporting $ 30,147 $ 31,801 $ (953 ) $ (1,117 ) Six Months Ended June 30 2016 2015 2016 2015 (Thousands of Dollars) Pension Benefits Postretirement Health Service cost $ 45,865 $ 49,656 $ 863 $ 1,058 Interest cost 80,051 74,262 13,053 12,648 Expected return on plan assets (105,150 ) (106,945 ) (12,497 ) (13,300 ) Amortization of prior service credit (961 ) (902 ) (5,343 ) (5,343 ) Amortization of net loss 48,770 62,576 2,020 2,702 Net periodic benefit cost (credit) 68,575 78,647 (1,904 ) (2,235 ) Costs not recognized due to the effects of regulation (8,611 ) (15,019 ) — — Net benefit cost (credit) recognized for financial reporting $ 59,964 $ 63,628 $ (1,904 ) $ (2,235 ) |
Other Comprehensive Income (Tab
Other Comprehensive Income (Tables) | 6 Months Ended |
Jun. 30, 2016 | |
Stockholders' Equity Note [Abstract] | |
Changes in Accumulated Other Comprehensive Income (Loss), Net of Tax | Changes in accumulated other comprehensive (loss) income, net of tax, for the three and six months ended June 30, 2016 and 2015 were as follows: Three Months Ended June 30, 2016 (Thousands of Dollars) Gains and Losses on Cash Flow Hedges Unrealized Gains and Losses on Marketable Securities Defined Benefit Pension and Postretirement Items Total Accumulated other comprehensive (loss) income at April 1 $ (53,928 ) $ 110 $ (54,790 ) $ (108,608 ) Other comprehensive income before reclassifications 12 — — 12 Losses reclassified from net accumulated other comprehensive loss 936 — 865 1,801 Net current period other comprehensive income 948 — 865 1,813 Accumulated other comprehensive (loss) income at June 30 $ (52,980 ) $ 110 $ (53,925 ) $ (106,795 ) Three Months Ended June 30, 2015 (Thousands of Dollars) Gains and Losses on Cash Flow Hedges Unrealized Gains and Losses on Marketable Securities Defined Benefit Pension and Total Accumulated other comprehensive (loss) income at April 1 $ (57,054 ) $ 111 $ (49,745 ) $ (106,688 ) Other comprehensive income before reclassifications 18 1 — 19 Losses reclassified from net accumulated other comprehensive loss 600 — 883 1,483 Net current period other comprehensive income 618 1 883 1,502 Accumulated other comprehensive (loss) income at June 30 $ (56,436 ) $ 112 $ (48,862 ) $ (105,186 ) Six Months Ended June 30, 2016 (Thousands of Dollars) Gains and Losses on Cash Flow Hedges Unrealized Gains and Losses on Marketable Securities Defined Benefit Pension and Postretirement Items Total Accumulated other comprehensive (loss) income at Jan. 1 $ (54,862 ) $ 110 $ (55,001 ) $ (109,753 ) Other comprehensive income (loss) before reclassifications 8 — (653 ) (645 ) Losses reclassified from net accumulated other comprehensive loss 1,874 — 1,729 3,603 Net current period other comprehensive income 1,882 — 1,076 2,958 Accumulated other comprehensive (loss) income at June 30 $ (52,980 ) $ 110 $ (53,925 ) $ (106,795 ) Six Months Ended June 30, 2015 (Thousands of Dollars) Gains and Losses on Cash Flow Hedges Unrealized Gains and Losses on Marketable Securities Defined Benefit Pension and Postretirement Items Total Accumulated other comprehensive (loss) income at Jan. 1 $ (57,628 ) $ 110 $ (50,621 ) $ (108,139 ) Other comprehensive income before reclassifications 7 2 — 9 Losses reclassified from net accumulated other comprehensive loss 1,185 — 1,759 2,944 Net current period other comprehensive income 1,192 2 1,759 2,953 Accumulated other comprehensive (loss) income at June 30 $ (56,436 ) $ 112 $ (48,862 ) $ (105,186 ) |
Reclassifications out of Accumulated Other Comprehensive Loss | Reclassifications from accumulated other comprehensive loss for the three and six months ended June 30, 2016 and 2015 were as follows: Amounts Reclassified from Accumulated Other Comprehensive Loss (Thousands of Dollars) Three Months Ended June 30, 2016 Three Months Ended June 30, 2015 (Gains) losses on cash flow hedges: Interest rate derivatives $ 1,483 (a) $ 954 (a) Vehicle fuel derivatives 47 (b) 28 (b) Total, pre-tax 1,530 982 Tax benefit (594 ) (382 ) Total, net of tax 936 600 Defined benefit pension and postretirement (gains) losses: Amortization of net loss 1,478 (c) 1,533 (c) Prior service credit (64 ) (c) (89 ) (c) Total, pre-tax 1,414 1,444 Tax benefit (549 ) (561 ) Total, net of tax 865 883 Total amounts reclassified, net of tax $ 1,801 $ 1,483 Amounts Reclassified from Accumulated Other Comprehensive Loss (Thousands of Dollars) Six Months Ended June 30, 2016 Six Months Ended June 30, 2015 (Gains) losses on cash flow hedges: Interest rate derivatives $ 2,968 (a) $ 1,894 (a) Vehicle fuel derivatives 104 (b) 55 (b) Total, pre-tax 3,072 1,949 Tax benefit (1,198 ) (764 ) Total, net of tax 1,874 1,185 Defined benefit pension and postretirement (gains) losses: Amortization of net loss 2,956 (c) 3,068 (c) Prior service credit (128 ) (c) (179 ) (c) Total, pre-tax 2,828 2,889 Tax benefit (1,099 ) (1,130 ) Total, net of tax 1,729 1,759 Total amounts reclassified, net of tax $ 3,603 $ 2,944 (a) Included in interest charges. (b) Included in O&M expenses. (c) Included in the computation of net periodic pension and postretirement benefit costs. See Note 12 for details regarding these benefit plans. |
Accounting Pronouncements Debt
Accounting Pronouncements Debt Issuance Costs (Details) - Accounting Standards Update 2015-03 - USD ($) $ in Millions | Mar. 31, 2016 | Dec. 31, 2015 |
Long-term Debt | ||
Debt Instrument [Line Items] | ||
Reclassification of deferred debt issuance costs, net | $ 94.5 | $ 91.8 |
Other Noncurrent Assets | ||
Debt Instrument [Line Items] | ||
Reclassification of deferred debt issuance costs, net | $ (91.8) |
Balance Sheet Data, Accounts Re
Balance Sheet Data, Accounts Receivable (Details) - USD ($) $ in Thousands | Jun. 30, 2016 | Dec. 31, 2015 |
Accounts receivable, net | ||
Accounts receivable | $ 735,586 | $ 776,494 |
Less allowance for bad debts | (46,022) | (51,888) |
Accounts receivable, net | $ 689,564 | $ 724,606 |
Balance Sheet Related Disclosur
Balance Sheet Related Disclosures, Inventories (Details) - USD ($) $ in Thousands | Jun. 30, 2016 | Dec. 31, 2015 |
Public Utilities, Inventory [Line Items] | ||
Inventories | $ 526,785 | $ 608,584 |
Materials and supplies | ||
Public Utilities, Inventory [Line Items] | ||
Inventories | 304,055 | 290,690 |
Fuel | ||
Public Utilities, Inventory [Line Items] | ||
Inventories | 164,054 | 202,271 |
Natural gas | ||
Public Utilities, Inventory [Line Items] | ||
Inventories | $ 58,676 | $ 115,623 |
Balance Sheet Related Disclos38
Balance Sheet Related Disclosures, Property, Plant and Equipment (Details) - USD ($) $ in Thousands | Jun. 30, 2016 | Dec. 31, 2015 | |
Public Utility, Property, Plant and Equipment [Line Items] | |||
Property, plant and equipment, gross | $ 45,519,786 | $ 44,413,513 | |
Less accumulated depreciation | (14,035,591) | (13,591,259) | |
Property, plant and equipment, net | 31,823,282 | 31,205,851 | |
Electric plant | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Property, plant and equipment, gross | 36,990,529 | 36,464,050 | |
Natural gas plant | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Property, plant and equipment, gross | 5,065,218 | 4,944,757 | |
Common and other property | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Property, plant and equipment, gross | 1,746,789 | 1,709,508 | |
Plant to be retired | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Property, plant and equipment, gross | [1] | 29,853 | 38,249 |
Construction work in progress | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Property, plant and equipment, gross | 1,687,397 | 1,256,949 | |
Nuclear fuel | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Property, plant and equipment, gross | 2,461,008 | 2,447,251 | |
Less accumulated depreciation | $ (2,121,921) | $ (2,063,654) | |
[1] | In 2017, PSCo expects to both early retire Valmont Unit 5 and convert Cherokee Unit 4 from a coal-fueled generating facility to natural gas, as approved by the Colorado Public Utilities Commission (CPUC). Amounts are presented net of accumulated depreciation. |
Income Taxes (Details)
Income Taxes (Details) - USD ($) | 1 Months Ended | 6 Months Ended | 9 Months Ended | 12 Months Ended | ||||
Jun. 30, 2016 | Feb. 29, 2016 | Jun. 30, 2016 | Sep. 30, 2015 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Income Tax Examination [Line Items] | ||||||||
Number Of Years Of Tax Loss Carryback Period | 2 years | |||||||
Tax Adjustments, Settlements, and Unusual Provisions | $ 5,000,000 | $ 17,000,000 | $ 12,000,000 | $ 15,000,000 | ||||
Unrecognized Tax Benefits [Abstract] | ||||||||
Unrecognized tax benefit — Permanent tax positions | $ 26,800,000 | $ 26,800,000 | 25,800,000 | |||||
Unrecognized tax benefit — Temporary tax positions | 97,600,000 | 97,600,000 | 94,900,000 | |||||
Total unrecognized tax benefit | 124,400,000 | 124,400,000 | 120,700,000 | |||||
NOL and tax credit carryforwards | (40,400,000) | (40,400,000) | (36,700,000) | |||||
Upper bound of decrease in unrecognized tax benefit that is reasonably possible | 58,000,000 | 58,000,000 | ||||||
Amounts accrued for penalties related to unrecognized tax benefits | $ 0 | 0 | $ 0 | |||||
Internal Revenue Service (IRS) | ||||||||
Tax Audits [Abstract] | ||||||||
Year(s) under examination | 2012 and 2013 | 2010 and 2011 | ||||||
Year of carryback claim under examination | 2,009 | |||||||
Potential Tax Adjustments | $ 14,000,000 | |||||||
Earliest year subject to examination | 2,009 | |||||||
Colorado | ||||||||
Tax Audits [Abstract] | ||||||||
Earliest year subject to examination | 2,009 | |||||||
Minnesota | ||||||||
Tax Audits [Abstract] | ||||||||
Year(s) under examination | 2010 through 2014 | |||||||
Earliest year subject to examination | 2,009 | |||||||
Texas | ||||||||
Tax Audits [Abstract] | ||||||||
Year(s) under examination | 2009 and 2010 | |||||||
Earliest year subject to examination | 2,009 | |||||||
Wisconsin | ||||||||
Tax Audits [Abstract] | ||||||||
Earliest year subject to examination | 2,011 |
Rate Matters, NSP-Minnesota (De
Rate Matters, NSP-Minnesota (Details) $ in Thousands | Jun. 30, 2016 | Jan. 06, 2015 | Jul. 31, 2016USD ($) | Jun. 30, 2016USD ($) | Dec. 31, 2015 | Nov. 30, 2015USD ($) | Mar. 31, 2015USD ($) | Feb. 28, 2015 | Nov. 30, 2013 | Jun. 30, 2016USD ($) | Jun. 30, 2015USD ($) | Mar. 31, 2015USD ($) | Jun. 30, 2016USD ($) | Jun. 30, 2015USD ($) | Dec. 31, 2015MW | Dec. 31, 2013USD ($) | Dec. 31, 2008USD ($) |
Rate Matters [Abstract] | |||||||||||||||||
Loss on Monticello life cycle management/extended power uprate project | $ 0 | $ 0 | $ 0 | $ 129,463 | |||||||||||||
NSP-Minnesota | MPUC Proceeding - Minnesota 2016 Multi-Year Electric Rate Case | |||||||||||||||||
Rate Matters [Abstract] | |||||||||||||||||
Public Utilities, Number Of Years Rate Case Is Applicable For | 3 years | ||||||||||||||||
Public Utilities, Requested Return on Equity, Percentage | 10.00% | ||||||||||||||||
Public Utilities, Requested Equity Capital Structure, Percentage | 52.50% | ||||||||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 297,100 | ||||||||||||||||
NSP-Minnesota | MPUC Proceeding - Minnesota 2016 Multi-Year Electric Rate Case, Rates 2016 | |||||||||||||||||
Rate Matters [Abstract] | |||||||||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 194,600 | ||||||||||||||||
Public Utilities, Requested Rate Increase (Decrease), Percentage | 6.40% | ||||||||||||||||
Public Utilities, Requested Rate Base, Amount | $ 7,800,000 | ||||||||||||||||
NSP-Minnesota | MPUC Proceeding - Minnesota 2016 Multi-Year Electric Rate Case, Rates 2017 | |||||||||||||||||
Rate Matters [Abstract] | |||||||||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 52,100 | ||||||||||||||||
Public Utilities, Requested Rate Increase (Decrease), Percentage | 1.70% | ||||||||||||||||
Public Utilities, Requested Interim Rate Increase (Decrease), Amount | $ 44,900 | ||||||||||||||||
Public Utilities, Requested Rate Base, Amount | 7,700,000 | ||||||||||||||||
NSP-Minnesota | MPUC Proceeding - Minnesota 2016 Multi-Year Electric Rate Case, Rates 2018 | |||||||||||||||||
Rate Matters [Abstract] | |||||||||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 50,400 | ||||||||||||||||
Public Utilities, Requested Rate Increase (Decrease), Percentage | 1.70% | ||||||||||||||||
Public Utilities, Requested Rate Base, Amount | $ 7,700,000 | ||||||||||||||||
NSP-Minnesota | MPUC Proceeding - Nuclear Project Prudency Investigation | |||||||||||||||||
Rate Matters [Abstract] | |||||||||||||||||
Nuclear Project Expenditures, Amount | $ 665,000 | ||||||||||||||||
Total Capitalized Nuclear Project Costs | $ 748,000 | ||||||||||||||||
Initial Estimated Nuclear Project Expenditures | $ 320,000 | ||||||||||||||||
Loss on Monticello life cycle management/extended power uprate project | $ 129,000 | ||||||||||||||||
NSP-Minnesota | FERC Proceeding, MISO ROE Complaint | |||||||||||||||||
Rate Matters [Abstract] | |||||||||||||||||
Public Utilities, Base Return On Equity Charged To Customers Through Transmission Formula Rates | 12.38% | 12.38% | |||||||||||||||
Public Utilities, ROE Applicable To Transmission Formula Rates In The Regional Transmission Operator's Region, Recommended By Third Parties | 8.67% | 9.15% | |||||||||||||||
Public Utilities, Maximum Equity Capital Structure Percentage Allowed Per The Complaint | 50.00% | ||||||||||||||||
NSP-Minnesota | Minnesota Department of Commerce | MPUC Proceeding - Minnesota 2016 Multi-Year Electric Rate Case | |||||||||||||||||
Rate Matters [Abstract] | |||||||||||||||||
Public Utilities, Rate Increase (Decrease) Recommended by Third Parties | $ 94,400 | ||||||||||||||||
Public Utilities, Return on Equity Recommended by Third Parties | 9.06% | ||||||||||||||||
Public Utilities, Equity Capital Structure Recommended by Third Parties | 52.50% | ||||||||||||||||
Public Utilities, Increase from Non-Earnings Adjustments, Recommended by Third Parties | $ 72,700 | ||||||||||||||||
Public Utilities, Decrease to Requested Return on Equity | (63,700) | ||||||||||||||||
Public Utilities, Decrease Related to Sales Forecast | (39,400) | ||||||||||||||||
Public Utilities, Decrease Related to Property Taxes | (5,600) | ||||||||||||||||
Public Utilities, Decrease Related to Depreciation Life | (9,800) | ||||||||||||||||
Public Utilities, Increase Related to Depreciation Life | 9,800 | ||||||||||||||||
Public Utilities, Decrease Related to Purchased Demand Timing | (19,400) | ||||||||||||||||
Public Utilities, Decrease Related to Nuclear Capital Costs | (14,000) | ||||||||||||||||
Public Utilities, Decrease Related to Tax Related Items | (700) | ||||||||||||||||
Public Utilities, Decrease Related to Operating and Maintenance Costs | (50,000) | ||||||||||||||||
Public Utilities, Decrease Related to Other, Net | (100) | ||||||||||||||||
Public Utilities, Total Decreases Recommended by Third Parties | (202,700) | ||||||||||||||||
Public Utilities, Increase Related to Sales Forecast | 37,400 | ||||||||||||||||
Public Utilities, Increase Related To Property Taxes | 5,600 | ||||||||||||||||
Public Utilities, Increase Related to Purchased Demand Timing | 19,400 | ||||||||||||||||
Public Utilities, Increase Related To Other | 500 | ||||||||||||||||
Public Utilities, Earnings Impact, Pre-tax | 167,100 | ||||||||||||||||
Public Utilities, Portion of Capital Costs on which Third Parties Recommend No Recovery | 15,000 | ||||||||||||||||
NSP-Minnesota | Minnesota Department of Commerce | MPUC Proceeding - Minnesota 2016 Multi-Year Electric Rate Case, Rates 2016 | |||||||||||||||||
Rate Matters [Abstract] | |||||||||||||||||
Public Utilities, Rate Increase (Decrease) Recommended by Third Parties | 45,600 | ||||||||||||||||
Public Utilities, Increase from Non-Earnings Adjustments, Recommended by Third Parties | 51,100 | ||||||||||||||||
Public Utilities, Decrease to Requested Return on Equity | (65,000) | ||||||||||||||||
Public Utilities, Decrease Related to Sales Forecast | (39,400) | ||||||||||||||||
Public Utilities, Decrease Related to Property Taxes | (5,200) | ||||||||||||||||
Public Utilities, Decrease Related to Depreciation Life | (8,000) | ||||||||||||||||
Public Utilities, Increase Related to Depreciation Life | 8,000 | ||||||||||||||||
Public Utilities, Decrease Related to Purchased Demand Timing | 0 | ||||||||||||||||
Public Utilities, Decrease Related to Nuclear Capital Costs | (3,600) | ||||||||||||||||
Public Utilities, Decrease Related to Tax Related Items | (12,200) | ||||||||||||||||
Public Utilities, Decrease Related to Operating and Maintenance Costs | (15,500) | ||||||||||||||||
Public Utilities, Decrease Related to Other, Net | (100) | ||||||||||||||||
Public Utilities, Total Decreases Recommended by Third Parties | (149,000) | ||||||||||||||||
Public Utilities, Increase Related to Sales Forecast | 37,400 | ||||||||||||||||
Public Utilities, Increase Related To Property Taxes | 5,200 | ||||||||||||||||
Public Utilities, Increase Related to Purchased Demand Timing | 0 | ||||||||||||||||
Public Utilities, Increase Related To Other | 500 | ||||||||||||||||
Public Utilities, Earnings Impact, Pre-tax | 96,700 | ||||||||||||||||
NSP-Minnesota | Minnesota Department of Commerce | MPUC Proceeding - Minnesota 2016 Multi-Year Electric Rate Case, Rates 2017 | |||||||||||||||||
Rate Matters [Abstract] | |||||||||||||||||
Public Utilities, Rate Increase (Decrease) Recommended by Third Parties | 53,800 | ||||||||||||||||
Public Utilities, Increase to Requested Return on Equity | 300 | ||||||||||||||||
Public Utilities, Decrease Related to Sales Forecast | 0 | ||||||||||||||||
Public Utilities, Decrease Related to Property Taxes | (300) | ||||||||||||||||
Public Utilities, Decrease Related to Depreciation Life | (400) | ||||||||||||||||
Public Utilities, Increase Related to Depreciation Life | 400 | ||||||||||||||||
Public Utilities, Decrease Related to Purchased Demand Timing | 0 | ||||||||||||||||
Public Utilities, Increase Related to Nuclear Capital Costs | 800 | ||||||||||||||||
Public Utilities, Increase Related to Tax Related Items | 18,400 | ||||||||||||||||
Public Utilities, Decrease Related to Operating and Maintenance Costs | (17,800) | ||||||||||||||||
Public Utilities, Decrease Related to Other, Net | (100) | ||||||||||||||||
Public Utilities, Total Increases Recommended by Third Parties | 1,700 | ||||||||||||||||
Public Utilities, Increase Related to Sales Forecast | 0 | ||||||||||||||||
Public Utilities, Increase Related To Property Taxes | 300 | ||||||||||||||||
Public Utilities, Increase Related to Purchased Demand Timing | 0 | ||||||||||||||||
Public Utilities, Increase Related To Other | 0 | ||||||||||||||||
Public Utilities, Decrease from Non-Earnings Adjustments, Recommended by Third Parties | (100) | ||||||||||||||||
Public Utilities, Earnings Impact, Pre-tax | 53,700 | ||||||||||||||||
NSP-Minnesota | Minnesota Department of Commerce | MPUC Proceeding - Minnesota 2016 Multi-Year Electric Rate Case, Rates 2018 | |||||||||||||||||
Rate Matters [Abstract] | |||||||||||||||||
Public Utilities, Rate Increase (Decrease) Recommended by Third Parties | (5,000) | ||||||||||||||||
Public Utilities, Increase from Non-Earnings Adjustments, Recommended by Third Parties | 21,700 | ||||||||||||||||
Public Utilities, Increase to Requested Return on Equity | 1,000 | ||||||||||||||||
Public Utilities, Decrease Related to Sales Forecast | 0 | ||||||||||||||||
Public Utilities, Decrease Related to Property Taxes | (100) | ||||||||||||||||
Public Utilities, Decrease Related to Depreciation Life | (2,200) | ||||||||||||||||
Public Utilities, Increase Related to Depreciation Life | 2,200 | ||||||||||||||||
Public Utilities, Decrease Related to Purchased Demand Timing | (19,400) | ||||||||||||||||
Public Utilities, Decrease Related to Nuclear Capital Costs | (11,200) | ||||||||||||||||
Public Utilities, Decrease Related to Tax Related Items | (6,900) | ||||||||||||||||
Public Utilities, Decrease Related to Operating and Maintenance Costs | (16,700) | ||||||||||||||||
Public Utilities, Increase Related To Other, Net | 100 | ||||||||||||||||
Public Utilities, Total Decreases Recommended by Third Parties | (55,400) | ||||||||||||||||
Public Utilities, Increase Related to Sales Forecast | 0 | ||||||||||||||||
Public Utilities, Increase Related To Property Taxes | 100 | ||||||||||||||||
Public Utilities, Increase Related to Purchased Demand Timing | 19,400 | ||||||||||||||||
Public Utilities, Increase Related To Other | 0 | ||||||||||||||||
Public Utilities, Earnings Impact, Pre-tax | $ 16,700 | ||||||||||||||||
NSP-Minnesota | Minnesota Public Utilities Commission | MPUC Proceeding - Minnesota 2016 Multi-Year Electric Rate Case, Rates 2016 | |||||||||||||||||
Rate Matters [Abstract] | |||||||||||||||||
Public Utilities, Approved Interim Rate Increase (Decrease), Amount | $ 163,700 | ||||||||||||||||
NSP-Minnesota | Minnesota Public Utilities Commission | MPUC Proceeding - Nuclear Project Prudency Investigation | |||||||||||||||||
Rate Matters [Abstract] | |||||||||||||||||
Public Utilities, Amount Of Recoverable Investment, With Return | $ 415,000 | ||||||||||||||||
Public Utilities, Amount Of Recoverable Investment, Without A Return | $ 333,000 | ||||||||||||||||
Public Utilities, Percentage Of Investment Considered Used And Useful | 50.00% | ||||||||||||||||
NSP-Minnesota | Administrative Law Judge | FERC Proceeding, MISO ROE Complaint | |||||||||||||||||
Rate Matters [Abstract] | |||||||||||||||||
Public Utilities, ROE Applicable To Transmission Formula Rates In The Regional Transmission Operator's Region, Recommended By Third Parties | 9.70% | 10.32% | |||||||||||||||
Public Utilities, Length of Refund Period, Recommended by Third Parties | 15 months | ||||||||||||||||
NSP-Minnesota | MPUC, NDPSC, SDPUC, and DOC | FERC Proceeding, MISO ROE Complaint | |||||||||||||||||
Rate Matters [Abstract] | |||||||||||||||||
Public Utilities, ROE Applicable To Transmission Formula Rates In The MISO Region, Upper Bound, Percentage | 8.82% | ||||||||||||||||
Public Utilities, ROE Applicable To Transmission Formula Rates In The MISO Region, Lower Bound, Percentage | 8.81% | ||||||||||||||||
NSP-Minnesota | MISO TOs | FERC Proceeding, MISO ROE Complaint | |||||||||||||||||
Rate Matters [Abstract] | |||||||||||||||||
Public Utilities, ROE Applicable To Transmission Formula Rates In The Regional Transmission Operator's Region, Recommended By Third Parties | 10.92% | ||||||||||||||||
NSP-Minnesota | FERC Staff | FERC Proceeding, MISO ROE Complaint | |||||||||||||||||
Rate Matters [Abstract] | |||||||||||||||||
Public Utilities, ROE Applicable To Transmission Formula Rates In The Regional Transmission Operator's Region, Recommended By Third Parties | 8.78% | ||||||||||||||||
NSP-Minnesota | Federal Energy Regulatory Commission (FERC) | FERC Proceeding, MISO ROE Complaint | |||||||||||||||||
Rate Matters [Abstract] | |||||||||||||||||
Public Utilities, ROE Basis Point Adder Requested By Third Parties | 50 | ||||||||||||||||
Minimum | NSP-Minnesota | MPUC Proceeding - Nuclear Project Prudency Investigation | |||||||||||||||||
Rate Matters [Abstract] | |||||||||||||||||
Public Utilities, Facility Generating Capacity, in MW | MW | 600 | ||||||||||||||||
Minimum | NSP-Minnesota | FERC Proceeding, MISO ROE Complaint | |||||||||||||||||
Rate Matters [Abstract] | |||||||||||||||||
Public Utilities, Decrease In Transmission Revenue, Net Of Expense, Due To New ROE Methodology | $ 8,000 | ||||||||||||||||
Maximum | NSP-Minnesota | MPUC Proceeding - Nuclear Project Prudency Investigation | |||||||||||||||||
Rate Matters [Abstract] | |||||||||||||||||
Public Utilities, Facility Generating Capacity, in MW | MW | 671 | ||||||||||||||||
Maximum | NSP-Minnesota | FERC Proceeding, MISO ROE Complaint | |||||||||||||||||
Rate Matters [Abstract] | |||||||||||||||||
Public Utilities, Decrease In Transmission Revenue, Net Of Expense, Due To New ROE Methodology | $ 10,000 | ||||||||||||||||
Subsequent Event | NSP-Minnesota | Minnesota Public Utilities Commission | Gas Utility Infrastructure Cost Rider 2016 | |||||||||||||||||
Rate Matters [Abstract] | |||||||||||||||||
Public Utilities, Approved Rider Revenue, Amount | $ 15,000 | ||||||||||||||||
Public Utilities, Approved Return on Equity, Percentage | 9.64% | ||||||||||||||||
Public Utilities, Length of Recovery Period, In Months | 15 months |
Rate Matters Rate Matters - NSP
Rate Matters Rate Matters - NSP-Wisconsin (Details) - NSP-Wisconsin - USD ($) $ in Millions | 1 Months Ended | ||
Jul. 31, 2016 | Apr. 30, 2016 | ||
PSCW Proceeding - Wisconsin 2017 Electric and Gas Rate Case - Electric Rates 2017 | |||
Public Utilities, General Disclosures [Line Items] | |||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 17.4 | ||
Public Utilities, Requested Rate Increase (Decrease), Percentage | 2.40% | ||
Public utilities, Requested Increase Related to Rate Base Investments | $ 11 | ||
Public Utilities, Requested Increase Related to Generation and Transmission Expenses | 6.8 | ||
Public Utilities, Requested Increase Related to Fuel and Purchased Power Expenses | 11 | ||
Public Utilities, Total Requested Rate Increase Excluding Refunds | 28.8 | ||
Public Utilities, Requested Decrease Related to Fuel Refunds | [1] | (9.5) | |
Public Utilities, Requested Decrease Related to Settlement Refund | (1.9) | ||
Public Utilities, Requested Rate Base, Amount | 1,188 | ||
PSCW Proceeding - Wisconsin 2017 Electric and Gas Rate Case - Gas Rates 2017 | |||
Public Utilities, General Disclosures [Line Items] | |||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 4.8 | ||
Public Utilities, Requested Rate Increase (Decrease), Percentage | 3.90% | ||
PSCW Proceeding - Wisconsin 2017 Electric and Gas Rate Case | |||
Public Utilities, General Disclosures [Line Items] | |||
Public Utilities, Requested Return on Equity, Percentage | 10.00% | ||
Public Utilities, Percentage of Excess Earnings to be Refunded due to Earnings Cap | 100.00% | ||
Public Service Commission of Wisconsin (PSCW) | Subsequent Event | PSCW Proceeding - Wisconsin 2017 Electric and Gas Rate Case - Electric Rates 2017 | |||
Public Utilities, General Disclosures [Line Items] | |||
Public Utilities, Revised Requested Rate Increase, Amount | $ 26.9 | ||
Public Utilities, Revised Requested Rate Increase, Percentage | 3.80% | ||
[1] | (a) In July 2016, the PSCW required NSP-Wisconsin to return the 2015 fuel refund directly to customers, rather than using it to offset the proposed 2017 rate increase, as originally proposed by NSP-Wisconsin. This decision effectively increases NSP-Wisconsin’s requested electric rate increase to $26.9 million, or 3.8 percent |
Rate Matters, PSCo (Details)
Rate Matters, PSCo (Details) - PSCo $ in Millions | 6 Months Ended |
Jun. 30, 2016USD ($) | |
CPUC Proceeding - Annual Electric Earnings Test | |
Rate Matters [Abstract] | |
Public Utilities, Return On Equity Threshold For Earnings Sharing For 2015 Through 2017 | 9.83% |
2015 Electric Earnings Test | |
Rate Matters [Abstract] | |
Public Utilities, Refund to customers due to annual earnings test | $ 14.9 |
Rate Matters, SPS (Details)
Rate Matters, SPS (Details) - SPS - USD ($) $ in Thousands | May 02, 2016 | Apr. 30, 2016 | Feb. 29, 2016 | Oct. 31, 2015 | Jun. 30, 2015 | Jun. 30, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
PUCT Proceeding - Texas 2015 Electric Rate Net Refund Case | ||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||
Customer Refund Liability, Current | $ 1,250 | |||||||
Length of Refund Period | 6 months | |||||||
PUCT Proceeding - Appeal of the Texas 2015 Electric Rate Case Decision | ||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 42,100 | $ 64,800 | ||||||
PUCT Proceeding - Texas 2016 Electric Rate Case | ||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 71,900 | |||||||
Public Utilities, Requested Rate Increase (Decrease), Percentage | 14.40% | |||||||
Public Utilities, Requested Return on Equity, Percentage | 10.25% | |||||||
Public Utilities, Requested Rate Base, Amount | $ 1,700,000 | |||||||
Public Utilities, Requested Equity Capital Structure, Percentage | 53.97% | |||||||
Public Utilities, Revised Requested Rate Increase | $ 68,600 | |||||||
Public utilities, Requested Increase Related to Capital Investment | 38,900 | |||||||
Public Utilities, Increase to Jurisdictional Allocation Factors | 9,800 | |||||||
Public Utilities, ROE and Capital Structure | 11,600 | |||||||
Public Utilities, Increase to Rate Case Expenses | 4,500 | |||||||
Public Utilities, Increase Related To Other, Net | $ 3,800 | |||||||
NMPRC Proceeding - New Mexico 2015 Electric Rate Case | ||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 45,400 | |||||||
Public Utilities, Requested Return on Equity, Percentage | 10.25% | |||||||
Public Utilities, Requested Rate Base, Amount | $ 734,000 | |||||||
Public Utilities, Requested Equity Capital Structure, Percentage | 53.97% | |||||||
Public Utilities, Decrease In Base Fuel Revenues | $ 21,100 | |||||||
Public Utilities, Non-fuel Base Rate Increase Under the Stipulation | $ 23,500 | |||||||
Public Utilities, Decrease In Base Fuel Revenues Under the Stipulation | $ 21,100 | |||||||
Public Utility Commission of Texas (PUCT) | PUCT Proceeding - Appeal of the Texas 2015 Electric Rate Case Decision | ||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||
Public Utilities, Approved Rate Decrease, Net of Rate Case Expenses | $ 4,000 | |||||||
Minimum | SPP Open Access Transmission Tariff Upgrade Costs | ||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||
Public Utilities, Estimated Charges For Transmission Service Upgrades | $ 5,000 | |||||||
Maximum | SPP Open Access Transmission Tariff Upgrade Costs | ||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||
Public Utilities, Estimated Charges For Transmission Service Upgrades | $ 10,000 |
Commitments and Contingencies,
Commitments and Contingencies, Purchased Power Agreements (Details) - Independent Power Producing Entities - MW | 6 Months Ended | 12 Months Ended |
Jun. 30, 2016 | Dec. 31, 2015 | |
Purchased Power Agreements [Abstract] | ||
Generating capacity under long term purchased power agreements | 3,467 | 3,698 |
Purchase Power Agreement Duration, Maximum | 2,033 | 2,033 |
Commitments and Contingencies45
Commitments and Contingencies, Guarantees and Indemnifications (Details) - USD ($) | Jun. 30, 2016 | Dec. 31, 2015 |
Guarantees [Abstract] | ||
Assets held as collateral | $ 0 | $ 0 |
Payment or Performance Guarantee | ||
Guarantees [Abstract] | ||
Guarantees issued and outstanding | 15,900,000 | 12,500,000 |
Current exposure under these guarantees | 100,000 | 100,000 |
Payment or Performance Guarantee | Surety Bonds | ||
Guarantees [Abstract] | ||
Guarantees issued and outstanding | $ 43,000,000 | $ 41,300,000 |
Commitments and Contingencies46
Commitments and Contingencies, Environmental Contingencies - Site Contingencies (Details) $ in Millions | 6 Months Ended | 12 Months Ended | |
Jun. 30, 2016USD ($)Site | Dec. 31, 2017USD ($) | Dec. 31, 2015USD ($) | |
NSP-Wisconsin | Ashland MGP Site | |||
Site Contingency [Line Items] | |||
Accrual for Environmental Loss Contingencies, Gross | $ 95 | $ 94.4 | |
Ashland Manufactured Gas Plant (MGP) Site [Abstract] | |||
Number of properties not owned included in superfund site | Site | 2 | ||
Liability for estimated cost of remediating sites, current | $ 18.7 | 17 | |
NSP-Wisconsin | Ashland MGP Site - Phase I Project Area | |||
Site Contingency [Line Items] | |||
Accrual for Environmental Loss Contingencies, Gross | 71.4 | ||
Ashland Manufactured Gas Plant (MGP) Site [Abstract] | |||
Estimated amount spent on cleanup | $ 51.8 | ||
Approved amortization period for recovery of remediation costs in natural gas rates (in years) | 10 | ||
Carrying cost percentage to be applied to unamortized regulatory asset | 3.00% | ||
NSP-Wisconsin | Ashland MGP Site - Sediments | |||
Ashland Manufactured Gas Plant (MGP) Site [Abstract] | |||
Estimated cost of remediating site, low end of range | $ 63 | ||
Estimated cost of remediating site, high end of range | $ 77 | ||
Potential percent of increase to the high end of the range of estimated site remediation costs (percent) | 50.00% | ||
Potential percent of decrease to the low end of the range of estimated site remediation costs (percent) | 30.00% | ||
NSP-Minnesota | Fargo MGP Site | |||
Site Contingency [Line Items] | |||
Accrual for Environmental Loss Contingencies, Gross | $ 1.6 | $ 2.7 | |
PSCW Proceeding - Electric and Gas Rate Case 2016 - Gas Rates 2016 | NSP-Minnesota | Ashland MGP Site | |||
Ashland Manufactured Gas Plant (MGP) Site [Abstract] | |||
Public Utilities, Approved annual recovery collected through base rates | $ 7.6 | ||
Scenario, Forecast [Member] | PSCW Proceeding - Gas Rate Case 2017 - Gas Rates 2017 | NSP-Minnesota | Ashland MGP Site | |||
Ashland Manufactured Gas Plant (MGP) Site [Abstract] | |||
Public Utilities, Requested annual recovery collected through base rates | $ 12.4 |
Commitments and Contingencies47
Commitments and Contingencies, Environmental Contingencies - Unrecorded Unconditional Purchase Obligation (Details) $ in Millions | 6 Months Ended |
Jun. 30, 2016USD ($) | |
Implementation of the National Ambient Air Quality Standard for Sulfur Dioxide | |
Environmental Requirements [Abstract] | |
Number of phases under a consent decree which the EPA is requiring states to evaluate areas for attainment | 3 |
Number of years unclassifiable areas will be monitored | 3 years |
Capital Commitments | SPS | Regional Haze Rules | |
Environmental Requirements [Abstract] | |
Liability for estimated cost to comply with regulation | $ 600 |
Commitments and Contingencies48
Commitments and Contingencies, Legal Contingencies (Details) | 6 Months Ended | |
Jun. 30, 2016USD ($) | Dec. 31, 2009 | |
Gas Trading Litigation | ||
Legal Contingencies [Abstract] | ||
Loss Contingency, Pending Claims, Number | 1 | 13 |
Loss Contingency, Claims Settled, Number | 5 | |
Loss Contingency, Claims Dismissed, Number | 7 | |
Loss Contingency, Subset of Cases within Multi-District Litigation, Number | 2 | |
PSCo | Pacific Northwest FERC Refund Proceeding | ||
Legal Contingencies [Abstract] | ||
Estimated City of Seattle's claim for refunds not including interest | $ 28,000,000 | |
Estimated City of Seattle's Claim for Refunds Including Interest | 60,000,000 | |
Accrual for legal contingency | 0 | |
PSCo | Line Extension Disputes | ||
Legal Contingencies [Abstract] | ||
Accrual for legal contingency | 0 | |
NSP-Wisconsin | Gas Trading Litigation | ||
Legal Contingencies [Abstract] | ||
Loss Contingency, Pending Claims, Number | 2 | |
Minimum | PSCo | Pacific Northwest FERC Refund Proceeding | ||
Legal Contingencies [Abstract] | ||
Amount Of Sales Claimed As Subject To Refund | 34,000,000 | |
Maximum | PSCo | Pacific Northwest FERC Refund Proceeding | ||
Legal Contingencies [Abstract] | ||
Amount Of Sales Claimed As Subject To Refund | $ 50,000,000 |
Borrowings and Other Financin49
Borrowings and Other Financing Instruments, Commercial Paper (Details) - USD ($) | 3 Months Ended | 12 Months Ended |
Jun. 30, 2016 | Dec. 31, 2015 | |
Short-term Debt [Line Items] | ||
Amount outstanding at period end | $ 447,000,000 | $ 846,000,000 |
Commercial Paper | ||
Short-term Debt [Line Items] | ||
Borrowing limit | 2,750,000,000 | 2,750,000,000 |
Amount outstanding at period end | 447,000,000 | 846,000,000 |
Average amount outstanding | 404,000,000 | 601,000,000 |
Maximum amount outstanding | $ 841,000,000 | $ 1,360,000,000 |
Weighted average interest rate, computed on a daily basis (percentage) | 0.72% | 0.48% |
Weighted average interest rate at period end (percentage) | 0.80% | 0.82% |
Borrowings and Other Financin50
Borrowings and Other Financing Instruments, Letters of Credit (Details) - USD ($) $ in Thousands | 6 Months Ended | |
Jun. 30, 2016 | Dec. 31, 2015 | |
Line of Credit Facility [Line Items] | ||
Amount outstanding at period end | $ 447,000 | $ 846,000 |
Letter of Credit | ||
Line of Credit Facility [Line Items] | ||
Amount outstanding at period end | $ 28,000 | $ 29,000 |
Letter of Credit | Letter of Credit | ||
Line of Credit Facility [Line Items] | ||
Term of letters of credit (in years) | 1 year |
Borrowings and Other Financin51
Borrowings and Other Financing Instruments, Credit Facilities (Details) - USD ($) | 6 Months Ended | ||
Jun. 30, 2016 | Dec. 31, 2015 | ||
Line of Credit Facility [Line Items] | |||
Amount outstanding at period end | $ 447,000,000 | $ 846,000,000 | |
Credit Facilities | |||
Line of Credit Facility [Line Items] | |||
Credit Facility | [1] | 2,750,000,000 | |
Drawn | [2] | 475,000,000 | |
Available | 2,275,000,000 | ||
Direct advances on the credit facility outstanding | $ 0 | ||
Xcel Energy Inc. | Credit Facilities | |||
Line of Credit Facility [Line Items] | |||
Maturity Date | Jun. 30, 2021 | ||
Credit Facility | [1] | $ 1,000,000,000 | |
Drawn | [2] | 414,000,000 | |
Available | 586,000,000 | ||
PSCo | Credit Facilities | |||
Line of Credit Facility [Line Items] | |||
Credit Facility | [1] | 700,000,000 | |
Drawn | [2] | 3,000,000 | |
Available | 697,000,000 | ||
NSP-Minnesota | Credit Facilities | |||
Line of Credit Facility [Line Items] | |||
Credit Facility | [1] | 500,000,000 | |
Drawn | [2] | 18,000,000 | |
Available | 482,000,000 | ||
SPS | Credit Facilities | |||
Line of Credit Facility [Line Items] | |||
Credit Facility | [1] | 400,000,000 | |
Drawn | [2] | 32,000,000 | |
Available | 368,000,000 | ||
NSP-Wisconsin | Credit Facilities | |||
Line of Credit Facility [Line Items] | |||
Credit Facility | [1] | 150,000,000 | |
Drawn | [2] | 8,000,000 | |
Available | 142,000,000 | ||
Letter of Credit | |||
Line of Credit Facility [Line Items] | |||
Amount outstanding at period end | $ 28,000,000 | $ 29,000,000 | |
[1] | These credit facilities expire in June 2021. | ||
[2] | Includes outstanding commercial paper and letters of credit. |
Borrowings and Other Financin52
Borrowings and Other Financing Instruments Borrowings and Other Financing Instruments, Amended Credit Agreements (Details) - Credit Facilities | 6 Months Ended | |
Jun. 30, 2016USD ($) | ||
Line of Credit Facility [Line Items] | ||
Borrowing limit | $ 2,750,000,000 | [1] |
Xcel Energy Inc. | ||
Line of Credit Facility [Line Items] | ||
Debt Instrument, Term | 5 years | |
Borrowing limit | $ 1,000,000,000 | [1] |
Maturity Date | Jun. 30, 2021 | |
Number Of Additional Periods Revolving Termination Date Can Be Extended Subject To Majority Bank Group Approval | 2 | |
Term Of Each Additional Period Revolving Termination Date Can Be Extended Subject To Majority Bank Group Approval | 1 year | |
Xcel Energy Inc. | Original Terms and Conditions [Member] | ||
Line of Credit Facility [Line Items] | ||
Maturity Date | Oct. 31, 2019 | |
Line Of Credit Facility Minimum Borrowing Margin Based On Long Term Credit Ratings | 0.875% | |
Line Of Credit Facility Maximum Borrowing Margin Based On Long Term Credit Ratings | 1.75% | |
Line Of Credit Facility Minimum Commitment Fees Calculated On Unused Portion Of Lines Of Credit | 0.075% | |
Line Of Credit Facility Maximum Commitment Fees Calculated On Unused Portion Of Lines Of Credit | 0.275% | |
Xcel Energy Inc. | Amended Terms and Conditions [Member] | ||
Line of Credit Facility [Line Items] | ||
Maturity Date | Jun. 30, 2021 | |
Line Of Credit Facility Minimum Borrowing Margin Based On Long Term Credit Ratings | 0.75% | |
Line Of Credit Facility Maximum Borrowing Margin Based On Long Term Credit Ratings | 1.50% | |
Line Of Credit Facility Minimum Commitment Fees Calculated On Unused Portion Of Lines Of Credit | 0.06% | |
Line Of Credit Facility Maximum Commitment Fees Calculated On Unused Portion Of Lines Of Credit | 0.225% | |
NSP-Minnesota | ||
Line of Credit Facility [Line Items] | ||
Debt Instrument, Term | 5 years | |
Borrowing limit | $ 500,000,000 | [1] |
Number Of Additional Periods Revolving Termination Date Can Be Extended Subject To Majority Bank Group Approval | 2 | |
Term Of Each Additional Period Revolving Termination Date Can Be Extended Subject To Majority Bank Group Approval | 1 year | |
NSP-Minnesota | Original Terms and Conditions [Member] | ||
Line of Credit Facility [Line Items] | ||
Line Of Credit Facility Minimum Borrowing Margin Based On Long Term Credit Ratings | 0.875% | |
Line Of Credit Facility Maximum Borrowing Margin Based On Long Term Credit Ratings | 1.75% | |
Line Of Credit Facility Minimum Commitment Fees Calculated On Unused Portion Of Lines Of Credit | 0.075% | |
Line Of Credit Facility Maximum Commitment Fees Calculated On Unused Portion Of Lines Of Credit | 0.275% | |
NSP-Minnesota | Amended Terms and Conditions [Member] | ||
Line of Credit Facility [Line Items] | ||
Line Of Credit Facility Minimum Borrowing Margin Based On Long Term Credit Ratings | 0.75% | |
Line Of Credit Facility Maximum Borrowing Margin Based On Long Term Credit Ratings | 1.50% | |
Line Of Credit Facility Minimum Commitment Fees Calculated On Unused Portion Of Lines Of Credit | 0.06% | |
Line Of Credit Facility Maximum Commitment Fees Calculated On Unused Portion Of Lines Of Credit | 0.225% | |
NSP-Wisconsin | ||
Line of Credit Facility [Line Items] | ||
Debt Instrument, Term | 5 years | |
Borrowing limit | $ 150,000,000 | [1] |
Number Of Additional Periods Revolving Termination Date Can Be Extended Subject To Majority Bank Group Approval | 1 | |
Term Of Each Additional Period Revolving Termination Date Can Be Extended Subject To Majority Bank Group Approval | 1 year | |
NSP-Wisconsin | Original Terms and Conditions [Member] | ||
Line of Credit Facility [Line Items] | ||
Line Of Credit Facility Minimum Borrowing Margin Based On Long Term Credit Ratings | 0.875% | |
Line Of Credit Facility Maximum Borrowing Margin Based On Long Term Credit Ratings | 1.75% | |
Line Of Credit Facility Minimum Commitment Fees Calculated On Unused Portion Of Lines Of Credit | 0.075% | |
Line Of Credit Facility Maximum Commitment Fees Calculated On Unused Portion Of Lines Of Credit | 0.275% | |
NSP-Wisconsin | Amended Terms and Conditions [Member] | ||
Line of Credit Facility [Line Items] | ||
Line Of Credit Facility Minimum Borrowing Margin Based On Long Term Credit Ratings | 0.75% | |
Line Of Credit Facility Maximum Borrowing Margin Based On Long Term Credit Ratings | 1.50% | |
Line Of Credit Facility Minimum Commitment Fees Calculated On Unused Portion Of Lines Of Credit | 0.06% | |
Line Of Credit Facility Maximum Commitment Fees Calculated On Unused Portion Of Lines Of Credit | 0.225% | |
PSCo | ||
Line of Credit Facility [Line Items] | ||
Debt Instrument, Term | 5 years | |
Borrowing limit | $ 700,000,000 | [1] |
Number Of Additional Periods Revolving Termination Date Can Be Extended Subject To Majority Bank Group Approval | 2 | |
Term Of Each Additional Period Revolving Termination Date Can Be Extended Subject To Majority Bank Group Approval | 1 year | |
PSCo | Original Terms and Conditions [Member] | ||
Line of Credit Facility [Line Items] | ||
Line Of Credit Facility Minimum Borrowing Margin Based On Long Term Credit Ratings | 0.875% | |
Line Of Credit Facility Maximum Borrowing Margin Based On Long Term Credit Ratings | 1.75% | |
Line Of Credit Facility Minimum Commitment Fees Calculated On Unused Portion Of Lines Of Credit | 0.075% | |
Line Of Credit Facility Maximum Commitment Fees Calculated On Unused Portion Of Lines Of Credit | 0.275% | |
PSCo | Amended Terms and Conditions [Member] | ||
Line of Credit Facility [Line Items] | ||
Line Of Credit Facility Minimum Borrowing Margin Based On Long Term Credit Ratings | 0.75% | |
Line Of Credit Facility Maximum Borrowing Margin Based On Long Term Credit Ratings | 1.50% | |
Line Of Credit Facility Minimum Commitment Fees Calculated On Unused Portion Of Lines Of Credit | 0.06% | |
Line Of Credit Facility Maximum Commitment Fees Calculated On Unused Portion Of Lines Of Credit | 0.225% | |
SPS | ||
Line of Credit Facility [Line Items] | ||
Debt Instrument, Term | 5 years | |
Borrowing limit | $ 400,000,000 | [1] |
Number Of Additional Periods Revolving Termination Date Can Be Extended Subject To Majority Bank Group Approval | 2 | |
Term Of Each Additional Period Revolving Termination Date Can Be Extended Subject To Majority Bank Group Approval | 1 year | |
SPS | Original Terms and Conditions [Member] | ||
Line of Credit Facility [Line Items] | ||
Line Of Credit Facility Minimum Borrowing Margin Based On Long Term Credit Ratings | 0.875% | |
Line Of Credit Facility Maximum Borrowing Margin Based On Long Term Credit Ratings | 1.75% | |
Line Of Credit Facility Minimum Commitment Fees Calculated On Unused Portion Of Lines Of Credit | 0.075% | |
Line Of Credit Facility Maximum Commitment Fees Calculated On Unused Portion Of Lines Of Credit | 0.275% | |
SPS | Amended Terms and Conditions [Member] | ||
Line of Credit Facility [Line Items] | ||
Line Of Credit Facility Minimum Borrowing Margin Based On Long Term Credit Ratings | 0.75% | |
Line Of Credit Facility Maximum Borrowing Margin Based On Long Term Credit Ratings | 1.50% | |
Line Of Credit Facility Minimum Commitment Fees Calculated On Unused Portion Of Lines Of Credit | 0.06% | |
Line Of Credit Facility Maximum Commitment Fees Calculated On Unused Portion Of Lines Of Credit | 0.225% | |
[1] | These credit facilities expire in June 2021. |
Borrowings and Other Financin53
Borrowings and Other Financing Instruments Borrowings and Other Financing Instruments, Long-Term Borrowings (Details) - USD ($) | 1 Months Ended | ||
Jun. 30, 2016 | May 31, 2016 | Mar. 31, 2016 | |
Xcel Energy Inc. | Senior Unsecured Notes | Series Due March 15, 2021 [Member] | |||
Debt Instrument [Line Items] | |||
Face amount | $ 400,000,000 | ||
Interest rate, stated percentage (in hundredths) | 2.40% | ||
Maturity Date | Mar. 15, 2021 | ||
Xcel Energy Inc. | Senior Unsecured Notes | Series Due June 1, 2025 [Member] | |||
Debt Instrument [Line Items] | |||
Face amount | $ 350,000,000 | ||
Interest rate, stated percentage (in hundredths) | 3.30% | ||
Maturity Date | Jun. 1, 2025 | ||
PSCo | Bonds [Member] | Series Due June 15, 2046 [Member] | |||
Debt Instrument [Line Items] | |||
Face amount | $ 250,000,000 | ||
Interest rate, stated percentage (in hundredths) | 3.55% | ||
Maturity Date | Jun. 15, 2046 | ||
NSP-Minnesota | Bonds [Member] | Series Due May 15, 2046 [Member] | |||
Debt Instrument [Line Items] | |||
Face amount | $ 350,000,000 | ||
Interest rate, stated percentage (in hundredths) | 3.60% | ||
Maturity Date | May 15, 2046 |
Fair Value of Financial Asset54
Fair Value of Financial Assets and Liabilities (Details) | 6 Months Ended |
Jun. 30, 2016 | |
Minimum | Commingled and international equity funds | |
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items] | |
Notice period for investment redemption (in days) | 1 day |
Minimum | Real Estate Funds | |
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items] | |
Notice period for investment redemption (in days) | 45 days |
Maximum | Commingled and international equity funds | |
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items] | |
Notice period for investment redemption (in days) | 90 days |
Maximum | Real Estate Funds | |
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items] | |
Notice period for investment redemption (in days) | 90 days |
Fair Value of Financial Asset55
Fair Value of Financial Assets and Liabilities, Cost and Fair Value of Nuclear Decommissioning Fund (Details) - USD ($) | 6 Months Ended | 12 Months Ended | ||
Jun. 30, 2016 | Dec. 31, 2015 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Available-for-sale Securities, Gross Unrealized Gain | $ 336,500,000 | $ 328,800,000 | ||
Available-for-sale Securities, Gross Unrealized Loss | 95,200,000 | 100,200,000 | ||
Investments [Abstract] | ||||
Equity investments in unconsolidated subsidiaries | 133,700,000 | 130,000,000 | ||
Miscellaneous investments | 99,000,000 | 48,900,000 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Cash Equivalents | 15,749,000 | 27,484,000 | ||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities | 1,513,516,000 | 1,495,599,000 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Commingled funds | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities | 389,700,000 | 392,838,000 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | International equity funds | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities | 259,090,000 | 259,114,000 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Private equity investments | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities | 119,370,000 | 105,965,000 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Real estate | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities | 72,956,000 | 61,816,000 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Government securities | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 35,199,000 | 24,444,000 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | U.S. corporate bonds | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 96,110,000 | 73,061,000 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | International corporate bonds | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 19,959,000 | 13,726,000 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Municipal bonds | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 11,966,000 | 49,255,000 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Asset-backed securities | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 2,844,000 | 2,837,000 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Mortgage-backed securities | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 10,708,000 | 11,444,000 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Common stock | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Equity Securities | 479,865,000 | 473,615,000 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Cash Equivalents | 15,749,000 | 27,484,000 | ||
Alternative Investments, Fair Value Disclosure | 916,073,000 | [1] | 884,034,000 | [2] |
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities | 1,754,802,000 | [3] | 1,724,150,000 | [4] |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Cash and Cash Equivalents [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Alternative Investments, Fair Value Disclosure | 0 | [1] | 0 | [2] |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Commingled funds | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Alternative Investments, Fair Value Disclosure | 411,788,000 | [1] | 410,634,000 | [2] |
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities | 411,788,000 | 410,634,000 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | International equity funds | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Alternative Investments, Fair Value Disclosure | 236,087,000 | [1] | 231,122,000 | [2] |
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities | 236,087,000 | 231,122,000 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Private equity investments | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Alternative Investments, Fair Value Disclosure | 166,054,000 | [1] | 157,528,000 | [2] |
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities | 166,054,000 | 157,528,000 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Real estate | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Alternative Investments, Fair Value Disclosure | 102,144,000 | [1] | 84,750,000 | [2] |
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities | 102,144,000 | 84,750,000 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Government securities | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Alternative Investments, Fair Value Disclosure | 0 | [1] | 0 | [2] |
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 35,828,000 | 21,356,000 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | U.S. corporate bonds | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Alternative Investments, Fair Value Disclosure | 0 | [1] | 0 | [2] |
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 91,350,000 | 65,276,000 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | International corporate bonds | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Alternative Investments, Fair Value Disclosure | 0 | [1] | 0 | [2] |
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 19,394,000 | 12,801,000 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Municipal bonds | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Alternative Investments, Fair Value Disclosure | 0 | [1] | 0 | [2] |
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 12,826,000 | 51,589,000 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Asset-backed securities | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Alternative Investments, Fair Value Disclosure | 0 | [1] | 0 | [2] |
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 2,881,000 | 2,830,000 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Mortgage-backed securities | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Alternative Investments, Fair Value Disclosure | 0 | [1] | 0 | [2] |
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 11,180,000 | 11,621,000 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Common stock | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Alternative Investments, Fair Value Disclosure | 0 | [1] | 0 | [2] |
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Equity Securities | 649,521,000 | 647,159,000 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Cash Equivalents | 15,749,000 | 27,484,000 | ||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities | 665,270,000 | 674,643,000 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Commingled funds | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities | 0 | 0 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | International equity funds | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities | 0 | 0 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Private equity investments | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities | 0 | 0 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Real estate | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities | 0 | 0 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Government securities | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 0 | 0 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | U.S. corporate bonds | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 0 | 0 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | International corporate bonds | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 0 | 0 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Municipal bonds | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 0 | 0 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Asset-backed securities | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 0 | 0 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Mortgage-backed securities | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 0 | 0 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Common stock | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Equity Securities | 649,521,000 | 647,159,000 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Cash Equivalents | 0 | 0 | ||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities | 173,459,000 | 165,473,000 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Commingled funds | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities | 0 | 0 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | International equity funds | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities | 0 | 0 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Private equity investments | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities | 0 | 0 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Real estate | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities | 0 | 0 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Government securities | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 35,828,000 | 21,356,000 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | U.S. corporate bonds | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 91,350,000 | 65,276,000 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | International corporate bonds | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 19,394,000 | 12,801,000 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Municipal bonds | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 12,826,000 | 51,589,000 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Asset-backed securities | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 2,881,000 | 2,830,000 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Mortgage-backed securities | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 11,180,000 | 11,621,000 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Common stock | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Equity Securities | 0 | 0 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Cash Equivalents | 0 | 0 | ||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities | 0 | 0 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Commingled funds | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities | 0 | 0 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | International equity funds | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities | 0 | 0 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Private equity investments | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities | 0 | 0 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Real estate | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities | 0 | 0 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Government securities | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 0 | 0 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | U.S. corporate bonds | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 0 | 0 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | International corporate bonds | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 0 | 0 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Municipal bonds | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 0 | 0 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Asset-backed securities | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 0 | 0 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Mortgage-backed securities | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 0 | 0 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Common stock | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Equity Securities | $ 0 | $ 0 | ||
[1] | (b) Based on the requirements of ASU 2015-07, investments measured at fair value using a NAV methodology have not been classified in the fair value hierarchy. See Note 2 for further information on the adoption of ASU 2015-07. | |||
[2] | Based on the requirements of ASU 2015-07, investments measured at fair value using a NAV methodology have not been classified in the fair value hierarchy. See Note 2 for further information on the adoption of ASU 2015-07. | |||
[3] | Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $133.7 million of equity investments in unconsolidated subsidiaries and $99.0 million of rabbi trust assets and miscellaneous investments. | |||
[4] | Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $130.0 million of equity investments in unconsolidated subsidiaries and $48.9 million of miscellaneous investments. |
Fair Value of Financial Asset56
Fair Value of Financial Assets and Liabilities, Final Contractual Maturity Dates of Debt Securities in Nuclear Decommissioning Fund (Details) $ in Thousands | Jun. 30, 2016USD ($) |
Final Contractual Maturity [Abstract] | |
Due in 1 Year or Less | $ 261 |
Due in 1 to 5 Years | 41,825 |
Due in 5 to 10 Years | 79,847 |
Due after 10 Years | 51,526 |
Total | 173,459 |
Government securities | |
Final Contractual Maturity [Abstract] | |
Due in 1 Year or Less | 0 |
Due in 1 to 5 Years | 10,659 |
Due in 5 to 10 Years | 982 |
Due after 10 Years | 24,187 |
Total | 35,828 |
U.S. corporate bonds | |
Final Contractual Maturity [Abstract] | |
Due in 1 Year or Less | 261 |
Due in 1 to 5 Years | 26,988 |
Due in 5 to 10 Years | 59,368 |
Due after 10 Years | 4,733 |
Total | 91,350 |
International corporate bonds | |
Final Contractual Maturity [Abstract] | |
Due in 1 Year or Less | 0 |
Due in 1 to 5 Years | 3,966 |
Due in 5 to 10 Years | 12,368 |
Due after 10 Years | 3,060 |
Total | 19,394 |
Municipal bonds | |
Final Contractual Maturity [Abstract] | |
Due in 1 Year or Less | 0 |
Due in 1 to 5 Years | 212 |
Due in 5 to 10 Years | 4,248 |
Due after 10 Years | 8,366 |
Total | 12,826 |
Asset-backed securities | |
Final Contractual Maturity [Abstract] | |
Due in 1 Year or Less | 0 |
Due in 1 to 5 Years | 0 |
Due in 5 to 10 Years | 2,881 |
Due after 10 Years | 0 |
Total | 2,881 |
Mortgage-backed securities | |
Final Contractual Maturity [Abstract] | |
Due in 1 Year or Less | 0 |
Due in 1 to 5 Years | 0 |
Due in 5 to 10 Years | 0 |
Due after 10 Years | 11,180 |
Total | $ 11,180 |
Fair Value of Financial Asset57
Fair Value of Financial Assets and Liabilities, Derivative Instruments (Details) gal in Thousands, MWh in Thousands, MMBTU in Thousands, $ in Millions | Jun. 30, 2016USD ($)galMMBTUMWhCounterparty | Dec. 31, 2015galMMBTUMWh | |
Commodity Derivatives [Abstract] | |||
Amount of accumulated other comprehensive gains (losses) related to commodity derivatives expected to be reclassified into earnings within the next twelve months | $ | $ (0.1) | ||
Credit Concentration Risk | |||
Consideration of Credit Risk and Concentrations [Abstract] | |||
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure | Counterparty | 10 | ||
Credit Concentration Risk | Municipal or Cooperative Entities or Other Utilities [Member] | |||
Consideration of Credit Risk and Concentrations [Abstract] | |||
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure | Counterparty | 9 | ||
Credit Concentration Risk | Credit Quality Less Than Investment Grade [Member] | |||
Consideration of Credit Risk and Concentrations [Abstract] | |||
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure | Counterparty | 2 | ||
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties | $ | $ 12.2 | ||
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths) | 6.00% | ||
Credit Concentration Risk | No Investment Grade Ratings from External Credit Rating Agencies [Member] | |||
Consideration of Credit Risk and Concentrations [Abstract] | |||
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure | Counterparty | 7 | ||
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties | $ | $ 55.6 | ||
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths) | 25.00% | ||
Credit Concentration Risk | External Credit Rating, Investment Grade [Member] | |||
Consideration of Credit Risk and Concentrations [Abstract] | |||
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure | Counterparty | 1 | ||
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties | $ | $ 13.5 | ||
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths) | 6.00% | ||
Interest Rate Swap | |||
Interest Rate Derivatives [Abstract] | |||
Amount of accumulated other comprehensive gains (losses) related to interest rate derivatives expected to be reclassified into earnings within the next twelve months | $ | $ (3.4) | ||
Electric Commodity (in megawatt hours) | |||
Gross Notional Amounts of Commodity Forwards, Options and FTRs [Abstract] | |||
Derivative, Nonmonetary Notional amount | MWh | [1],[2] | 81,667 | 50,487 |
Natural Gas Commodity (in million British thermal units) | |||
Gross Notional Amounts of Commodity Forwards, Options and FTRs [Abstract] | |||
Derivative, Nonmonetary Notional amount | MMBTU | [1],[2] | 84,578 | 20,874 |
Vehicle Fuel Commodity (in gallons) | |||
Gross Notional Amounts of Commodity Forwards, Options and FTRs [Abstract] | |||
Derivative, Nonmonetary Notional amount | gal | [1],[2] | 70 | 141 |
[1] | Amounts are not reflective of net positions in the underlying commodities. | ||
[2] | Notional amounts for options are included on a gross basis, but are weighted for the probability of exercise. |
Fair Value of Financial Asset58
Fair Value of Financial Assets and Liabilities, Impact of Derivative Activity (Details) - USD ($) | 3 Months Ended | 6 Months Ended | |||||||
Jun. 30, 2016 | Jun. 30, 2015 | Jun. 30, 2016 | Jun. 30, 2015 | ||||||
Financial Impact of Qualifying Fair Value Hedges on Earnings [Abstract] | |||||||||
Derivative instruments designated as fair value hedges | $ 0 | $ 0 | $ 0 | $ 0 | |||||
Recognized gains (losses) from fair value hedges or related hedged transactions | 0 | 0 | 0 | 0 | |||||
Designated as Hedging Instrument | Cash Flow Hedges | |||||||||
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract] | |||||||||
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss | 19,000 | 29,000 | 13,000 | 11,000 | |||||
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities | 0 | 0 | 0 | 0 | |||||
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss | 1,530,000 | 982,000 | 3,072,000 | 1,949,000 | |||||
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities) | 0 | 0 | 0 | 0 | |||||
Pre-tax gains (losses) recognized during the period in income | 0 | 0 | 0 | 0 | |||||
Designated as Hedging Instrument | Cash Flow Hedges | Interest Rate | |||||||||
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract] | |||||||||
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss | 0 | 0 | 0 | 0 | |||||
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities | 0 | 0 | 0 | 0 | |||||
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss | [1] | 1,483,000 | 954,000 | 2,968,000 | 1,894,000 | ||||
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities) | 0 | 0 | 0 | 0 | |||||
Pre-tax gains (losses) recognized during the period in income | 0 | 0 | 0 | 0 | |||||
Designated as Hedging Instrument | Cash Flow Hedges | Vehicle Fuel And Other Commodity | |||||||||
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract] | |||||||||
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss | 19,000 | 29,000 | 13,000 | 11,000 | |||||
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities | 0 | 0 | 0 | 0 | |||||
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss | [2] | 47,000 | 28,000 | 104,000 | 55,000 | ||||
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities) | 0 | 0 | 0 | 0 | |||||
Pre-tax gains (losses) recognized during the period in income | 0 | 0 | 0 | 0 | |||||
Other Derivative Instruments | |||||||||
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract] | |||||||||
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss | 0 | 0 | 0 | 0 | |||||
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities | 5,358,000 | (4,969,000) | 2,391,000 | (14,656,000) | |||||
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss | 0 | 0 | 0 | 0 | |||||
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities) | 16,642,000 | (8,059,000) | 39,199,000 | (22,012,000) | |||||
Pre-tax gains (losses) recognized during the period in income | 506,000 | 4,401,000 | (3,509,000) | 17,272,000 | |||||
Other Derivative Instruments | Commodity Trading | |||||||||
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract] | |||||||||
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss | 0 | 0 | 0 | 0 | |||||
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities | 0 | 0 | 0 | 0 | |||||
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss | 0 | 0 | 0 | 0 | |||||
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities) | 0 | 0 | 0 | 0 | |||||
Pre-tax gains (losses) recognized during the period in income | [3] | 481,000 | 4,401,000 | 1,490,000 | 8,281,000 | ||||
Other Derivative Instruments | Electric Commodity | |||||||||
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract] | |||||||||
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss | 0 | 0 | 0 | 0 | |||||
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities | (705,000) | (4,737,000) | (970,000) | (14,208,000) | |||||
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss | 0 | 0 | 0 | 0 | |||||
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities) | [4] | 16,642,000 | (8,037,000) | 27,533,000 | (13,160,000) | ||||
Pre-tax gains (losses) recognized during the period in income | 0 | 0 | 0 | 0 | |||||
Other Derivative Instruments | Natural Gas Commodity | |||||||||
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract] | |||||||||
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss | 0 | 0 | 0 | 0 | |||||
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities | 6,063,000 | (232,000) | 3,361,000 | (448,000) | |||||
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss | 0 | 0 | 0 | 0 | |||||
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities) | 0 | (22,000) | [5] | 11,666,000 | [5] | (8,852,000) | [5] | ||
Pre-tax gains (losses) recognized during the period in income | $ 25,000 | [5] | $ 0 | $ (4,999,000) | [5] | $ 8,991,000 | [5] | ||
[1] | Amounts are recorded to interest charges. | ||||||||
[2] | Amounts are recorded to O&M expenses. | ||||||||
[3] | Amounts are recorded to electric operating revenues. Portions of these gains and losses are subject to sharing with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate. | ||||||||
[4] | Amounts are recorded to electric fuel and purchased power. These derivative settlement gain and loss amounts are shared with electric customers through fuel and purchased energy cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate. | ||||||||
[5] | Amounts for the three and six months ended June 30, 2016 and 2015 included an immaterial amount of settlement losses on derivatives entered to mitigate natural gas price risk for electric generation, recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate. The remaining derivative settlement gains and losses for the three and six months ended June 30, 2016 and 2015 relate to natural gas operations and are recorded to cost of natural gas sold and transported. These gains and losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset or liability, as appropriate. |
Fair Value of Financial Asset59
Fair Value of Financial Assets and Liabilities, Credit Related Contingent Features (Details) - USD ($) | Jun. 30, 2016 | Dec. 31, 2015 |
Fair Value Disclosures [Abstract] | ||
Derivative instruments in a gross liability position | $ 0 | $ 0 |
Collateral posted on derivative instruments | 0 | 0 |
Collateral posted related to adequate assurance clauses in derivative contracts | $ 0 | $ 0 |
Fair Value of Financial Asset60
Fair Value of Financial Assets and Liabilities, Derivative Assets and Liabilities at Fair Value (Details) - USD ($) $ in Thousands | Jun. 30, 2016 | Dec. 31, 2015 | |||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Collateral, Obligation to Return Cash, Offset | $ 0 | $ 0 | |||
Derivative Liability, Collateral, Right to Reclaim Cash, Offset | 4,700 | 4,300 | |||
Other Current Assets | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 46,953 | 33,842 | |||
Other Noncurrent Assets | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 50,644 | 51,083 | |||
Other Current Liabilities | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 26,542 | 29,839 | |||
Other Noncurrent Liabilities | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 156,357 | 168,311 | |||
Fair Value Measured on a Recurring Basis | Other Current Assets | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 39,094 | 23,756 | |||
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset | (17,641) | [1] | (10,256) | [2] | |
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 6,042 | 6,230 | |||
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset | (14,017) | [1] | (5,865) | [2] | |
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Electric Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 24,558 | 17,333 | |||
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset | (3,593) | [1] | (4,088) | [2] | |
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 8,494 | 193 | |||
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset | (31) | [1] | (303) | [2] | |
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 23,464 | 20,861 | |||
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset | (6,986) | [1] | (6,555) | [2] | |
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 22,109 | 20,861 | |||
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset | (6,986) | [1] | (6,555) | [2] | |
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 1,355 | ||||
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset | [1] | 0 | |||
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 82 | 205 | |||
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset | 0 | [1] | 0 | [2] | |
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 3,695 | 6,978 | |||
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset | (18,199) | [1] | (11,295) | [2] | |
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 3,613 | 1,669 | |||
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset | (14,575) | [1] | (6,904) | [2] | |
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Electric Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 0 | 0 | |||
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset | (3,593) | [1] | (4,088) | [2] | |
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 0 | 5,104 | |||
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset | (31) | [1] | (303) | [2] | |
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Other Derivative Instruments | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 9,710 | 10,118 | |||
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset | (11,162) | [1] | (9,780) | [2] | |
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 9,710 | 10,118 | |||
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset | (11,162) | [1] | (9,780) | [2] | |
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 5,384 | 225 | |||
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 5,384 | 225 | |||
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets | Other Derivative Instruments | Electric Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Assets | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 1,037 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Assets | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 1,037 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Assets | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 0 | ||||
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 0 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities | Other Derivative Instruments | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 5,407 | 152 | |||
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 5,407 | 152 | |||
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities | Other Derivative Instruments | Electric Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 0 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 0 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Liabilities | Other Derivative Instruments | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 1,086 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 1,086 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 23,200 | 11,116 | |||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 14,675 | 10,620 | |||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets | Other Derivative Instruments | Electric Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 8,525 | 496 | |||
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Assets | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 29,413 | 27,416 | |||
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Assets | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 28,058 | 27,416 | |||
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Assets | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 1,355 | ||||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 82 | 205 | |||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities | Other Derivative Instruments | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 12,853 | 13,478 | |||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 12,740 | 7,866 | |||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities | Other Derivative Instruments | Electric Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 0 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 31 | 5,407 | |||
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Liabilities | Other Derivative Instruments | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 19,786 | 19,898 | |||
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 19,786 | 19,898 | |||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 28,151 | 22,671 | |||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 0 | 1,250 | |||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets | Other Derivative Instruments | Electric Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 28,151 | 21,421 | |||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Assets | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Assets | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Assets | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 0 | ||||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 0 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities | Other Derivative Instruments | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 3,634 | 4,643 | |||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 41 | 555 | |||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities | Other Derivative Instruments | Electric Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 3,593 | 4,088 | |||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 0 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Liabilities | Other Derivative Instruments | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 0 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 0 | 0 | |||
Fair Value, Measurements, Nonrecurring | Other Current Assets | Purchased Power Agreements | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 7,859 | [3] | 10,086 | [4] | |
Fair Value, Measurements, Nonrecurring | Other Noncurrent Assets | Purchased Power Agreements | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 27,180 | [3] | 30,222 | [4] | |
Fair Value, Measurements, Nonrecurring | Other Current Liabilities | Purchased Power Agreements | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 22,847 | [3] | 22,861 | [4] | |
Fair Value, Measurements, Nonrecurring | Other Noncurrent Liabilities | Purchased Power Agreements | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 146,647 | [3] | 158,193 | [4] | |
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Assets | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 56,735 | 34,012 | |||
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 20,059 | 12,095 | |||
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Electric Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 28,151 | 21,421 | |||
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 8,525 | 496 | |||
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 30,450 | 27,416 | |||
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 29,095 | 27,416 | |||
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 1,355 | ||||
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Liabilities | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 82 | 205 | |||
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 21,894 | 18,273 | |||
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 18,188 | 8,573 | |||
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Electric Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 3,593 | 4,088 | |||
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 31 | 5,407 | |||
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Other Derivative Instruments | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 20,872 | 19,898 | |||
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | $ 20,872 | $ 19,898 | |||
[1] | Xcel Energy nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at June 30, 2016. At June 30, 2016, derivative assets and liabilities include no obligations to return cash collateral and the rights to reclaim cash collateral of $4.7 million. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements. | ||||
[2] | Xcel Energy nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2015. At Dec. 31, 2015, derivative assets and liabilities include no obligations to return cash collateral and rights to reclaim cash collateral of $4.3 million. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements. | ||||
[3] | In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, Xcel Energy began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, Xcel Energy qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities. | ||||
[4] | In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, Xcel Energy began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, Xcel Energy qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities. |
Fair Value of Financial Asset61
Fair Value of Financial Assets and Liabilities, Changes in Level 3 Commodity Derivatives (Details) - Commodity Contract - USD ($) | 3 Months Ended | 6 Months Ended | |||
Jun. 30, 2016 | Jun. 30, 2015 | Jun. 30, 2016 | Jun. 30, 2015 | ||
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward] | |||||
Balance at beginning of period | $ 6,854,000 | $ 17,429,000 | $ 18,028,000 | $ 56,155,000 | |
Purchases | 29,826,000 | 57,446,000 | 31,670,000 | 63,238,000 | |
Settlements | (14,111,000) | (17,315,000) | (26,161,000) | (37,246,000) | |
Losses (gains) recognized in earnings | [1] | (18,000) | 1,220,000 | (43,000) | 1,280,000 |
Gains (losses) recognized as regulatory assets and liabilities | 1,966,000 | (11,953,000) | 1,023,000 | (36,600,000) | |
Balance at end of period | 24,517,000 | 46,827,000 | 24,517,000 | 46,827,000 | |
Transfers into Level 3 | 0 | 0 | 0 | 0 | |
Transfers out of Level 3 | $ 0 | $ 0 | $ 0 | $ 0 | |
[1] | (a)These amounts relate to commodity derivatives held at the end of the period. |
Fair Value of Financial Asset62
Fair Value of Financial Assets and Liabilities, Fair Value of Long-Term Debt (Details) - USD ($) $ in Thousands | Jun. 30, 2016 | Dec. 31, 2015 | |
Carrying Amount | |||
Financial Liabilities, Balance Sheet Groupings [Abstract] | |||
Long-term Debt, Including Current Portion | [1] | $ 13,814,921 | $ 13,055,901 |
Fair Value | |||
Financial Liabilities, Balance Sheet Groupings [Abstract] | |||
Long-term Debt, Including Current Portion | [1] | $ 15,935,100 | $ 14,094,744 |
[1] | Amounts reflect the classification of debt issuance costs as a deduction from the carrying amount of the related debt. See Note 2, Accounting Pronouncements for more information on the adoption of ASU 2015-03. |
Fair Value of Financial Asset63
Fair Value of Financial Assets and Liabilities Fair Value of Financial Assets and Liabilities, Cost and Fair Value of Rabbi Trust (Details) - Fair Value, Measurements, Recurring [Member] $ in Thousands | Jun. 30, 2016USD ($) | |
Cost | Rabbi Trust [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Cash Equivalents | $ 47,762 | |
Trading Securities | 49,355 | |
Cost | Mutual Funds [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Trading Securities | 1,593 | |
Fair Value | Rabbi Trust [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Cash Equivalents | 47,762 | |
Trading Securities | 49,540 | [1] |
Fair Value | Rabbi Trust [Member] | Level 1 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Cash Equivalents | 47,762 | |
Trading Securities | 49,540 | |
Fair Value | Rabbi Trust [Member] | Level 2 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Cash Equivalents | 0 | |
Trading Securities | 0 | |
Fair Value | Rabbi Trust [Member] | Level 3 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Cash Equivalents | 0 | |
Trading Securities | 0 | |
Fair Value | Mutual Funds [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Trading Securities | 1,778 | |
Fair Value | Mutual Funds [Member] | Level 1 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Trading Securities | 1,778 | |
Fair Value | Mutual Funds [Member] | Level 2 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Trading Securities | 0 | |
Fair Value | Mutual Funds [Member] | Level 3 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Trading Securities | $ 0 | |
[1] | (a)Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet. |
Other Income, Net (Details)
Other Income, Net (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2016 | Jun. 30, 2015 | Jun. 30, 2016 | Jun. 30, 2015 | |
Other Income and Expenses [Abstract] | ||||
Interest income | $ 984 | $ 389 | $ 5,054 | $ 4,627 |
Other nonoperating income | 1,496 | 794 | 2,176 | 1,762 |
Insurance policy expense | (920) | (222) | (1,420) | (2,267) |
Other income, net | $ 1,560 | $ 961 | $ 5,810 | $ 4,122 |
Segment Information (Details)
Segment Information (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||||
Jun. 30, 2016 | Jun. 30, 2015 | Jun. 30, 2016 | Jun. 30, 2015 | Dec. 31, 2015 | ||
Segment Reporting Information [Line Items] | ||||||
Equity investments in unconsolidated subsidiaries | $ 133,700 | $ 133,700 | $ 130,000 | |||
Operating revenues | 2,499,849 | $ 2,515,134 | 5,272,122 | $ 5,477,353 | ||
Net income (loss) | 196,795 | 196,931 | 438,107 | 348,997 | ||
Regulated Electric | ||||||
Segment Reporting Information [Line Items] | ||||||
Operating revenues | 2,224,563 | 2,213,880 | 4,410,017 | 4,439,073 | ||
Net income (loss) | 205,440 | 214,955 | 383,677 | 295,976 | [1] | |
Regulated Natural Gas | ||||||
Segment Reporting Information [Line Items] | ||||||
Equity investments in unconsolidated subsidiaries | 133,700 | 133,700 | $ 130,000 | |||
Operating revenues | 259,140 | 284,303 | 825,116 | 1,000,975 | ||
Net income (loss) | 11,933 | (6,883) | 90,271 | 76,793 | ||
All Other | ||||||
Segment Reporting Information [Line Items] | ||||||
Operating revenues | 16,808 | 17,543 | 38,273 | 38,903 | ||
Net income (loss) | (20,578) | (11,141) | (35,841) | (23,772) | ||
Operating Segments | ||||||
Segment Reporting Information [Line Items] | ||||||
Operating revenues | 2,499,849 | 2,515,134 | 5,272,122 | 5,477,353 | ||
Operating Segments | Regulated Electric | ||||||
Segment Reporting Information [Line Items] | ||||||
Operating revenues | 2,224,142 | 2,213,460 | 4,409,261 | 4,438,323 | ||
Operating Segments | Regulated Natural Gas | ||||||
Segment Reporting Information [Line Items] | ||||||
Operating revenues | 258,899 | 284,131 | 824,588 | 1,000,127 | ||
Operating Segments | All Other | ||||||
Segment Reporting Information [Line Items] | ||||||
Operating revenues | 16,808 | 17,543 | 38,273 | 38,903 | ||
Intersegment Eliminations | ||||||
Segment Reporting Information [Line Items] | ||||||
Operating revenues | (662) | (592) | (1,284) | (1,598) | ||
Net income (loss) | 0 | 0 | 0 | 0 | ||
Intersegment Eliminations | Regulated Electric | ||||||
Segment Reporting Information [Line Items] | ||||||
Operating revenues | 421 | 420 | 756 | 750 | ||
Intersegment Eliminations | Regulated Natural Gas | ||||||
Segment Reporting Information [Line Items] | ||||||
Operating revenues | 241 | 172 | 528 | 848 | ||
Intersegment Eliminations | All Other | ||||||
Segment Reporting Information [Line Items] | ||||||
Operating revenues | $ 0 | $ 0 | $ 0 | $ 0 | ||
[1] | Includes a net of tax charge related to the Monticello LCM/EPU project. See Note 5. |
Earnings Per Share (Details)
Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2016 | Jun. 30, 2015 | Jun. 30, 2016 | Jun. 30, 2015 | |
Dilutive Impact of Common Stock Equivalents on Earnings per Share (Abstract] | ||||
Net income | $ 196,795 | $ 196,931 | $ 438,107 | $ 348,997 |
Basic earnings per share [Abstract] | ||||
Earnings available to common shareholders | $ 196,795 | $ 196,931 | $ 438,107 | $ 348,997 |
Weighted average common shares outstanding - basic (in shares) | 508,930 | 507,707 | 508,789 | 507,359 |
Earnings available to common shareholders - basic (in dollars per share) | $ 0.39 | $ 0.39 | $ 0.86 | $ 0.69 |
Effect of dilutive securities [Abstract] | ||||
Time based equity awards (in shares) | 560 | 367 | 522 | 388 |
Diluted earnings per share [Abstract] | ||||
Earnings available to common shareholders | $ 196,795 | $ 196,931 | $ 438,107 | $ 348,997 |
Weighted average common shares outstanding - diluted (in shares) | 509,490 | 508,074 | 509,311 | 507,747 |
Earnings available to common shareholders - diluted (in dollars per share) | $ 0.39 | $ 0.39 | $ 0.86 | $ 0.69 |
Benefit Plans and Other Postr67
Benefit Plans and Other Postretirement Benefits (Details) $ in Thousands | 1 Months Ended | 3 Months Ended | 6 Months Ended | ||
Jan. 31, 2016USD ($)Plan | Jun. 30, 2016USD ($) | Jun. 30, 2015USD ($) | Jun. 30, 2016USD ($) | Jun. 30, 2015USD ($) | |
Pension Benefits | |||||
Components of Net Periodic Benefit Cost [Abstract] | |||||
Service cost | $ 22,945 | $ 24,828 | $ 45,865 | $ 49,656 | |
Interest cost | 40,028 | 37,131 | 80,051 | 74,262 | |
Expected return on plan assets | (52,575) | (53,472) | (105,150) | (106,945) | |
Amortization of prior service credit | (477) | (451) | (961) | (902) | |
Amortization of net loss | 24,385 | 31,288 | 48,770 | 62,576 | |
Net periodic benefit cost (credit) | 34,306 | 39,324 | 68,575 | 78,647 | |
Costs not recognized due to the effects of regulation | (4,159) | (7,523) | (8,611) | (15,019) | |
Net benefit cost (credit) recognized for financial reporting | 30,147 | 31,801 | 59,964 | 63,628 | |
Total contributions to Xcel Energy's pension plans during the period | $ 125,000 | ||||
Number of pension plans to which contributions were made | Plan | 4 | ||||
Postretirement Health Care Benefits | |||||
Components of Net Periodic Benefit Cost [Abstract] | |||||
Service cost | 431 | 529 | 863 | 1,058 | |
Interest cost | 6,526 | 6,324 | 13,053 | 12,648 | |
Expected return on plan assets | (6,248) | (6,650) | (12,497) | (13,300) | |
Amortization of prior service credit | (2,671) | (2,671) | (5,343) | (5,343) | |
Amortization of net loss | 1,009 | 1,351 | 2,020 | 2,702 | |
Net periodic benefit cost (credit) | (953) | (1,117) | (1,904) | (2,235) | |
Costs not recognized due to the effects of regulation | 0 | 0 | 0 | 0 | |
Net benefit cost (credit) recognized for financial reporting | $ (953) | $ (1,117) | $ (1,904) | $ (2,235) |
Other Comprehensive Income (Det
Other Comprehensive Income (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2016 | Jun. 30, 2015 | Jun. 30, 2016 | Jun. 30, 2015 | |
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | ||||
Accumulated other comprehensive income (loss) at beginning of period | $ 10,600,920 | |||
(Gains) losses reclassified from net accumulated other comprehensive loss | $ 1,801 | $ 1,483 | 3,603 | $ 2,944 |
Accumulated other comprehensive income (loss) at end of period | 10,703,134 | 10,703,134 | ||
Gains and Losses on Cash Flow Hedges | ||||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | ||||
Accumulated other comprehensive income (loss) at beginning of period | (53,928) | (57,054) | (54,862) | (57,628) |
Other comprehensive income (loss) before reclassifications | 12 | 18 | 8 | 7 |
(Gains) losses reclassified from net accumulated other comprehensive loss | 936 | 600 | 1,874 | 1,185 |
Net current period other comprehensive income (loss) | 948 | 618 | 1,882 | 1,192 |
Accumulated other comprehensive income (loss) at end of period | (52,980) | (56,436) | (52,980) | (56,436) |
Unrealized Gains and Losses on Marketable Securities | ||||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | ||||
Accumulated other comprehensive income (loss) at beginning of period | 110 | 111 | 110 | 110 |
Other comprehensive income (loss) before reclassifications | 0 | 1 | 0 | 2 |
(Gains) losses reclassified from net accumulated other comprehensive loss | 0 | 0 | 0 | 0 |
Net current period other comprehensive income (loss) | 0 | 1 | 0 | 2 |
Accumulated other comprehensive income (loss) at end of period | 110 | 112 | 110 | 112 |
Defined Benefit Pension and Postretirement Items | ||||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | ||||
Accumulated other comprehensive income (loss) at beginning of period | (54,790) | (49,745) | (55,001) | (50,621) |
Other comprehensive income (loss) before reclassifications | 0 | 0 | (653) | 0 |
(Gains) losses reclassified from net accumulated other comprehensive loss | 865 | 883 | 1,729 | 1,759 |
Net current period other comprehensive income (loss) | 865 | 883 | 1,076 | 1,759 |
Accumulated other comprehensive income (loss) at end of period | (53,925) | (48,862) | (53,925) | (48,862) |
Total | ||||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | ||||
Accumulated other comprehensive income (loss) at beginning of period | (108,608) | (106,688) | (109,753) | (108,139) |
Other comprehensive income (loss) before reclassifications | 12 | 19 | (645) | 9 |
(Gains) losses reclassified from net accumulated other comprehensive loss | 1,801 | 1,483 | 3,603 | 2,944 |
Net current period other comprehensive income (loss) | 1,813 | 1,502 | 2,958 | 2,953 |
Accumulated other comprehensive income (loss) at end of period | $ (106,795) | $ (105,186) | $ (106,795) | $ (105,186) |
Other Comprehensive Income (Rec
Other Comprehensive Income (Reclassifications from AOCI) (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | |||
Jun. 30, 2016 | Jun. 30, 2015 | Jun. 30, 2016 | Jun. 30, 2015 | ||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||||
Operating and maintenance expenses | $ 596,978 | $ 594,279 | $ 1,174,388 | $ 1,180,109 | |
Total, pre-tax | (301,192) | (306,812) | (671,154) | (542,458) | |
Tax benefit | 104,397 | 109,881 | 233,047 | 193,461 | |
Total amounts reclassified, net of tax | 1,801 | 1,483 | 3,603 | 2,944 | |
Gains and Losses on Cash Flow Hedges | |||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||||
Total amounts reclassified, net of tax | 936 | 600 | 1,874 | 1,185 | |
Gains and Losses on Cash Flow Hedges | Amounts Reclassified from Accumulated Other Comprehensive Loss | |||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||||
Total, pre-tax | 1,530 | 982 | 3,072 | 1,949 | |
Tax benefit | (594) | (382) | (1,198) | (764) | |
Total, net of tax | 936 | 600 | 1,874 | 1,185 | |
Prior service credit | Amounts Reclassified from Accumulated Other Comprehensive Loss | |||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||||
Total, pre-tax | [1] | 1,478 | 1,533 | 2,956 | 3,068 |
Amortization of net loss | Amounts Reclassified from Accumulated Other Comprehensive Loss | |||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||||
Total, pre-tax | [1] | (64) | (89) | (128) | (179) |
Defined Benefit Pension and Postretirement Items | |||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||||
Total amounts reclassified, net of tax | 865 | 883 | 1,729 | 1,759 | |
Defined Benefit Pension and Postretirement Items | Amounts Reclassified from Accumulated Other Comprehensive Loss | |||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||||
Total, pre-tax | 1,414 | 1,444 | 2,828 | 2,889 | |
Tax benefit | (549) | (561) | (1,099) | (1,130) | |
Total amounts reclassified, net of tax | 865 | 883 | 1,729 | 1,759 | |
Interest Rate Swap | Gains and Losses on Cash Flow Hedges | Amounts Reclassified from Accumulated Other Comprehensive Loss | |||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||||
Interest charges | [2] | 1,483 | 954 | 2,968 | 1,894 |
Vehicle Fuel Derivatives | Gains and Losses on Cash Flow Hedges | Amounts Reclassified from Accumulated Other Comprehensive Loss | |||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||||
Operating and maintenance expenses | [3] | $ 47 | $ 28 | $ 104 | $ 55 |
[1] | Included in the computation of net periodic pension and postretirement benefit costs. See Note 12 for details regarding these benefit plans. | ||||
[2] | Included in interest charges. | ||||
[3] | Included in O&M expenses. |