Document_and_Entity_Informatio
Document and Entity Information | 9 Months Ended | |
Sep. 30, 2013 | Oct. 18, 2013 | |
Document and Entity Information [Abstract] | ||
Entity Registrant Name | XCEL ENERGY INC | |
Entity Central Index Key | 72903 | |
Current Fiscal Year End Date | -19 | |
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 | 497,639,485 | |
Document Fiscal Year Focus | 2013 | |
Document Fiscal Period Focus | Q3 | |
Document Type | 10-Q | |
Amendment Flag | FALSE | |
Document Period End Date | 30-Sep-13 |
CONSOLIDATED_STATEMENTS_OF_INC
CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) (USD $) | 3 Months Ended | 9 Months Ended | ||
In Thousands, except Per Share data, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 |
Operating revenues | ||||
Electric | $2,599,925 | $2,532,709 | $6,911,998 | $6,506,320 |
Natural gas | 205,358 | 174,513 | 1,216,275 | 1,016,861 |
Other | 17,055 | 17,119 | 55,827 | 53,907 |
Total operating revenues | 2,822,338 | 2,724,341 | 8,184,100 | 7,577,088 |
Operating expenses | ||||
Electric fuel and purchased power | 1,097,944 | 1,006,830 | 3,034,031 | 2,725,183 |
Cost of natural gas sold and transported | 74,847 | 49,739 | 702,987 | 557,444 |
Cost of sales — other | 7,540 | 7,251 | 23,832 | 20,499 |
Operating and maintenance expenses | 575,305 | 531,480 | 1,667,093 | 1,576,178 |
Conservation and demand side management program expenses | 67,811 | 68,920 | 192,288 | 191,242 |
Depreciation and amortization | 228,491 | 239,051 | 721,131 | 694,364 |
Taxes (other than income taxes) | 105,287 | 100,636 | 320,765 | 305,892 |
Total operating expenses | 2,157,225 | 2,003,907 | 6,662,127 | 6,070,802 |
Operating income | 665,113 | 720,434 | 1,521,973 | 1,506,286 |
Other (expense) income, net | -404 | 488 | 3,931 | 4,953 |
Equity earnings of unconsolidated subsidiaries | 7,273 | 7,490 | 22,379 | 22,150 |
Allowance for funds used during construction — equity | 21,284 | 15,860 | 63,147 | 44,504 |
Interest charges and financing costs | ||||
Interest charges — includes other financing costs of $6,020, $6,010, $24,058 and $18,126, respectively | 144,758 | 153,719 | 431,199 | 457,470 |
Allowance for funds used during construction — debt | -9,377 | -10,439 | -28,451 | -24,729 |
Total interest charges and financing costs | 135,381 | 143,280 | 402,748 | 432,741 |
Income from continuing operations before income taxes | 557,885 | 600,992 | 1,208,682 | 1,145,152 |
Income taxes | 193,349 | 202,845 | 410,676 | 380,161 |
Income from continuing operations | 364,536 | 398,147 | 798,006 | 764,991 |
Income (loss) from discontinued operations, net of tax | 216 | -41 | 173 | 68 |
Net income | $364,752 | $398,106 | $798,179 | $765,059 |
Weighted average common shares outstanding: | ||||
Basic (in shares) | 498,149 | 488,084 | 495,256 | 487,722 |
Diluted (in shares) | 498,641 | 488,578 | 495,767 | 488,198 |
Earnings per average common share: | ||||
Basic (in dollars per share) | $0.73 | $0.82 | $1.61 | $1.57 |
Diluted (in dollars per share) | $0.73 | $0.81 | $1.61 | $1.57 |
Cash dividends declared per common share (in dollars per share) | $0.28 | $0.27 | $0.83 | $0.80 |
CONSOLIDATED_STATEMENTS_OF_INC1
CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) (Parenthetical) (USD $) | 3 Months Ended | 9 Months Ended | ||
In Thousands, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 |
Interest charges and financing costs | ||||
Other financing costs | $6,020 | $6,010 | $24,058 | $18,126 |
CONSOLIDATED_STATEMENTS_OF_COM
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) (USD $) | 3 Months Ended | 9 Months Ended | ||
In Thousands, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 |
Comprehensive income: | ||||
Net income | $364,752 | $398,106 | $798,179 | $765,059 |
Pension and retiree medical benefits: | ||||
Amortization of losses included in net periodic benefit cost, net of tax of $686, $636, $3,918 and $1,905, respectively | 1,179 | 911 | 1,675 | 2,738 |
Derivative instruments: | ||||
Net fair value increase (decrease), net of tax of $14, $(5,913), $(2) and $(12,586), respectively | 22 | -8,853 | -9 | -19,188 |
Reclassification of losses to net income, net of tax of $266, $296, $2,145 and $610, respectively | 539 | 393 | 928 | 756 |
Total derivative instruments, net of tax | 561 | -8,460 | 919 | -18,432 |
Marketable securities: | ||||
Net fair value increase (decrease), net of tax of $73, $(30), $56 and $89, respectively | 115 | -45 | 79 | 129 |
Other comprehensive income (loss) | 1,855 | -7,594 | 2,673 | -15,565 |
Comprehensive income | $366,607 | $390,512 | $800,852 | $749,494 |
CONSOLIDATED_STATEMENTS_OF_COM1
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) (Parenthetical) (USD $) | 3 Months Ended | 9 Months Ended | ||
In Thousands, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 |
Pension and retiree medical benefits: | ||||
Amortization of losses included in net periodic benefit cost, tax | $686 | $636 | $3,918 | $1,905 |
Derivative instruments: | ||||
Net fair value increase (decrease), tax | 14 | -5,913 | -2 | -12,586 |
Reclassification of losses to net income, tax | 266 | 296 | 2,145 | 610 |
Marketable securities: | ||||
Net fair value increase (decrease), tax | $73 | ($30) | $56 | $89 |
CONSOLIDATED_STATEMENTS_OF_CAS
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) (USD $) | 9 Months Ended | |
In Thousands, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 |
Operating activities | ||
Net income | $798,179 | $765,059 |
Remove income from discontinued operations | -173 | -68 |
Adjustments to reconcile net income to cash provided by operating activities: | ||
Depreciation and amortization | 740,623 | 707,630 |
Conservation and demand side management program amortization | 5,024 | 5,511 |
Nuclear fuel amortization | 76,447 | 79,171 |
Deferred income taxes | 409,662 | 440,413 |
Amortization of investment tax credits | -4,973 | -4,656 |
Allowance for equity funds used during construction | -63,147 | -44,504 |
Equity earnings of unconsolidated subsidiaries | -22,379 | -22,150 |
Dividends from unconsolidated subsidiaries | 27,503 | 24,922 |
Share-based compensation expense | 28,362 | 20,886 |
Net realized and unrealized hedging and derivative transactions | -12,011 | -90,123 |
Changes in operating assets and liabilities: | ||
Accounts receivable | -108,488 | -125,803 |
Accrued unbilled revenues | 87,652 | 166,857 |
Inventories | -69,918 | 55,511 |
Other current assets | 6,060 | -30,289 |
Accounts payable | -3,297 | -118,276 |
Net regulatory assets and liabilities | 100,648 | 1,848 |
Other current liabilities | 129,984 | -35,283 |
Pension and other employee benefit obligations | -159,592 | -181,281 |
Change in other noncurrent assets | 26,710 | -38,790 |
Change in other noncurrent liabilities | 10,032 | -4,664 |
Net cash provided by operating activities | 2,002,908 | 1,571,921 |
Investing activities | ||
Utility capital/construction expenditures | -2,454,198 | -1,805,843 |
Proceeds from insurance recoveries | 90,000 | 56,892 |
Allowance for equity funds used during construction | 63,147 | 44,504 |
Purchases of investments in external decommissioning fund | -1,177,398 | -501,009 |
Proceeds from the sale of investments in external decommissioning fund | 1,172,597 | 501,009 |
Investment in WYCO Development LLC | -3,418 | -779 |
Change in restricted cash | 0 | 95,287 |
Other, net | -1,524 | 343 |
Net cash used in investing activities | -2,310,794 | -1,609,596 |
Financing activities | ||
(Repayments of) proceeds from short-term borrowings, net | -300,000 | 85,000 |
Proceeds from issuance of long-term debt | 1,434,989 | 1,691,322 |
Repayments of long-term debt, including reacquisition premiums | -654,864 | -653,532 |
Proceeds from issuance of common stock | 229,420 | 5,878 |
Repurchase of common stock | 0 | -18,529 |
Purchase of common stock for settlement of equity awards | 0 | -23,307 |
Dividends paid | -382,148 | -362,568 |
Net cash provided by financing activities | 327,397 | 724,264 |
Net change in cash and cash equivalents | 19,511 | 686,589 |
Cash and cash equivalents at beginning of period | 82,323 | 60,684 |
Cash and cash equivalents at end of period | 101,834 | 747,273 |
Supplemental disclosure of cash flow information: | ||
Cash paid for interest (net of amounts capitalized) | -411,130 | -436,296 |
Cash received (paid) for income taxes, net | 16,851 | -6,257 |
Supplemental disclosure of non-cash investing and financing transactions: | ||
Property, plant and equipment additions in accounts payable | 299,209 | 229,847 |
Issuance of common stock for reinvested dividends and 401(k) plans | $54,963 | $51,350 |
CONSOLIDATED_BALANCE_SHEETS_UN
CONSOLIDATED BALANCE SHEETS (UNAUDITED) (USD $) | Sep. 30, 2013 | Dec. 31, 2012 |
In Thousands, unless otherwise specified | ||
Current assets | ||
Cash and cash equivalents | $101,834 | $82,323 |
Accounts receivable, net | 786,874 | 718,046 |
Accrued unbilled revenues | 575,711 | 663,363 |
Inventories | 604,628 | 535,574 |
Regulatory assets | 396,271 | 352,977 |
Derivative instruments | 92,687 | 69,013 |
Deferred income taxes | 325,972 | 32,528 |
Prepayments and other | 236,764 | 171,315 |
Total current assets | 3,120,741 | 2,625,139 |
Property, plant and equipment, net | 25,342,578 | 23,809,348 |
Other assets | ||
Nuclear decommissioning fund and other investments | 1,679,987 | 1,617,865 |
Regulatory assets | 2,709,283 | 2,762,029 |
Derivative instruments | 95,894 | 126,297 |
Other | 178,169 | 200,008 |
Total other assets | 4,663,333 | 4,706,199 |
Total assets | 33,126,652 | 31,140,686 |
Current liabilities | ||
Current portion of long-term debt | 280,538 | 258,155 |
Short-term debt | 302,000 | 602,000 |
Accounts payable | 965,572 | 959,093 |
Regulatory liabilities | 208,943 | 168,858 |
Taxes accrued | 335,846 | 334,441 |
Accrued interest | 134,612 | 162,494 |
Dividends payable | 139,333 | 131,748 |
Derivative instruments | 26,729 | 32,482 |
Other | 445,488 | 287,802 |
Total current liabilities | 2,839,061 | 2,937,073 |
Deferred credits and other liabilities | ||
Deferred income taxes | 5,186,944 | 4,434,909 |
Deferred investment tax credits | 79,609 | 82,761 |
Regulatory liabilities | 1,052,726 | 1,059,939 |
Asset retirement obligations | 1,785,319 | 1,719,796 |
Derivative instruments | 217,027 | 242,866 |
Customer advances | 266,676 | 252,888 |
Pension and employee benefit obligations | 998,212 | 1,163,265 |
Other | 239,519 | 229,207 |
Total deferred credits and other liabilities | 9,826,032 | 9,185,631 |
Commitments and contingencies | ||
Capitalization | ||
Long-term debt | 10,914,273 | 10,143,905 |
Common stock — 1,000,000,000 shares authorized of $2.50 par value; 497,625,709 and 487,959,516 shares outstanding at Sept. 30, 2013 and Dec. 31, 2012, respectively | 1,244,064 | 1,219,899 |
Additional paid in capital | 5,615,716 | 5,353,015 |
Retained earnings | 2,797,486 | 2,413,816 |
Accumulated other comprehensive loss | -109,980 | -112,653 |
Total common stockholders’ equity | 9,547,286 | 8,874,077 |
Total liabilities and equity | $33,126,652 | $31,140,686 |
CONSOLIDATED_BALANCE_SHEETS_UN1
CONSOLIDATED BALANCE SHEETS (UNAUDITED) (Parenthetical) (USD $) | Sep. 30, 2013 | Dec. 31, 2012 |
Capitalization, Long-term Debt and Equity [Abstract] | ||
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) | 497,625,709 | 487,959,516 |
CONSOLIDATED_STATEMENTS_OF_COM2
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY (UNAUDITED) (USD $) | Total | Common Stock [Member] | Additional Paid In Capital [Member] | Retained Earnings [Member] | Accumulated Other Comprehensive Loss [Member] |
In Thousands, except Share data, unless otherwise specified | |||||
Beginning balance at Dec. 31, 2011 | $8,482,198 | $1,216,234 | $5,327,443 | $2,032,556 | ($94,035) |
Balance (in shares) at Dec. 31, 2011 | 486,494,000 | ||||
Increase (Decrease) in Stockholders' Equity | |||||
Net income | 765,059 | 765,059 | |||
Other comprehensive income (loss) | -15,565 | -15,565 | |||
Dividends declared: | |||||
Common stock | -391,599 | -391,599 | |||
Issuances of common stock | 23,997 | 4,548 | 19,449 | ||
Issuances of common stock (in shares) | 1,819,000 | ||||
Repurchase of common stock | -18,529 | -1,750 | -16,779 | ||
Repurchase of common stock (in shares) | -700,000 | ||||
Purchase of common stock for settlement of equity awards | -23,307 | -23,307 | |||
Share-based compensation | 27,909 | 27,909 | |||
Ending balance at Sep. 30, 2012 | 8,850,163 | 1,219,032 | 5,334,715 | 2,406,016 | -109,600 |
Balance (in shares) at Sep. 30, 2012 | 487,613,000 | ||||
Beginning balance at Jun. 30, 2012 | 8,573,505 | 1,218,214 | 5,316,658 | 2,140,639 | -102,006 |
Balance (in shares) at Jun. 30, 2012 | 487,286,000 | ||||
Increase (Decrease) in Stockholders' Equity | |||||
Net income | 398,106 | 398,106 | |||
Other comprehensive income (loss) | -7,594 | -7,594 | |||
Dividends declared: | |||||
Common stock | -132,729 | -132,729 | |||
Issuances of common stock | 9,497 | 818 | 8,679 | ||
Issuances of common stock (in shares) | 327,000 | ||||
Share-based compensation | 9,378 | 9,378 | |||
Ending balance at Sep. 30, 2012 | 8,850,163 | 1,219,032 | 5,334,715 | 2,406,016 | -109,600 |
Balance (in shares) at Sep. 30, 2012 | 487,613,000 | ||||
Beginning balance at Dec. 31, 2012 | 8,874,077 | 1,219,899 | 5,353,015 | 2,413,816 | -112,653 |
Balance (in shares) at Dec. 31, 2012 | 487,959,516 | 487,960,000 | |||
Increase (Decrease) in Stockholders' Equity | |||||
Net income | 798,179 | 798,179 | |||
Other comprehensive income (loss) | 2,673 | 2,673 | |||
Dividends declared: | |||||
Common stock | -414,509 | -414,509 | |||
Issuances of common stock | 252,916 | 24,165 | 228,751 | ||
Issuances of common stock (in shares) | 9,666,000 | ||||
Share-based compensation | 33,950 | 33,950 | |||
Ending balance at Sep. 30, 2013 | 9,547,286 | 1,244,064 | 5,615,716 | 2,797,486 | -109,980 |
Balance (in shares) at Sep. 30, 2013 | 497,625,709 | 497,626,000 | |||
Beginning balance at Jun. 30, 2013 | 9,300,245 | 1,243,239 | 5,595,906 | 2,572,935 | -111,835 |
Balance (in shares) at Jun. 30, 2013 | 497,296,000 | ||||
Increase (Decrease) in Stockholders' Equity | |||||
Net income | 364,752 | 364,752 | |||
Other comprehensive income (loss) | 1,855 | 1,855 | |||
Dividends declared: | |||||
Common stock | -140,201 | -140,201 | |||
Issuances of common stock | 9,791 | 825 | 8,966 | ||
Issuances of common stock (in shares) | 330,000 | ||||
Share-based compensation | 10,844 | 10,844 | |||
Ending balance at Sep. 30, 2013 | $9,547,286 | $1,244,064 | $5,615,716 | $2,797,486 | ($109,980) |
Balance (in shares) at Sep. 30, 2013 | 497,625,709 | 497,626,000 |
Managements_Opinion
Management's Opinion | 9 Months Ended |
Sep. 30, 2013 | |
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 Sept. 30, 2013 and Dec. 31, 2012; the results of its operations, including the components of net income and comprehensive income, and changes in stockholders’ equity for the three and nine months ended Sept. 30, 2013 and 2012; and its cash flows for the nine months ended Sept. 30, 2013 and 2012. All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after Sept. 30, 2013 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, 2012 balance sheet information has been derived from the audited 2012 consolidated financial statements included in the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, 2012. 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, 2012, filed with the SEC on Feb. 22, 2013. 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_Account
Summary of Significant Accounting Policies | 9 Months Ended |
Sep. 30, 2013 | |
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, 2012, appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference. |
Accounting_Pronouncements
Accounting Pronouncements | 9 Months Ended |
Sep. 30, 2013 | |
New Accounting Pronouncements and Changes in Accounting Principles [Abstract] | |
Accounting Pronouncements | Accounting Pronouncements |
Recently Adopted | |
Balance Sheet Offsetting — In December 2011, the Financial Accounting Standards Board (FASB) issued Balance Sheet (Topic 210) — Disclosures about Offsetting Assets and Liabilities (Accounting Standards Update (ASU) No. 2011-11), which requires disclosures regarding netting arrangements in agreements underlying derivatives, certain financial instruments and related collateral amounts, and the extent to which an entity’s financial statement presentation policies related to netting arrangements impact amounts recorded to the financial statements. In January 2013, the FASB issued Balance Sheet (Topic 210) – Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities (ASU No. 2013-01) to clarify the specific instruments that should be considered in these disclosures. These disclosure requirements do not affect the presentation of amounts in the consolidated balance sheets, and were effective for annual reporting periods beginning on or after Jan. 1, 2013, and interim periods within those annual reporting periods. Xcel Energy implemented the disclosure guidance effective Jan. 1, 2013, and the implementation did not have a material impact on its consolidated financial statements. See Note 8 for the required disclosures. | |
Comprehensive Income Disclosures — In February 2013, the FASB issued Comprehensive Income (Topic 220) — Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income (ASU No. 2013-02), which requires detailed disclosures regarding changes in components of accumulated other comprehensive income and amounts reclassified out of accumulated other comprehensive income. These disclosure requirements do not change how net income or comprehensive income are presented in the consolidated financial statements. These disclosure requirements were effective for annual reporting periods beginning on or after Dec. 15, 2012, and interim periods within those annual reporting periods. Xcel Energy implemented the disclosure guidance effective Jan. 1, 2013, and the implementation did not have a material impact on its consolidated financial statements. See Note 13 for the required disclosures. |
Selected_Balance_Sheet_Data
Selected Balance Sheet Data | 9 Months Ended | ||||||||
Sep. 30, 2013 | |||||||||
Balance Sheet Related Disclosures [Abstract] | |||||||||
Selected Balance Sheet Data | Selected Balance Sheet Data | ||||||||
(Thousands of Dollars) | Sept. 30, 2013 | Dec. 31, 2012 | |||||||
Accounts receivable, net | |||||||||
Accounts receivable | $ | 838,271 | $ | 769,440 | |||||
Less allowance for bad debts | (51,397 | ) | (51,394 | ) | |||||
$ | 786,874 | $ | 718,046 | ||||||
(Thousands of Dollars) | Sept. 30, 2013 | Dec. 31, 2012 | |||||||
Inventories | |||||||||
Materials and supplies | $ | 228,302 | $ | 213,739 | |||||
Fuel | 201,728 | 189,425 | |||||||
Natural gas | 174,598 | 132,410 | |||||||
$ | 604,628 | $ | 535,574 | ||||||
(Thousands of Dollars) | Sept. 30, 2013 | Dec. 31, 2012 | |||||||
Property, plant and equipment, net | |||||||||
Electric plant | $ | 29,550,871 | $ | 28,285,031 | |||||
Natural gas plant | 3,942,182 | 3,836,335 | |||||||
Common and other property | 1,467,811 | 1,480,558 | |||||||
Plant to be retired (a) | 115,753 | 152,730 | |||||||
Construction work in progress | 2,391,783 | 1,757,189 | |||||||
Total property, plant and equipment | 37,468,400 | 35,511,843 | |||||||
Less accumulated depreciation | (12,462,716 | ) | (12,048,697 | ) | |||||
Nuclear fuel | 2,157,940 | 2,090,801 | |||||||
Less accumulated amortization | (1,821,046 | ) | (1,744,599 | ) | |||||
$ | 25,342,578 | $ | 23,809,348 | ||||||
(a) | In 2010, in response to the Clean Air Clean Jobs Act (CACJA), the Colorado Public Utilities Commission (CPUC) approved the early retirement of Cherokee Units 1, 2 and 3, Arapahoe Unit 3 and Valmont Unit 5 between 2011 and 2017. In 2011, Cherokee Unit 2 was retired and in 2012, Cherokee Unit 1 was retired. Amounts are presented net of accumulated depreciation. |
Income_Taxes
Income Taxes | 9 Months Ended | ||||||||
Sep. 30, 2013 | |||||||||
Income Tax Disclosure [Abstract] | |||||||||
Income Taxes | Income Taxes | ||||||||
Except to the extent noted below, the circumstances set forth in 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, 2012 appropriately represent, in all material respects, the current status of other income tax matters, and are incorporated herein by reference. | |||||||||
Federal Audit — Xcel Energy files a consolidated federal income tax return. The statute of limitations applicable to Xcel Energy’s 2008 federal income tax return expired in September 2012. The statute of limitations applicable to Xcel Energy’s 2009 federal income tax return expires in June 2015. In the third quarter of 2012, the Internal Revenue Service (IRS) commenced an examination of tax years 2010 and 2011. As of Sept. 30, 2013, the IRS had not proposed any material adjustments to tax years 2010 and 2011. | |||||||||
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 Sept. 30, 2013, 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 | 2006 | ||||||||
Minnesota | 2009 | ||||||||
Texas | 2009 | ||||||||
Wisconsin | 2009 | ||||||||
In the fourth quarter of 2012, the state of Colorado commenced an examination of tax years 2006 through 2009. In the first quarter of 2013, the state of Wisconsin commenced an examination of tax years 2009 through 2011. As of Sept. 30, 2013, no material adjustments had been proposed for either of these audits. There are currently 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) | Sept. 30, 2013 | Dec. 31, 2012 | |||||||
Unrecognized tax benefit — Permanent tax positions | $ | 8.8 | $ | 4.7 | |||||
Unrecognized tax benefit — Temporary tax positions | 32.4 | 29.8 | |||||||
Total unrecognized tax benefit | $ | 41.2 | $ | 34.5 | |||||
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) | Sept. 30, 2013 | Dec. 31, 2012 | |||||||
NOL and tax credit carryforwards | $ | (40.1 | ) | $ | (33.5 | ) | |||
It is reasonably possible that Xcel Energy’s amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS and state audits progress. As the IRS examination moves closer to completion, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $35 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 Sept. 30, 2013 and Dec. 31, 2012 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of Sept. 30, 2013 or Dec. 31, 2012. | |||||||||
Tangible Property Regulations — In September 2013, the U.S. Treasury issued final regulations addressing the tax consequences associated with the acquisition, production and improvement of tangible property. As Xcel Energy had adopted certain utility-specific guidance previously issued by the IRS, the issuance is not expected to have a material impact on its consolidated financial statements. |
Rate_Matters
Rate Matters | 9 Months Ended | ||||||||||||
Sep. 30, 2013 | |||||||||||||
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, 2012 and in Note 5 to Xcel Energy Inc.’s Quarterly Reports on Form 10-Q for the quarter periods ended March 31, 2013 and June 30, 2013, appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference. | |||||||||||||
NSP-Minnesota | |||||||||||||
Recently Concluded Regulatory Proceedings — Minnesota Public Utilities Commission (MPUC) | |||||||||||||
NSP-Minnesota – Minnesota 2013 Electric Rate Case — In November 2012, NSP-Minnesota filed a request with the MPUC for an increase in annual revenues of approximately $285 million, or 10.7 percent. The rate filing was based on a 2013 forecast test year (FTY), a requested return on equity (ROE) of 10.6 percent, an average electric rate base of approximately $6.3 billion and an equity ratio of 52.56 percent. In January 2013, interim rates of approximately $251 million became effective, subject to refund. | |||||||||||||
NSP-Minnesota subsequently revised the requested annual revenue increase to approximately $209 million, or 7.8 percent, based on an ROE of 10.6 percent, a rate base of approximately $6.3 billion an equity ratio of 52.56 percent. The revenue requirement reflected a requested deficiency of $259 million combined with $50 million of rate mitigation through deferral mechanisms. | |||||||||||||
On Sept. 3, 2013, the MPUC issued an order approving a rate increase of approximately $103 million, or 3.8 percent, based on a 9.83 percent ROE and 52.56 percent equity ratio. In addition, the MPUC authorized approximately $20 million in deferrals, as well as a $24 million reduction in revenue and depreciation expense. | |||||||||||||
The table below reconciles NSP-Minnesota’s original request to the final MPUC order: | |||||||||||||
(Millions of Dollars) | NSP-Minnesota Request | Administrative Law Judge (ALJ) Recommendation | MPUC Order | ||||||||||
NSP-Minnesota original request | $ | 285 | $ | 285 | $ | 285 | |||||||
ROE | — | (43 | ) | (43 | ) | ||||||||
Sherco Unit 3 | (35 | ) | (38 | ) | (34 | ) | |||||||
Reduced recovery for nuclear plants | (11 | ) | (14 | ) | (15 | ) | |||||||
Incentive compensation | (3 | ) | (4 | ) | (4 | ) | |||||||
Sales forecast | (1 | ) | (26 | ) | (26 | ) | |||||||
Pension | (10 | ) | (13 | ) | (13 | ) | |||||||
Employee benefits | (4 | ) | (6 | ) | (6 | ) | |||||||
Black Dog remediation | (5 | ) | (5 | ) | (5 | ) | |||||||
Estimated impact of the theoretical depreciation reserve | — | — | (24 | ) | |||||||||
NSP-Wisconsin wholesale allocation | (7 | ) | (7 | ) | (7 | ) | |||||||
Other, net | — | (2 | ) | (5 | ) | ||||||||
Recommended rate increase | 209 | 127 | 103 | ||||||||||
Estimated impact of cost deferrals | 50 | 34 | 20 | ||||||||||
Estimated impact of the theoretical depreciation reserve | — | — | 24 | ||||||||||
Impact on pre-tax income | $ | 259 | $ | 161 | $ | 147 | |||||||
NSP-Minnesota filed its final rate implementation and interim rate refund compliance filing on Sept. 19, 2013, requesting final rates be implemented Dec. 1, 2013, with interim rate refunds of approximately $132.2 million, including interest, to begin by January 2014. The Office of the Attorney General requested the MPUC to reconsider its Sept. 3, 2013 order with respect to the calculation of AFUDC. NSP-Minnesota has filed a response opposing the motion. Both items are pending MPUC action. | |||||||||||||
In the third quarter of 2013, NSP-Minnesota increased the reserve for revenue subject to refund by $30 million, and also recorded a reduction to depreciation expense and other operating expenses in the same amount, to implement the cost deferral and depreciation requirements of the final MPUC order. Adjustments to the reserve in the third quarter of 2013 related to revenue recognized in the first and second quarters of 2013 were not material. | |||||||||||||
NSP-Minnesota Nuclear Project Prudence Investigation — In the NSP-Minnesota 2013 Minnesota electric rate case final order, the MPUC initiated an investigation to determine whether the costs in excess of those included in the Certificate of Need (CON) for NSP-Minnesota’s Monticello life cycle management (LCM)/extended power uprate (EPU) project were prudently incurred. In October 2013, NSP-Minnesota filed a summary report and witness testimony to further support the change in and prudence of the incurred costs. The filing indicated the increase in costs was primarily attributable to three factors: (1) the original estimate was based on a high level conceptual design and the project scope increased as the actual conditions of the plant were incorporated into the design; (2) implementation difficulties, including the amount of work that occurred in confined and radioactive or electrically sensitive spaces and NSP-Minnesota’s and its vendors’ ability to attract and retain experienced workers; and (3) additional Nuclear Regulatory Commission (NRC) licensing related requests over the five-plus year application process. In September 2013, the Advisory Committee to the NRC on Reactor Safety recommended approval of the EPU license. The EPU license is expected to be granted by the end of 2013 and the complementary MELLA Plus fuel license is anticipated to be received in March 2014. NSP-Minnesota has provided information that the cost deviation is in line with similar upgrade projects undertaken and the project remains economically beneficial to customers. The results and any recommendations from the conclusion of this prudence proceeding are expected to be considered by the MPUC in NSP-Minnesota’s 2014 Minnesota electric rate case. | |||||||||||||
Pending Regulatory Proceedings — North Dakota Public Service Commission (NDPSC) | |||||||||||||
NSP-Minnesota – North Dakota 2013 Electric Rate Case — In December 2012, NSP-Minnesota filed a request with the NDPSC to increase annual retail electric rates approximately $16.9 million, or 9.25 percent. The rate filing is based on a 2013 FTY, a requested ROE of 10.6 percent, an electric rate base of approximately $377.6 million and an equity ratio of 52.56 percent. In January 2013, the NDPSC approved an interim electric increase of $14.7 million, effective Feb. 16, 2013, subject to refund. In June 2013, NSP-Minnesota revised its rate increase to $16 million, reflecting updated information. | |||||||||||||
On Aug. 12, 2013, NSP-Minnesota filed rebuttal testimony revising the requested increase in retail electric rates to approximately $14.9 million, based on a revised ROE of 10.25 percent and incorporating the updated information from June 2013. | |||||||||||||
On Aug. 22, 2013, NDPSC Staff filed supplemental testimony revising their recommendation by removing a positive adjustment for federal taxes and adjusting depreciation to reflect longer asset lives. In total, the NDPSC Staff’s filed position was modified to a $10 million rate reduction. The recommendation reflects a 9.0 percent ROE. | |||||||||||||
Primary revenue requirement adjustments include: | |||||||||||||
(Millions of Dollars) | NSP-Minnesota Rebuttal Testimony | NDPSC Position | |||||||||||
as Supplemented | |||||||||||||
NSP-Minnesota revised request | $ | 16 | $ | 16 | |||||||||
Use of a one month coincident peak demand allocator for certain rate base and operation expenses | — | (20.4 | ) | ||||||||||
ROE | (1.2 | ) | (5.2 | ) | |||||||||
Incentive compensation | — | (0.8 | ) | ||||||||||
Adjustment for various O&M expenses | — | (0.7 | ) | ||||||||||
Modified cost of capital and increased capital structure to 53.42 percent | 0.1 | 1.3 | |||||||||||
Depreciation/remaining life study | — | (1.1 | ) | ||||||||||
Other, net | — | 0.9 | |||||||||||
Recommended rate increase (decrease) | $ | 14.9 | $ | (10.0 | ) | ||||||||
Evidentiary hearings were conducted in late August 2013. A final NDPSC decision on the case is anticipated in the fourth quarter of 2013 or the first quarter of 2014. | |||||||||||||
Recently Concluded Regulatory Proceedings — South Dakota Public Utilities Commission (SDPUC) | |||||||||||||
NSP-Minnesota – South Dakota 2012 Electric Rate Case — In March 2013, NSP-Minnesota and the SDPUC Staff reached a settlement agreement that provides for a base rate increase of approximately $11.6 million and the implementation of a new rider. On Oct. 1, 2013, NSP-Minnesota filed its compliance report consistent with the settlement to recover the revenue requirement on the specific major capital additions and incremental property tax resulting in recovery of $8.7 million for 2014. | |||||||||||||
NSP-Wisconsin | |||||||||||||
Pending Regulatory Proceedings — Public Service Commission of Wisconsin (PSCW) | |||||||||||||
NSP-Wisconsin – Wisconsin 2014 Electric and Gas Rate Case — On May 31, 2013, NSP-Wisconsin filed a request with the PSCW to increase rates for electric and natural gas service effective Jan. 1, 2014. NSP-Wisconsin requested an overall increase in annual electric rates of $40.0 million, or 6.5 percent, and an increase in natural gas rates of $4.7 million, or 3.8 percent. | |||||||||||||
The rate filing is based on a 2014 FTY, an ROE of 10.4 percent, an equity ratio of 52.5 percent and a forecasted average net investment rate base of approximately $895.3 million for the electric utility and $89.8 million for the natural gas utility. | |||||||||||||
On Oct. 4, 2013, the PSCW Staff filed their direct testimony and recommended an electric rate increase of $23.8 million, or 3.8 percent, and a natural gas rate decrease of $1.1 million, or 0.9 percent. PSCW Staff’s recommendations were based on a 10.2 percent ROE and a 52.5 percent equity ratio. | |||||||||||||
The most significant adjustments proposed by the PSCW Staff are shown in the table below: | |||||||||||||
(Millions of Dollars) | Electric | Natural Gas | |||||||||||
Staff Testimony | Staff Testimony | ||||||||||||
Oct-13 | Oct-13 | ||||||||||||
Rate request | $ | 40 | $ | 4.7 | |||||||||
Electric fuel and purchased power | (5.1 | ) | — | ||||||||||
Sales forecast | (4.8 | ) | — | ||||||||||
Incentive compensation and merit pay | (3.0 | ) | (0.6 | ) | |||||||||
ROE | (1.6 | ) | (0.2 | ) | |||||||||
Conservation funding transfer | 0.7 | (0.7 | ) | ||||||||||
Depreciation expense | (0.7 | ) | (1.3 | ) | |||||||||
Ashland site amortization expense | — | (2.3 | ) | ||||||||||
Other, net | (1.7 | ) | (0.7 | ) | |||||||||
Recommended rate increase (decrease) | $ | 23.8 | $ | (1.1 | ) | ||||||||
The majority of the adjustment to electric fuel and purchased power is the result of the PSCW Staff’s proposal to discontinue using the New York Mercantile Exchange (NYMEX) futures prices as a basis for setting the fuel price forecast and instead using a discounted percentage of the NYMEX futures prices. PSCW Staff’s sales forecast adjustment is based on the assumption that the strong sales growth trend from 2010 through 2012, primarily in the large commercial/industrial sector, will continue through 2013 and 2014, while NSP-Wisconsin’s forecast shows moderating growth. | |||||||||||||
On Oct. 18, 2013, NSP-Wisconsin filed rebuttal testimony, revising the requested electric rate increase to $34.0 million and natural gas rate increase to zero, based on a 10.4 percent ROE and other adjustments. | |||||||||||||
Next steps in the procedural schedule are as follows: | |||||||||||||
• | Surrebuttal testimony - Oct. 28, 2013; | ||||||||||||
• | Hearing - Oct. 30, 2013; | ||||||||||||
• | Initial brief - Nov. 13, 2013; and | ||||||||||||
• | Reply brief - Nov. 20, 2013. | ||||||||||||
A PSCW decision is anticipated in December 2013, with final rates going into effect in January 2014. | |||||||||||||
PSCo | |||||||||||||
Pending and Recently Concluded Regulatory Proceedings — CPUC | |||||||||||||
PSCo – Colorado 2013 Gas Rate Case — In December 2012, PSCo filed a multi-year request with the CPUC to increase Colorado retail natural gas rates by $48.5 million in 2013 with subsequent step increases of $9.9 million in 2014 and $12.1 million in 2015. The request is based on a 2013 FTY, a 10.5 percent ROE, a rate base of $1.3 billion and an equity ratio of 56 percent. PSCo is requesting an extension of its Pipeline System Integrity Adjustment (PSIA) rider mechanism to collect the costs associated with its pipeline integrity efforts, including accelerated system renewal projects. PSCo estimates that the PSIA will increase by $26.8 million in 2014 with a subsequent step increase of $24.7 million in 2015 in addition to the proposed changes in base rate revenue. In conjunction with the multi-year base rate step increases, PSCo is proposing a stay-out provision and an earnings test through the end of 2015 with a commitment to file a rate case to implement revised rates on Jan. 1, 2016. Interim rates, subject to refund, went into effect in August 2013. | |||||||||||||
In April 2013, four parties filed answer testimony in the natural gas case. The CPUC Staff recommended an incremental base revenue decrease of $1.1 million, based on a historic test year (HTY), an ROE of 9 percent and an equity ratio of 52 percent. The Office of Consumer Counsel (OCC) recommended an incremental base revenue increase of $15.4 million based on an HTY, an ROE of 9 percent and equity ratio of 51.03 percent and other adjustments. The recommended incremental base revenues are inclusive of proposed changes to the level of integrity management costs moved from the PSIA rider to base rates. | |||||||||||||
In April 2013, PSCo filed rebuttal testimony and revised its requested annual rate increase to $44.8 million for 2013, with subsequent step increases of $9.0 million for 2014 and $10.9 million for 2015, based on an ROE of 10.3 percent. This requested increase includes amounts to be transferred from the PSIA rider mechanism. The deficiency, based on an FTY, was $30.6 million. | |||||||||||||
In October 2013, the ALJ issued her recommendation. As part of this decision, she recommended the use of an HTY, an ROE of 9.72 percent and an equity ratio of 56 percent. The ALJ also recommended to reject PSCo’s proposed changes to the PSIA, instead leaving the current rider in effect and suggested that changes be presented in a separate application. The recommended incremental base revenue increase was approximately $15.0 million. | |||||||||||||
The following table summarizes the CPUC Staff, OCC and ALJ’s recommendations: | |||||||||||||
(Millions of Dollars) | CPUC Staff | OCC | ALJ | ||||||||||
PSCo deficiency based on a FTY | $ | 44.8 | $ | 44.8 | $ | 44.8 | |||||||
Move to HTY | (1.6 | ) | (1.6 | ) | (1.6 | ) | |||||||
ROE and capital structure adjustments | (20.8 | ) | (20.0 | ) | (7.7 | ) | |||||||
Move to a 13 month average from year end rate base | (5.7 | ) | (3.2 | ) | (3.3 | ) | |||||||
Remove pension asset | (5.9 | ) | — | — | |||||||||
Reduce pension expense net of corrections | (1.6 | ) | — | — | |||||||||
Remove incentive compensation | (3.5 | ) | (0.2 | ) | (0.2 | ) | |||||||
Challenge known and measurable | — | (9.0 | ) | — | |||||||||
Eliminate depreciation annualization | — | (1.8 | ) | — | |||||||||
Revenue adjustments | (4.1 | ) | (1.4 | ) | (1.4 | ) | |||||||
Resulting tax impacts | 1.5 | 4.7 | (0.2 | ) | |||||||||
Other adjustments | (4.2 | ) | 3.1 | (1.2 | ) | ||||||||
Remove PSIA from base rates | (14.2 | ) | (14.2 | ) | — | ||||||||
Recommendation | $ | (15.3 | ) | $ | 1.2 | $ | 29.2 | ||||||
Neutralize PSIA - base rate transfer | 14.2 | 14.2 | (14.2 | ) | |||||||||
Incremental base revenue | $ | (1.1 | ) | $ | 15.4 | $ | 15 | ||||||
Exceptions and corresponding responses are due to be filed in November 2013 and a CPUC decision is expected in December 2013. | |||||||||||||
PSCo – Colorado 2013 Steam Rate Case — In December 2012, PSCo filed a request to increase Colorado retail steam rates by $1.6 million in 2013 with subsequent step increases of $0.9 million in 2014 and $2.3 million in 2015. The request is based on a 2013 FTY, a 10.5 percent ROE, a rate base of $21 million for steam and an equity ratio of 56 percent. | |||||||||||||
In October 2013, PSCo, the CPUC Staff, the OCC and Colorado Energy Consumers representing the Buildings Owners Management Association filed a comprehensive settlement which ties the outcome of the steam rate case to key issues to be decided in the natural gas rate case, including ROE and capital structure and allows the filed rates to be effective on Jan. 1, 2014, subject to refund for 60 days, resulting in a minimum 2014 annual rate increase of $1.2 million. The settlement withdraws the rate relief request for 2015 pending the outcome of the certificate of public convenience and necessity (CPCN) proceeding for the construction of the Sun Valley Steam Center. A decision on the settlement is expected at the end of 2013. | |||||||||||||
PSCo – Annual Electric Earnings Test — An earnings sharing mechanism is used to apply prospective electric rate adjustments for earnings in the prior year over PSCo’s authorized ROE threshold of 10 percent. In June 2013, PSCo entered into a comprehensive settlement of issues with all parties associated with the 2012 earnings test, resulting in a refund obligation of approximately $8.2 million to be refunded through June 2014. As of Sept. 30, 2013, PSCo has also recognized management’s best estimate of an accrual for the 2013 test year. | |||||||||||||
PSCo – Production Formula Rate ROE Complaint — On Aug. 30, 2013, PSCo’s wholesale production customers filed a complaint with the Federal Energy Regulatory Commission (FERC), and requested it reduce the stated ROEs ranging from 10.1 percent through 10.4 percent to 9.04 percent in the PSCo power sales formula rates, which could reduce revenues approximately $2 million per year prospectively. The matter is currently pending the FERC’s action. | |||||||||||||
Renewable Energy Credit (REC) Sharing — In May 2011, the CPUC determined that margin sharing on stand-alone REC transactions would be shared 20 percent to PSCo and 80 percent to customers and ultimately becoming 10 percent to PSCo and 90 percent to customers by 2014. The CPUC also approved a change to the treatment of hybrid REC trading margins (RECs that are bundled with energy) that allows the customers’ share of the margins to be netted against the renewable energy standard adjustment (RESA) regulatory asset balance. | |||||||||||||
In March 2012, the CPUC approved an annual margin sharing on the first $20 million of margins on hybrid REC trades of 80 percent to the customers and 20 percent to PSCo. Margins in excess of the $20 million are to be shared 90 percent to the customers and 10 percent to PSCo. The CPUC authorized PSCo to return to customers unspent carbon offset funds by crediting the RESA regulatory asset balance. For the three months ended Sept. 30, 2013 and 2012, PSCo credited the RESA regulatory asset balance $6.1 million and $6.2 million, respectively. The cumulative credit to the RESA regulatory asset balance was $99.4 million and $82.8 million at Sept. 30, 2013 and Dec. 31, 2012, respectively. The credits include the customers’ share of REC trading margins and the customers’ share of carbon offset funds. | |||||||||||||
This sharing mechanism will be effective through 2014. The CPUC is then expecting to review the framework and evidence regarding actual deliveries before determining to continue the sharing mechanism. | |||||||||||||
Electric Commodity Adjustment (ECA) / RESA Adjustment — In July 2013, PSCo advised the CPUC that it had inadvertently allocated purchased power expense between the deferred accounts for the ECA and the RESA from 2010 to 2012. In order to be in compliance with a series of CPUC orders, PSCo proposed to transfer from the RESA deferred account to the ECA deferred account approximately $26.2 million and to amortize the recovery of this amount over 12 months. The transfer, if approved, would mainly impact the timing of recovery. In addition, interest of $2.6 million was accrued on the amount related to the RESA. The PSCo application to change the ECA tariff to address this issue has been set for hearing in December 2013 by the CPUC. | |||||||||||||
ECA Prudence Review — In September 2013, the CPUC Staff requested that the 2012 annual ECA prudence review be set for hearing. The prudence review, as determined by the ALJ, will primarily consider if replacement power costs during the outage of jointly owned facilities were properly allocated between wholesale and retail customers. A hearing is expected in January 2014. | |||||||||||||
2012 PSIA Report — In April 2013, PSCo filed its 2012 PSIA report. The OCC and CPUC Staff requested the CPUC set the matter for hearing to review in detail the information provided, including a review of the prudence of expenditures in 2012, and to develop standards for future filings. The CPUC approved the request on July 10, 2013 and assigned the matter to an ALJ. | |||||||||||||
Next steps in the procedural schedule are as follows: | |||||||||||||
• | Direct testimony - Nov. 5, 2013; | ||||||||||||
• | Intervenor testimony - Jan. 7, 2014; | ||||||||||||
• | Rebuttal testimony - Feb. 6, 2014; | ||||||||||||
• | Evidentiary hearing - March 3 - March 7, 2014; | ||||||||||||
• | Initial brief - March 28, 2014; and | ||||||||||||
• | Reply brief - April 11, 2014. | ||||||||||||
SPS | |||||||||||||
Recently Concluded Regulatory Proceedings — Public Utility Commission of Texas (PUCT) | |||||||||||||
SPS – Texas 2012 Electric Rate Case — In November 2012, SPS filed an electric rate case in Texas with the PUCT for an increase in annual revenue of approximately $90.2 million. The rate filing is based on a historic twelve month test year ended June 30, 2012 (adjusted for known and measurable changes), a requested ROE of 10.65 percent, an electric rate base of $1.15 billion and an equity ratio of 52 percent. | |||||||||||||
In June 2013, the PUCT approved a settlement agreement in which SPS’ base rate increased by $37 million, effective May 1, 2013 and by an additional $13.8 million on Sept. 1, 2013. In addition, the settlement allows SPS to file a transmission cost recovery adjustment rider in the fourth quarter of 2013 and for those rates to become effective on an interim basis in January 2014. Under the settlement, SPS cannot file another base rate case in 2013, but there are no restrictions on SPS filing a base rate case in 2014. | |||||||||||||
Pending Regulatory Proceedings — New Mexico Public Regulation Commission (NMPRC) | |||||||||||||
SPS – New Mexico 2014 Electric Rate Case — In December 2012, SPS filed an electric rate case in New Mexico with the NMPRC for an increase in annual revenue of approximately $45.9 million effective in 2014. The rate filing is based on a 2014 FTY, a requested ROE of 10.65 percent, a jurisdictional electric rate base of $479.8 million and an equity ratio of 53.89 percent. On June 19, 2013, SPS revised its requested rate increase to $43.3 million. | |||||||||||||
In August 2013, the NMPRC Staff (Staff), the New Mexico Attorney General (NMAG), the Federal Executive Agencies, the Coalition of Clean Affordable Energy, Occidental Permian, Ltd. and New Mexico Gas Company filed testimony. | |||||||||||||
The following table summarizes certain parties’ recommendations from SPS’ revised request: | |||||||||||||
(Millions of Dollars) | Staff | NMAG | |||||||||||
Testimony | Testimony | ||||||||||||
Aug-13 | Aug-13 | ||||||||||||
SPS revised request | $ | 43.3 | $ | 43.3 | |||||||||
Rate rider for renewable energy costs (a) | (14.5 | ) | (8.5 | ) | |||||||||
Present revenues (sales growth and weather) | (4.4 | ) | (6.4 | ) | |||||||||
ROE (9.8 percent and 8.63 percent, respectively) | (3.2 | ) | (8.1 | ) | |||||||||
Capital structure | (1.5 | ) | (1.1 | ) | |||||||||
Employee benefits | (2.8 | ) | (1.8 | ) | |||||||||
Reduced recovery for payroll expense | (0.1 | ) | (0.1 | ) | |||||||||
Gain on sale of transmission assets | — | (1.7 | ) | ||||||||||
Fuel clause revenue | 6 | — | |||||||||||
Other, net | (5.0 | ) | (6.6 | ) | |||||||||
Recommended rate increase | $ | 17.8 | $ | 9 | |||||||||
Means of recovery: | |||||||||||||
Base revenue | $ | 8.8 | $ | (6.0 | ) | ||||||||
Rider revenue | 7.3 | 13.3 | |||||||||||
Fuel cost adjustment revenue | 1.7 | 1.7 | |||||||||||
$ | 17.8 | $ | 9 | ||||||||||
(a) | Adjustments represent recommended deferrals, extended amortizations and moving costs from rider to fuel in base rates. | ||||||||||||
On Sept. 9, 2013, SPS filed rebuttal testimony, revising its requested rate increase to $32.5 million, based on updated information and an ROE of 10.25 percent. This reflects a base and fuel increase of $20.9 million, an increase of rider revenue of $12.1 million and a decrease to other of $0.5 million. | |||||||||||||
The hearings on the merits of the case concluded in September 2013. Next steps in the procedural schedule are expected to be as follows: | |||||||||||||
• | A recommended decision is anticipated from the hearing examiner in November 2013; | ||||||||||||
• | An NMPRC decision is anticipated in the first quarter of 2014; and | ||||||||||||
• | Final rates are expected to be effective in the first quarter of 2014. | ||||||||||||
SPS – 2004 FERC Complaint Case Orders — In August 2013, the FERC issued an order on rehearing and clarification related to a 2004 Complaint case brought by Golden Spread (a wholesale cooperative customer) and Public Service Company of New Mexico (PNM) and an Order on Initial Decision in a subsequent 2006 rate case filed by SPS. The original Complaint included two key components; the first was the appropriateness of the allocations of system average fuel costs and the second was a base rate complaint, including the appropriate demand-related cost allocator. | |||||||||||||
The first issue related to PNM’s claim regarding inappropriate allocation of fuel costs. The FERC clarified its initial order and granted SPS’ request for clarification that PNM was not entitled to refunds based on the FERC’s April 2008 Order in the Complaint case. The FERC determined that refunds should apply only to firm requirements customers and not PNM’s contractual load. | |||||||||||||
The second issue related to the use of a 12 coincident peak (CP) vs. 3CP demand allocator. This issue first arose in the base rate revenue requirements portion of Golden Spread’s 2004 Complaint as well as SPS’ 2006 rate case. In December 2007, SPS reached a settlement of all fuel issues with Golden Spread, and entered a formula rate agreement for its production costs. That agreement indicated that all issues from the complaint period were resolved and that all base rate issues from the 2006 rate case were resolved other than the 12CP vs. 3CP issue and the formula rate tariff allows this issue to be resolved. | |||||||||||||
In April 2008, the FERC issued an order resolving the remaining rate issues and found in favor of SPS on the disputed rate issue, concluding that SPS was a 12CP system. Golden Spread asked for rehearing of this issue in May of 2008. Also in May 2008, in a subsequent SPS rate case involving all requirements customers (other than Golden Spread), the FERC granted the motion of the full requirements customers and SPS reaffirming that SPS was a 12CP system. As a result of these FERC actions, SPS considered the issued to be resolved and the risk of loss to be remote. | |||||||||||||
In the orders issued in August 2013, the FERC reversed itself, stating that it erred in its initial analysis and determined that the SPS system was a 3CP rather than a 12CP system. As a result, SPS estimates that the combination of the order and the December 2007 settlement creates a refund liability of approximately $42 million including interest. This would be partially offset by a reserve that had been established for the PNM decision and the amounts for which the New Mexico Cooperatives had agreed to refund in the event of this outcome. The pre-tax impact to 2013 earnings from these orders is approximately $35 million, which was recorded in the third quarter of 2013. Pending the timing and resolution of this matter, the annual impact to revenues through 2014 could be up to $6 million and decreasing to $4 million on June 1, 2015. | |||||||||||||
In September 2013, SPS filed a request for rehearing of the FERC ruling on the CP allocation and refund decisions. SPS asserted that the FERC applied an improper burden of proof in reversing the 2008 ruling and that precedent did not support retroactive refunds. PNM also requested rehearing of the FERC decision not to reverse its prior ruling. In October 2013, the FERC issued orders further considering the requests for rehearing. These matters are currently pending the FERC’s action. If unsuccessful in its rehearing request, SPS will have the opportunity to file rate cases with the FERC and its retail jurisdictions in attempt to change all customers to a 3CP allocation method. | |||||||||||||
Purchase and Sale Agreement for Certain Texas Transmission Assets — On March 29, 2013, SPS entered into a purchase and sale agreement with Sharyland Distribution and Transmission Services, LLC (Sharyland) for the sale of certain segments of SPS’ transmission lines and two related substations for a base purchase price of $37 million, subject to adjustments for unplanned capital expenditures. The transaction is subject to various regulatory approvals including that of the FERC. | |||||||||||||
On April 29, 2013, SPS made filings regarding the planned transaction with the PUCT, the NMPRC and the FERC. If approved, the sale is expected to close by the end of 2013. The FERC approved the transaction in August 2013 and on Sept. 20, 2013 SPS filed an unopposed stipulation at the PUCT resolving all issues related to the SPS items in the joint application SPS filed together with Sharyland. In the proposed settlement to the PUCT, the Texas retail jurisdiction would be allocated 45 percent of the net pre-tax gain on sale and this amount would be shared 60 percent with customers and 40 percent would be retained by SPS. | |||||||||||||
On Sept. 12, 2013, the NMPRC Staff and the NMAG filed testimony in support of the sale of the transmission assets. Both parties proposed that SPS’ New Mexico retail customers should retain 100 percent of any New Mexico jurisdictional share of the gain on sale. On Sept. 27, 2013, SPS filed rebuttal testimony before the NMPRC disputing the positions presented by the NMPRC Staff and the NMAG. An evidentiary hearing was held on Oct. 8, 2013. | |||||||||||||
Decisions are expected from the NMPRC and PUCT in the fourth quarter of 2013. |
Commitments_and_Contingencies
Commitments and Contingencies | 9 Months Ended | ||||||||
Sep. 30, 2013 | |||||||||
Commitments and Contingencies Disclosure [Abstract] | |||||||||
Commitments and Contingencies | Commitments and Contingencies | ||||||||
Except to the extent noted below and in Note 5, 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, 2012, appropriately represent, in all material respects, the current status of commitments and contingent liabilities, including those regarding public liability for claims resulting from any nuclear incident, 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 | |||||||||
Under certain purchased power agreements, 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 purchased power agreements create a variable interest in the associated independent power producing entity. | |||||||||
The Xcel Energy utility subsidiaries had approximately 3,338 megawatts (MW) and 3,324 MW of capacity under long-term purchased power agreements as of Sept. 30, 2013 and Dec. 31, 2012, respectively, 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 the year 2033. | |||||||||
Guarantees and 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 Sept. 30, 2013 and Dec. 31, 2012, 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 Inc.: | |||||||||
(Millions of Dollars) | Sept. 30, 2013 | Dec. 31, 2012 | |||||||
Guarantees issued and outstanding | $ | 54.8 | $ | 69.5 | |||||
Current exposure under these guarantees | 17.8 | 17.9 | |||||||
Bonds with indemnity protection | 31.9 | 29.6 | |||||||
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 Manufactured Gas Plant (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 Ashland site) includes property owned by NSP-Wisconsin, which was a site previously operated by a predecessor company as a MGP facility (the Upper Bluff), and two other properties: an adjacent city lakeshore park area (Kreher Park), on which an unaffiliated third party previously operated a sawmill and conducted creosote treating operations; and an area of Lake Superior’s Chequamegon Bay adjoining the park (the Sediments). | |||||||||
The U.S. Environmental Protection Agency (EPA) issued its Record of Decision (ROD) in 2010, which describes the preferred remedy the EPA has selected for the cleanup of the Ashland site. In 2011, the EPA issued special notice letters identifying several entities, including NSP-Wisconsin, as PRPs, for future remediation at the site. The special notice letters requested that those PRPs participate in negotiations with the EPA regarding how the PRPs intended to conduct or pay for the remediation at the Ashland site. As a result of those settlement negotiations, the EPA agreed to segment the Ashland site into separate areas. The first area (Phase I Project Area) includes soil and groundwater in Kreher Park and the Upper Bluff. The second area includes the Sediments. | |||||||||
In October 2012, a settlement among the EPA, the Wisconsin Department of Natural Resources (WDNR), the Bad River and Red Cliff Bands of the Lake Superior Tribe of Chippewa Indians and NSP-Wisconsin was approved by the U.S. District Court for the Western District of Wisconsin. This settlement resolves claims against NSP-Wisconsin for its alleged responsibility for the remediation of the Phase I Project Area. Under the terms of the settlement, NSP-Wisconsin agreed to perform the remediation of the Phase I Project Area, but does not admit any liability with respect to the Ashland site. The settlement reflects a cost estimate for the clean up of the Phase I Project Area of $40 million. The settlement also resolves claims by the federal, state and tribal trustees against NSP-Wisconsin for alleged natural resource damages at the Ashland site, including both the Phase I Project Area and the Sediments. As part of the settlement, NSP-Wisconsin has conveyed approximately 1,390 acres of land to the State of Wisconsin and tribal trustees. Fieldwork to address the Phase I Project Area at the Ashland site began at the end of 2012 and continues. | |||||||||
Negotiations between the EPA and NSP-Wisconsin regarding who will pay or perform the cleanup of the Sediments are ongoing. In August and September 2013, NSP-Wisconsin performed field studies in the Sediments to gather more data about site conditions. The data from that investigation will be received and reported in November 2013. Also, in September 2013, the EPA requested NSP-Wisconsin consider re-submitting another proposal to perform a wet dredge pilot study for a portion of the Sediments. NSP-Wisconsin previously submitted a proposal for a wet dredge pilot study in 2011. The EPA’s ROD for the Ashland site includes estimates that the cost of the preferred remediation related to the Sediments is between $63 million and $77 million, with a potential deviation in such estimated costs of up to 50 percent higher to 30 percent lower. | |||||||||
In August 2012, NSP-Wisconsin also filed litigation against other PRPs for their share of the cleanup costs for the Ashland site. Trial for this matter has been rescheduled for April 2015. Negotiations between the EPA, NSP-Wisconsin and several of the other PRPs regarding the PRPs’ fair share of the cleanup costs for the Ashland site are also ongoing. | |||||||||
At Sept. 30, 2013 and Dec. 31, 2012, NSP-Wisconsin had recorded a liability of $101.2 million and $103.7 million, respectively, for the Ashland site based upon potential remediation and design costs together with estimated outside legal and consultant costs; of which $19.5 million and $20.1 million, respectively, was considered a current liability. NSP-Wisconsin’s potential liability, the actual cost of remediation and the time frame over which the amounts may be paid are subject to change. NSP-Wisconsin also continues to work to identify and access state and federal funds to apply to the ultimate remediation cost of the entire site. Unresolved issues or factors that could result in higher or lower NSP-Wisconsin remediation costs for the Ashland site include the cleanup approach implemented for the Sediments, which party implements the cleanup, the timing of when the cleanup is implemented, potential contributions by other PRPs and whether federal or state funding may be directed to help offset remediation costs at the Ashland site. | |||||||||
NSP-Wisconsin has deferred the estimated site remediation costs, as a regulatory asset, based on an expectation that the PSCW will continue to allow NSP-Wisconsin to recover payments for environmental remediation from its customers. The PSCW has consistently authorized in NSP-Wisconsin rates recovery of all remediation costs incurred at the Ashland site, and has authorized recovery of MGP remediation costs by other Wisconsin utilities. External MGP remediation costs are subject to deferral in the Wisconsin retail jurisdiction and are reviewed for prudence as part of the Wisconsin retail rate case process. Under an existing PSCW policy, utilities have recovered remediation costs for MGPs in natural gas rates, amortized over a four- to six-year period. The PSCW historically has not allowed utilities to recover their carrying costs on unamortized regulatory assets for MGP remediation. | |||||||||
In the last rate case decision, the PSCW recognized the potential magnitude of the future liability for the cleanup at the Ashland site and granted an exception to its existing policy at the request of NSP-Wisconsin. The elements of this exception include: 1) approval to begin recovery of estimated Phase 1 Project costs beginning on Jan. 1, 2013; 2) approval to amortize these estimated costs over a ten-year period; and 3) approval to apply a three percent carrying cost to the unamortized regulatory asset. Implementation of this exception will help mitigate the rate impact to natural gas customers and the risk to NSP-Wisconsin from a longer amortization period. | |||||||||
Environmental Requirements | |||||||||
Greenhouse Gas (GHG) New Source Performance Standard (NSPS) Proposal and Emission Guideline for Existing Sources — In September 2013, the EPA re-proposed a GHG NSPS for newly constructed power plants which seeks to establish carbon dioxide (CO2) emission rates for coal-fired power plants that reflect emission reductions using partial carbon capture and storage technology (CCS). The EPA’s proposed CO2 emission limits for gas-fired power plants reflect emissions levels from combined cycle technology with no CCS. The EPA continues to propose that the NSPS not apply to modified or reconstructed existing power plants. In addition, installation of control equipment on existing plants would not constitute a “modification” to those plants under the NSPS program. It is not possible to evaluate the impact of the re-proposed NSPS until its final requirements are known. | |||||||||
In June 2013, President Obama issued a memorandum directing the EPA to develop GHG emission standards for existing power plants. The memorandum anticipates the EPA will issue a proposed GHG emission standard for existing power plants in June 2014. It is not possible to evaluate the impact of existing source standards until the upcoming proposal and final requirements are known. | |||||||||
Cross-State Air Pollution Rule (CSAPR) — In 2011, the EPA issued the CSAPR to address long range transport of particulate matter (PM) and ozone by requiring reductions in sulfur dioxide (SO2) and nitrogen oxide (NOx) from utilities in the eastern half of the United States. For Xcel Energy, the rule would have applied in Minnesota, Wisconsin and Texas. The CSAPR would have set more stringent requirements than the proposed Clean Air Transport Rule and specifically would have required plants in Texas to reduce their SO2 and annual NOx emissions. The rule also would have created an emissions trading program. | |||||||||
In August 2012, the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit) vacated the CSAPR and remanded it back to the EPA. The D.C. Circuit stated that the EPA must continue administering the Clean Air Interstate Rule (CAIR) pending adoption of a valid replacement. In June 2013, the U.S. Supreme Court elected to review the D.C. Circuit’s 2012 decision to vacate the CSAPR. The Court has ordered the parties to file briefs in the appeal this fall and will hear arguments in December 2013. The Court will likely issue a decision by June 2014. | |||||||||
As the EPA continues administering the CAIR while the CSAPR or a replacement rule is pending, Xcel Energy expects to comply with the CAIR as described below. | |||||||||
CAIR — In 2005, the EPA issued the CAIR to further regulate SO2 and NOx emissions. The CAIR applies to Texas and Wisconsin. The CAIR does not apply to Minnesota. | |||||||||
Under the CAIR’s cap and trade structure, companies can comply through capital investments in emission controls or purchase of emission allowances from other utilities making reductions on their systems. NSP-Wisconsin purchased allowances in 2012 and plans to continue to purchase allowances in 2013 to comply with the CAIR. In the SPS region, installation of low-NOx combustion control technology was completed in 2012 on Tolk Unit 1. SPS plans to install the same combustion control technology on Tolk Unit 2 in 2014. These installations will reduce or eliminate SPS’ need to purchase NOx emission allowances. In addition, SPS has sufficient SO2 allowances to comply with the CAIR in 2013. At Sept. 30, 2013, the estimated annual CAIR NOx allowance cost for Xcel Energy did not have a material impact on the results of operations, financial position or cash flows. | |||||||||
Federal Clean Water Act - Effluent Limitations Guidelines (ELG) — In June 2013, the EPA published a proposed ELG rule for power plants that use coal, natural gas, oil or nuclear materials as fuel and discharge treated effluent to surface waters as well as utility-owned landfills that receive coal combustion residuals. Refuse derived fuel, biomass and other alternatively fueled power plants are not addressed by the proposed revisions. The proposed rule identifies four potential regulatory options and invites comments on those regulatory approaches. The options differ in the number of waste streams covered, size of the units controlled and stringency of controls. A final rule is anticipated in 2014. Under the current proposed rule, facilities would need to comply as soon as possible after July 2017 but no later than July 2022. The impact of this rule on Xcel Energy is uncertain at this time. | |||||||||
Regional Haze Rules — In 2005, the EPA finalized amendments to its regional haze rules, known as best available retrofit technology (BART), which require the installation and operation of emission controls for industrial facilities emitting air pollutants that reduce visibility in certain national parks and wilderness areas. Xcel Energy generating facilities in several states are subject to BART requirements. Individual states were required to identify the facilities located in their states that will have to reduce SO2, NOx and PM emissions under BART and then set emissions limits for those facilities. | |||||||||
PSCo | |||||||||
In 2011, the Colorado Air Quality Control Commission approved a BART state implementation plan (SIP) incorporating the Colorado CACJA emission reduction plan, which will satisfy regional haze requirements. The Colorado legislature enacted a statute approving the SIP (the Colorado SIP), which was signed into law in 2011. Subsequently, the Colorado Mining Association (CMA) challenged the Colorado SIP in a Colorado District Court. In June 2012, the CMA’s appeal was dismissed. The CMA appealed this decision, which is now pending in the Colorado Court of Appeals. | |||||||||
In September 2012, the EPA granted final approval of the Colorado SIP, including the CACJA emission reduction plan for PSCo, as satisfying BART requirements. The emission controls are expected to be installed between 2014 and 2017. Projected costs for emission controls at the Hayden and Pawnee plants are $343.0 million. PSCo expects the cost of any required capital investment will be recoverable from customers. | |||||||||
In March 2013, WildEarth Guardians petitioned the U.S. Court of Appeals for the 10th Circuit to review the EPA’s decision approving the Colorado SIP. WildEarth Guardians has stated that it will challenge the BART determination made for Comanche Units 1 and 2, which was a separate determination that was not part of the CACJA emission reduction plan. In comments before the EPA, WildEarth Guardians urged that current emission limitations be made more stringent, or that Selective Catalytic Reduction (SCR) be added to the units. PSCo has intervened in the case. | |||||||||
In 2010, two environmental groups petitioned the U.S. Department of the Interior (DOI) to certify that 12 coal-fired boilers and one coal-fired cement kiln in Colorado are contributing to visibility problems in Rocky Mountain National Park. The following PSCo plants are named in the petition: Cherokee, Hayden, Pawnee and Valmont. The groups allege that the Colorado BART rule is inadequate to satisfy the Clean Air Act (CAA) mandate of ensuring reasonable further progress towards restoring natural visibility conditions in the park. It is not known when the DOI will rule on the petition. | |||||||||
NSP-Minnesota | |||||||||
In 2009, the Minnesota Pollution Control Agency (MPCA) approved the SIP for Minnesota (the Minnesota SIP), and submitted it to the EPA for approval. The MPCA selected the BART controls for Sherco Units 1 and 2 to improve visibility in the national parks. The MPCA concluded SCRs should not be required because the minor visibility benefits derived from SCRs do not outweigh the substantial costs. The MPCA’s source-specific BART controls for Sherco Units 1 and 2 consist of combustion controls for NOx and scrubber upgrades for SO2. The combustion controls have been installed on Sherco Units 1 and 2. The scrubber upgrades are underway and scheduled to be completed by January 2015. | |||||||||
The EPA’s preliminary review of the Minnesota SIP in 2011 indicated that SCR controls should be added to Sherco Units 1 and 2. Subsequently, the EPA and MPCA both determined that CSAPR meets BART requirements for purposes of the Minnesota SIP. In addition, the MPCA retained its source-specific BART determination for Sherco Units 1 and 2 from the 2009 Minnesota SIP. The EPA approved the Minnesota SIP for electric generating units (EGUs), and also approved the source-specific emission limits for Sherco Units 1 and 2 as strengthening the Minnesota SIP, but avoided characterizing them as BART limits. | |||||||||
In August 2012, the National Parks Conservation Association, Sierra Club, Voyageurs National Park Association, Friends of the Boundary Waters Wilderness, Minnesota Center for Environmental Advocacy and Fresh Energy appealed the EPA’s approval of the Minnesota SIP to the U.S. Court of Appeals for the Eighth Circuit. The Court denied intervention in the case to NSP-Minnesota and other regulated parties who petitioned to intervene. In June 2013, the Court ordered this case to be held in abeyance until the U.S. Supreme Court decides the CSAPR case. | |||||||||
NSP-Minnesota’s estimated cost for meeting the BART, regional haze and other CAA requirements is approximately $50 million, of which $37 million has already been spent on projects to reduce NOx emissions on Sherco Units 1 and 2. Xcel Energy anticipates that all costs associated with BART compliance will be fully recoverable through regulatory recovery mechanisms. If the above litigation results in further EPA proceedings concerning the Minnesota SIP, such proceedings may consider whether SCRs should be required for Sherco Units 1 and 2. | |||||||||
In addition to the regional haze rules, there are other visibility rules related to a program called the Reasonably Attributable Visibility Impairment (RAVI) program. In 2009, the DOI certified that a portion of the visibility impairment in Voyageurs and Isle Royale National Parks is reasonably attributable to emissions from NSP-Minnesota’s Sherco Units 1 and 2. The EPA is required to make its own determination as to whether Sherco Units 1 and 2 cause or contribute to RAVI and, if so, whether the level of controls required by the MPCA is appropriate. The EPA plans to issue a separate notice on the issue of BART for Sherco Units 1 and 2 under the RAVI program. It is not yet known when the EPA will publish a proposal under RAVI or what that proposal will entail. In December 2012, a lawsuit against the EPA was filed in the U.S. District Court for the District of Minnesota by the following organizations: National Parks Conservation Association, Minnesota Center for Environmental Advocacy, Friends of the Boundary Waters Wilderness, Voyageurs National Park Association, Fresh Energy and Sierra Club. The lawsuit alleges that the EPA has failed to perform a nondiscretionary duty to determine BART for the Sherco Units 1 and 2 under the RAVI program. The EPA filed an answer denying the allegations and asserting that it did not have a nondiscretionary duty under the RAVI program. The Court denied NSP-Minnesota’s motion to intervene in July 2013. NSP-Minnesota appealed this decision to the U.S. Court of Appeals for the Eighth Circuit. | |||||||||
SPS | |||||||||
Harrington Units 1 and 2 are potentially subject to BART. Texas has developed a SIP (the Texas SIP) that finds the CAIR equal to BART for EGUs. As a result, no additional controls beyond CAIR compliance would be required. In May 2012, the EPA deferred its review of the Texas SIP in its final rule allowing states to find that CSAPR compliance meets BART requirements for EGUs. It is not yet known how the D.C. Circuit’s reversal of the CSAPR may impact the EPA’s approval of the Texas SIP. | |||||||||
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. | |||||||||
Environmental Litigation | |||||||||
Comer vs. Xcel Energy Inc. et al. — In May 2011, less than a year after their initial lawsuit was dismissed, plaintiffs in this purported class action lawsuit filed a second lawsuit against more than 85 utility, oil, chemical and coal companies in the U.S. District Court in Mississippi. The complaint alleges defendants’ CO2 emissions intensified the strength of Hurricane Katrina and increased the damage plaintiffs purportedly sustained to their property. Plaintiffs base their claims on public and private nuisance, trespass and negligence. Among the defendants named in the complaint are Xcel Energy Inc., SPS, PSCo, NSP-Wisconsin and NSP-Minnesota. The amount of damages claimed by plaintiffs is unknown. The defendants believe this lawsuit is without merit and filed a motion to dismiss the lawsuit. In March 2012, the U.S. District Court granted this motion for dismissal. In April 2012, plaintiffs appealed this decision to the U.S. Court of Appeals for the Fifth Circuit. In May 2013, the Fifth Circuit affirmed the district court’s dismissal of this lawsuit. Plaintiffs elected not to seek further review of this decision, which brings this litigation to a close. No accrual was recorded for this matter. | |||||||||
Employment, Tort and Commercial Litigation | |||||||||
Merricourt Wind Project Litigation — In April 2011, NSP-Minnesota terminated its agreements with enXco Development Corporation (enXco) for the development of a 150 MW wind project in southeastern North Dakota. NSP-Minnesota’s decision to terminate the agreements was based in large part on the adverse impact this project could have on endangered or threatened species protected by federal law and the uncertainty in cost and timing in mitigating this impact. NSP-Minnesota also terminated the agreements due to enXco’s nonperformance of certain other conditions, including failure to obtain a Certificate of Site Compatibility and the failure to close on the contracts by an agreed upon date of March 31, 2011. NSP-Minnesota recorded a $101 million deposit in the first quarter of 2011, which was collected in April 2011. In May 2011, NSP-Minnesota filed a declaratory judgment action in the U.S. District Court in Minnesota to obtain a determination that it acted properly in terminating the agreements. enXco also filed a separate lawsuit in the same court seeking approximately $240 million for an alleged breach of contract. NSP-Minnesota believes enXco’s lawsuit is without merit. In October 2012, NSP-Minnesota filed a motion for summary judgment. In April 2013, the U.S. District Court granted NSP-Minnesota’s motion and entered judgment in its favor. In April 2013, enXco filed a notice of appeal to the Eighth Circuit. It is uncertain when the Eighth Circuit will decide this appeal. Although Xcel Energy believes the likelihood of loss is remote based on existing case law and the U.S. District Court’s April 2013 decision, it is not possible to estimate the amount or range of reasonably possible loss in the event of an adverse outcome of this matter. No accrual has been recorded for this matter. | |||||||||
Exelon Wind (formerly John Deere Wind) Complaint — Several lawsuits in Texas state and federal courts and regulatory proceedings have arisen out of a dispute concerning SPS’ payments for energy and capacity produced from the Exelon Wind subsidiaries’ projects. There are two main areas of dispute. First, Exelon Wind claims that it established legally enforceable obligations (LEOs) for each of its 12 wind facilities in 2005 through 2008 that require SPS to buy power based on SPS’ forecasted avoided cost as determined in 2005 through 2008. Although SPS has refused to accept Exelon Wind’s LEOs, SPS accepts that it must take energy from Exelon Wind under SPS’ PUCT-approved Qualifying Facilities (QF) Tariff. Second, Exelon Wind has raised various challenges to SPS’ PUCT-approved QF Tariff, which became effective in August 2010. The state and federal lawsuits and regulatory proceedings are in various stages of litigation. SPS believes the likelihood of loss in these lawsuits and proceedings is remote based primarily on existing case law and while it is not possible to estimate the amount or range of reasonably possible loss in the event of an adverse outcome, SPS believes such loss would not be material based upon its belief that it would be permitted to recover such costs, if needed, through its various fuel clause mechanisms. No accrual has been recorded for this matter. | |||||||||
Pacific Northwest FERC Refund Proceeding — In July 2001, the FERC ordered a preliminary hearing to determine whether there were unjust and unreasonable charges for spot market bilateral sales in the Pacific Northwest for December 2000 through June 2001. PSCo supplied energy to the Pacific Northwest markets during this period and has been a participant in the hearings. In September 2001, the presiding ALJ concluded that prices in the Pacific Northwest during the referenced period were the result of a number of factors, including the shortage of supply, excess demand, drought and increased natural gas prices. Under these circumstances, the ALJ concluded that the prices in the Pacific Northwest markets were not unreasonable or unjust and no refunds should be ordered. Subsequent to the ruling, the FERC has allowed the parties to request additional evidence. Parties have claimed that the total amount of transactions with PSCo subject to refund is $34 million. In June 2003, the FERC issued an order terminating the proceeding without ordering further proceedings. Certain purchasers filed appeals of the FERC’s orders in this proceeding with the Ninth Circuit. | |||||||||
In an order issued in August 2007, the Ninth Circuit remanded the proceeding back to the FERC and indicated that the FERC should consider other rulings addressing overcharges in the California organized markets. The Ninth Circuit denied a petition for rehearing in April 2009, and the mandate was issued. | |||||||||
The FERC issued an order on remand establishing principles for the review proceeding in October 2011. In September 2012, the City of Seattle filed its direct case against PSCo and other Pacific Northwest sellers claiming refunds for the period January 2000 through June 2001. The City of Seattle indicated that for the period June 2000 through June 2001 PSCo had sales to the City of Seattle of approximately $50 million. The City of Seattle did not identify specific instances of unlawful market activity by PSCo, but rather based its claim for refunds on market dysfunction in the Western markets. PSCo submitted its answering case in December 2012. | |||||||||
In April 2013, the FERC issued an order on rehearing. The FERC confirmed that the City of Seattle would be able to attempt to obtain refunds back from January 2000, but reaffirmed the transaction-specific standard that the City of Seattle and other complainants would have to comply with to obtain refunds. In addition, the FERC rejected the imposition of any market-wide remedies. Although the FERC order on rehearing established the period for which the City of Seattle could seek refunds as January 2000 through June 2001, it is unclear what claim the City of Seattle has against PSCo prior to June 2000. In the proceeding, The City of Seattle does not allege specific misconduct or tariff violations by PSCo but instead asserts generally that the rates charged by PSCo and other sellers were excessive. A FERC hearing on the issue is presently in progress. An ALJ initial decision is expected in December 2013. | |||||||||
Preliminary calculations of the City of Seattle’s claim for refunds from PSCo are approximately $28 million excluding interest. PSCo has concluded that a loss is reasonably possible with respect to this matter; 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. In making this assessment, PSCo considered two factors. First, not withstanding PSCo’s view that the City of Seattle has failed to apply the standard that the FERC has established in this proceeding, and the recognition that this case raises a novel issue and the FERC’s standard has been challenged on appeal to the Ninth Circuit, the outcome of such an appeal cannot be predicted with any certainty. Second, PSCo would expect to make equitable arguments against refunds even if the City of Seattle were to establish that it was overcharged for transactions. If a loss were sustained, PSCo would attempt to recover those losses from other PRPs. No accrual has been recorded for this matter. | |||||||||
Nuclear Power Operations and Waste Disposal | |||||||||
Nuclear Waste Disposal Litigation — In 1998, NSP-Minnesota filed a complaint in the U.S. Court of Federal Claims against the United States requesting breach of contract damages for the U.S. Department of Energy’s (DOE) failure to begin accepting spent nuclear fuel by Jan. 31, 1998, as required by the contract between the United States and NSP-Minnesota. NSP-Minnesota sought contract damages in this lawsuit through Dec. 31, 2004. In September 2007, the court awarded NSP-Minnesota $116.5 million in damages. In August 2007, NSP-Minnesota filed a second complaint; this lawsuit claimed damages for the period Jan. 1, 2005 through Dec. 31, 2008. | |||||||||
In July 2011, the United States and NSP-Minnesota executed a settlement agreement resolving both lawsuits, providing an initial $100 million payment from the United States to NSP-Minnesota, and providing a method by which NSP-Minnesota can recover its spent fuel storage costs through 2013, estimated to be an additional $100 million. The settlement does not address costs for used fuel storage after 2013; such costs could be the subject of future litigation. NSP-Minnesota received the initial $100 million payment in August 2011, the second installment of $18.6 million in March 2012, and the third installment of $20.7 million in October 2012. NSP-Minnesota’s claim submission for the fourth installment, in the amount of $42.8 million, was filed May 15, 2013 for costs incurred in 2012. The DOE recommended payment of $42.6 million for this claim in August 2013. Amounts received from the installments were subsequently credited to customers, except for approved reductions such as legal costs and amounts set aside to be credited through another regulatory mechanism. | |||||||||
In NSP-Wisconsin’s 2012 Electric and Gas Rate Case, the PSCW authorized NSP-Wisconsin to utilize the proceeds from the second and third installments to be included as a reduction of the 2013 electric rate increase. In December 2012, the MPUC approved NSP-Minnesota’s triennial nuclear decommissioning filing which required NSP-Minnesota to place the Minnesota retail portion of the DOE settlement payments for the third installment of $15.3 million and the anticipated fourth installment in 2013 into the nuclear decommissioning fund when received. NSP-Minnesota proposed to contribute the North Dakota retail portion of the second, third and fourth installments to the nuclear decommissioning fund to offset the increase in the decommissioning accrual that was included in the 2012 North Dakota electric rate case. That filing is pending NDPSC action. |
Borrowings_and_Other_Financing
Borrowings and Other Financing Instruments | 9 Months Ended | ||||||||||||
Sep. 30, 2013 | |||||||||||||
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 | Twelve Months Ended | |||||||||||
Sept. 30, 2013 | Dec. 31, 2012 | ||||||||||||
Borrowing limit | $ | 2,450 | $ | 2,450 | |||||||||
Amount outstanding at period end | 302 | 602 | |||||||||||
Average amount outstanding | 347 | 403 | |||||||||||
Maximum amount outstanding | 491 | 634 | |||||||||||
Weighted average interest rate, computed on a daily basis | 0.27 | % | 0.35 | % | |||||||||
Weighted average interest rate at period end | 0.25 | 0.36 | |||||||||||
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 Sept. 30, 2013 and Dec. 31, 2012, there were $18.8 million and $14.2 million of letters of credit outstanding, respectively, under the credit facilities. The contract amounts of these letters of credit approximate their fair value and are subject to fees determined in the marketplace. | |||||||||||||
Credit Facilities — In order to use their commercial paper programs to fulfill short-term funding needs, Xcel Energy Inc. and its utility subsidiaries must have revolving credit facilities in place at least equal to the amount of their respective commercial paper borrowing limits and cannot issue commercial paper in an aggregate amount exceeding available capacity under these credit facilities. 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 Sept. 30, 2013, 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. | $ | 800 | $ | 258 | $ | 542 | |||||||
PSCo | 700 | 6.9 | 693.1 | ||||||||||
NSP-Minnesota | 500 | 44.9 | 455.1 | ||||||||||
SPS | 300 | — | 300 | ||||||||||
NSP-Wisconsin | 150 | 11 | 139 | ||||||||||
Total | $ | 2,450.00 | $ | 320.8 | $ | 2,129.20 | |||||||
(a) | These credit facilities expire in July 2017. | ||||||||||||
(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 Sept. 30, 2013 and Dec. 31, 2012. | |||||||||||||
Long-Term Borrowings and Other Financing Instruments | |||||||||||||
PSCo — In March 2013, PSCo issued $250 million of 2.50 percent first mortgage bonds due March 15, 2023 and $250 million of 3.95 percent first mortgage bonds due March 15, 2043. | |||||||||||||
Xcel Energy Inc. — In May 2013, Xcel Energy Inc. issued $450 million of 0.75 percent senior unsecured notes due May 9, 2016. | |||||||||||||
NSP-Minnesota — In May 2013, NSP-Minnesota issued $400 million of 2.60 percent first mortgage bonds due May 15, 2023. | |||||||||||||
SPS — In August 2013, SPS issued $100 million of 4.50 percent first mortgage bonds due Aug. 15, 2041. Including the $300 million of this series previously issued, total principal outstanding for this series is $400 million. | |||||||||||||
Issuances of Common Stock — In March 2013, Xcel Energy Inc. filed a prospectus supplement under which it may sell up to $400 million of its common stock through an at-the-market offering program. No shares of common stock were issued through this program during the third quarter of 2013. As of Sept. 30, 2013, Xcel Energy Inc. had issued 7.7 million shares of common stock through this program and received cash proceeds of $223.1 million, net of $2.3 million in fees and commissions. The proceeds from the issuances of common stock were used to repay short-term debt, infuse equity into the utility subsidiaries and for other general corporate purposes. | |||||||||||||
Debt Redemption — On May 31, 2013, Xcel Energy Inc. redeemed the entire $400 million principal amount of its 7.60 percent junior subordinated notes. Upon redemption, Xcel Energy Inc. recognized $6.3 million of related unamortized debt issuance costs as interest charges. |
Fair_Value_of_Financial_Assets
Fair Value of Financial Assets and Liabilities | 9 Months Ended | ||||||||||||||||||||||||
Sep. 30, 2013 | |||||||||||||||||||||||||
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 discounted cash flow or option pricing 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 net asset values. | |||||||||||||||||||||||||
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 net asset values, which take 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 net asset value 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. Based on Xcel Energy’s evaluation of its ability to redeem private equity and real estate investments, fair value measurements for private equity and real estate investments have been assigned a Level 3. | |||||||||||||||||||||||||
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 include financial transmission rights (FTRs) purchased from Midcontinent Independent Transmission System Operator, Inc. (MISO). FTRs purchased from MISO 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 overall transmission load and other transmission constraints. In addition to overall transmission load, congestion is also influenced by the operating schedules of power plants and the consumption of electricity pertinent to a given transmission path. Unplanned plant outages, scheduled plant maintenance, changes in the relative costs of fuels used in generation, weather and overall changes in demand for electricity can each impact the operating schedules of the power plants on the transmission grid and the value of an FTR. NSP-Minnesota’s 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 – including expected plant operating schedules and retail and wholesale demand, fair value measurements for FTRs have been assigned a Level 3. Non-trading monthly FTR settlements are included in the fuel clause adjustment, and therefore changes in the fair value of the yet to be settled portions of FTRs are deferred as a regulatory asset or liability. Given this regulatory treatment and the limited magnitude of NSP-Minnesota’s FTRs relative to its electric utility operations, 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 | |||||||||||||||||||||||||
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 Prairie Island 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. The MPUC approved NSP-Minnesota’s proposed change in escrow fund investment strategy in September 2012. The MPUC approved an 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. Given the purpose and legal restrictions on the use of nuclear decommissioning fund assets, 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. 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 $202.4 million and $135.8 million at Sept. 30, 2013 and Dec. 31, 2012, respectively, and unrealized losses and amounts recorded as other-than-temporary impairments were $65.3 million and $46.4 million at Sept. 30, 2013 and Dec. 31, 2012, 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 Sept. 30, 2013 and Dec. 31, 2012: | |||||||||||||||||||||||||
Sept. 30, 2013 | |||||||||||||||||||||||||
Fair Value | |||||||||||||||||||||||||
(Thousands of Dollars) | Cost | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||
Nuclear decommissioning fund (a) | |||||||||||||||||||||||||
Cash equivalents | $ | 74,103 | $ | 74,103 | $ | — | $ | — | $ | 74,103 | |||||||||||||||
Commingled funds | 436,533 | — | 438,906 | — | 438,906 | ||||||||||||||||||||
International equity funds | 65,529 | — | 68,164 | — | 68,164 | ||||||||||||||||||||
Private equity investments | 43,286 | — | — | 52,474 | 52,474 | ||||||||||||||||||||
Real estate | 41,645 | — | — | 51,356 | 51,356 | ||||||||||||||||||||
Debt securities: | |||||||||||||||||||||||||
Government securities | 34,475 | — | 28,946 | — | 28,946 | ||||||||||||||||||||
U.S. corporate bonds | 86,719 | — | 88,561 | — | 88,561 | ||||||||||||||||||||
International corporate bonds | 15,999 | — | 15,976 | — | 15,976 | ||||||||||||||||||||
Municipal bonds | 207,417 | — | 197,917 | — | 197,917 | ||||||||||||||||||||
Equity securities: | |||||||||||||||||||||||||
Common stock | 410,820 | 537,189 | — | — | 537,189 | ||||||||||||||||||||
Total | $ | 1,416,526 | $ | 611,292 | $ | 838,470 | $ | 103,830 | $ | 1,553,592 | |||||||||||||||
(a) | Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $87.8 million of equity investments in unconsolidated subsidiaries and $38.6 million of miscellaneous investments. | ||||||||||||||||||||||||
Dec. 31, 2012 | |||||||||||||||||||||||||
Fair Value | |||||||||||||||||||||||||
(Thousands of Dollars) | Cost | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||
Nuclear decommissioning fund (a) | |||||||||||||||||||||||||
Cash equivalents | $ | 246,904 | $ | 237,938 | $ | 8,966 | $ | — | $ | 246,904 | |||||||||||||||
Commingled funds | 396,681 | — | 417,583 | — | 417,583 | ||||||||||||||||||||
International equity funds | 66,452 | — | 69,481 | — | 69,481 | ||||||||||||||||||||
Private equity investments | 27,943 | — | — | 33,250 | 33,250 | ||||||||||||||||||||
Real estate | 32,561 | — | — | 39,074 | 39,074 | ||||||||||||||||||||
Debt securities: | |||||||||||||||||||||||||
Government securities | 21,092 | — | 21,521 | — | 21,521 | ||||||||||||||||||||
U.S. corporate bonds | 162,053 | — | 169,488 | — | 169,488 | ||||||||||||||||||||
International corporate bonds | 15,165 | — | 16,052 | — | 16,052 | ||||||||||||||||||||
Municipal bonds | 21,392 | — | 23,650 | — | 23,650 | ||||||||||||||||||||
Asset-backed securities | 2,066 | — | — | 2,067 | 2,067 | ||||||||||||||||||||
Mortgage-backed securities | 28,743 | — | — | 30,209 | 30,209 | ||||||||||||||||||||
Equity securities: | |||||||||||||||||||||||||
Common stock | 379,093 | 420,263 | — | — | 420,263 | ||||||||||||||||||||
Total | $ | 1,400,145 | $ | 658,201 | $ | 726,741 | $ | 104,600 | $ | 1,489,542 | |||||||||||||||
(a) | Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $91.2 million of equity investments in unconsolidated subsidiaries and $37.1 million of miscellaneous investments. | ||||||||||||||||||||||||
The following tables present the changes in Level 3 nuclear decommissioning fund investments for the three and nine months ended Sept. 30, 2013 and 2012: | |||||||||||||||||||||||||
(Thousands of Dollars) | 1-Jul-13 | Purchases | Settlements | Gains | Transfers Out of Level 3 | Sept. 30, 2013 | |||||||||||||||||||
Recognized as | |||||||||||||||||||||||||
Regulatory Liabilities | |||||||||||||||||||||||||
Private equity investments | $ | 45,590 | $ | 6,790 | $ | — | $ | 94 | $ | — | $ | 52,474 | |||||||||||||
Real estate | 38,140 | 11,288 | — | 1,928 | — | 51,356 | |||||||||||||||||||
Total | $ | 83,730 | $ | 18,078 | $ | — | $ | 2,022 | $ | — | $ | 103,830 | |||||||||||||
(Thousands of Dollars) | 1-Jul-12 | Purchases | Settlements | Gains | Transfers Out of Level 3 | Sept. 30, 2012 | |||||||||||||||||||
Recognized as | |||||||||||||||||||||||||
Regulatory Liabilities | |||||||||||||||||||||||||
Private equity investments | $ | 23,303 | $ | — | $ | (1,931 | ) | $ | 2,701 | $ | — | $ | 24,073 | ||||||||||||
Real estate | 32,721 | 2,882 | (1,165 | ) | 795 | — | 35,233 | ||||||||||||||||||
Asset-backed securities | 7,068 | — | (2,085 | ) | 12 | — | 4,995 | ||||||||||||||||||
Mortgage-backed securities | 66,321 | 16,782 | (19,681 | ) | 535 | — | 63,957 | ||||||||||||||||||
Total | $ | 129,413 | $ | 19,664 | $ | (24,862 | ) | $ | 4,043 | $ | — | $ | 128,258 | ||||||||||||
(Thousands of Dollars) | Jan. 1, 2013 | Purchases | Settlements | Gains | Transfers Out of Level 3 (a) | Sept. 30, 2013 | |||||||||||||||||||
Recognized as | |||||||||||||||||||||||||
Regulatory Liabilities | |||||||||||||||||||||||||
Private equity investments | $ | 33,250 | $ | 15,344 | $ | — | $ | 3,880 | $ | — | $ | 52,474 | |||||||||||||
Real estate | 39,074 | 18,106 | (9,022 | ) | 3,198 | — | 51,356 | ||||||||||||||||||
Asset-backed securities | 2,067 | — | — | — | (2,067 | ) | — | ||||||||||||||||||
Mortgage-backed securities | 30,209 | — | — | — | (30,209 | ) | — | ||||||||||||||||||
Total | $ | 104,600 | $ | 33,450 | $ | (9,022 | ) | $ | 7,078 | $ | (32,276 | ) | $ | 103,830 | |||||||||||
(a) | Transfers out of Level 3 into Level 2 were principally due to diminished use of unobservable inputs that were previously significant to these fair value measurements. | ||||||||||||||||||||||||
(Thousands of Dollars) | Jan. 1, 2012 | Purchases | Settlements | Gains | Transfers Out of Level 3 | Sept. 30, 2012 | |||||||||||||||||||
Recognized as | |||||||||||||||||||||||||
Regulatory Liabilities | |||||||||||||||||||||||||
Private equity investments | $ | 9,203 | $ | 13,390 | $ | (1,931 | ) | $ | 3,411 | $ | — | $ | 24,073 | ||||||||||||
Real estate | 26,395 | 6,789 | (2,931 | ) | 4,980 | — | 35,233 | ||||||||||||||||||
Asset-backed securities | 16,501 | — | (11,544 | ) | 38 | — | 4,995 | ||||||||||||||||||
Mortgage-backed securities | 78,664 | 31,100 | (46,099 | ) | 292 | — | 63,957 | ||||||||||||||||||
Total | $ | 130,763 | $ | 51,279 | $ | (62,505 | ) | $ | 8,721 | $ | — | $ | 128,258 | ||||||||||||
The following table summarizes the final contractual maturity dates of the debt securities in the nuclear decommissioning fund, by asset class, at Sept. 30, 2013: | |||||||||||||||||||||||||
Final Contractual Maturity | |||||||||||||||||||||||||
(Thousands of Dollars) | Due in 1 Year | Due in 1 to 5 | Due in 5 to 10 | Due after 10 | Total | ||||||||||||||||||||
or Less | Years | Years | Years | ||||||||||||||||||||||
Government securities | $ | — | $ | — | $ | — | $ | 28,946 | $ | 28,946 | |||||||||||||||
U.S. corporate bonds | 306 | 21,488 | 64,953 | 1,814 | 88,561 | ||||||||||||||||||||
International corporate bonds | — | 4,506 | 11,470 | — | 15,976 | ||||||||||||||||||||
Municipal bonds | 3,118 | 23,549 | 26,922 | 144,328 | 197,917 | ||||||||||||||||||||
Debt securities | $ | 3,424 | $ | 49,543 | $ | 103,345 | $ | 175,088 | $ | 331,400 | |||||||||||||||
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 Sept. 30, 2013, accumulated other comprehensive losses related to interest rate derivatives included $2.3 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 any unsettled hedges. | |||||||||||||||||||||||||
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, which is made up of management personnel not directly involved in the activities governed by this policy. | |||||||||||||||||||||||||
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 and vehicle fuel. | |||||||||||||||||||||||||
At Sept. 30, 2013, 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 nine months ended Sept. 30, 2013 and 2012. | |||||||||||||||||||||||||
At Sept. 30, 2013, net gains related to commodity derivative cash flow hedges recorded as a component of accumulated other comprehensive losses included $0.1 million of net gains 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 Sept. 30, 2013 and Dec. 31, 2012: | |||||||||||||||||||||||||
(Amounts in Thousands) (a)(b) | Sept. 30, 2013 | Dec. 31, 2012 | |||||||||||||||||||||||
Megawatt hours (MWh) of electricity | 69,682 | 55,976 | |||||||||||||||||||||||
Million British thermal units (MMBtu) of natural gas | 11,752 | 725 | |||||||||||||||||||||||
Gallons of vehicle fuel | 532 | 682 | |||||||||||||||||||||||
(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. | ||||||||||||||||||||||||
Consideration of Credit Risk and Concentrations — Xcel Energy continuously 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 set forth in the contracts. 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 when appropriate, 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 with particular entities or industries are contracts with counterparties to their wholesale, trading and non-trading commodity activities. At Sept. 30, 2013, four of Xcel Energy’s 10 most significant counterparties for these activities, comprising $70.6 million or 23 percent of this credit exposure, had investment grade credit ratings from Standard & Poor’s, Moody’s or Fitch Ratings. Five of the 10 most significant counterparties, comprising $89.4 million or 29 percent of this credit exposure at Sept. 30, 2013, were not rated by these agencies, but based on Xcel Energy’s internal analysis, had credit quality consistent with investment grade. Another of these significant counterparties, comprising $9.4 million or 3 percent of this credit exposure at Sept. 30, 2013, had credit quality less than investment grade, based on Xcel Energy’s internal analysis. All 10 of these significant counterparties are municipal or cooperative electric entities or other utilities. | |||||||||||||||||||||||||
Financial Impact of Qualifying Cash Flow Hedges — The impact of qualifying interest rate and vehicle fuel cash flow hedges on Xcel Energy’s accumulated other comprehensive loss, included in the consolidated statements of common stockholders’ equity and in the consolidated statements of comprehensive income, is detailed in the following table: | |||||||||||||||||||||||||
Three Months Ended Sept. 30 | |||||||||||||||||||||||||
(Thousands of Dollars) | 2013 | 2012 | |||||||||||||||||||||||
Accumulated other comprehensive loss related to cash flow hedges at July 1 | $ | (60,883 | ) | $ | (55,710 | ) | |||||||||||||||||||
After-tax net unrealized gains (losses) related to derivatives accounted for as hedges | 22 | (8,853 | ) | ||||||||||||||||||||||
After-tax net realized losses on derivative transactions reclassified into earnings | 539 | 393 | |||||||||||||||||||||||
Accumulated other comprehensive loss related to cash flow hedges at Sept. 30 | $ | (60,322 | ) | $ | (64,170 | ) | |||||||||||||||||||
Nine Months Ended Sept. 30 | |||||||||||||||||||||||||
(Thousands of Dollars) | 2013 | 2012 | |||||||||||||||||||||||
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1 | $ | (61,241 | ) | $ | (45,738 | ) | |||||||||||||||||||
After-tax net unrealized losses related to derivatives accounted for as hedges | (9 | ) | (19,188 | ) | |||||||||||||||||||||
After-tax net realized losses on derivative transactions reclassified into earnings | 928 | 756 | |||||||||||||||||||||||
Accumulated other comprehensive loss related to cash flow hedges at Sept. 30 | $ | (60,322 | ) | $ | (64,170 | ) | |||||||||||||||||||
The following tables detail the impact of derivative activity during the three and nine months ended Sept. 30, 2013 and 2012, on accumulated other comprehensive loss, regulatory assets and liabilities, and income: | |||||||||||||||||||||||||
Three Months Ended Sept. 30, 2013 | |||||||||||||||||||||||||
Pre-Tax Fair Value | Pre-Tax (Gains) Losses | ||||||||||||||||||||||||
Gains (Losses) Recognized | Reclassified into Income | ||||||||||||||||||||||||
During the Period in: | During the Period from: | ||||||||||||||||||||||||
(Thousands of Dollars) | Accumulated | Regulatory | Accumulated | Regulatory | Pre-Tax Gains Recognized | ||||||||||||||||||||
Other | (Assets) and Liabilities | Other | Assets and(Liabilities) | During the Period in Income | |||||||||||||||||||||
Comprehensive Loss | Comprehensive Loss | ||||||||||||||||||||||||
Derivatives designated as cash flow hedges | |||||||||||||||||||||||||
Interest rate | $ | — | $ | — | $ | 829 | (a) | $ | — | $ | — | ||||||||||||||
Vehicle fuel and other commodity | 36 | — | (24 | ) | (b) | — | — | ||||||||||||||||||
Total | $ | 36 | $ | — | $ | 805 | $ | — | $ | — | |||||||||||||||
Other derivative instruments | |||||||||||||||||||||||||
Commodity trading | $ | — | $ | — | $ | — | $ | — | $ | 7,094 | (c) | ||||||||||||||
Electric commodity | — | 921 | — | (9,823 | ) | (d) | — | ||||||||||||||||||
Natural gas commodity | — | (1,967 | ) | — | — | 12 | (d) | ||||||||||||||||||
Total | $ | — | $ | (1,046 | ) | $ | — | $ | (9,823 | ) | $ | 7,106 | |||||||||||||
Nine Months Ended Sept. 30, 2013 | |||||||||||||||||||||||||
Pre-Tax Fair Value | Pre-Tax (Gains) Losses | ||||||||||||||||||||||||
Gains (Losses) Recognized | Reclassified into Income | ||||||||||||||||||||||||
During the Period in: | During the Period from: | ||||||||||||||||||||||||
(Thousands of Dollars) | Accumulated | Regulatory | Accumulated | Regulatory | Pre-Tax Gains | ||||||||||||||||||||
Other | (Assets) and Liabilities | Other | Assets and (Liabilities) | (Losses) Recognized | |||||||||||||||||||||
Comprehensive Loss | Comprehensive Loss | During the Period in Income | |||||||||||||||||||||||
Derivatives designated as cash flow hedges | |||||||||||||||||||||||||
Interest rate | $ | — | $ | — | $ | 3,140 | (a) | $ | — | $ | — | ||||||||||||||
Vehicle fuel and other commodity | (11 | ) | — | (67 | ) | (b) | — | — | |||||||||||||||||
Total | $ | (11 | ) | $ | — | $ | 3,073 | $ | — | $ | — | ||||||||||||||
Other derivative instruments | |||||||||||||||||||||||||
Commodity trading | $ | — | $ | — | $ | — | $ | — | $ | 9,372 | (c) | ||||||||||||||
Electric commodity | — | 61,314 | — | (38,816 | ) | (d) | — | ||||||||||||||||||
Natural gas commodity | — | (5,341 | ) | — | 9 | (e) | (216 | ) | (d) | ||||||||||||||||
Total | $ | — | $ | 55,973 | $ | — | $ | (38,807 | ) | $ | 9,156 | ||||||||||||||
Three Months Ended Sept. 30, 2012 | |||||||||||||||||||||||||
Pre-Tax Fair Value | Pre-Tax (Gains) Losses | ||||||||||||||||||||||||
Gains (Losses) Recognized | Reclassified into Income | ||||||||||||||||||||||||
During the Period in: | During the Period from: | ||||||||||||||||||||||||
(Thousands of Dollars) | Accumulated | Regulatory | Accumulated | Regulatory | Pre-Tax Gains | ||||||||||||||||||||
Other | (Assets) and Liabilities | Other | Assets and(Liabilities) | Recognized | |||||||||||||||||||||
Comprehensive Loss | Comprehensive Loss | During the Period in Income | |||||||||||||||||||||||
Derivatives designated as cash flow hedges | |||||||||||||||||||||||||
Interest rate | $ | (14,923 | ) | $ | — | $ | 733 | (a) | $ | — | $ | — | |||||||||||||
Vehicle fuel and other commodity | 157 | — | (44 | ) | (b) | — | — | ||||||||||||||||||
Total | $ | (14,766 | ) | $ | — | $ | 689 | $ | — | $ | — | ||||||||||||||
Other derivative instruments | |||||||||||||||||||||||||
Commodity trading | $ | — | $ | — | $ | — | $ | — | $ | 7,651 | (c) | ||||||||||||||
Electric commodity | — | 3,923 | — | (11,931 | ) | (d) | — | ||||||||||||||||||
Natural gas commodity | — | 1,193 | — | — | — | ||||||||||||||||||||
Total | $ | — | $ | 5,116 | $ | — | $ | (11,931 | ) | $ | 7,651 | ||||||||||||||
Nine Months Ended Sept. 30, 2012 | |||||||||||||||||||||||||
Pre-Tax Fair Value | Pre-Tax (Gains) Losses | ||||||||||||||||||||||||
Gains (Losses) Recognized | Reclassified into Income | ||||||||||||||||||||||||
During the Period in: | During the Period from: | ||||||||||||||||||||||||
(Thousands of Dollars) | Accumulated | Regulatory | Accumulated | Regulatory | Pre-Tax Gains | ||||||||||||||||||||
Other | (Assets) and Liabilities | Other | Assets and (Liabilities) | (Losses) Recognized | |||||||||||||||||||||
Comprehensive Loss | Comprehensive Loss | During the Period in Income | |||||||||||||||||||||||
Derivatives designated as cash flow hedges | |||||||||||||||||||||||||
Interest rate | $ | (31,914 | ) | $ | — | $ | 1,511 | (a) | $ | — | $ | — | |||||||||||||
Vehicle fuel and other commodity | 140 | — | (145 | ) | (b) | — | — | ||||||||||||||||||
Total | $ | (31,774 | ) | $ | — | $ | 1,366 | $ | — | $ | — | ||||||||||||||
Other derivative instruments | |||||||||||||||||||||||||
Commodity trading | $ | — | $ | — | $ | — | $ | — | $ | 10,963 | (c) | ||||||||||||||
Electric commodity | — | 43,679 | — | (29,616 | ) | (d) | — | ||||||||||||||||||
Natural gas commodity | — | (8,705 | ) | — | 80,939 | (e) | (109 | ) | (d) | ||||||||||||||||
Total | $ | — | $ | 34,974 | $ | — | $ | 51,323 | $ | 10,854 | |||||||||||||||
(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 gains and losses 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 nine months ended Sept. 30, 2012 included $5.0 million 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. Such losses for the nine months ended Sept. 30, 2013 were immaterial. The remaining settlement losses for the nine months ended Sept. 30, 2013 and 2012 relate to natural gas operations and are recorded to cost of natural gas sold and transported. These losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset, as appropriate. | ||||||||||||||||||||||||
Xcel Energy had no derivative instruments designated as fair value hedges during the three and nine months ended Sept. 30, 2013 and 2012. Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for these periods. | |||||||||||||||||||||||||
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 (NPNS) 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. If the credit ratings of Xcel Energy Inc.’s utility subsidiaries were downgraded below investment grade, derivative instruments reflected in a $2.7 million and $4.6 million gross liability position on the consolidated balance sheets at Sept. 30, 2013 and Dec. 31, 2012, respectively, would have required Xcel Energy Inc.’s utility subsidiaries to post collateral or settle outstanding contracts, including other contracts subject to master netting agreements, which would have resulted in payments of $2.7 million and $4.6 million at Sept. 30, 2013 and Dec. 31, 2012, respectively. At Sept. 30, 2013 and Dec. 31, 2012, there was no collateral posted on these specific contracts. | |||||||||||||||||||||||||
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 given 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 Sept. 30, 2013 and Dec. 31, 2012. | |||||||||||||||||||||||||
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 Sept. 30, 2013: | |||||||||||||||||||||||||
Sept. 30, 2013 | |||||||||||||||||||||||||
Fair Value | |||||||||||||||||||||||||
(Thousands of Dollars) | Level 1 | Level 2 | Level 3 | Fair Value Total | Counterparty | Total | |||||||||||||||||||
Netting (b) | |||||||||||||||||||||||||
Current derivative assets | |||||||||||||||||||||||||
Derivatives designated as cash flow hedges: | |||||||||||||||||||||||||
Vehicle fuel and other commodity | $ | — | $ | 72 | $ | — | $ | 72 | $ | — | $ | 72 | |||||||||||||
Other derivative instruments: | |||||||||||||||||||||||||
Commodity trading | — | 23,112 | 2,142 | 25,254 | (8,490 | ) | 16,764 | ||||||||||||||||||
Electric commodity | — | — | 41,052 | 41,052 | (2,672 | ) | 38,380 | ||||||||||||||||||
Natural gas commodity | — | 4,443 | — | 4,443 | — | 4,443 | |||||||||||||||||||
Total current derivative assets | $ | — | $ | 27,627 | $ | 43,194 | $ | 70,821 | $ | (11,162 | ) | 59,659 | |||||||||||||
Purchased power agreements (a) | 33,028 | ||||||||||||||||||||||||
Current derivative instruments | $ | 92,687 | |||||||||||||||||||||||
Noncurrent derivative assets | |||||||||||||||||||||||||
Derivatives designated as cash flow hedges: | |||||||||||||||||||||||||
Vehicle fuel and other commodity | $ | — | $ | 27 | $ | — | $ | 27 | $ | (15 | ) | $ | 12 | ||||||||||||
Other derivative instruments: | |||||||||||||||||||||||||
Commodity trading | — | 33,862 | 2,716 | 36,578 | (7,306 | ) | 29,272 | ||||||||||||||||||
Total noncurrent derivative assets | $ | — | $ | 33,889 | $ | 2,716 | $ | 36,605 | $ | (7,321 | ) | 29,284 | |||||||||||||
Purchased power agreements (a) | 66,610 | ||||||||||||||||||||||||
Noncurrent derivative instruments | $ | 95,894 | |||||||||||||||||||||||
Current derivative liabilities | |||||||||||||||||||||||||
Other derivative instruments: | |||||||||||||||||||||||||
Commodity trading | $ | — | $ | 13,607 | $ | 1,770 | $ | 15,377 | $ | (11,751 | ) | $ | 3,626 | ||||||||||||
Electric commodity | — | — | 2,672 | 2,672 | (2,672 | ) | — | ||||||||||||||||||
Total current derivative liabilities | $ | — | $ | 13,607 | $ | 4,442 | $ | 18,049 | $ | (14,423 | ) | 3,626 | |||||||||||||
Purchased power agreements (a) | 23,103 | ||||||||||||||||||||||||
Current derivative instruments | $ | 26,729 | |||||||||||||||||||||||
Noncurrent derivative liabilities | |||||||||||||||||||||||||
Other derivative instruments: | |||||||||||||||||||||||||
Commodity trading | $ | — | $ | 14,767 | $ | — | $ | 14,767 | $ | (7,321 | ) | $ | 7,446 | ||||||||||||
Total noncurrent derivative liabilities | $ | — | $ | 14,767 | $ | — | $ | 14,767 | $ | (7,321 | ) | 7,446 | |||||||||||||
Purchased power agreements (a) | 209,581 | ||||||||||||||||||||||||
Noncurrent derivative instruments | $ | 217,027 | |||||||||||||||||||||||
(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 purchased power agreements 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 Sept. 30, 2013. At Sept. 30, 2013, derivative assets and liabilities include obligations to return cash collateral of $0.4 million and rights to reclaim cash collateral of $3.6 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, 2012: | |||||||||||||||||||||||||
Dec. 31, 2012 | |||||||||||||||||||||||||
Fair Value | |||||||||||||||||||||||||
Fair Value | Counterparty | ||||||||||||||||||||||||
(Thousands of Dollars) | Level 1 | Level 2 | Level 3 | Total | Netting (b) | Total | |||||||||||||||||||
Current derivative assets | |||||||||||||||||||||||||
Derivatives designated as cash flow hedges: | |||||||||||||||||||||||||
Vehicle fuel and other commodity | $ | — | $ | 95 | $ | — | $ | 95 | $ | — | $ | 95 | |||||||||||||
Other derivative instruments: | |||||||||||||||||||||||||
Commodity trading | — | 26,303 | 692 | 26,995 | (6,675 | ) | 20,320 | ||||||||||||||||||
Electric commodity | — | — | 16,724 | 16,724 | (843 | ) | 15,881 | ||||||||||||||||||
Natural gas commodity | — | 7 | — | 7 | (7 | ) | — | ||||||||||||||||||
Total current derivative assets | $ | — | $ | 26,405 | $ | 17,416 | $ | 43,821 | $ | (7,525 | ) | 36,296 | |||||||||||||
Purchased power agreements (a) | 32,717 | ||||||||||||||||||||||||
Current derivative instruments | $ | 69,013 | |||||||||||||||||||||||
Noncurrent derivative assets | |||||||||||||||||||||||||
Derivatives designated as cash flow hedges: | |||||||||||||||||||||||||
Vehicle fuel and other commodity | $ | — | $ | 86 | $ | — | $ | 86 | $ | (47 | ) | $ | 39 | ||||||||||||
Other derivative instruments: | |||||||||||||||||||||||||
Commodity trading | — | 41,282 | 77 | 41,359 | (4,162 | ) | 37,197 | ||||||||||||||||||
Total noncurrent derivative assets | $ | — | $ | 41,368 | $ | 77 | $ | 41,445 | $ | (4,209 | ) | 37,236 | |||||||||||||
Purchased power agreements (a) | 89,061 | ||||||||||||||||||||||||
Noncurrent derivative instruments | $ | 126,297 | |||||||||||||||||||||||
Current derivative liabilities | |||||||||||||||||||||||||
Other derivative instruments: | |||||||||||||||||||||||||
Commodity trading | $ | — | $ | 18,622 | $ | 1 | $ | 18,623 | $ | (9,112 | ) | $ | 9,511 | ||||||||||||
Electric commodity | — | — | 843 | 843 | (843 | ) | — | ||||||||||||||||||
Natural gas commodity | — | 98 | — | 98 | (7 | ) | 91 | ||||||||||||||||||
Total current derivative liabilities | $ | — | $ | 18,720 | $ | 844 | $ | 19,564 | $ | (9,962 | ) | 9,602 | |||||||||||||
Purchased power agreements (a) | 22,880 | ||||||||||||||||||||||||
Current derivative instruments | $ | 32,482 | |||||||||||||||||||||||
Noncurrent derivative liabilities | |||||||||||||||||||||||||
Other derivative instruments: | |||||||||||||||||||||||||
Commodity trading | $ | — | $ | 21,417 | $ | — | $ | 21,417 | $ | (4,210 | ) | $ | 17,207 | ||||||||||||
Total noncurrent derivative liabilities | $ | — | $ | 21,417 | $ | — | $ | 21,417 | $ | (4,210 | ) | 17,207 | |||||||||||||
Purchased power agreements (a) | 225,659 | ||||||||||||||||||||||||
Noncurrent derivative instruments | $ | 242,866 | |||||||||||||||||||||||
(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 purchased power agreements 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, 2012. At Dec. 31, 2012, derivative assets and liabilities include obligations to return cash collateral of $0.6 million and rights to reclaim cash collateral of $3.0 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 nine months ended Sept. 30, 2013 and 2012: | |||||||||||||||||||||||||
Three Months Ended Sept. 30 | |||||||||||||||||||||||||
(Thousands of Dollars) | 2013 | 2012 | |||||||||||||||||||||||
Balance at July 1 | $ | 47,218 | $ | 33,789 | |||||||||||||||||||||
Purchases | 155 | — | |||||||||||||||||||||||
Settlements | (9,342 | ) | (12,649 | ) | |||||||||||||||||||||
Net transactions recorded during the period: | |||||||||||||||||||||||||
Gains recognized in earnings (a) | 4,008 | 13 | |||||||||||||||||||||||
(Losses) gains recognized as regulatory assets and liabilities | (571 | ) | 4,629 | ||||||||||||||||||||||
Balance at Sept. 30 | $ | 41,468 | $ | 25,782 | |||||||||||||||||||||
Nine Months Ended Sept. 30 | |||||||||||||||||||||||||
(Thousands of Dollars) | 2013 | 2012 | |||||||||||||||||||||||
Balance at Jan. 1 | $ | 16,649 | $ | 12,417 | |||||||||||||||||||||
Purchases | 51,541 | 37,296 | |||||||||||||||||||||||
Settlements | (30,294 | ) | (34,209 | ) | |||||||||||||||||||||
Net transactions recorded during the period: | |||||||||||||||||||||||||
Gains recognized in earnings (a) | 3,729 | 5 | |||||||||||||||||||||||
(Losses) gains recognized as regulatory assets and liabilities | (157 | ) | 10,273 | ||||||||||||||||||||||
Balance at Sept. 30 | $ | 41,468 | $ | 25,782 | |||||||||||||||||||||
(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 nine months ended Sept. 30, 2013 and 2012. | |||||||||||||||||||||||||
Fair Value of Long-Term Debt | |||||||||||||||||||||||||
As of Sept. 30, 2013 and Dec. 31, 2012, other financial instruments for which the carrying amount did not equal fair value were as follows: | |||||||||||||||||||||||||
Sept. 30, 2013 | Dec. 31, 2012 | ||||||||||||||||||||||||
(Thousands of Dollars) | Carrying Amount | Fair Value | Carrying Amount | Fair Value | |||||||||||||||||||||
Long-term debt, including current portion | $ | 11,194,811 | $ | 12,007,389 | $ | 10,402,060 | $ | 12,207,866 | |||||||||||||||||
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 Sept. 30, 2013 and Dec. 31, 2012, 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_Expense_Income_Net
Other (Expense) Income, Net | 9 Months Ended | ||||||||||||||||
Sep. 30, 2013 | |||||||||||||||||
Other Income and Expenses [Abstract] | |||||||||||||||||
Other (Expense) Income, Net | Other (Expense) Income, Net | ||||||||||||||||
Other (expense) income, net consisted of the following: | |||||||||||||||||
Three Months Ended Sept. 30 | Nine Months Ended Sept. 30 | ||||||||||||||||
(Thousands of Dollars) | 2013 | 2012 | 2013 | 2012 | |||||||||||||
Interest income | $ | 1,304 | $ | 1,820 | $ | 7,615 | $ | 8,323 | |||||||||
Other nonoperating income | 739 | 714 | 2,494 | 2,793 | |||||||||||||
Insurance policy expense | (2,386 | ) | (2,042 | ) | (5,932 | ) | (5,902 | ) | |||||||||
Other nonoperating expense | (61 | ) | (4 | ) | (246 | ) | (261 | ) | |||||||||
Other (expense) income, net | $ | (404 | ) | $ | 488 | $ | 3,931 | $ | 4,953 | ||||||||
Segment_Information
Segment Information | 9 Months Ended | ||||||||||||||||||||
Sep. 30, 2013 | |||||||||||||||||||||
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 in 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 $87.8 million and $91.2 million as of Sept. 30, 2013 and Dec. 31, 2012, 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 continuing 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 | Reconciling Eliminations | Consolidated Total | ||||||||||||||||
Other | |||||||||||||||||||||
Three Months Ended Sept. 30, 2013 | |||||||||||||||||||||
Operating revenues from external customers | $ | 2,599,925 | $ | 205,358 | $ | 17,055 | $ | — | $ | 2,822,338 | |||||||||||
Intersegment revenues | 346 | 1,106 | — | (1,452 | ) | — | |||||||||||||||
Total revenues | $ | 2,600,271 | $ | 206,464 | $ | 17,055 | $ | (1,452 | ) | $ | 2,822,338 | ||||||||||
Income (loss) from continuing operations | $ | 365,156 | $ | (174 | ) | $ | (446 | ) | $ | — | $ | 364,536 | |||||||||
(Thousands of Dollars) | Regulated Electric | Regulated Natural Gas | All | Reconciling Eliminations | Consolidated Total | ||||||||||||||||
Other | |||||||||||||||||||||
Three Months Ended Sept. 30, 2012 | |||||||||||||||||||||
Operating revenues from external customers | $ | 2,532,709 | $ | 174,513 | $ | 17,119 | $ | — | $ | 2,724,341 | |||||||||||
Intersegment revenues | 287 | 461 | — | (748 | ) | — | |||||||||||||||
Total revenues | $ | 2,532,996 | $ | 174,974 | $ | 17,119 | $ | (748 | ) | $ | 2,724,341 | ||||||||||
Income (loss) from continuing operations | $ | 400,185 | $ | 4,296 | $ | (6,334 | ) | $ | — | $ | 398,147 | ||||||||||
(Thousands of Dollars) | Regulated Electric | Regulated Natural Gas | All | Reconciling Eliminations | Consolidated Total | ||||||||||||||||
Other | |||||||||||||||||||||
Nine Months Ended Sept. 30, 2013 | |||||||||||||||||||||
Operating revenues from external customers | $ | 6,911,998 | $ | 1,216,275 | $ | 55,827 | $ | — | $ | 8,184,100 | |||||||||||
Intersegment revenues | 955 | 2,163 | — | (3,118 | ) | — | |||||||||||||||
Total revenues | $ | 6,912,953 | $ | 1,218,438 | $ | 55,827 | $ | (3,118 | ) | $ | 8,184,100 | ||||||||||
Income (loss) from continuing operations | $ | 740,347 | $ | 80,698 | $ | (23,039 | ) | $ | — | $ | 798,006 | ||||||||||
(Thousands of Dollars) | Regulated Electric | Regulated Natural Gas | All | Reconciling Eliminations | Consolidated Total | ||||||||||||||||
Other | |||||||||||||||||||||
Nine Months Ended Sept. 30, 2012 | |||||||||||||||||||||
Operating revenues from external customers | $ | 6,506,320 | $ | 1,016,861 | $ | 53,907 | $ | — | $ | 7,577,088 | |||||||||||
Intersegment revenues | 886 | 1,179 | — | (2,065 | ) | — | |||||||||||||||
Total revenues | $ | 6,507,206 | $ | 1,018,040 | $ | 53,907 | $ | (2,065 | ) | $ | 7,577,088 | ||||||||||
Income (loss) from continuing operations | $ | 733,557 | $ | 60,688 | $ | (29,254 | ) | $ | — | $ | 764,991 | ||||||||||
Earnings_Per_Share
Earnings Per Share | 9 Months Ended | ||||||||||||||||||||||
Sep. 30, 2013 | |||||||||||||||||||||||
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 based on the treasury stock method. | |||||||||||||||||||||||
Common Stock Equivalents — Xcel Energy Inc. currently has common stock equivalents related to certain equity awards. | |||||||||||||||||||||||
Share-Based Compensation | |||||||||||||||||||||||
Common stock equivalents related to share-based compensation causing dilutive impact to EPS include commitments to issue common stock as an employer match to 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, pending remaining service conditions. | |||||||||||||||||||||||
Share-based compensation arrangements for which there is currently no dilutive impact to EPS include the following: | |||||||||||||||||||||||
• | Restricted stock unit 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. | ||||||||||||||||||||||
• | Performance share plan 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 Sept. 30, 2013 | Three Months Ended Sept. 30, 2012 | ||||||||||||||||||||||
(Amounts in thousands, except per share data) | Income | Shares | Per Share | Income | Shares | Per Share | |||||||||||||||||
Amount | Amount | ||||||||||||||||||||||
Net income | $ | 364,752 | $ | 398,106 | |||||||||||||||||||
Basic earnings per share: | |||||||||||||||||||||||
Earnings available to common shareholders | 364,752 | 498,149 | $ | 0.73 | 398,106 | 488,084 | $ | 0.82 | |||||||||||||||
Effect of dilutive securities: | |||||||||||||||||||||||
401(k) equity awards | — | 492 | — | 494 | |||||||||||||||||||
Diluted earnings per share: | |||||||||||||||||||||||
Earnings available to common shareholders | $ | 364,752 | 498,641 | $ | 0.73 | $ | 398,106 | 488,578 | $ | 0.81 | |||||||||||||
Nine Months Ended Sept. 30, 2013 | Nine Months Ended Sept. 30, 2012 | ||||||||||||||||||||||
(Amounts in thousands, except per share data) | Income | Shares | Per Share | Income | Shares | Per Share | |||||||||||||||||
Amount | Amount | ||||||||||||||||||||||
Net income | $ | 798,179 | $ | 765,059 | |||||||||||||||||||
Basic earnings per share: | |||||||||||||||||||||||
Earnings available to common shareholders | 798,179 | 495,256 | $ | 1.61 | 765,059 | 487,722 | $ | 1.57 | |||||||||||||||
Effect of dilutive securities: | |||||||||||||||||||||||
401(k) equity awards | — | 511 | — | 476 | |||||||||||||||||||
Diluted earnings per share: | |||||||||||||||||||||||
Earnings available to common shareholders | $ | 798,179 | 495,767 | $ | 1.61 | $ | 765,059 | 488,198 | $ | 1.57 | |||||||||||||
Benefit_Plans_and_Other_Postre
Benefit Plans and Other Postretirement Benefits | 9 Months Ended | ||||||||||||||||
Sep. 30, 2013 | |||||||||||||||||
Compensation and Retirement Disclosure [Abstract] | |||||||||||||||||
Benefit Plans and Other Postretirement Benefits | Benefit Plans and Other Postretirement Benefits | ||||||||||||||||
Components of Net Periodic Benefit Cost | |||||||||||||||||
Three Months Ended Sept. 30 | |||||||||||||||||
2013 | 2012 | 2013 | 2012 | ||||||||||||||
(Thousands of Dollars) | Pension Benefits | Postretirement Health | |||||||||||||||
Care Benefits | |||||||||||||||||
Service cost | $ | 24,071 | $ | 21,591 | $ | 1,182 | $ | 1,050 | |||||||||
Interest cost | 35,173 | 39,043 | 8,417 | 9,465 | |||||||||||||
Expected return on plan assets | (49,613 | ) | (51,774 | ) | (8,253 | ) | (7,102 | ) | |||||||||
Amortization of transition obligation | — | — | 206 | 3,580 | |||||||||||||
Amortization of prior service cost (credit) | 1,468 | 5,266 | (2,438 | ) | (1,888 | ) | |||||||||||
Amortization of net loss | 36,038 | 26,893 | 5,646 | 4,228 | |||||||||||||
Net periodic benefit cost | 47,137 | 41,019 | 4,760 | 9,333 | |||||||||||||
Costs not recognized and additional cost recognized due to the effects of regulation | (12,986 | ) | (9,645 | ) | — | 972 | |||||||||||
Net benefit cost recognized for financial reporting | $ | 34,151 | $ | 31,374 | $ | 4,760 | $ | 10,305 | |||||||||
Nine Months Ended Sept. 30 | |||||||||||||||||
2013 | 2012 | 2013 | 2012 | ||||||||||||||
(Thousands of Dollars) | Pension Benefits | Postretirement Health | |||||||||||||||
Care Benefits | |||||||||||||||||
Service cost | $ | 72,212 | $ | 64,773 | $ | 3,546 | $ | 3,152 | |||||||||
Interest cost | 105,518 | 117,131 | 25,251 | 28,396 | |||||||||||||
Expected return on plan assets | (148,839 | ) | (155,322 | ) | (24,759 | ) | (21,307 | ) | |||||||||
Amortization of transition obligation | — | — | 618 | 10,740 | |||||||||||||
Amortization of prior service cost (credit) | 4,404 | 15,799 | (7,314 | ) | (5,664 | ) | |||||||||||
Amortization of net loss | 108,114 | 80,678 | 16,938 | 12,680 | |||||||||||||
Net periodic benefit cost | 141,409 | 123,059 | 14,280 | 27,997 | |||||||||||||
Costs not recognized and additional cost recognized due to the effects of regulation | (27,922 | ) | (28,936 | ) | — | 2,918 | |||||||||||
Net benefit cost recognized for financial reporting | $ | 113,487 | $ | 94,123 | $ | 14,280 | $ | 30,915 | |||||||||
In 2013, contributions of $192.2 million were made across four of Xcel Energy’s pension plans. Xcel Energy does not expect additional pension contributions during 2013. |
Other_Comprehensive_Income
Other Comprehensive Income | 9 Months Ended | ||||||||||||||||
Sep. 30, 2013 | |||||||||||||||||
Stockholders' Equity Note [Abstract] | |||||||||||||||||
Other Comprehensive Income | Other Comprehensive Income | ||||||||||||||||
Changes in accumulated other comprehensive loss, net of tax, for the three and nine months ended Sept. 30, 2013 were as follows: | |||||||||||||||||
Three Months Ended Sept. 30, 2013 | |||||||||||||||||
(Thousands of Dollars) | Gains and | Unrealized | Defined Benefit | Total | |||||||||||||
Losses on Cash Flow Hedges | Gains and Losses | Pension and | |||||||||||||||
on Marketable | Postretirement | ||||||||||||||||
Securities | Items | ||||||||||||||||
Accumulated other comprehensive loss at July 1 | $ | (60,883 | ) | $ | (135 | ) | $ | (50,817 | ) | $ | (111,835 | ) | |||||
Other comprehensive gain before reclassifications | 22 | 115 | — | 137 | |||||||||||||
Losses reclassified from net accumulated other comprehensive loss | 539 | — | 1,179 | 1,718 | |||||||||||||
Net current period other comprehensive income | 561 | 115 | 1,179 | 1,855 | |||||||||||||
Accumulated other comprehensive loss at Sept. 30 | $ | (60,322 | ) | $ | (20 | ) | $ | (49,638 | ) | $ | (109,980 | ) | |||||
Nine Months Ended Sept. 30, 2013 | |||||||||||||||||
(Thousands of Dollars) | Gains and | Unrealized | Defined Benefit | Total | |||||||||||||
Losses on Cash Flow Hedges | Gains and Losses | Pension and | |||||||||||||||
on Marketable | Postretirement | ||||||||||||||||
Securities | Items | ||||||||||||||||
Accumulated other comprehensive loss at Jan. 1 | $ | (61,241 | ) | $ | (99 | ) | $ | (51,313 | ) | $ | (112,653 | ) | |||||
Other comprehensive gain (loss) before reclassifications | (9 | ) | 79 | — | 70 | ||||||||||||
Losses reclassified from net accumulated other comprehensive loss | 928 | — | 1,675 | 2,603 | |||||||||||||
Net current period other comprehensive income | 919 | 79 | 1,675 | 2,673 | |||||||||||||
Accumulated other comprehensive loss at Sept. 30 | $ | (60,322 | ) | $ | (20 | ) | $ | (49,638 | ) | $ | (109,980 | ) | |||||
Reclassifications from accumulated other comprehensive loss for the three and nine months ended Sept. 30, 2013 were as follows: | |||||||||||||||||
Amounts Reclassified from | |||||||||||||||||
Accumulated Other | |||||||||||||||||
Comprehensive Loss | |||||||||||||||||
(Thousands of Dollars) | Three Months Ended Sept. 30, 2013 | Nine Months Ended Sept. 30, 2013 | |||||||||||||||
(Gains) losses on cash flow hedges: | |||||||||||||||||
Interest rate derivatives | $ | 829 | (a) | $ | 3,140 | (a) | |||||||||||
Vehicle fuel derivatives | (24 | ) | (b) | (67 | ) | (b) | |||||||||||
Total, pre-tax | 805 | 3,073 | |||||||||||||||
Tax benefit | (266 | ) | (2,145 | ) | |||||||||||||
Total, net of tax | 539 | 928 | |||||||||||||||
Defined benefit pension and postretirement losses: | |||||||||||||||||
Amortization of net loss | 1,770 | (c) | 5,308 | (c) | |||||||||||||
Prior service cost | 93 | (c) | 279 | (c) | |||||||||||||
Transition obligation | 2 | (c) | 6 | (c) | |||||||||||||
Total, pre-tax | 1,865 | 5,593 | |||||||||||||||
Tax benefit | (686 | ) | (3,918 | ) | |||||||||||||
Total, net of tax | 1,179 | 1,675 | |||||||||||||||
Total amounts reclassified, net of tax | $ | 1,718 | $ | 2,603 | |||||||||||||
(a) | Included in interest charges. | ||||||||||||||||
(b) | Included in O&M expenses. | ||||||||||||||||
(c) | Included in the computation of net periodic pension and post retirement benefit costs. See Note 12 for details regarding these benefit plans. |
Selected_Balance_Sheet_Data_Ta
Selected Balance Sheet Data (Tables) | 9 Months Ended | ||||||||
Sep. 30, 2013 | |||||||||
Balance Sheet Related Disclosures [Abstract] | |||||||||
Accounts Receivable, Net | |||||||||
(Thousands of Dollars) | Sept. 30, 2013 | Dec. 31, 2012 | |||||||
Accounts receivable, net | |||||||||
Accounts receivable | $ | 838,271 | $ | 769,440 | |||||
Less allowance for bad debts | (51,397 | ) | (51,394 | ) | |||||
$ | 786,874 | $ | 718,046 | ||||||
Inventories | |||||||||
(Thousands of Dollars) | Sept. 30, 2013 | Dec. 31, 2012 | |||||||
Inventories | |||||||||
Materials and supplies | $ | 228,302 | $ | 213,739 | |||||
Fuel | 201,728 | 189,425 | |||||||
Natural gas | 174,598 | 132,410 | |||||||
$ | 604,628 | $ | 535,574 | ||||||
Property, Plant and Equipment, Net | |||||||||
(Thousands of Dollars) | Sept. 30, 2013 | Dec. 31, 2012 | |||||||
Property, plant and equipment, net | |||||||||
Electric plant | $ | 29,550,871 | $ | 28,285,031 | |||||
Natural gas plant | 3,942,182 | 3,836,335 | |||||||
Common and other property | 1,467,811 | 1,480,558 | |||||||
Plant to be retired (a) | 115,753 | 152,730 | |||||||
Construction work in progress | 2,391,783 | 1,757,189 | |||||||
Total property, plant and equipment | 37,468,400 | 35,511,843 | |||||||
Less accumulated depreciation | (12,462,716 | ) | (12,048,697 | ) | |||||
Nuclear fuel | 2,157,940 | 2,090,801 | |||||||
Less accumulated amortization | (1,821,046 | ) | (1,744,599 | ) | |||||
$ | 25,342,578 | $ | 23,809,348 | ||||||
(a) | In 2010, in response to the Clean Air Clean Jobs Act (CACJA), the Colorado Public Utilities Commission (CPUC) approved the early retirement of Cherokee Units 1, 2 and 3, Arapahoe Unit 3 and Valmont Unit 5 between 2011 and 2017. In 2011, Cherokee Unit 2 was retired and in 2012, Cherokee Unit 1 was retired. Amounts are presented net of accumulated depreciation. |
Income_Taxes_Tables
Income Taxes (Tables) | 9 Months Ended | ||||||||
Sep. 30, 2013 | |||||||||
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 Sept. 30, 2013, 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 | 2006 | ||||||||
Minnesota | 2009 | ||||||||
Texas | 2009 | ||||||||
Wisconsin | 2009 | ||||||||
Reconciliation of Unrecognized Tax Benefits | A reconciliation of the amount of unrecognized tax benefit is as follows: | ||||||||
(Millions of Dollars) | Sept. 30, 2013 | Dec. 31, 2012 | |||||||
Unrecognized tax benefit — Permanent tax positions | $ | 8.8 | $ | 4.7 | |||||
Unrecognized tax benefit — Temporary tax positions | 32.4 | 29.8 | |||||||
Total unrecognized tax benefit | $ | 41.2 | $ | 34.5 | |||||
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) | Sept. 30, 2013 | Dec. 31, 2012 | |||||||
NOL and tax credit carryforwards | $ | (40.1 | ) | $ | (33.5 | ) |
Rate_Matters_Tables
Rate Matters (Tables) | 9 Months Ended | ||||||||||||
Sep. 30, 2013 | |||||||||||||
Public Utilities, General Disclosures [Abstract] | |||||||||||||
CPUC Staff, OCC and ALJ’s recommendations in the PSCo Colorado 2013 Gas Rate Case [Table Text Block] | The following table summarizes the CPUC Staff, OCC and ALJ’s recommendations: | ||||||||||||
(Millions of Dollars) | CPUC Staff | OCC | ALJ | ||||||||||
PSCo deficiency based on a FTY | $ | 44.8 | $ | 44.8 | $ | 44.8 | |||||||
Move to HTY | (1.6 | ) | (1.6 | ) | (1.6 | ) | |||||||
ROE and capital structure adjustments | (20.8 | ) | (20.0 | ) | (7.7 | ) | |||||||
Move to a 13 month average from year end rate base | (5.7 | ) | (3.2 | ) | (3.3 | ) | |||||||
Remove pension asset | (5.9 | ) | — | — | |||||||||
Reduce pension expense net of corrections | (1.6 | ) | — | — | |||||||||
Remove incentive compensation | (3.5 | ) | (0.2 | ) | (0.2 | ) | |||||||
Challenge known and measurable | — | (9.0 | ) | — | |||||||||
Eliminate depreciation annualization | — | (1.8 | ) | — | |||||||||
Revenue adjustments | (4.1 | ) | (1.4 | ) | (1.4 | ) | |||||||
Resulting tax impacts | 1.5 | 4.7 | (0.2 | ) | |||||||||
Other adjustments | (4.2 | ) | 3.1 | (1.2 | ) | ||||||||
Remove PSIA from base rates | (14.2 | ) | (14.2 | ) | — | ||||||||
Recommendation | $ | (15.3 | ) | $ | 1.2 | $ | 29.2 | ||||||
Neutralize PSIA - base rate transfer | 14.2 | 14.2 | (14.2 | ) | |||||||||
Incremental base revenue | $ | (1.1 | ) | $ | 15.4 | $ | 15 | ||||||
PSCW Staff signficant adjustments to the NSP-Wisconsin 2014 Electric and Gas Rate Case [Table Text Block] | The most significant adjustments proposed by the PSCW Staff are shown in the table below: | ||||||||||||
(Millions of Dollars) | Electric | Natural Gas | |||||||||||
Staff Testimony | Staff Testimony | ||||||||||||
Oct-13 | Oct-13 | ||||||||||||
Rate request | $ | 40 | $ | 4.7 | |||||||||
Electric fuel and purchased power | (5.1 | ) | — | ||||||||||
Sales forecast | (4.8 | ) | — | ||||||||||
Incentive compensation and merit pay | (3.0 | ) | (0.6 | ) | |||||||||
ROE | (1.6 | ) | (0.2 | ) | |||||||||
Conservation funding transfer | 0.7 | (0.7 | ) | ||||||||||
Depreciation expense | (0.7 | ) | (1.3 | ) | |||||||||
Ashland site amortization expense | — | (2.3 | ) | ||||||||||
Other, net | (1.7 | ) | (0.7 | ) | |||||||||
Recommended rate increase (decrease) | $ | 23.8 | $ | (1.1 | ) | ||||||||
NSP-Minnesota’s original request to the final MPUC order in the 2013 Electric Rate Case [Table Text Block] | The table below reconciles NSP-Minnesota’s original request to the final MPUC order: | ||||||||||||
(Millions of Dollars) | NSP-Minnesota Request | Administrative Law Judge (ALJ) Recommendation | MPUC Order | ||||||||||
NSP-Minnesota original request | $ | 285 | $ | 285 | $ | 285 | |||||||
ROE | — | (43 | ) | (43 | ) | ||||||||
Sherco Unit 3 | (35 | ) | (38 | ) | (34 | ) | |||||||
Reduced recovery for nuclear plants | (11 | ) | (14 | ) | (15 | ) | |||||||
Incentive compensation | (3 | ) | (4 | ) | (4 | ) | |||||||
Sales forecast | (1 | ) | (26 | ) | (26 | ) | |||||||
Pension | (10 | ) | (13 | ) | (13 | ) | |||||||
Employee benefits | (4 | ) | (6 | ) | (6 | ) | |||||||
Black Dog remediation | (5 | ) | (5 | ) | (5 | ) | |||||||
Estimated impact of the theoretical depreciation reserve | — | — | (24 | ) | |||||||||
NSP-Wisconsin wholesale allocation | (7 | ) | (7 | ) | (7 | ) | |||||||
Other, net | — | (2 | ) | (5 | ) | ||||||||
Recommended rate increase | 209 | 127 | 103 | ||||||||||
Estimated impact of cost deferrals | 50 | 34 | 20 | ||||||||||
Estimated impact of the theoretical depreciation reserve | — | — | 24 | ||||||||||
Impact on pre-tax income | $ | 259 | $ | 161 | $ | 147 | |||||||
Revenue requirements adjustments as filed by the NDPSC Advocacy Staff and NSP-Minnesota Rebuttal Testimony [Table Text Block] [Table Text Block] | Primary revenue requirement adjustments include: | ||||||||||||
(Millions of Dollars) | NSP-Minnesota Rebuttal Testimony | NDPSC Position | |||||||||||
as Supplemented | |||||||||||||
NSP-Minnesota revised request | $ | 16 | $ | 16 | |||||||||
Use of a one month coincident peak demand allocator for certain rate base and operation expenses | — | (20.4 | ) | ||||||||||
ROE | (1.2 | ) | (5.2 | ) | |||||||||
Incentive compensation | — | (0.8 | ) | ||||||||||
Adjustment for various O&M expenses | — | (0.7 | ) | ||||||||||
Modified cost of capital and increased capital structure to 53.42 percent | 0.1 | 1.3 | |||||||||||
Depreciation/remaining life study | — | (1.1 | ) | ||||||||||
Other, net | — | 0.9 | |||||||||||
Recommended rate increase (decrease) | $ | 14.9 | $ | (10.0 | ) | ||||||||
New Mexico Public Regulation Commission (NMPRC) and New Mexico Attorney General (NMAG) recommendations to SPS' 2014 Electric Rate Case [Table Text Block] | The following table summarizes certain parties’ recommendations from SPS’ revised request: | ||||||||||||
(Millions of Dollars) | Staff | NMAG | |||||||||||
Testimony | Testimony | ||||||||||||
Aug-13 | Aug-13 | ||||||||||||
SPS revised request | $ | 43.3 | $ | 43.3 | |||||||||
Rate rider for renewable energy costs (a) | (14.5 | ) | (8.5 | ) | |||||||||
Present revenues (sales growth and weather) | (4.4 | ) | (6.4 | ) | |||||||||
ROE (9.8 percent and 8.63 percent, respectively) | (3.2 | ) | (8.1 | ) | |||||||||
Capital structure | (1.5 | ) | (1.1 | ) | |||||||||
Employee benefits | (2.8 | ) | (1.8 | ) | |||||||||
Reduced recovery for payroll expense | (0.1 | ) | (0.1 | ) | |||||||||
Gain on sale of transmission assets | — | (1.7 | ) | ||||||||||
Fuel clause revenue | 6 | — | |||||||||||
Other, net | (5.0 | ) | (6.6 | ) | |||||||||
Recommended rate increase | $ | 17.8 | $ | 9 | |||||||||
Means of recovery: | |||||||||||||
Base revenue | $ | 8.8 | $ | (6.0 | ) | ||||||||
Rider revenue | 7.3 | 13.3 | |||||||||||
Fuel cost adjustment revenue | 1.7 | 1.7 | |||||||||||
$ | 17.8 | $ | 9 | ||||||||||
(a) | Adjustments represent recommended deferrals, extended amortizations and moving costs from rider to fuel in base rates. |
Commitments_and_Contingencies_
Commitments and Contingencies (Tables) | 9 Months Ended | ||||||||
Sep. 30, 2013 | |||||||||
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 Inc.: | ||||||||
(Millions of Dollars) | Sept. 30, 2013 | Dec. 31, 2012 | |||||||
Guarantees issued and outstanding | $ | 54.8 | $ | 69.5 | |||||
Current exposure under these guarantees | 17.8 | 17.9 | |||||||
Bonds with indemnity protection | 31.9 | 29.6 | |||||||
Borrowings_and_Other_Financing1
Borrowings and Other Financing Instruments (Tables) | 9 Months Ended | ||||||||||||
Sep. 30, 2013 | |||||||||||||
Debt Disclosure [Abstract] | |||||||||||||
Commercial Paper | 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 | Twelve Months Ended | |||||||||||
Sept. 30, 2013 | Dec. 31, 2012 | ||||||||||||
Borrowing limit | $ | 2,450 | $ | 2,450 | |||||||||
Amount outstanding at period end | 302 | 602 | |||||||||||
Average amount outstanding | 347 | 403 | |||||||||||
Maximum amount outstanding | 491 | 634 | |||||||||||
Weighted average interest rate, computed on a daily basis | 0.27 | % | 0.35 | % | |||||||||
Weighted average interest rate at period end | 0.25 | 0.36 | |||||||||||
Committed Credit Facilities Available | At Sept. 30, 2013, 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. | $ | 800 | $ | 258 | $ | 542 | |||||||
PSCo | 700 | 6.9 | 693.1 | ||||||||||
NSP-Minnesota | 500 | 44.9 | 455.1 | ||||||||||
SPS | 300 | — | 300 | ||||||||||
NSP-Wisconsin | 150 | 11 | 139 | ||||||||||
Total | $ | 2,450.00 | $ | 320.8 | $ | 2,129.20 | |||||||
(a) | These credit facilities expire in July 2017. | ||||||||||||
(b) | Includes outstanding commercial paper and letters of credit. |
Fair_Value_of_Financial_Assets1
Fair Value of Financial Assets and Liabilities (Tables) | 9 Months Ended | ||||||||||||||||||||||||
Sep. 30, 2013 | |||||||||||||||||||||||||
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 Sept. 30, 2013 and Dec. 31, 2012: | ||||||||||||||||||||||||
Sept. 30, 2013 | |||||||||||||||||||||||||
Fair Value | |||||||||||||||||||||||||
(Thousands of Dollars) | Cost | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||
Nuclear decommissioning fund (a) | |||||||||||||||||||||||||
Cash equivalents | $ | 74,103 | $ | 74,103 | $ | — | $ | — | $ | 74,103 | |||||||||||||||
Commingled funds | 436,533 | — | 438,906 | — | 438,906 | ||||||||||||||||||||
International equity funds | 65,529 | — | 68,164 | — | 68,164 | ||||||||||||||||||||
Private equity investments | 43,286 | — | — | 52,474 | 52,474 | ||||||||||||||||||||
Real estate | 41,645 | — | — | 51,356 | 51,356 | ||||||||||||||||||||
Debt securities: | |||||||||||||||||||||||||
Government securities | 34,475 | — | 28,946 | — | 28,946 | ||||||||||||||||||||
U.S. corporate bonds | 86,719 | — | 88,561 | — | 88,561 | ||||||||||||||||||||
International corporate bonds | 15,999 | — | 15,976 | — | 15,976 | ||||||||||||||||||||
Municipal bonds | 207,417 | — | 197,917 | — | 197,917 | ||||||||||||||||||||
Equity securities: | |||||||||||||||||||||||||
Common stock | 410,820 | 537,189 | — | — | 537,189 | ||||||||||||||||||||
Total | $ | 1,416,526 | $ | 611,292 | $ | 838,470 | $ | 103,830 | $ | 1,553,592 | |||||||||||||||
(a) | Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $87.8 million of equity investments in unconsolidated subsidiaries and $38.6 million of miscellaneous investments. | ||||||||||||||||||||||||
Dec. 31, 2012 | |||||||||||||||||||||||||
Fair Value | |||||||||||||||||||||||||
(Thousands of Dollars) | Cost | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||
Nuclear decommissioning fund (a) | |||||||||||||||||||||||||
Cash equivalents | $ | 246,904 | $ | 237,938 | $ | 8,966 | $ | — | $ | 246,904 | |||||||||||||||
Commingled funds | 396,681 | — | 417,583 | — | 417,583 | ||||||||||||||||||||
International equity funds | 66,452 | — | 69,481 | — | 69,481 | ||||||||||||||||||||
Private equity investments | 27,943 | — | — | 33,250 | 33,250 | ||||||||||||||||||||
Real estate | 32,561 | — | — | 39,074 | 39,074 | ||||||||||||||||||||
Debt securities: | |||||||||||||||||||||||||
Government securities | 21,092 | — | 21,521 | — | 21,521 | ||||||||||||||||||||
U.S. corporate bonds | 162,053 | — | 169,488 | — | 169,488 | ||||||||||||||||||||
International corporate bonds | 15,165 | — | 16,052 | — | 16,052 | ||||||||||||||||||||
Municipal bonds | 21,392 | — | 23,650 | — | 23,650 | ||||||||||||||||||||
Asset-backed securities | 2,066 | — | — | 2,067 | 2,067 | ||||||||||||||||||||
Mortgage-backed securities | 28,743 | — | — | 30,209 | 30,209 | ||||||||||||||||||||
Equity securities: | |||||||||||||||||||||||||
Common stock | 379,093 | 420,263 | — | — | 420,263 | ||||||||||||||||||||
Total | $ | 1,400,145 | $ | 658,201 | $ | 726,741 | $ | 104,600 | $ | 1,489,542 | |||||||||||||||
(a) | Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $91.2 million of equity investments in unconsolidated subsidiaries and $37.1 million of miscellaneous investments. | ||||||||||||||||||||||||
Changes in Level 3 Nuclear Decommissioning Fund Investments | The following tables present the changes in Level 3 nuclear decommissioning fund investments for the three and nine months ended Sept. 30, 2013 and 2012: | ||||||||||||||||||||||||
(Thousands of Dollars) | 1-Jul-13 | Purchases | Settlements | Gains | Transfers Out of Level 3 | Sept. 30, 2013 | |||||||||||||||||||
Recognized as | |||||||||||||||||||||||||
Regulatory Liabilities | |||||||||||||||||||||||||
Private equity investments | $ | 45,590 | $ | 6,790 | $ | — | $ | 94 | $ | — | $ | 52,474 | |||||||||||||
Real estate | 38,140 | 11,288 | — | 1,928 | — | 51,356 | |||||||||||||||||||
Total | $ | 83,730 | $ | 18,078 | $ | — | $ | 2,022 | $ | — | $ | 103,830 | |||||||||||||
(Thousands of Dollars) | 1-Jul-12 | Purchases | Settlements | Gains | Transfers Out of Level 3 | Sept. 30, 2012 | |||||||||||||||||||
Recognized as | |||||||||||||||||||||||||
Regulatory Liabilities | |||||||||||||||||||||||||
Private equity investments | $ | 23,303 | $ | — | $ | (1,931 | ) | $ | 2,701 | $ | — | $ | 24,073 | ||||||||||||
Real estate | 32,721 | 2,882 | (1,165 | ) | 795 | — | 35,233 | ||||||||||||||||||
Asset-backed securities | 7,068 | — | (2,085 | ) | 12 | — | 4,995 | ||||||||||||||||||
Mortgage-backed securities | 66,321 | 16,782 | (19,681 | ) | 535 | — | 63,957 | ||||||||||||||||||
Total | $ | 129,413 | $ | 19,664 | $ | (24,862 | ) | $ | 4,043 | $ | — | $ | 128,258 | ||||||||||||
(Thousands of Dollars) | Jan. 1, 2013 | Purchases | Settlements | Gains | Transfers Out of Level 3 (a) | Sept. 30, 2013 | |||||||||||||||||||
Recognized as | |||||||||||||||||||||||||
Regulatory Liabilities | |||||||||||||||||||||||||
Private equity investments | $ | 33,250 | $ | 15,344 | $ | — | $ | 3,880 | $ | — | $ | 52,474 | |||||||||||||
Real estate | 39,074 | 18,106 | (9,022 | ) | 3,198 | — | 51,356 | ||||||||||||||||||
Asset-backed securities | 2,067 | — | — | — | (2,067 | ) | — | ||||||||||||||||||
Mortgage-backed securities | 30,209 | — | — | — | (30,209 | ) | — | ||||||||||||||||||
Total | $ | 104,600 | $ | 33,450 | $ | (9,022 | ) | $ | 7,078 | $ | (32,276 | ) | $ | 103,830 | |||||||||||
(a) | Transfers out of Level 3 into Level 2 were principally due to diminished use of unobservable inputs that were previously significant to these fair value measurements. | ||||||||||||||||||||||||
(Thousands of Dollars) | Jan. 1, 2012 | Purchases | Settlements | Gains | Transfers Out of Level 3 | Sept. 30, 2012 | |||||||||||||||||||
Recognized as | |||||||||||||||||||||||||
Regulatory Liabilities | |||||||||||||||||||||||||
Private equity investments | $ | 9,203 | $ | 13,390 | $ | (1,931 | ) | $ | 3,411 | $ | — | $ | 24,073 | ||||||||||||
Real estate | 26,395 | 6,789 | (2,931 | ) | 4,980 | — | 35,233 | ||||||||||||||||||
Asset-backed securities | 16,501 | — | (11,544 | ) | 38 | — | 4,995 | ||||||||||||||||||
Mortgage-backed securities | 78,664 | 31,100 | (46,099 | ) | 292 | — | 63,957 | ||||||||||||||||||
Total | $ | 130,763 | $ | 51,279 | $ | (62,505 | ) | $ | 8,721 | $ | — | $ | 128,258 | ||||||||||||
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 Sept. 30, 2013: | ||||||||||||||||||||||||
Final Contractual Maturity | |||||||||||||||||||||||||
(Thousands of Dollars) | Due in 1 Year | Due in 1 to 5 | Due in 5 to 10 | Due after 10 | Total | ||||||||||||||||||||
or Less | Years | Years | Years | ||||||||||||||||||||||
Government securities | $ | — | $ | — | $ | — | $ | 28,946 | $ | 28,946 | |||||||||||||||
U.S. corporate bonds | 306 | 21,488 | 64,953 | 1,814 | 88,561 | ||||||||||||||||||||
International corporate bonds | — | 4,506 | 11,470 | — | 15,976 | ||||||||||||||||||||
Municipal bonds | 3,118 | 23,549 | 26,922 | 144,328 | 197,917 | ||||||||||||||||||||
Debt securities | $ | 3,424 | $ | 49,543 | $ | 103,345 | $ | 175,088 | $ | 331,400 | |||||||||||||||
Gross Notional Amounts of Commodity Forwards, Options, and FTRs | The following table details the gross notional amounts of commodity forwards, options and FTRs at Sept. 30, 2013 and Dec. 31, 2012: | ||||||||||||||||||||||||
(Amounts in Thousands) (a)(b) | Sept. 30, 2013 | Dec. 31, 2012 | |||||||||||||||||||||||
Megawatt hours (MWh) of electricity | 69,682 | 55,976 | |||||||||||||||||||||||
Million British thermal units (MMBtu) of natural gas | 11,752 | 725 | |||||||||||||||||||||||
Gallons of vehicle fuel | 532 | 682 | |||||||||||||||||||||||
(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. | ||||||||||||||||||||||||
Financial Impact of Qualifying Cash Flow Hedges on Accumulated Other Comprehensive Loss | Financial Impact of Qualifying Cash Flow Hedges — The impact of qualifying interest rate and vehicle fuel cash flow hedges on Xcel Energy’s accumulated other comprehensive loss, included in the consolidated statements of common stockholders’ equity and in the consolidated statements of comprehensive income, is detailed in the following table: | ||||||||||||||||||||||||
Three Months Ended Sept. 30 | |||||||||||||||||||||||||
(Thousands of Dollars) | 2013 | 2012 | |||||||||||||||||||||||
Accumulated other comprehensive loss related to cash flow hedges at July 1 | $ | (60,883 | ) | $ | (55,710 | ) | |||||||||||||||||||
After-tax net unrealized gains (losses) related to derivatives accounted for as hedges | 22 | (8,853 | ) | ||||||||||||||||||||||
After-tax net realized losses on derivative transactions reclassified into earnings | 539 | 393 | |||||||||||||||||||||||
Accumulated other comprehensive loss related to cash flow hedges at Sept. 30 | $ | (60,322 | ) | $ | (64,170 | ) | |||||||||||||||||||
Nine Months Ended Sept. 30 | |||||||||||||||||||||||||
(Thousands of Dollars) | 2013 | 2012 | |||||||||||||||||||||||
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1 | $ | (61,241 | ) | $ | (45,738 | ) | |||||||||||||||||||
After-tax net unrealized losses related to derivatives accounted for as hedges | (9 | ) | (19,188 | ) | |||||||||||||||||||||
After-tax net realized losses on derivative transactions reclassified into earnings | 928 | 756 | |||||||||||||||||||||||
Accumulated other comprehensive loss related to cash flow hedges at Sept. 30 | $ | (60,322 | ) | $ | (64,170 | ) | |||||||||||||||||||
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 nine months ended Sept. 30, 2013 and 2012, on accumulated other comprehensive loss, regulatory assets and liabilities, and income: | ||||||||||||||||||||||||
Three Months Ended Sept. 30, 2013 | |||||||||||||||||||||||||
Pre-Tax Fair Value | Pre-Tax (Gains) Losses | ||||||||||||||||||||||||
Gains (Losses) Recognized | Reclassified into Income | ||||||||||||||||||||||||
During the Period in: | During the Period from: | ||||||||||||||||||||||||
(Thousands of Dollars) | Accumulated | Regulatory | Accumulated | Regulatory | Pre-Tax Gains Recognized | ||||||||||||||||||||
Other | (Assets) and Liabilities | Other | Assets and(Liabilities) | During the Period in Income | |||||||||||||||||||||
Comprehensive Loss | Comprehensive Loss | ||||||||||||||||||||||||
Derivatives designated as cash flow hedges | |||||||||||||||||||||||||
Interest rate | $ | — | $ | — | $ | 829 | (a) | $ | — | $ | — | ||||||||||||||
Vehicle fuel and other commodity | 36 | — | (24 | ) | (b) | — | — | ||||||||||||||||||
Total | $ | 36 | $ | — | $ | 805 | $ | — | $ | — | |||||||||||||||
Other derivative instruments | |||||||||||||||||||||||||
Commodity trading | $ | — | $ | — | $ | — | $ | — | $ | 7,094 | (c) | ||||||||||||||
Electric commodity | — | 921 | — | (9,823 | ) | (d) | — | ||||||||||||||||||
Natural gas commodity | — | (1,967 | ) | — | — | 12 | (d) | ||||||||||||||||||
Total | $ | — | $ | (1,046 | ) | $ | — | $ | (9,823 | ) | $ | 7,106 | |||||||||||||
Nine Months Ended Sept. 30, 2013 | |||||||||||||||||||||||||
Pre-Tax Fair Value | Pre-Tax (Gains) Losses | ||||||||||||||||||||||||
Gains (Losses) Recognized | Reclassified into Income | ||||||||||||||||||||||||
During the Period in: | During the Period from: | ||||||||||||||||||||||||
(Thousands of Dollars) | Accumulated | Regulatory | Accumulated | Regulatory | Pre-Tax Gains | ||||||||||||||||||||
Other | (Assets) and Liabilities | Other | Assets and (Liabilities) | (Losses) Recognized | |||||||||||||||||||||
Comprehensive Loss | Comprehensive Loss | During the Period in Income | |||||||||||||||||||||||
Derivatives designated as cash flow hedges | |||||||||||||||||||||||||
Interest rate | $ | — | $ | — | $ | 3,140 | (a) | $ | — | $ | — | ||||||||||||||
Vehicle fuel and other commodity | (11 | ) | — | (67 | ) | (b) | — | — | |||||||||||||||||
Total | $ | (11 | ) | $ | — | $ | 3,073 | $ | — | $ | — | ||||||||||||||
Other derivative instruments | |||||||||||||||||||||||||
Commodity trading | $ | — | $ | — | $ | — | $ | — | $ | 9,372 | (c) | ||||||||||||||
Electric commodity | — | 61,314 | — | (38,816 | ) | (d) | — | ||||||||||||||||||
Natural gas commodity | — | (5,341 | ) | — | 9 | (e) | (216 | ) | (d) | ||||||||||||||||
Total | $ | — | $ | 55,973 | $ | — | $ | (38,807 | ) | $ | 9,156 | ||||||||||||||
Three Months Ended Sept. 30, 2012 | |||||||||||||||||||||||||
Pre-Tax Fair Value | Pre-Tax (Gains) Losses | ||||||||||||||||||||||||
Gains (Losses) Recognized | Reclassified into Income | ||||||||||||||||||||||||
During the Period in: | During the Period from: | ||||||||||||||||||||||||
(Thousands of Dollars) | Accumulated | Regulatory | Accumulated | Regulatory | Pre-Tax Gains | ||||||||||||||||||||
Other | (Assets) and Liabilities | Other | Assets and(Liabilities) | Recognized | |||||||||||||||||||||
Comprehensive Loss | Comprehensive Loss | During the Period in Income | |||||||||||||||||||||||
Derivatives designated as cash flow hedges | |||||||||||||||||||||||||
Interest rate | $ | (14,923 | ) | $ | — | $ | 733 | (a) | $ | — | $ | — | |||||||||||||
Vehicle fuel and other commodity | 157 | — | (44 | ) | (b) | — | — | ||||||||||||||||||
Total | $ | (14,766 | ) | $ | — | $ | 689 | $ | — | $ | — | ||||||||||||||
Other derivative instruments | |||||||||||||||||||||||||
Commodity trading | $ | — | $ | — | $ | — | $ | — | $ | 7,651 | (c) | ||||||||||||||
Electric commodity | — | 3,923 | — | (11,931 | ) | (d) | — | ||||||||||||||||||
Natural gas commodity | — | 1,193 | — | — | — | ||||||||||||||||||||
Total | $ | — | $ | 5,116 | $ | — | $ | (11,931 | ) | $ | 7,651 | ||||||||||||||
Nine Months Ended Sept. 30, 2012 | |||||||||||||||||||||||||
Pre-Tax Fair Value | Pre-Tax (Gains) Losses | ||||||||||||||||||||||||
Gains (Losses) Recognized | Reclassified into Income | ||||||||||||||||||||||||
During the Period in: | During the Period from: | ||||||||||||||||||||||||
(Thousands of Dollars) | Accumulated | Regulatory | Accumulated | Regulatory | Pre-Tax Gains | ||||||||||||||||||||
Other | (Assets) and Liabilities | Other | Assets and (Liabilities) | (Losses) Recognized | |||||||||||||||||||||
Comprehensive Loss | Comprehensive Loss | During the Period in Income | |||||||||||||||||||||||
Derivatives designated as cash flow hedges | |||||||||||||||||||||||||
Interest rate | $ | (31,914 | ) | $ | — | $ | 1,511 | (a) | $ | — | $ | — | |||||||||||||
Vehicle fuel and other commodity | 140 | — | (145 | ) | (b) | — | — | ||||||||||||||||||
Total | $ | (31,774 | ) | $ | — | $ | 1,366 | $ | — | $ | — | ||||||||||||||
Other derivative instruments | |||||||||||||||||||||||||
Commodity trading | $ | — | $ | — | $ | — | $ | — | $ | 10,963 | (c) | ||||||||||||||
Electric commodity | — | 43,679 | — | (29,616 | ) | (d) | — | ||||||||||||||||||
Natural gas commodity | — | (8,705 | ) | — | 80,939 | (e) | (109 | ) | (d) | ||||||||||||||||
Total | $ | — | $ | 34,974 | $ | — | $ | 51,323 | $ | 10,854 | |||||||||||||||
(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 gains and losses 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 nine months ended Sept. 30, 2012 included $5.0 million 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. Such losses for the nine months ended Sept. 30, 2013 were immaterial. The remaining settlement losses for the nine months ended Sept. 30, 2013 and 2012 relate to natural gas operations and are recorded to cost of natural gas sold and transported. These losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset, 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 Sept. 30, 2013: | ||||||||||||||||||||||||
Sept. 30, 2013 | |||||||||||||||||||||||||
Fair Value | |||||||||||||||||||||||||
(Thousands of Dollars) | Level 1 | Level 2 | Level 3 | Fair Value Total | Counterparty | Total | |||||||||||||||||||
Netting (b) | |||||||||||||||||||||||||
Current derivative assets | |||||||||||||||||||||||||
Derivatives designated as cash flow hedges: | |||||||||||||||||||||||||
Vehicle fuel and other commodity | $ | — | $ | 72 | $ | — | $ | 72 | $ | — | $ | 72 | |||||||||||||
Other derivative instruments: | |||||||||||||||||||||||||
Commodity trading | — | 23,112 | 2,142 | 25,254 | (8,490 | ) | 16,764 | ||||||||||||||||||
Electric commodity | — | — | 41,052 | 41,052 | (2,672 | ) | 38,380 | ||||||||||||||||||
Natural gas commodity | — | 4,443 | — | 4,443 | — | 4,443 | |||||||||||||||||||
Total current derivative assets | $ | — | $ | 27,627 | $ | 43,194 | $ | 70,821 | $ | (11,162 | ) | 59,659 | |||||||||||||
Purchased power agreements (a) | 33,028 | ||||||||||||||||||||||||
Current derivative instruments | $ | 92,687 | |||||||||||||||||||||||
Noncurrent derivative assets | |||||||||||||||||||||||||
Derivatives designated as cash flow hedges: | |||||||||||||||||||||||||
Vehicle fuel and other commodity | $ | — | $ | 27 | $ | — | $ | 27 | $ | (15 | ) | $ | 12 | ||||||||||||
Other derivative instruments: | |||||||||||||||||||||||||
Commodity trading | — | 33,862 | 2,716 | 36,578 | (7,306 | ) | 29,272 | ||||||||||||||||||
Total noncurrent derivative assets | $ | — | $ | 33,889 | $ | 2,716 | $ | 36,605 | $ | (7,321 | ) | 29,284 | |||||||||||||
Purchased power agreements (a) | 66,610 | ||||||||||||||||||||||||
Noncurrent derivative instruments | $ | 95,894 | |||||||||||||||||||||||
Current derivative liabilities | |||||||||||||||||||||||||
Other derivative instruments: | |||||||||||||||||||||||||
Commodity trading | $ | — | $ | 13,607 | $ | 1,770 | $ | 15,377 | $ | (11,751 | ) | $ | 3,626 | ||||||||||||
Electric commodity | — | — | 2,672 | 2,672 | (2,672 | ) | — | ||||||||||||||||||
Total current derivative liabilities | $ | — | $ | 13,607 | $ | 4,442 | $ | 18,049 | $ | (14,423 | ) | 3,626 | |||||||||||||
Purchased power agreements (a) | 23,103 | ||||||||||||||||||||||||
Current derivative instruments | $ | 26,729 | |||||||||||||||||||||||
Noncurrent derivative liabilities | |||||||||||||||||||||||||
Other derivative instruments: | |||||||||||||||||||||||||
Commodity trading | $ | — | $ | 14,767 | $ | — | $ | 14,767 | $ | (7,321 | ) | $ | 7,446 | ||||||||||||
Total noncurrent derivative liabilities | $ | — | $ | 14,767 | $ | — | $ | 14,767 | $ | (7,321 | ) | 7,446 | |||||||||||||
Purchased power agreements (a) | 209,581 | ||||||||||||||||||||||||
Noncurrent derivative instruments | $ | 217,027 | |||||||||||||||||||||||
(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 purchased power agreements 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 Sept. 30, 2013. At Sept. 30, 2013, derivative assets and liabilities include obligations to return cash collateral of $0.4 million and rights to reclaim cash collateral of $3.6 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, 2012: | |||||||||||||||||||||||||
Dec. 31, 2012 | |||||||||||||||||||||||||
Fair Value | |||||||||||||||||||||||||
Fair Value | Counterparty | ||||||||||||||||||||||||
(Thousands of Dollars) | Level 1 | Level 2 | Level 3 | Total | Netting (b) | Total | |||||||||||||||||||
Current derivative assets | |||||||||||||||||||||||||
Derivatives designated as cash flow hedges: | |||||||||||||||||||||||||
Vehicle fuel and other commodity | $ | — | $ | 95 | $ | — | $ | 95 | $ | — | $ | 95 | |||||||||||||
Other derivative instruments: | |||||||||||||||||||||||||
Commodity trading | — | 26,303 | 692 | 26,995 | (6,675 | ) | 20,320 | ||||||||||||||||||
Electric commodity | — | — | 16,724 | 16,724 | (843 | ) | 15,881 | ||||||||||||||||||
Natural gas commodity | — | 7 | — | 7 | (7 | ) | — | ||||||||||||||||||
Total current derivative assets | $ | — | $ | 26,405 | $ | 17,416 | $ | 43,821 | $ | (7,525 | ) | 36,296 | |||||||||||||
Purchased power agreements (a) | 32,717 | ||||||||||||||||||||||||
Current derivative instruments | $ | 69,013 | |||||||||||||||||||||||
Noncurrent derivative assets | |||||||||||||||||||||||||
Derivatives designated as cash flow hedges: | |||||||||||||||||||||||||
Vehicle fuel and other commodity | $ | — | $ | 86 | $ | — | $ | 86 | $ | (47 | ) | $ | 39 | ||||||||||||
Other derivative instruments: | |||||||||||||||||||||||||
Commodity trading | — | 41,282 | 77 | 41,359 | (4,162 | ) | 37,197 | ||||||||||||||||||
Total noncurrent derivative assets | $ | — | $ | 41,368 | $ | 77 | $ | 41,445 | $ | (4,209 | ) | 37,236 | |||||||||||||
Purchased power agreements (a) | 89,061 | ||||||||||||||||||||||||
Noncurrent derivative instruments | $ | 126,297 | |||||||||||||||||||||||
Current derivative liabilities | |||||||||||||||||||||||||
Other derivative instruments: | |||||||||||||||||||||||||
Commodity trading | $ | — | $ | 18,622 | $ | 1 | $ | 18,623 | $ | (9,112 | ) | $ | 9,511 | ||||||||||||
Electric commodity | — | — | 843 | 843 | (843 | ) | — | ||||||||||||||||||
Natural gas commodity | — | 98 | — | 98 | (7 | ) | 91 | ||||||||||||||||||
Total current derivative liabilities | $ | — | $ | 18,720 | $ | 844 | $ | 19,564 | $ | (9,962 | ) | 9,602 | |||||||||||||
Purchased power agreements (a) | 22,880 | ||||||||||||||||||||||||
Current derivative instruments | $ | 32,482 | |||||||||||||||||||||||
Noncurrent derivative liabilities | |||||||||||||||||||||||||
Other derivative instruments: | |||||||||||||||||||||||||
Commodity trading | $ | — | $ | 21,417 | $ | — | $ | 21,417 | $ | (4,210 | ) | $ | 17,207 | ||||||||||||
Total noncurrent derivative liabilities | $ | — | $ | 21,417 | $ | — | $ | 21,417 | $ | (4,210 | ) | 17,207 | |||||||||||||
Purchased power agreements (a) | 225,659 | ||||||||||||||||||||||||
Noncurrent derivative instruments | $ | 242,866 | |||||||||||||||||||||||
(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 purchased power agreements 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, 2012. At Dec. 31, 2012, derivative assets and liabilities include obligations to return cash collateral of $0.6 million and rights to reclaim cash collateral of $3.0 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 nine months ended Sept. 30, 2013 and 2012: | ||||||||||||||||||||||||
Three Months Ended Sept. 30 | |||||||||||||||||||||||||
(Thousands of Dollars) | 2013 | 2012 | |||||||||||||||||||||||
Balance at July 1 | $ | 47,218 | $ | 33,789 | |||||||||||||||||||||
Purchases | 155 | — | |||||||||||||||||||||||
Settlements | (9,342 | ) | (12,649 | ) | |||||||||||||||||||||
Net transactions recorded during the period: | |||||||||||||||||||||||||
Gains recognized in earnings (a) | 4,008 | 13 | |||||||||||||||||||||||
(Losses) gains recognized as regulatory assets and liabilities | (571 | ) | 4,629 | ||||||||||||||||||||||
Balance at Sept. 30 | $ | 41,468 | $ | 25,782 | |||||||||||||||||||||
Nine Months Ended Sept. 30 | |||||||||||||||||||||||||
(Thousands of Dollars) | 2013 | 2012 | |||||||||||||||||||||||
Balance at Jan. 1 | $ | 16,649 | $ | 12,417 | |||||||||||||||||||||
Purchases | 51,541 | 37,296 | |||||||||||||||||||||||
Settlements | (30,294 | ) | (34,209 | ) | |||||||||||||||||||||
Net transactions recorded during the period: | |||||||||||||||||||||||||
Gains recognized in earnings (a) | 3,729 | 5 | |||||||||||||||||||||||
(Losses) gains recognized as regulatory assets and liabilities | (157 | ) | 10,273 | ||||||||||||||||||||||
Balance at Sept. 30 | $ | 41,468 | $ | 25,782 | |||||||||||||||||||||
(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 Sept. 30, 2013 and Dec. 31, 2012, other financial instruments for which the carrying amount did not equal fair value were as follows: | ||||||||||||||||||||||||
Sept. 30, 2013 | Dec. 31, 2012 | ||||||||||||||||||||||||
(Thousands of Dollars) | Carrying Amount | Fair Value | Carrying Amount | Fair Value | |||||||||||||||||||||
Long-term debt, including current portion | $ | 11,194,811 | $ | 12,007,389 | $ | 10,402,060 | $ | 12,207,866 | |||||||||||||||||
Other_Expense_Income_Net_Table
Other (Expense) Income, Net (Tables) | 9 Months Ended | ||||||||||||||||
Sep. 30, 2013 | |||||||||||||||||
Other Income and Expenses [Abstract] | |||||||||||||||||
Other (Expense) Income, Net | Other (expense) income, net consisted of the following: | ||||||||||||||||
Three Months Ended Sept. 30 | Nine Months Ended Sept. 30 | ||||||||||||||||
(Thousands of Dollars) | 2013 | 2012 | 2013 | 2012 | |||||||||||||
Interest income | $ | 1,304 | $ | 1,820 | $ | 7,615 | $ | 8,323 | |||||||||
Other nonoperating income | 739 | 714 | 2,494 | 2,793 | |||||||||||||
Insurance policy expense | (2,386 | ) | (2,042 | ) | (5,932 | ) | (5,902 | ) | |||||||||
Other nonoperating expense | (61 | ) | (4 | ) | (246 | ) | (261 | ) | |||||||||
Other (expense) income, net | $ | (404 | ) | $ | 488 | $ | 3,931 | $ | 4,953 | ||||||||
Segment_Information_Tables
Segment Information (Tables) | 9 Months Ended | ||||||||||||||||||||
Sep. 30, 2013 | |||||||||||||||||||||
Segment Reporting [Abstract] | |||||||||||||||||||||
Results from Continuing Operations by Reportable Segment | |||||||||||||||||||||
(Thousands of Dollars) | Regulated Electric | Regulated Natural Gas | All | Reconciling Eliminations | Consolidated Total | ||||||||||||||||
Other | |||||||||||||||||||||
Three Months Ended Sept. 30, 2013 | |||||||||||||||||||||
Operating revenues from external customers | $ | 2,599,925 | $ | 205,358 | $ | 17,055 | $ | — | $ | 2,822,338 | |||||||||||
Intersegment revenues | 346 | 1,106 | — | (1,452 | ) | — | |||||||||||||||
Total revenues | $ | 2,600,271 | $ | 206,464 | $ | 17,055 | $ | (1,452 | ) | $ | 2,822,338 | ||||||||||
Income (loss) from continuing operations | $ | 365,156 | $ | (174 | ) | $ | (446 | ) | $ | — | $ | 364,536 | |||||||||
(Thousands of Dollars) | Regulated Electric | Regulated Natural Gas | All | Reconciling Eliminations | Consolidated Total | ||||||||||||||||
Other | |||||||||||||||||||||
Three Months Ended Sept. 30, 2012 | |||||||||||||||||||||
Operating revenues from external customers | $ | 2,532,709 | $ | 174,513 | $ | 17,119 | $ | — | $ | 2,724,341 | |||||||||||
Intersegment revenues | 287 | 461 | — | (748 | ) | — | |||||||||||||||
Total revenues | $ | 2,532,996 | $ | 174,974 | $ | 17,119 | $ | (748 | ) | $ | 2,724,341 | ||||||||||
Income (loss) from continuing operations | $ | 400,185 | $ | 4,296 | $ | (6,334 | ) | $ | — | $ | 398,147 | ||||||||||
(Thousands of Dollars) | Regulated Electric | Regulated Natural Gas | All | Reconciling Eliminations | Consolidated Total | ||||||||||||||||
Other | |||||||||||||||||||||
Nine Months Ended Sept. 30, 2013 | |||||||||||||||||||||
Operating revenues from external customers | $ | 6,911,998 | $ | 1,216,275 | $ | 55,827 | $ | — | $ | 8,184,100 | |||||||||||
Intersegment revenues | 955 | 2,163 | — | (3,118 | ) | — | |||||||||||||||
Total revenues | $ | 6,912,953 | $ | 1,218,438 | $ | 55,827 | $ | (3,118 | ) | $ | 8,184,100 | ||||||||||
Income (loss) from continuing operations | $ | 740,347 | $ | 80,698 | $ | (23,039 | ) | $ | — | $ | 798,006 | ||||||||||
(Thousands of Dollars) | Regulated Electric | Regulated Natural Gas | All | Reconciling Eliminations | Consolidated Total | ||||||||||||||||
Other | |||||||||||||||||||||
Nine Months Ended Sept. 30, 2012 | |||||||||||||||||||||
Operating revenues from external customers | $ | 6,506,320 | $ | 1,016,861 | $ | 53,907 | $ | — | $ | 7,577,088 | |||||||||||
Intersegment revenues | 886 | 1,179 | — | (2,065 | ) | — | |||||||||||||||
Total revenues | $ | 6,507,206 | $ | 1,018,040 | $ | 53,907 | $ | (2,065 | ) | $ | 7,577,088 | ||||||||||
Income (loss) from continuing operations | $ | 733,557 | $ | 60,688 | $ | (29,254 | ) | $ | — | $ | 764,991 | ||||||||||
Earnings_Per_Share_Tables
Earnings Per Share (Tables) | 9 Months Ended | ||||||||||||||||||||||
Sep. 30, 2013 | |||||||||||||||||||||||
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 Sept. 30, 2013 | Three Months Ended Sept. 30, 2012 | ||||||||||||||||||||||
(Amounts in thousands, except per share data) | Income | Shares | Per Share | Income | Shares | Per Share | |||||||||||||||||
Amount | Amount | ||||||||||||||||||||||
Net income | $ | 364,752 | $ | 398,106 | |||||||||||||||||||
Basic earnings per share: | |||||||||||||||||||||||
Earnings available to common shareholders | 364,752 | 498,149 | $ | 0.73 | 398,106 | 488,084 | $ | 0.82 | |||||||||||||||
Effect of dilutive securities: | |||||||||||||||||||||||
401(k) equity awards | — | 492 | — | 494 | |||||||||||||||||||
Diluted earnings per share: | |||||||||||||||||||||||
Earnings available to common shareholders | $ | 364,752 | 498,641 | $ | 0.73 | $ | 398,106 | 488,578 | $ | 0.81 | |||||||||||||
Nine Months Ended Sept. 30, 2013 | Nine Months Ended Sept. 30, 2012 | ||||||||||||||||||||||
(Amounts in thousands, except per share data) | Income | Shares | Per Share | Income | Shares | Per Share | |||||||||||||||||
Amount | Amount | ||||||||||||||||||||||
Net income | $ | 798,179 | $ | 765,059 | |||||||||||||||||||
Basic earnings per share: | |||||||||||||||||||||||
Earnings available to common shareholders | 798,179 | 495,256 | $ | 1.61 | 765,059 | 487,722 | $ | 1.57 | |||||||||||||||
Effect of dilutive securities: | |||||||||||||||||||||||
401(k) equity awards | — | 511 | — | 476 | |||||||||||||||||||
Diluted earnings per share: | |||||||||||||||||||||||
Earnings available to common shareholders | $ | 798,179 | 495,767 | $ | 1.61 | $ | 765,059 | 488,198 | $ | 1.57 | |||||||||||||
Benefit_Plans_and_Other_Postre1
Benefit Plans and Other Postretirement Benefits (Tables) | 9 Months Ended | ||||||||||||||||
Sep. 30, 2013 | |||||||||||||||||
Compensation and Retirement Disclosure [Abstract] | |||||||||||||||||
Components of Net Periodic Benefit Cost | Components of Net Periodic Benefit Cost | ||||||||||||||||
Three Months Ended Sept. 30 | |||||||||||||||||
2013 | 2012 | 2013 | 2012 | ||||||||||||||
(Thousands of Dollars) | Pension Benefits | Postretirement Health | |||||||||||||||
Care Benefits | |||||||||||||||||
Service cost | $ | 24,071 | $ | 21,591 | $ | 1,182 | $ | 1,050 | |||||||||
Interest cost | 35,173 | 39,043 | 8,417 | 9,465 | |||||||||||||
Expected return on plan assets | (49,613 | ) | (51,774 | ) | (8,253 | ) | (7,102 | ) | |||||||||
Amortization of transition obligation | — | — | 206 | 3,580 | |||||||||||||
Amortization of prior service cost (credit) | 1,468 | 5,266 | (2,438 | ) | (1,888 | ) | |||||||||||
Amortization of net loss | 36,038 | 26,893 | 5,646 | 4,228 | |||||||||||||
Net periodic benefit cost | 47,137 | 41,019 | 4,760 | 9,333 | |||||||||||||
Costs not recognized and additional cost recognized due to the effects of regulation | (12,986 | ) | (9,645 | ) | — | 972 | |||||||||||
Net benefit cost recognized for financial reporting | $ | 34,151 | $ | 31,374 | $ | 4,760 | $ | 10,305 | |||||||||
Nine Months Ended Sept. 30 | |||||||||||||||||
2013 | 2012 | 2013 | 2012 | ||||||||||||||
(Thousands of Dollars) | Pension Benefits | Postretirement Health | |||||||||||||||
Care Benefits | |||||||||||||||||
Service cost | $ | 72,212 | $ | 64,773 | $ | 3,546 | $ | 3,152 | |||||||||
Interest cost | 105,518 | 117,131 | 25,251 | 28,396 | |||||||||||||
Expected return on plan assets | (148,839 | ) | (155,322 | ) | (24,759 | ) | (21,307 | ) | |||||||||
Amortization of transition obligation | — | — | 618 | 10,740 | |||||||||||||
Amortization of prior service cost (credit) | 4,404 | 15,799 | (7,314 | ) | (5,664 | ) | |||||||||||
Amortization of net loss | 108,114 | 80,678 | 16,938 | 12,680 | |||||||||||||
Net periodic benefit cost | 141,409 | 123,059 | 14,280 | 27,997 | |||||||||||||
Costs not recognized and additional cost recognized due to the effects of regulation | (27,922 | ) | (28,936 | ) | — | 2,918 | |||||||||||
Net benefit cost recognized for financial reporting | $ | 113,487 | $ | 94,123 | $ | 14,280 | $ | 30,915 | |||||||||
Other_Comprehensive_Income_Tab
Other Comprehensive Income (Tables) | 9 Months Ended | ||||||||||||||||
Sep. 30, 2013 | |||||||||||||||||
Stockholders' Equity Note [Abstract] | |||||||||||||||||
Changes in Accumulated Other Comprehensive Loss, Net of Tax | Changes in accumulated other comprehensive loss, net of tax, for the three and nine months ended Sept. 30, 2013 were as follows: | ||||||||||||||||
Three Months Ended Sept. 30, 2013 | |||||||||||||||||
(Thousands of Dollars) | Gains and | Unrealized | Defined Benefit | Total | |||||||||||||
Losses on Cash Flow Hedges | Gains and Losses | Pension and | |||||||||||||||
on Marketable | Postretirement | ||||||||||||||||
Securities | Items | ||||||||||||||||
Accumulated other comprehensive loss at July 1 | $ | (60,883 | ) | $ | (135 | ) | $ | (50,817 | ) | $ | (111,835 | ) | |||||
Other comprehensive gain before reclassifications | 22 | 115 | — | 137 | |||||||||||||
Losses reclassified from net accumulated other comprehensive loss | 539 | — | 1,179 | 1,718 | |||||||||||||
Net current period other comprehensive income | 561 | 115 | 1,179 | 1,855 | |||||||||||||
Accumulated other comprehensive loss at Sept. 30 | $ | (60,322 | ) | $ | (20 | ) | $ | (49,638 | ) | $ | (109,980 | ) | |||||
Nine Months Ended Sept. 30, 2013 | |||||||||||||||||
(Thousands of Dollars) | Gains and | Unrealized | Defined Benefit | Total | |||||||||||||
Losses on Cash Flow Hedges | Gains and Losses | Pension and | |||||||||||||||
on Marketable | Postretirement | ||||||||||||||||
Securities | Items | ||||||||||||||||
Accumulated other comprehensive loss at Jan. 1 | $ | (61,241 | ) | $ | (99 | ) | $ | (51,313 | ) | $ | (112,653 | ) | |||||
Other comprehensive gain (loss) before reclassifications | (9 | ) | 79 | — | 70 | ||||||||||||
Losses reclassified from net accumulated other comprehensive loss | 928 | — | 1,675 | 2,603 | |||||||||||||
Net current period other comprehensive income | 919 | 79 | 1,675 | 2,673 | |||||||||||||
Accumulated other comprehensive loss at Sept. 30 | $ | (60,322 | ) | $ | (20 | ) | $ | (49,638 | ) | $ | (109,980 | ) | |||||
Reclassifications out of Accumulated Other Comprehensive Loss | Reclassifications from accumulated other comprehensive loss for the three and nine months ended Sept. 30, 2013 were as follows: | ||||||||||||||||
Amounts Reclassified from | |||||||||||||||||
Accumulated Other | |||||||||||||||||
Comprehensive Loss | |||||||||||||||||
(Thousands of Dollars) | Three Months Ended Sept. 30, 2013 | Nine Months Ended Sept. 30, 2013 | |||||||||||||||
(Gains) losses on cash flow hedges: | |||||||||||||||||
Interest rate derivatives | $ | 829 | (a) | $ | 3,140 | (a) | |||||||||||
Vehicle fuel derivatives | (24 | ) | (b) | (67 | ) | (b) | |||||||||||
Total, pre-tax | 805 | 3,073 | |||||||||||||||
Tax benefit | (266 | ) | (2,145 | ) | |||||||||||||
Total, net of tax | 539 | 928 | |||||||||||||||
Defined benefit pension and postretirement losses: | |||||||||||||||||
Amortization of net loss | 1,770 | (c) | 5,308 | (c) | |||||||||||||
Prior service cost | 93 | (c) | 279 | (c) | |||||||||||||
Transition obligation | 2 | (c) | 6 | (c) | |||||||||||||
Total, pre-tax | 1,865 | 5,593 | |||||||||||||||
Tax benefit | (686 | ) | (3,918 | ) | |||||||||||||
Total, net of tax | 1,179 | 1,675 | |||||||||||||||
Total amounts reclassified, net of tax | $ | 1,718 | $ | 2,603 | |||||||||||||
(a) | Included in interest charges. | ||||||||||||||||
(b) | Included in O&M expenses. | ||||||||||||||||
(c) | Included in the computation of net periodic pension and post retirement benefit costs. See Note 12 for details regarding these benefit plans. |
Balance_Sheet_Data_Accounts_Re
Balance Sheet Data, Accounts Receivable (Details) (USD $) | Sep. 30, 2013 | Dec. 31, 2012 |
In Thousands, unless otherwise specified | ||
Accounts receivable, net | ||
Accounts receivable | $838,271 | $769,440 |
Less allowance for bad debts | -51,397 | -51,394 |
Accounts receivable, net | $786,874 | $718,046 |
Selected_Balance_Sheet_Data_Ba
Selected Balance Sheet Data Balance Sheet Related Disclosures, Inventories (Details) (USD $) | Sep. 30, 2013 | Dec. 31, 2012 |
In Thousands, unless otherwise specified | ||
Public Utilities, Inventory [Line Items] | ||
Inventories | $604,628 | $535,574 |
Materials and supplies | ||
Public Utilities, Inventory [Line Items] | ||
Inventories | 228,302 | 213,739 |
Fuel | ||
Public Utilities, Inventory [Line Items] | ||
Inventories | 201,728 | 189,425 |
Natural gas | ||
Public Utilities, Inventory [Line Items] | ||
Inventories | $174,598 | $132,410 |
Selected_Balance_Sheet_Data_Ba1
Selected Balance Sheet Data Balance Sheet Related Disclosures, Property, Plant and Equipment (Details) (USD $) | Sep. 30, 2013 | Dec. 31, 2012 | ||
In Thousands, unless otherwise specified | ||||
Public Utility, Property, Plant and Equipment [Line Items] | ||||
Property, plant and equipment, gross | $37,468,400 | $35,511,843 | ||
Less accumulated depreciation | -12,462,716 | -12,048,697 | ||
Property, plant and equipment, net | 25,342,578 | 23,809,348 | ||
Electric plant | ||||
Public Utility, Property, Plant and Equipment [Line Items] | ||||
Property, plant and equipment, gross | 29,550,871 | 28,285,031 | ||
Natural gas plant | ||||
Public Utility, Property, Plant and Equipment [Line Items] | ||||
Property, plant and equipment, gross | 3,942,182 | 3,836,335 | ||
Common and other property | ||||
Public Utility, Property, Plant and Equipment [Line Items] | ||||
Property, plant and equipment, gross | 1,467,811 | 1,480,558 | ||
Plant to be retired | ||||
Public Utility, Property, Plant and Equipment [Line Items] | ||||
Property, plant and equipment, gross | 115,753 | [1] | 152,730 | [1] |
Construction work in progress | ||||
Public Utility, Property, Plant and Equipment [Line Items] | ||||
Property, plant and equipment, gross | 2,391,783 | 1,757,189 | ||
Nuclear fuel | ||||
Public Utility, Property, Plant and Equipment [Line Items] | ||||
Property, plant and equipment, gross | 2,157,940 | 2,090,801 | ||
Less accumulated depreciation | ($1,821,046) | ($1,744,599) | ||
[1] | In 2010, in response to the Clean Air Clean Jobs Act (CACJA), the Colorado Public Utilities Commission (CPUC) approved the early retirement of Cherokee Units 1, 2 and 3, Arapahoe Unit 3 and Valmont Unit 5 between 2011 and 2017. In 2011, Cherokee Unit 2 was retired and in 2012, Cherokee Unit 1 was retired. Amounts are presented net of accumulated depreciation. |
Income_Taxes_Details
Income Taxes (Details) (USD $) | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Mar. 31, 2013 | Sep. 30, 2013 |
Internal Revenue Service (IRS) | Internal Revenue Service (IRS) | Colorado | Colorado | Minnesota | Texas | Wisconsin | Wisconsin | |||
Tax Audits [Abstract] | ||||||||||
Year(s) no longer subject to audit as statute of limitations has expired | 2008 | |||||||||
Earliest year subject to examination | 2009 | 2006 | 2009 | 2009 | 2009 | |||||
Year(s) under examination | 2010 and 2011 | 2006 through 2009 | None | None | 2009 through 2011 | |||||
Unrecognized Tax Benefits [Abstract] | ||||||||||
Unrecognized tax benefit — Permanent tax positions | $8,800,000 | $4,700,000 | ||||||||
Unrecognized tax benefit — Temporary tax positions | 32,400,000 | 29,800,000 | ||||||||
Total unrecognized tax benefit | 41,200,000 | 34,500,000 | ||||||||
NOL and tax credit carryforwards | -40,100,000 | -33,500,000 | ||||||||
Upper bound of decrease in unrecognized tax benefit that is reasonably possible | -35,000,000 | |||||||||
Amounts accrued for penalties related to unrecognized tax benefits | $0 | $0 |
Rate_Matters_NSPMinnesota_Deta
Rate Matters, NSP-Minnesota (Details) (USD $) | 1 Months Ended | 0 Months Ended | 1 Months Ended | 3 Months Ended | 0 Months Ended | 1 Months Ended | 0 Months Ended | 1 Months Ended | 0 Months Ended | ||||||
Oct. 31, 2013 | Sep. 19, 2013 | Sep. 03, 2013 | Jan. 31, 2013 | Nov. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Aug. 12, 2013 | Jun. 30, 2013 | Jan. 31, 2013 | Dec. 31, 2012 | Aug. 22, 2013 | Aug. 22, 2013 | Mar. 31, 2013 | Oct. 02, 2013 | |
Nuclear Project Prudency Investigation [Member] [Member] | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | |
Subsequent Event [Member] | Minnesota Public Utilities Commission [Member] | Minnesota Public Utilities Commission [Member] | Minnesota Public Utilities Commission [Member] | Minnesota Public Utilities Commission [Member] | Minnesota Public Utilities Commission [Member] | Administrative Law Judge [Member] | North Dakota Public Service Commission [Member] | North Dakota Public Service Commission [Member] | North Dakota Public Service Commission [Member] | North Dakota Public Service Commission [Member] | NDPSC Advocacy Staff [Member] | NDPSC Advocacy Staff [Member] | South Dakota Public Utilities Commission [Member] | South Dakota Public Utilities Commission [Member] | |
Electric Rate Case 2013 [Member] | Electric Rate Case 2013 [Member] | Electric Rate Case 2013 [Member] | Electric Rate Case 2013 [Member] | Electric Rate Case 2013 [Member] | Electric Rate Case 2013 [Member] | Electric Rate Case 2013 [Member] | Electric Rate Case 2013 [Member] | Electric Rate Case 2013 [Member] | Electric Rate Case 2013 [Member] | Electric Rate Case 2013 [Member] | Electric Rate Case 2012 [Member] | Electric Rate Case 2012 [Member] | Electric Rate Case 2012 [Member] | ||
Subsequent Event [Member] | |||||||||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||||||||
Interim Rate Refund, Amount | $132,200,000 | ||||||||||||||
Rate Matters [Abstract] | |||||||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | 285,000,000 | 16,900,000 | |||||||||||||
Public Utilities, Requested Rate Increase (Decrease), Percentage | 10.70% | 9.25% | |||||||||||||
Public Utilities, Requested Return on Equity, Percentage | 10.60% | 10.60% | 10.60% | ||||||||||||
Public Utilities, Requested Rate Base, Amount | 6,300,000,000 | 6,300,000,000 | 377,600,000 | ||||||||||||
Public Utilities, Requested Equity Capital Structure, Percentage | 52.56% | 52.56% | 52.56% | ||||||||||||
Public Utilities, Interim Rate Increase (Decrease), Amount | 251,000,000 | 14,700,000 | |||||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount | 209,000,000 | 14,900,000 | 16,000,000 | ||||||||||||
Public Utilities, Adjustment requested by public utility to rate increase (decrease) related to use of a one month coincident peak demand allocator for certain rate base and operation expenses | 0 | ||||||||||||||
Public Utilities, Requested Return on Equity, Revised, Percentage | 10.25% | ||||||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amended, Percentage | 7.80% | ||||||||||||||
Public Utilities, Return on equity recommended by third parties | 9.00% | ||||||||||||||
Public Utilities, Rate increase (decrease) subsequently recommended by third parties | 127,000,000 | ||||||||||||||
Public Utilities, Requested Rate Increase (Decrease) Including Deferral Mechanisms | 259,000,000 | ||||||||||||||
Public Utilities, Deferral Mechanisms for Rate Mitigation | 50,000,000 | ||||||||||||||
Public Utilities, Deferral Mechanism for Rate Mitigation requested by third parties - reduction to expense | 34,000,000 | ||||||||||||||
Public Utilities, Adjustment requested by public utility related to return on equity | 0 | -1,200,000 | |||||||||||||
Public Utilities, Adjustment recommended by third parties related to return on equity | -43,000,000 | -5,200,000 | |||||||||||||
Public Utilities, Approved Rate Increase (Decrease) due to return on equity, Amount | -43,000,000 | ||||||||||||||
Public Utilities, Adjustment requested by public utility to rate increase (decrease) related to removal of avoided costs of electric generation unit | -35,000,000 | ||||||||||||||
Public Utilities, Adjustment to requested rate increase (decrease) requested by third parties related to removal of avoided costs of electric generation unit | -38,000,000 | ||||||||||||||
Public Utilities, Approved Rate Increase (Decrease) due to Sherco Unit 3, Amount | -34,000,000 | ||||||||||||||
Public Utilities, Adjustment requested by public utility to rate increase (decrease) related to reduced recovery for nuclear plants | -11,000,000 | ||||||||||||||
Public Utilities, Adjustment to requested rate increase (decrease) requested by third parties related to reduced recovery for nuclear plants | -14,000,000 | ||||||||||||||
Public Utilities, Approved Rate Increase (Decrease) due to reduced recovery for nuclear plants, Amount | -15,000,000 | ||||||||||||||
Public Utilities, Adjustment requested by public utility to rate increase (decrease) related to elimination of certain incentive compensation | -3,000,000 | 0 | |||||||||||||
Public Utilities, Adjustment to requested rate increase (decrease) requested by third parties related to incentive compensation | -4,000,000 | -800,000 | |||||||||||||
Public Utilities, Adjustment requested by public utility to rate increase (decrease) related to various operating & maintenance expenses | 0 | ||||||||||||||
Public Utilities, Approved Rate Increase (Decrease) due to incentive compensation, Amount | -4,000,000 | ||||||||||||||
Public Utilities, Adjustment requested by public utility to rate increase (decrease) related to an increase to sales forecast | -1,000,000 | ||||||||||||||
Public Utilities, Adjustment to requested rate increase (decrease) requested by third parties related to an increase to sales forecast | -26,000,000 | ||||||||||||||
Public Utilities, Adjustment to requested rate increase (decrease) requested by third parties related to reduced recovery for pension benefits | -13,000,000 | ||||||||||||||
Public Utilities, Approved Rate Increase (Decrease) due to sales forecast, Amount | -26,000,000 | ||||||||||||||
Public Utilities, Adjustment requested by public utility to rate increase (decrease) related to reduced recovery for pension benefits | -10,000,000 | ||||||||||||||
Public Utilities, Approved Rate Increase (Decrease) due to pension, Amount | -13,000,000 | ||||||||||||||
Public Utilities, Adjustment requested by public utility to rate increase (decrease) related to reduced recovery for employee benefits | -4,000,000 | ||||||||||||||
Public Utilities, Adjustment to requested rate increase (decrease) requested by third parties related to reduced recovery for employee benefits | -6,000,000 | ||||||||||||||
Public Utilities, Approved Rate Increase (Decrease) due to employee benefits, Amount | -6,000,000 | ||||||||||||||
Public Utilities, Adjustment requested by public utility to rate increase (decrease) related to Black Dog remediation costs | -5,000,000 | ||||||||||||||
Public Utilities, Adjustment to requested rate increase (decrease) requested by third parties related to Black Dog remediation costs | -5,000,000 | ||||||||||||||
Public Utilities, Approved Rate Increase (Decrease) due to Black Dog remedation, Amount | -5,000,000 | ||||||||||||||
Public Utilities, Adjustment requested by public utility to rate increase (decrease) related to theoretical depreciation reserve | 0 | ||||||||||||||
Public Utilities, Adjustment to requested rate increase (decrease) requested by third parties related to theoretical depreciation reserve | 0 | ||||||||||||||
Public Utilities, impact of theoretical depreciation reserve | -24,000,000 | ||||||||||||||
Public Utilities, impact of theoretical depreciation reserve - reduction to expense | 24,000,000 | ||||||||||||||
Public Utilities, Adjustment requested by public utility to rate increase (decrease) related to NSP-Wisconsin wholesale allocation | -7,000,000 | ||||||||||||||
Public Utilities, Adjustment to requested rate increase (decrease) requested by third parties related to NSP-Wisconsin wholesale allocation | -7,000,000 | ||||||||||||||
Public Utilities, Approved Rate Increase (Decrease) due to NSP-Wisconsin wholesale allocation, Amount | -7,000,000 | ||||||||||||||
Public Utilities, Adjustment requested by public utility to rate increase (decrease) related to other costs | 0 | 0 | |||||||||||||
Public Utilities, Adjustment to requested rate increase (decrease) requested by third parties related to other costs | -2,000,000 | 900,000 | |||||||||||||
Public Utilities, Approved Rate Increase (Decrease) due to other, Amount | -5,000,000 | ||||||||||||||
Public Utilities, increase in reserve for revenue subject to refund, Amount | 30,000,000 | ||||||||||||||
Number of factors attributable to project cost increases | 3 | ||||||||||||||
Number of years for the application process | 5 | ||||||||||||||
Public Utilities, Rate increase (decrease) recommended by third parties | -10,000,000 | ||||||||||||||
Public Utilities, Recommended rate increase (decrease) impact on pre-tax income | 161,000,000 | ||||||||||||||
Public Utilities, Adjustment to requested rate increase (decrease) requested by third parties related to use of a one month coincident peak demand allocator for certain rate base and operation exps | -20,400,000 | ||||||||||||||
Public Utilities, Number of months used for coincident peak demand allocator for certain rate base and operation expenses | 1 month | ||||||||||||||
Public Utilities, Adjustment to requested rate increase (decrease) requested by third parties related to various operating & maintenance expenses | -700,000 | ||||||||||||||
Public Utilities, Adjustment requested by public utility to rate increase (decrease) related to modified cost of capital and increased capital structure | 100,000 | ||||||||||||||
Public Utilities, Adjustment to requested rate increase (decrease) requested by third parties related to modified cost of capital and increased capital structure | 1,300,000 | ||||||||||||||
Public Utilities, Adjustment requested by public utility to rate increase (decrease) related to depreciation/remaining life study | 0 | ||||||||||||||
Public Utilities, Adjustment to requested rate increase (decrease) requested by third parties related to depreciation/remaining life study | -1,100,000 | ||||||||||||||
Public Utilities, Cost of Capital and Capital Structure requested by third parties | 53.42% | ||||||||||||||
Public Utilities, Approved Rate Increase (Decrease), Amount | 103,000,000 | 11,600,000 | |||||||||||||
Public Utilities, Projected incremental revenue from rider in 2014 | 8,700,000 | ||||||||||||||
Public Utilities, Approved Rate Increase (Decrease), Percentage | 3.80% | ||||||||||||||
Public Utilities, Approved Return on Equity, Percentage | 9.83% | ||||||||||||||
Public Utilities, Approved Equity Capital Structure, Percentage | 52.56% | ||||||||||||||
Public Utilities, Authorized Deferrals - reduction to expense | 20,000,000 | ||||||||||||||
Public Utilities, Approved Rate Increase (Decrease) - impact on pre-tax income, Amount | $147,000,000 |
Rate_Matters_NSPWisconsin_Deta
Rate Matters, NSP-Wisconsin (Details) (Public Service Commission of Wisconsin (PSCW) [Member], NSP-Wisconsin [Member], USD $) | 1 Months Ended | 0 Months Ended | 1 Months Ended | 0 Months Ended | 1 Months Ended | 0 Months Ended | |||
31-May-13 | Oct. 18, 2013 | Oct. 04, 2013 | 31-May-13 | Oct. 18, 2013 | Oct. 04, 2013 | 31-May-13 | Oct. 18, 2013 | Oct. 04, 2013 | |
Electric and Gas Rate Case 2014, Electric Rates [Member] | Electric and Gas Rate Case 2014, Electric Rates [Member] | Electric and Gas Rate Case 2014, Electric Rates [Member] | Electric and Gas Rate Case 2014, Gas Rates [Member] | Electric and Gas Rate Case 2014, Gas Rates [Member] | Electric and Gas Rate Case 2014, Gas Rates [Member] | Electric and Gas Rate Case 2014 [Member] | Electric and Gas Rate Case 2014 [Member] | Electric and Gas Rate Case 2014 [Member] | |
Subsequent Event [Member] | Subsequent Event [Member] | Subsequent Event [Member] | Subsequent Event [Member] | Subsequent Event [Member] | Subsequent Event [Member] | ||||
Public Utilities, General Disclosures [Line Items] | |||||||||
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount | $34,000,000 | $0 | |||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | 40,000,000 | 4,700,000 | |||||||
Public Utilities, Requested Rate Increase (Decrease), Percentage | 6.50% | 3.80% | |||||||
Public Utilities, Requested Return on Equity, Percentage | 10.40% | 10.40% | |||||||
Public Utilities, Requested Equity Capital Structure, Percentage | 52.50% | ||||||||
Forecasted Average Net Investment Rate Base, Electric Utility | 895,300,000 | ||||||||
Forecasted Average Net Investment Rate Base, Natural Gas Utility | 89,800,000 | ||||||||
Public Utilities, Adjustment to requested rate increase (decrease) recommended by third parties related to electric fuel and purchased power | -5,100,000 | 0 | |||||||
Public Utilities, Adjustment to requested rate increase (decrease) recommended by third parties related to the sales forecast | -4,800,000 | 0 | |||||||
Public Utilities, Adjustment to requested rate increase (decrease) requested by third parties related to incentive compensation | -3,000,000 | -600,000 | |||||||
Public Utilities, Adjustment recommended by third parties related to return on equity | -1,600,000 | -200,000 | |||||||
Public Utilities, Adjustment to requested rate increase (decrease) recommended by third parties related to conservation programs | 700,000 | -700,000 | |||||||
Public Utilities, Adjustment to requested rate increase (decrease) recommended by third parties related to depreciation expense | -700,000 | -1,300,000 | |||||||
Public Utilities, Adjustment to requested rate increase (decrease) recommended by third parties related to amortization expenses | 0 | -2,300,000 | |||||||
Public Utilities, Adjustment to requested rate increase (decrease) requested by third parties related to other costs | -1,700,000 | -700,000 | |||||||
Public Utilities, Rate increase (decrease) recommended by third parties | $23,800,000 | ($1,100,000) | |||||||
Public Utilities, Rate increase (decrease) recommended by third parties, percentage | 3.80% | -0.90% | |||||||
Public Utilities, Return on equity recommended by third parties | 10.20% | ||||||||
Public Utilities, Equity capital structure recommended by third parties | 52.50% |
Rate_Matters_PSCo_Details
Rate Matters, PSCo (Details) (PSCo, USD $) | 0 Months Ended | 1 Months Ended | 9 Months Ended | 1 Months Ended | 3 Months Ended | 1 Months Ended | |||||||||||||||||||||||||
Aug. 30, 2013 | Apr. 30, 2013 | Dec. 31, 2012 | Apr. 30, 2013 | Dec. 31, 2012 | Apr. 30, 2013 | Dec. 31, 2012 | Apr. 30, 2013 | Dec. 31, 2012 | Dec. 31, 2012 | Dec. 31, 2012 | Apr. 30, 2013 | Dec. 31, 2012 | Dec. 31, 2012 | Dec. 31, 2012 | Dec. 31, 2012 | Sep. 30, 2013 | Mar. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Dec. 31, 2012 | Mar. 31, 2012 | 31-May-11 | Mar. 31, 2012 | 31-May-11 | Jul. 31, 2013 | Apr. 30, 2013 | Apr. 30, 2013 | Oct. 31, 2013 | Oct. 31, 2013 | Oct. 31, 2013 | |
Production Formula Rate ROE Complaint [Member] | Colorado Public Utilities Commission (CPUC) [Member] | Colorado Public Utilities Commission (CPUC) [Member] | Colorado Public Utilities Commission (CPUC) [Member] | Colorado Public Utilities Commission (CPUC) [Member] | Colorado Public Utilities Commission (CPUC) [Member] | Colorado Public Utilities Commission (CPUC) [Member] | Colorado Public Utilities Commission (CPUC) [Member] | Colorado Public Utilities Commission (CPUC) [Member] | Colorado Public Utilities Commission (CPUC) [Member] | Colorado Public Utilities Commission (CPUC) [Member] | Colorado Public Utilities Commission (CPUC) [Member] | Colorado Public Utilities Commission (CPUC) [Member] | Colorado Public Utilities Commission (CPUC) [Member] | Colorado Public Utilities Commission (CPUC) [Member] | Colorado Public Utilities Commission (CPUC) [Member] | Colorado Public Utilities Commission (CPUC) [Member] | Colorado Public Utilities Commission (CPUC) [Member] | Colorado Public Utilities Commission (CPUC) [Member] | Colorado Public Utilities Commission (CPUC) [Member] | Colorado Public Utilities Commission (CPUC) [Member] | Colorado Public Utilities Commission (CPUC) [Member] | Colorado Public Utilities Commission (CPUC) [Member] | Colorado Public Utilities Commission (CPUC) [Member] | Colorado Public Utilities Commission (CPUC) [Member] | Colorado Public Utilities Commission (CPUC) [Member] | Office of Consumer Counsel [Member] | Office of Consumer Counsel [Member] | Subsequent Event [Member] | Subsequent Event [Member] | Subsequent Event [Member] | |
2013 Gas Rate Case [Member] | 2013 Gas Rate Case [Member] | Gas Rate Case 2013, Gas Rates 2013 [Member] | Gas Rate Case 2013, Gas Rates 2013 [Member] | Gas Rate Case 2013, Gas Rates 2014 [Member] | Gas Rate Case 2013, Gas Rates 2014 [Member] | Gas Rate Case 2013, Gas Rates 2015 [Member] | Gas Rate Case 2013, Gas Rates 2015 [Member] | Gas Rate Case 2013, Pipeline System Integrity Adjustment 2014 [Member] | Gas Rate Case 2013, Pipeline System Integrity Adjustment 2015 [Member] | Gas Rate Case 2013 Net of Pipeline System Integrity Adjustment Based on Historical Test Year [Member] | 2013 Steam Rate Case [Member] | Steam Rate Case 2013, Steam Rates 2013 [Member] | Steam Rate Case 2013, Steam Rates 2014 [Member] | Steam Rate Case 2013, Steam Rates 2015 [Member] | Annual Electric Earnings Test [Member] | Renewable Energy Credit Sharing [Member] | Renewable Energy Credit Sharing [Member] | Renewable Energy Credit Sharing [Member] | Renewable Energy Credit Sharing [Member] | Renewable Energy Credit Sharing [Member] | Renewable Energy Credit Sharing [Member] | Renewable Energy Credit Sharing [Member] | Renewable Energy Credit Sharing [Member] | Electric Commodity Adjustment / RESA Adjustment [Member] | 2013 Gas Rate Case [Member] | Gas Rate Case 2013 Net of Pipeline System Integrity Adjustment Based on Historical Test Year [Member] | Colorado Public Utilities Commission (CPUC) [Member] | Administrative Law Judge [Member] | Administrative Law Judge [Member] | ||
Counterparty | Shareholders [Member] | Shareholders [Member] | Customers [Member] | Customers [Member] | Steam Rate Case 2013, Steam Rates 2014 [Member] | 2013 Gas Rate Case [Member] | Gas Rate Case 2013 Net of Pipeline System Integrity Adjustment Based on Historical Test Year [Member] | ||||||||||||||||||||||||
Rate Matters [Abstract] | |||||||||||||||||||||||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $48,500,000 | $9,900,000 | $12,100,000 | $26,800,000 | $24,700,000 | $1,600,000 | $900,000 | $2,300,000 | |||||||||||||||||||||||
Public Utilities, Requested Return on Equity, Percentage | 10.30% | 10.50% | 10.50% | ||||||||||||||||||||||||||||
Public Utilities, Revenue deficiency based on a forecast test year | 30,600,000 | ||||||||||||||||||||||||||||||
Public Utilities, Requested Rate Base, Amount | 1,300,000,000 | 21,000,000 | |||||||||||||||||||||||||||||
Public Utilities, Requested Equity Capital Structure, Percentage | 56.00% | 56.00% | |||||||||||||||||||||||||||||
Number of days subject to refund | 60 | ||||||||||||||||||||||||||||||
Public Utilities, Approved Rate Increase (Decrease), Amount | 1,200,000 | ||||||||||||||||||||||||||||||
Public Utilities, Number of intervenors filing testimony | 4 | ||||||||||||||||||||||||||||||
Public Utilities, Incremental Base Revenue increase (decrease) recommended by third party | -1,100,000 | -1,100,000 | 15,400,000 | 15,400,000 | 15,000,000 | 15,000,000 | |||||||||||||||||||||||||
Public Utilities, Return on equity recommended by third parties | 9.00% | 9.00% | 9.72% | ||||||||||||||||||||||||||||
Public Utilities, Equity capital structure recommended by third parties | 52.00% | 51.03% | 56.00% | ||||||||||||||||||||||||||||
Public Utilities, Adjustment requested by third parties related to return on equity and capital structure adjustments | -20,800,000 | -20,000,000 | -7,700,000 | ||||||||||||||||||||||||||||
Public Utilities, Adjustment to requested rate increase (decrease) requested by third parties related to use of 13 month average from year end rate base | -5,700,000 | -3,200,000 | -3,300,000 | ||||||||||||||||||||||||||||
Public Utilities, Adjustment to requested rate increase (decrease) requested by third parties related to removal of pension asset | -5,900,000 | 0 | 0 | ||||||||||||||||||||||||||||
Public Utilities, Adjustment to requested rate increase (decrease) requested by third parties related to pension expense net of corrections | -1,600,000 | 0 | 0 | ||||||||||||||||||||||||||||
Public Utilities, Adjustment to requested rate increase (decrease) requested by third parties related to incentive compensation | -3,500,000 | -200,000 | -200,000 | ||||||||||||||||||||||||||||
Public Utilities, Adjustment to requested rate increase (decrease) requested by third parties related to challenge of known and measurable | 0 | -9,000,000 | 0 | ||||||||||||||||||||||||||||
Public Utilities, Adjustment to requested rate increase (decrease) requested by third parties related to elimination of depreciation annualization | 0 | -1,800,000 | 0 | ||||||||||||||||||||||||||||
Public Utilities, Adjustment to requested rate increase (decrease) requested by third parties related to revenue adjustments | -4,100,000 | -1,400,000 | -1,400,000 | ||||||||||||||||||||||||||||
Public Utilities, Tax impact of adjustments to requested rate increase (decrease) requested by third parties | 1,500,000 | 4,700,000 | -200,000 | ||||||||||||||||||||||||||||
Public Utilities, Adjustment to requested rate increase (decrease) requested by third parties related to other costs | -4,200,000 | 3,100,000 | -1,200,000 | ||||||||||||||||||||||||||||
Public Utilities, Adjustment to requested rate increase (decrease) requested by third parties related to removal of PSIA from base rates | -14,200,000 | -14,200,000 | 0 | ||||||||||||||||||||||||||||
Public Utilities, Rate increase (decrease) recommended by third parties | -15,300,000 | 1,200,000 | 29,200,000 | ||||||||||||||||||||||||||||
Public Utilities, Adjustment to requested rate increase (decrease) requested by third parties related to neutralization of PSIA - base rate transfer | 14,200,000 | 14,200,000 | -14,200,000 | ||||||||||||||||||||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount | 44,800,000 | 9,000,000 | 10,900,000 | ||||||||||||||||||||||||||||
Public Utilities, Adjustment for historic test year | -1,600,000 | -1,600,000 | -1,600,000 | ||||||||||||||||||||||||||||
Public Utilities, Return on equity used in weather normalized earnings test | 10.00% | ||||||||||||||||||||||||||||||
Public Utilities, Refund to customers due to weather normalized earnings test | 8,200,000 | ||||||||||||||||||||||||||||||
Return on equity for third parties, lower bound | 10.10% | ||||||||||||||||||||||||||||||
Public Utilities, Initial percentage of margin associated with stand alone REC transactions | 20.00% | 80.00% | |||||||||||||||||||||||||||||
Public Utilities, Ultimate percentage of margin associated with stand alone REC transactions | 10.00% | 90.00% | |||||||||||||||||||||||||||||
Public Utilities, Margin threshold determining percentage of margin sharing | 20,000,000 | ||||||||||||||||||||||||||||||
Public Utilities, Percentage of margin on hybrid REC approved for first 20 million of margins | 20.00% | 80.00% | |||||||||||||||||||||||||||||
Public Utilities, Percentage of margin on hybrid REC approved for margins in excess of 20 million | 10.00% | 90.00% | |||||||||||||||||||||||||||||
Public Utilities, Customers share of margins credited against RESA regulatory asset balance | 6,100,000 | 6,200,000 | |||||||||||||||||||||||||||||
Public Utilities, Cumulative credit against RESA regulatory asset balance | 99,400,000 | 82,800,000 | |||||||||||||||||||||||||||||
Return on equity for third parties, upper bound | 10.40% | ||||||||||||||||||||||||||||||
Proposed return on equity recommended by third parties | 9.04% | ||||||||||||||||||||||||||||||
Potential prospective annual revenue increase (decrease) | -2,000,000 | ||||||||||||||||||||||||||||||
Proposed transfer between ECA and RESA deferred accounts | 26,200,000 | ||||||||||||||||||||||||||||||
Proposed Amortization Period For Recovery Of Deferred Costs | 12 | ||||||||||||||||||||||||||||||
Interest Expense, Other | $2,600,000 |
Rate_Matters_SPS_Details
Rate Matters, SPS (Details) (SPS, USD $) | 0 Months Ended | 1 Months Ended | 0 Months Ended | 1 Months Ended | 0 Months Ended | ||||||||||||||
Mar. 29, 2013 | Sep. 21, 2013 | Nov. 30, 2012 | Jun. 30, 2013 | Jun. 30, 2013 | Aug. 31, 2013 | Dec. 31, 2012 | Sep. 09, 2013 | Jun. 19, 2013 | Aug. 31, 2013 | Aug. 31, 2013 | Aug. 31, 2013 | Aug. 31, 2013 | Sep. 21, 2013 | Sep. 12, 2013 | Sep. 12, 2013 | Sep. 21, 2013 | |||
Certain Texas Transmission Assets [Member] | Public Utility Commission of Texas [Member] | Public Utility Commission of Texas [Member] | Public Utility Commission of Texas [Member] | Public Utility Commission of Texas [Member] | New Mexico Attorney General [Member] | New Mexico Public Regulation Commission [Member] | New Mexico Public Regulation Commission [Member] | New Mexico Public Regulation Commission [Member] | New Mexico Public Regulation Commission [Member] | Federal Energy Regulatory Commission (FERC) [Member] | Federal Energy Regulatory Commission (FERC) [Member] | Federal Energy Regulatory Commission (FERC) [Member] | Customers [Member] | Customers [Member] | Customers [Member] | Shareholders [Member] | |||
Facility | Certain Texas Transmission Assets [Member] | Electric Rate Case 2012 [Member] | Electric Rate Case 2012, Settlement Rates Effective May 1, 2013 [Member] | Electric Rate Case 2012, Settlement Rates Effective September 1, 2013 [Member] | 2014 Electric Rate Case [Member] | Electric Rate Case 2012 [Member] | 2014 Electric Rate Case [Member] | 2014 Electric Rate Case [Member] | 2014 Electric Rate Case [Member] | Federal Energy Regulatory Commission (FERC) Orders [Member] | FERC Orders, Settlement Impact Through May 31, 2015 [Member] | FERC Orders, Settlement Impact Effective June 1, 2015 [Member] | Public Utility Commission of Texas [Member] | New Mexico Attorney General [Member] | New Mexico Public Regulation Commission [Member] | Public Utility Commission of Texas [Member] | |||
Factor | Certain Texas Transmission Assets [Member] | Certain Texas Transmission Assets [Member] | Certain Texas Transmission Assets [Member] | Certain Texas Transmission Assets [Member] | |||||||||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||||||||||||
Public utilities, ROE recommended by third parties | 8.63% | 9.80% | |||||||||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $90,200,000 | $45,900,000 | |||||||||||||||||
Public Utilities, Number of months included in test year for rate filing | 12 months | ||||||||||||||||||
Public Utilities, Requested Return on Equity, Percentage | 10.65% | 10.65% | 10.25% | ||||||||||||||||
Public utilities, portion of revised rate increase (decrease) related to base and fuel revenue. | 20,900,000 | ||||||||||||||||||
Public utilities, portion of revised rate increase (decrease) related to rider revenue | 12,100,000 | ||||||||||||||||||
Public utilities, portion of revised rate increase (decrease) related to other costs | -500,000 | ||||||||||||||||||
Number of components included in regulatory proceeding | 2 | ||||||||||||||||||
Number of coincident peaks used as demand allocator, original | 12 | ||||||||||||||||||
Public utilities, estimated refund to customers resulting from regulatory proceedings | 42,000,000 | ||||||||||||||||||
Number of coincident peaks used as demand allocator, revised | 3 | ||||||||||||||||||
Public Utilities, Requested Rate Base, Amount | 1,150,000,000 | 479,800,000 | |||||||||||||||||
Public Utilities, Requested Equity Capital Structure, Percentage | 52.00% | 53.89% | |||||||||||||||||
Public Utilities, Approved Rate Increase (Decrease), Amount | 37,000,000 | 13,800,000 | |||||||||||||||||
Public Utilities, Adjustment to requested rate increase (decrease) requested by third parties related to other costs | -6,600,000 | -5,000,000 | |||||||||||||||||
Public utilities, adjustment to requested rate increase (decrease) recommended by third parties related to fuel clause revenue | 0 | 6,000,000 | |||||||||||||||||
Public utilities, adjustment to requested rate increase (decrease) recommended by third parties related to gain on sale of assets | -1,700,000 | 0 | |||||||||||||||||
Public utilities, adjustment to requested rate increase (decrease) recommended by third parties related to reduced recovery for payroll expense | -100,000 | -100,000 | |||||||||||||||||
Public Utilities, Adjustment to requested rate increase (decrease) requested by third parties related to reduced recovery for employee benefits | -1,800,000 | -2,800,000 | |||||||||||||||||
Public utilities, adjustment to requested rate increase (decrease) related to change in capital structure | -1,100,000 | -1,500,000 | |||||||||||||||||
Public utilities, adjustment to requested rate increase (decrease) recommended by third parties related to the rate rider for renewable energy costs | -8,500,000 | [1] | -14,500,000 | [1] | |||||||||||||||
Public Utilities, Adjustment to requested rate increase (decrease) requested by third parties related to revenue adjustments | -6,400,000 | -4,400,000 | |||||||||||||||||
Public Utilities, Adjustment recommended by third parties related to return on equity | -8,100,000 | -3,200,000 | |||||||||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount | 32,500,000 | 43,300,000 | |||||||||||||||||
Number of substations included in purchase and sale agreement | 2 | ||||||||||||||||||
Proceeds from Sale of Property, Plant, and Equipment | 37,000,000 | ||||||||||||||||||
Public utilities, portion of rate increase (decrease) recommended by third parties to be recovered in base revenue | -6,000,000 | 8,800,000 | |||||||||||||||||
Public utilities, portion of rate increase (decrease) recommended by third parties to be recovered in rider revenue | 13,300,000 | 7,300,000 | |||||||||||||||||
Public utilities, portion of rate increase (decrease) recommended by third parties to be recovered in fuel cost adjustment revenue | 1,700,000 | 1,700,000 | |||||||||||||||||
Current year pre-tax earnings impact of regulatory proceedings | -35,000,000 | ||||||||||||||||||
Public utilities, annual increase (decrease) in revenues resulting from regualtory proceeding | -6,000,000 | -4,000,000 | |||||||||||||||||
Amount of the net pre-tax gain allocable to the Texas retail jurisdiction | 45.00% | ||||||||||||||||||
Percentage of net pre-tax gain associated with the Texas retail jurisdiction to be allocated | 60.00% | 40.00% | |||||||||||||||||
Percentage of net pre-tax gain allocable to the New Mexico jurisdiction to be retained by customers | 100.00% | 100.00% | |||||||||||||||||
Public Utilities, Rate increase (decrease) recommended by third parties | $9,000,000 | $17,800,000 | |||||||||||||||||
[1] | Adjustments represent recommended deferrals, extended amortizations and moving costs from rider to fuel in base rates. |
Commitments_and_Contingencies_1
Commitments and Contingencies, Purchased Power Agreements (Details) (Independent Power Producing Entities) | Sep. 30, 2013 | Dec. 31, 2012 |
MW | MW | |
Independent Power Producing Entities | ||
Purchased Power Agreements [Abstract] | ||
Generating capacity (in MW) | 3,338 | 3,324 |
Commitments_and_Contingencies_2
Commitments and Contingencies, Guarantees and Indemnifications (Details) (USD $) | Sep. 30, 2013 | Dec. 31, 2012 |
Guarantees [Abstract] | ||
Assets held as collateral | $0 | $0 |
Payment or Performance Guarantee | ||
Guarantees [Abstract] | ||
Guarantees issued and outstanding | 54,800,000 | 69,500,000 |
Current exposure under these guarantees | 17,800,000 | 17,900,000 |
Payment or Performance Guarantee | Surety Bonds | ||
Guarantees [Abstract] | ||
Guarantees issued and outstanding | $31,900,000 | $29,600,000 |
Commitments_and_Contingencies_3
Commitments and Contingencies, Environmental Contingencies - Site Contingencies (Details) (NSP-Wisconsin [Member], USD $) | 9 Months Ended | |
In Millions, unless otherwise specified | Sep. 30, 2013 | Dec. 31, 2012 |
Site | ||
Ashland MGP Site | ||
Ashland Manufactured Gas Plant (MGP) Site [Abstract] | ||
Number of properties included in superfund site which NSP-Wisconsin does not own | 2 | |
Liability for estimated cost of remediating sites | $101.20 | $103.70 |
Liability for estimated cost of remediating sites, current | 19.5 | 20.1 |
Amortization period for recovery of remediation costs in natural gas rates, low end of range (in years) | 4 years | |
Amortization period for recovery of remediation costs in natural gas rates, high end of range (in years) | 6 years | |
Ashland MGP Site - Phase I Project Area | ||
Ashland Manufactured Gas Plant (MGP) Site [Abstract] | ||
Liability for estimated cost of remediating sites | 40 | |
Number of acres of land conveyed to the State of Wisconsin and tribal trustees (in acres) | 1,390 | |
Approved amortization period for recovery of remediation costs in natural gas rates (in years) | 10 years | |
Carrying cost percentage to be applied to the unamortized regulatory asset for MGP remediation (in hundredths) | 3.00% | |
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 (in hundredths) | 50.00% | |
Potential percent of decrease to the low end of the range of estimated site remediation costs (in hundredths) | 30.00% |
Commitments_and_Contingencies_4
Commitments and Contingencies, Environmental Contingencies - Unrecorded Unconditional Purchase Obligation (Details) (USD $) | Jun. 30, 2013 | Dec. 31, 2010 | Sep. 30, 2013 | Sep. 30, 2013 |
In Millions, unless otherwise specified | Federal Clean Water Act | PSCo | Capital Addition Purchase Commitments | Capital Addition Purchase Commitments |
Regulation | Regional Haze Rules | PSCo | NSP-Minnesota | |
Group | Regional Haze Rules | Regional Haze Rules | ||
Boiler | ||||
Kiln | ||||
Environmental Requirements [Abstract] | ||||
Number of potential regulatory options under the proposed Effluent Limitations Guidelines rule | 4 | |||
Liability for estimated cost to comply with regulation | $343 | $50 | ||
Number of environmental groups who petitioned the U.S. Department of the Interior | 2 | |||
Number of coal-fired boilers in Colorado | 12 | |||
Number of coal-fired cement kilns in Colorado | 1 | |||
Estimated amount spent on projects to reduce NOx emissions on Sherco Units 1 and 2 | $37 |
Commitments_and_Contingencies_5
Commitments and Contingencies, Legal Contingencies (Details) (USD $) | 3 Months Ended | 9 Months Ended | 9 Months Ended | 1 Months Ended | 13 Months Ended | ||||||||||||||||||
Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | 31-May-11 | Sep. 30, 2013 | Sep. 30, 2013 | 31-May-11 | Apr. 30, 2011 | Mar. 31, 2011 | Dec. 31, 2012 | Oct. 31, 2012 | Mar. 31, 2012 | Aug. 31, 2011 | Jul. 31, 2011 | Sep. 30, 2007 | Sep. 30, 2013 | Aug. 31, 2013 | 15-May-13 | Sep. 30, 2013 | Jun. 30, 2001 | Sep. 30, 2013 | |
Comer vs. Xcel Energy Inc. et al. [Member] | Comer vs. Xcel Energy Inc. et al. [Member] | Pacific Northwest FERC Refund Proceeding [Member] | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | SPS | PSCo | PSCo | |||||
Counterparty | Factor | Merricourt Wind Project Litigation [Member] | Merricourt Wind Project Litigation [Member] | Merricourt Wind Project Litigation [Member] | Merricourt Wind Project Litigation [Member] | Nuclear Waste Disposal Litigation [Member] | Nuclear Waste Disposal Litigation [Member] | Nuclear Waste Disposal Litigation [Member] | Nuclear Waste Disposal Litigation [Member] | Nuclear Waste Disposal Litigation [Member] | Nuclear Waste Disposal Litigation [Member] | Nuclear Waste Disposal Litigation [Member] | Nuclear Waste Disposal Litigation [Member] | Nuclear Waste Disposal Litigation [Member] | Exelon Wind Complaint [Member] | Pacific Northwest FERC Refund Proceeding [Member] | Pacific Northwest FERC Refund Proceeding [Member] | ||||||
MW | Site | ||||||||||||||||||||||
Dispute | |||||||||||||||||||||||
Legal Contingencies [Abstract] | |||||||||||||||||||||||
Accrual for legal contingency | $0 | $0 | $0 | $0 | |||||||||||||||||||
Minimum number of utility, oil, chemical and coal companies against which a lawsuit was filed in U.S. District Court in Mississippi | 85 | ||||||||||||||||||||||
Generating capacity (in MW) | 150 | ||||||||||||||||||||||
Merricourt deposit | 101,000,000 | ||||||||||||||||||||||
Minimum amount of damages claimed by plaintiff | 240,000,000 | 34,000,000 | |||||||||||||||||||||
Number of main areas of dispute | 2 | ||||||||||||||||||||||
Number of wind facilities | 12 | ||||||||||||||||||||||
Sales to the City of Seattle | 2,822,338,000 | 2,724,341,000 | 8,184,100,000 | 7,577,088,000 | 50,000,000 | ||||||||||||||||||
Estimated City of Seattle's claim for refunds not including interest | 28,000,000 | ||||||||||||||||||||||
Number of factors considered in assessment | 2 | ||||||||||||||||||||||
Damages awarded | 116,500,000 | ||||||||||||||||||||||
Storage costs for spent nuclear fuel | 100,000,000 | ||||||||||||||||||||||
Cash payment received under settlement agreement | 20,700,000 | 18,600,000 | 100,000,000 | 100,000,000 | |||||||||||||||||||
Claim submitted for storage costs for spent nuclear fuel | 42,800,000 | ||||||||||||||||||||||
Recommended payment for claim submitted, estimated storage costs of spent nuclear fuel | 42,600,000 | ||||||||||||||||||||||
Minnesota retail portion of the Department of Energy settlement required to be placed into the nuclear decommissioning fund | $15,300,000 |
Borrowings_and_Other_Financing2
Borrowings and Other Financing Instruments, Commercial Paper (Details) (USD $) | 3 Months Ended | 12 Months Ended |
Sep. 30, 2013 | Dec. 31, 2012 | |
Commercial Paper [Abstract] | ||
Borrowing limit | $2,450,000,000 | $2,450,000,000 |
Amount outstanding at period end | 302,000,000 | 602,000,000 |
Average amount outstanding | 347,000,000 | 403,000,000 |
Maximum amount outstanding | $491,000,000 | $634,000,000 |
Weighted average interest rate, computed on a daily basis (in hundredths) | 0.27% | 0.35% |
Weighted average interest rate at period end (in hundredths) | 0.25% | 0.36% |
Borrowings_and_Other_Financing3
Borrowings and Other Financing Instruments, Letters of Credit (Details) (USD $) | 9 Months Ended | |
In Millions, unless otherwise specified | Sep. 30, 2013 | Dec. 31, 2012 |
Letters of Credit [Abstract] | ||
Terms of letters of credit (in years) | 1 year | |
Letters of credit outstanding under credit facilities | $18.80 | $14.20 |
Borrowings_and_Other_Financing4
Borrowings and Other Financing Instruments, Credit Facilities (Details) (USD $) | Sep. 30, 2013 | Dec. 31, 2012 | |
Credit Facilities [Abstract] | |||
Credit facility | $2,450,000,000 | [1] | |
Drawn | 320,800,000 | [2] | |
Available | 2,129,200,000 | ||
Credit facility bank borrowings outstanding | 0 | 0 | |
Xcel Energy Inc. | |||
Credit Facilities [Abstract] | |||
Credit facility | 800,000,000 | [1] | |
Drawn | 258,000,000 | [2] | |
Available | 542,000,000 | ||
PSCo | |||
Credit Facilities [Abstract] | |||
Credit facility | 700,000,000 | [1] | |
Drawn | 6,900,000 | [2] | |
Available | 693,100,000 | ||
NSP-Minnesota | |||
Credit Facilities [Abstract] | |||
Credit facility | 500,000,000 | [1] | |
Drawn | 44,900,000 | [2] | |
Available | 455,100,000 | ||
SPS | |||
Credit Facilities [Abstract] | |||
Credit facility | 300,000,000 | [1] | |
Drawn | 0 | [2] | |
Available | 300,000,000 | ||
NSP-Wisconsin [Member] | |||
Credit Facilities [Abstract] | |||
Credit facility | 150,000,000 | [1] | |
Drawn | 11,000,000 | [2] | |
Available | $139,000,000 | ||
[1] | These credit facilities expire in July 2017. | ||
[2] | Includes outstanding commercial paper and letters of credit. |
Borrowings_and_Other_Financing5
Borrowings and Other Financing Instruments, Long-Term Borrowings and Other Financing Instruments (Details) (USD $) | 1 Months Ended | ||||||
Mar. 31, 2013 | Mar. 31, 2013 | 31-May-13 | 31-May-13 | Aug. 31, 2013 | Sep. 30, 2013 | Dec. 31, 2012 | |
PSCo | PSCo | Xcel Energy Inc. | NSP-Minnesota | SPS | SPS | SPS | |
First Mortgage Bonds | First Mortgage Bonds | Senior Unsecured Notes | First Mortgage Bonds | First Mortgage Bonds | First Mortgage Bonds | First Mortgage Bonds | |
Series Due March 15, 2023 | Series Due March 15, 2043 | Series Due May 9, 2016 | Series Due May 15, 2023 | Series Due Aug. 15, 2041 | Series Due Aug. 15, 2041 | Series Due Aug. 15, 2041 | |
Long-Term Borrowings and Other Financing Instruments [Abstract] | |||||||
Face amount | $250,000,000 | $250,000,000 | $450,000,000 | $400,000,000 | $100,000,000 | ||
Interest rate, stated percentage (in hundredths) | 2.50% | 3.95% | 0.75% | 2.60% | 4.50% | ||
Maturity date | 15-Mar-23 | 15-Mar-43 | 9-May-16 | 15-May-23 | 15-Aug-41 | ||
Principal outstanding | $400,000,000 | $300,000,000 |
Borrowings_and_Other_Financing6
Borrowings and Other Financing Instruments, Issuances of Common Stock (Details) (At-the-Market Program, USD $) | 1 Months Ended | 3 Months Ended |
Mar. 31, 2013 | Sep. 30, 2013 | |
At-the-Market Program | ||
Issuances of Common Stock [Abstract] | ||
Maximum aggregate gross sales price of common stock that can be offered and sold | $400,000,000 | |
Issuances of common stock (in shares) | 0 | |
Shares of common stock issued (in shares) | 7,700,000 | |
Net cash proceeds from issuance of common stock | 223,100,000 | |
Fees and commissions | $2,300,000 |
Borrowings_and_Other_Financing7
Borrowings and Other Financing Instruments, Debt Redemption (Details) (USD $) | 1 Months Ended | 3 Months Ended | 9 Months Ended | ||
31-May-13 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | |
Long-Term Borrowings and Other Financing Instruments [Abstract] | |||||
Interest charges | $6,300,000 | $144,758,000 | $153,719,000 | $431,199,000 | $457,470,000 |
Xcel Energy Inc. | Junior Subordinated Notes | Series Due Jan. 1, 2068 | |||||
Long-Term Borrowings and Other Financing Instruments [Abstract] | |||||
Repurchased debt | $400,000,000 | ||||
Interest rate, stated percentage (in hundredths) | 7.60% |
Fair_Value_of_Financial_Assets2
Fair Value of Financial Assets and Liabilities, Cost and Fair Value of Nuclear Decommissioning Fund (Details) (USD $) | Sep. 30, 2013 | Dec. 31, 2012 | ||
Non-Derivative Instruments Fair Value Measurements [Abstract] | ||||
Nuclear decommissioning fund available-for-sale securities, unrealized gains | $202,400,000 | $135,800,000 | ||
Nuclear decommissioning fund available-for-sale securities, unrealized losses | 65,300,000 | 46,400,000 | ||
Available-for-sale Securities [Abstract] | ||||
Equity investments in unconsolidated subsidiaries | 87,800,000 | 91,200,000 | ||
Miscellaneous investments | 38,600,000 | 37,100,000 | ||
Nuclear Decommissioning Fund | ||||
Available-for-sale Securities, Amortized Cost Basis [Abstract] | ||||
Available-for-sale Securities, Amortized Cost Basis | 1,416,526,000 | [1] | 1,400,145,000 | [2] |
Fair Value Measured on a Recurring Basis | Nuclear Decommissioning Fund | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities | 1,553,592,000 | [1] | 1,489,542,000 | [2] |
Fair Value Measured on a Recurring Basis | Level 1 | Nuclear Decommissioning Fund | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities | 611,292,000 | [1] | 658,201,000 | [2] |
Fair Value Measured on a Recurring Basis | Level 2 | Nuclear Decommissioning Fund | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities | 838,470,000 | [1] | 726,741,000 | [2] |
Fair Value Measured on a Recurring Basis | Level 3 | Nuclear Decommissioning Fund | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities | 103,830,000 | [1] | 104,600,000 | [2] |
Cash equivalents | Nuclear Decommissioning Fund | ||||
Available-for-sale Securities, Amortized Cost Basis [Abstract] | ||||
Available-for-sale Securities, Amortized Cost Basis | 74,103,000 | [1] | 246,904,000 | [2] |
Cash equivalents | Fair Value Measured on a Recurring Basis | Nuclear Decommissioning Fund | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities | 74,103,000 | [1] | 246,904,000 | [2] |
Cash equivalents | Fair Value Measured on a Recurring Basis | Level 1 | Nuclear Decommissioning Fund | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities | 74,103,000 | [1] | 237,938,000 | [2] |
Cash equivalents | Fair Value Measured on a Recurring Basis | Level 2 | Nuclear Decommissioning Fund | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities | 0 | [1] | 8,966,000 | [2] |
Cash equivalents | Fair Value Measured on a Recurring Basis | Level 3 | Nuclear Decommissioning Fund | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities | 0 | [1] | 0 | [2] |
Commingled funds | Nuclear Decommissioning Fund | ||||
Available-for-sale Securities, Amortized Cost Basis [Abstract] | ||||
Available-for-sale Securities, Amortized Cost Basis | 436,533,000 | [1] | 396,681,000 | [2] |
Commingled funds | Fair Value Measured on a Recurring Basis | Nuclear Decommissioning Fund | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities | 438,906,000 | [1] | 417,583,000 | [2] |
Commingled funds | Fair Value Measured on a Recurring Basis | Level 1 | Nuclear Decommissioning Fund | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities | 0 | [1] | 0 | [2] |
Commingled funds | Fair Value Measured on a Recurring Basis | Level 2 | Nuclear Decommissioning Fund | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities | 438,906,000 | [1] | 417,583,000 | [2] |
Commingled funds | Fair Value Measured on a Recurring Basis | Level 3 | Nuclear Decommissioning Fund | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities | 0 | [1] | 0 | [2] |
International equity funds | Nuclear Decommissioning Fund | ||||
Available-for-sale Securities, Amortized Cost Basis [Abstract] | ||||
Available-for-sale Securities, Amortized Cost Basis | 65,529,000 | [1] | 66,452,000 | [2] |
International equity funds | Fair Value Measured on a Recurring Basis | Nuclear Decommissioning Fund | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities | 68,164,000 | [1] | 69,481,000 | [2] |
International equity funds | Fair Value Measured on a Recurring Basis | Level 1 | Nuclear Decommissioning Fund | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities | 0 | [1] | 0 | [2] |
International equity funds | Fair Value Measured on a Recurring Basis | Level 2 | Nuclear Decommissioning Fund | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities | 68,164,000 | [1] | 69,481,000 | [2] |
International equity funds | Fair Value Measured on a Recurring Basis | Level 3 | Nuclear Decommissioning Fund | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities | 0 | [1] | 0 | [2] |
Private equity investments | Nuclear Decommissioning Fund | ||||
Available-for-sale Securities, Amortized Cost Basis [Abstract] | ||||
Available-for-sale Securities, Amortized Cost Basis | 43,286,000 | [1] | 27,943,000 | [2] |
Private equity investments | Fair Value Measured on a Recurring Basis | Nuclear Decommissioning Fund | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities | 52,474,000 | [1] | 33,250,000 | [2] |
Private equity investments | Fair Value Measured on a Recurring Basis | Level 1 | Nuclear Decommissioning Fund | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities | 0 | [1] | 0 | [2] |
Private equity investments | Fair Value Measured on a Recurring Basis | Level 2 | Nuclear Decommissioning Fund | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities | 0 | [1] | 0 | [2] |
Private equity investments | Fair Value Measured on a Recurring Basis | Level 3 | Nuclear Decommissioning Fund | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities | 52,474,000 | [1] | 33,250,000 | [2] |
Real Estate | Nuclear Decommissioning Fund | ||||
Available-for-sale Securities, Amortized Cost Basis [Abstract] | ||||
Available-for-sale Securities, Amortized Cost Basis | 41,645,000 | [1] | 32,561,000 | [2] |
Real Estate | Fair Value Measured on a Recurring Basis | Nuclear Decommissioning Fund | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities | 51,356,000 | [1] | 39,074,000 | [2] |
Real Estate | Fair Value Measured on a Recurring Basis | Level 1 | Nuclear Decommissioning Fund | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities | 0 | [1] | 0 | [2] |
Real Estate | Fair Value Measured on a Recurring Basis | Level 2 | Nuclear Decommissioning Fund | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities | 0 | [1] | 0 | [2] |
Real Estate | Fair Value Measured on a Recurring Basis | Level 3 | Nuclear Decommissioning Fund | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities | 51,356,000 | [1] | 39,074,000 | [2] |
Government Securities | Nuclear Decommissioning Fund | ||||
Available-for-sale Securities, Amortized Cost Basis [Abstract] | ||||
Available-for-sale Debt Securities, Amortized Cost Basis | 34,475,000 | [1] | 21,092,000 | [2] |
Government Securities | Fair Value Measured on a Recurring Basis | Nuclear Decommissioning Fund | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 28,946,000 | [1] | 21,521,000 | [2] |
Government Securities | Fair Value Measured on a Recurring Basis | Level 1 | Nuclear Decommissioning Fund | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 0 | [1] | 0 | [2] |
Government Securities | Fair Value Measured on a Recurring Basis | Level 2 | Nuclear Decommissioning Fund | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 28,946,000 | [1] | 21,521,000 | [2] |
Government Securities | Fair Value Measured on a Recurring Basis | Level 3 | Nuclear Decommissioning Fund | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 0 | [1] | 0 | [2] |
U.S. Corporate Bonds | Nuclear Decommissioning Fund | ||||
Available-for-sale Securities, Amortized Cost Basis [Abstract] | ||||
Available-for-sale Debt Securities, Amortized Cost Basis | 86,719,000 | [1] | 162,053,000 | [2] |
U.S. Corporate Bonds | Fair Value Measured on a Recurring Basis | Nuclear Decommissioning Fund | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 88,561,000 | [1] | 169,488,000 | [2] |
U.S. Corporate Bonds | Fair Value Measured on a Recurring Basis | Level 1 | Nuclear Decommissioning Fund | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 0 | [1] | 0 | [2] |
U.S. Corporate Bonds | Fair Value Measured on a Recurring Basis | Level 2 | Nuclear Decommissioning Fund | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 88,561,000 | [1] | 169,488,000 | [2] |
U.S. Corporate Bonds | Fair Value Measured on a Recurring Basis | Level 3 | Nuclear Decommissioning Fund | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 0 | [1] | 0 | [2] |
International Corporate Bonds | Nuclear Decommissioning Fund | ||||
Available-for-sale Securities, Amortized Cost Basis [Abstract] | ||||
Available-for-sale Debt Securities, Amortized Cost Basis | 15,999,000 | [1] | 15,165,000 | [2] |
International Corporate Bonds | Fair Value Measured on a Recurring Basis | Nuclear Decommissioning Fund | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 15,976,000 | [1] | 16,052,000 | [2] |
International Corporate Bonds | Fair Value Measured on a Recurring Basis | Level 1 | Nuclear Decommissioning Fund | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 0 | [1] | 0 | [2] |
International Corporate Bonds | Fair Value Measured on a Recurring Basis | Level 2 | Nuclear Decommissioning Fund | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 15,976,000 | [1] | 16,052,000 | [2] |
International Corporate Bonds | Fair Value Measured on a Recurring Basis | Level 3 | Nuclear Decommissioning Fund | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 0 | [1] | 0 | [2] |
Municipal Bonds | Nuclear Decommissioning Fund | ||||
Available-for-sale Securities, Amortized Cost Basis [Abstract] | ||||
Available-for-sale Debt Securities, Amortized Cost Basis | 207,417,000 | [1] | 21,392,000 | [2] |
Municipal Bonds | Fair Value Measured on a Recurring Basis | Nuclear Decommissioning Fund | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 197,917,000 | [1] | 23,650,000 | [2] |
Municipal Bonds | Fair Value Measured on a Recurring Basis | Level 1 | Nuclear Decommissioning Fund | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 0 | [1] | 0 | [2] |
Municipal Bonds | Fair Value Measured on a Recurring Basis | Level 2 | Nuclear Decommissioning Fund | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 197,917,000 | [1] | 23,650,000 | [2] |
Municipal Bonds | Fair Value Measured on a Recurring Basis | Level 3 | Nuclear Decommissioning Fund | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 0 | [1] | 0 | [2] |
Asset-backed Securities | Nuclear Decommissioning Fund | ||||
Available-for-sale Securities, Amortized Cost Basis [Abstract] | ||||
Available-for-sale Debt Securities, Amortized Cost Basis | 2,066,000 | [2] | ||
Asset-backed Securities | Fair Value Measured on a Recurring Basis | Nuclear Decommissioning Fund | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 2,067,000 | [2] | ||
Asset-backed Securities | Fair Value Measured on a Recurring Basis | Level 1 | Nuclear Decommissioning Fund | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 0 | [2] | ||
Asset-backed Securities | Fair Value Measured on a Recurring Basis | Level 2 | Nuclear Decommissioning Fund | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 0 | [2] | ||
Asset-backed Securities | Fair Value Measured on a Recurring Basis | Level 3 | Nuclear Decommissioning Fund | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 2,067,000 | [2] | ||
Mortgage-backed Securities | Nuclear Decommissioning Fund | ||||
Available-for-sale Securities, Amortized Cost Basis [Abstract] | ||||
Available-for-sale Debt Securities, Amortized Cost Basis | 28,743,000 | [2] | ||
Mortgage-backed Securities | Fair Value Measured on a Recurring Basis | Nuclear Decommissioning Fund | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 30,209,000 | [2] | ||
Mortgage-backed Securities | Fair Value Measured on a Recurring Basis | Level 1 | Nuclear Decommissioning Fund | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 0 | [2] | ||
Mortgage-backed Securities | Fair Value Measured on a Recurring Basis | Level 2 | Nuclear Decommissioning Fund | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 0 | [2] | ||
Mortgage-backed Securities | Fair Value Measured on a Recurring Basis | Level 3 | Nuclear Decommissioning Fund | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 30,209,000 | [2] | ||
Common stock | Nuclear Decommissioning Fund | ||||
Available-for-sale Securities, Amortized Cost Basis [Abstract] | ||||
Available-for-sale Equity Securities, Amortized Cost Basis | 410,820,000 | [1] | 379,093,000 | [2] |
Common stock | Fair Value Measured on a Recurring Basis | Nuclear Decommissioning Fund | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Equity Securities | 537,189,000 | [1] | 420,263,000 | [2] |
Common stock | Fair Value Measured on a Recurring Basis | Level 1 | Nuclear Decommissioning Fund | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Equity Securities | 537,189,000 | [1] | 420,263,000 | [2] |
Common stock | Fair Value Measured on a Recurring Basis | Level 2 | Nuclear Decommissioning Fund | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Equity Securities | 0 | [1] | 0 | [2] |
Common stock | Fair Value Measured on a Recurring Basis | Level 3 | Nuclear Decommissioning Fund | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Equity Securities | $0 | [1] | $0 | [2] |
[1] | Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $87.8 million of equity investments in unconsolidated subsidiaries and $38.6 million of miscellaneous investments. | |||
[2] | Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $91.2 million of equity investments in unconsolidated subsidiaries and $37.1 million of miscellaneous investments. |
Fair_Value_of_Financial_Assets3
Fair Value of Financial Assets and Liabilities, Changes in Level 3 Nuclear Decommissioning Fund (Details) (USD $) | 3 Months Ended | 9 Months Ended | ||||
In Thousands, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | ||
Changes in Level 3 Nuclear Decommissioning Fund Assets [Roll Forward] | ||||||
Balance at beginning of period | $83,730 | $129,413 | $104,600 | $130,763 | ||
Purchases | 18,078 | 19,664 | 33,450 | 51,279 | ||
Settlements | 0 | -24,862 | -9,022 | -62,505 | ||
Gains (losses) recognized as regulatory assets and liabilities | 2,022 | 4,043 | 7,078 | 8,721 | ||
Transfers out of Level 3 | 0 | [1] | 0 | -32,276 | [1] | 0 |
Balance at end of period | 103,830 | 128,258 | 103,830 | 128,258 | ||
Private equity investments | ||||||
Changes in Level 3 Nuclear Decommissioning Fund Assets [Roll Forward] | ||||||
Balance at beginning of period | 45,590 | 23,303 | 33,250 | 9,203 | ||
Purchases | 6,790 | 0 | 15,344 | 13,390 | ||
Settlements | 0 | -1,931 | 0 | -1,931 | ||
Gains (losses) recognized as regulatory assets and liabilities | 94 | 2,701 | 3,880 | 3,411 | ||
Transfers out of Level 3 | 0 | 0 | 0 | [1] | 0 | |
Balance at end of period | 52,474 | 24,073 | 52,474 | 24,073 | ||
Real Estate | ||||||
Changes in Level 3 Nuclear Decommissioning Fund Assets [Roll Forward] | ||||||
Balance at beginning of period | 38,140 | 32,721 | 39,074 | 26,395 | ||
Purchases | 11,288 | 2,882 | 18,106 | 6,789 | ||
Settlements | 0 | -1,165 | -9,022 | -2,931 | ||
Gains (losses) recognized as regulatory assets and liabilities | 1,928 | 795 | 3,198 | 4,980 | ||
Transfers out of Level 3 | 0 | 0 | 0 | [1] | 0 | |
Balance at end of period | 51,356 | 35,233 | 51,356 | 35,233 | ||
Asset-backed Securities | ||||||
Changes in Level 3 Nuclear Decommissioning Fund Assets [Roll Forward] | ||||||
Balance at beginning of period | 7,068 | 2,067 | 16,501 | |||
Purchases | 0 | 0 | 0 | |||
Settlements | -2,085 | 0 | -11,544 | |||
Gains (losses) recognized as regulatory assets and liabilities | 12 | 0 | 38 | |||
Transfers out of Level 3 | 0 | -2,067 | [1] | 0 | ||
Balance at end of period | 0 | 4,995 | 0 | 4,995 | ||
Mortgage-backed Securities | ||||||
Changes in Level 3 Nuclear Decommissioning Fund Assets [Roll Forward] | ||||||
Balance at beginning of period | 66,321 | 30,209 | 78,664 | |||
Purchases | 16,782 | 0 | 31,100 | |||
Settlements | -19,681 | 0 | -46,099 | |||
Gains (losses) recognized as regulatory assets and liabilities | 535 | 0 | 292 | |||
Transfers out of Level 3 | 0 | -30,209 | [1] | 0 | ||
Balance at end of period | $0 | $63,957 | $0 | $63,957 | ||
[1] | Transfers out of Level 3 into Level 2 were principally due to diminished use of unobservable inputs that were previously significant to these fair value measurements. |
Fair_Value_of_Financial_Assets4
Fair Value of Financial Assets and Liabilities, Final Contractual Maturity Dates of Debt Securities in Nuclear Decommissioning Fund (Details) (USD $) | Sep. 30, 2013 |
In Thousands, unless otherwise specified | |
Final Contractual Maturity [Abstract] | |
Due in 1 Year or Less | $3,424 |
Due in 1 to 5 Years | 49,543 |
Due in 5 to 10 Years | 103,345 |
Due after 10 Years | 175,088 |
Total | 331,400 |
Government 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 | 28,946 |
Total | 28,946 |
U.S. Corporate Bonds | |
Final Contractual Maturity [Abstract] | |
Due in 1 Year or Less | 306 |
Due in 1 to 5 Years | 21,488 |
Due in 5 to 10 Years | 64,953 |
Due after 10 Years | 1,814 |
Total | 88,561 |
International Corporate Bonds | |
Final Contractual Maturity [Abstract] | |
Due in 1 Year or Less | 0 |
Due in 1 to 5 Years | 4,506 |
Due in 5 to 10 Years | 11,470 |
Due after 10 Years | 0 |
Total | 15,976 |
Municipal Bonds | |
Final Contractual Maturity [Abstract] | |
Due in 1 Year or Less | 3,118 |
Due in 1 to 5 Years | 23,549 |
Due in 5 to 10 Years | 26,922 |
Due after 10 Years | 144,328 |
Total | $197,917 |
Fair_Value_of_Financial_Assets5
Fair Value of Financial Assets and Liabilities, Derivative Instruments (Details) (USD $) | Sep. 30, 2013 | Dec. 31, 2012 | ||
In Millions, unless otherwise specified | MWh | MWh | ||
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 [Member] | ||||
Consideration of Credit Risk and Concentrations [Abstract] | ||||
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure | 10 | |||
Credit Concentration Risk [Member] | Investment Grade Ratings from Standard & Poor's, Moody's, or Fitch Ratings [Member] | ||||
Consideration of Credit Risk and Concentrations [Abstract] | ||||
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure | 4 | |||
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties | 70.6 | |||
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths) | 23.00% | |||
Credit Concentration Risk [Member] | 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 | 5 | |||
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties | 89.4 | |||
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths) | 29.00% | |||
Credit Concentration Risk [Member] | 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 | 1 | |||
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties | 9.4 | |||
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths) | 3.00% | |||
Interest Rate Swap [Member] | ||||
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 | -2.3 | |||
Electric Commodity [Member] | ||||
Gross Notional Amounts of Commodity Forwards, Options and FTRs [Abstract] | ||||
Notional amount | 69,682,000 | [1],[2] | 55,976,000 | [1],[2] |
Natural Gas Commodity [Member] | ||||
Gross Notional Amounts of Commodity Forwards, Options and FTRs [Abstract] | ||||
Notional amount | 11,752,000 | [1],[2] | 725,000 | [1],[2] |
Vehicle Fuel Commodity [Member] | ||||
Gross Notional Amounts of Commodity Forwards, Options and FTRs [Abstract] | ||||
Notional amount | 532,000 | [1],[2] | 682,000 | [1],[2] |
[1] | Notional amounts for options are included on a gross basis, but are weighted for the probability of exercise. | |||
[2] | Amounts are not reflective of net positions in the underlying commodities. |
Fair_Value_of_Financial_Assets6
Fair Value of Financial Assets and Liabilities, Financial Impact of Qualifying Cash Flow Hedges (Details) (USD $) | 3 Months Ended | 9 Months Ended | ||
In Thousands, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 |
Financial Impact of Qualifying Cash Flow Hedges on Accumulated Other Comprehensive Income (Loss) [Roll Forward] | ||||
Accumulated other comprehensive loss related to cash flow hedges at beginning of period | ($60,883) | ($55,710) | ($61,241) | ($45,738) |
After-tax net unrealized gains (losses) related to derivatives accounted for as hedges | 22 | -8,853 | -9 | -19,188 |
After-tax net realized losses on derivative transactions reclassified into earnings | 539 | 393 | 928 | 756 |
Accumulated other comprehensive loss related to cash flow hedges at end of period | ($60,322) | ($64,170) | ($60,322) | ($64,170) |
Fair_Value_of_Financial_Assets7
Fair Value of Financial Assets and Liabilities, Impact of Derivative Activity (Details) (USD $) | 3 Months Ended | 9 Months Ended | ||||||
Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | |||||
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 | ||||
Cash Flow Hedges [Member] | ||||||||
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 | 36,000 | -14,766,000 | -11,000 | -31,774,000 | ||||
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 | 805,000 | 689,000 | 3,073,000 | 1,366,000 | ||||
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 | ||||
Cash Flow Hedges [Member] | Interest Rate [Member] | ||||||||
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 | -14,923,000 | 0 | -31,914,000 | ||||
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 | 829,000 | [1] | 733,000 | [1] | 3,140,000 | [1] | 1,511,000 | [1] |
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 | ||||
Cash Flow Hedges [Member] | Vehicle Fuel And Other Commodity [Member] | ||||||||
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 | 36,000 | 157,000 | -11,000 | 140,000 | ||||
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 | -24,000 | [2] | -44,000 | [2] | -67,000 | [2] | -145,000 | [2] |
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 [Member] | ||||||||
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 | -1,046,000 | 5,116,000 | 55,973,000 | 34,974,000 | ||||
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) | -9,823,000 | -11,931,000 | -38,807,000 | 51,323,000 | ||||
Pre-tax gains (losses) recognized during the period in income | 7,106,000 | 7,651,000 | 9,156,000 | 10,854,000 | ||||
Other Derivative Instruments [Member] | Commodity Trading [Member] | ||||||||
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 | 7,094,000 | [3] | 7,651,000 | [3] | 9,372,000 | [3] | 10,963,000 | [3] |
Other Derivative Instruments [Member] | Electric Commodity [Member] | ||||||||
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 | 921,000 | 3,923,000 | 61,314,000 | 43,679,000 | ||||
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) | -9,823,000 | [4] | -11,931,000 | [4] | -38,816,000 | [4] | -29,616,000 | [4] |
Pre-tax gains (losses) recognized during the period in income | 0 | 0 | 0 | 0 | ||||
Other Derivative Instruments [Member] | Natural Gas Commodity [Member] | ||||||||
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 | -1,967,000 | 1,193,000 | -5,341,000 | -8,705,000 | ||||
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 | 0 | 9,000 | [5] | 80,939,000 | [5] | ||
Pre-tax gains (losses) recognized during the period in income | 12,000 | [4] | 0 | -216,000 | [4] | -109,000 | [4] | |
Other Derivative Instruments [Member] | Natural Gas Commodity for Electric Generation [Member] | ||||||||
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract] | ||||||||
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities) | $5,000,000 | |||||||
[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 gains and losses 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 nine months ended Sept. 30, 2012 included $5.0 million 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. Such losses for the nine months ended Sept. 30, 2013 were immaterial. The remaining settlement losses for the nine months ended Sept. 30, 2013 and 2012 relate to natural gas operations and are recorded to cost of natural gas sold and transported. These losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset, as appropriate. |
Fair_Value_of_Financial_Assets8
Fair Value of Financial Assets and Liabilities, Credit Related Contingent Features (Details) (USD $) | Sep. 30, 2013 | Dec. 31, 2012 |
Fair Value Disclosures [Abstract] | ||
Derivative instruments in a gross liability position | $2,700,000 | $4,600,000 |
Payments required if credit ratings were downgraded below investment grade | 2,700,000 | 4,600,000 |
Collateral posted on derivative instruments | 0 | 0 |
Collateral posted related to adequate assurance clauses in derivative contracts | $0 | $0 |
Fair_Value_of_Financial_Assets9
Fair Value of Financial Assets and Liabilities, Derivative Assets and Liabilities at Fair Value (Details) (USD $) | Sep. 30, 2013 | Dec. 31, 2012 | ||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Collateral, Right to Reclaim Cash, Offset | $3,600,000 | $3,000,000 | ||
Derivative Asset, Collateral, Obligation to Return Cash, Offset | 400,000 | 600,000 | ||
Fair Value Measured on a Recurring Basis | Other Current Assets [Member] | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | 92,687,000 | 69,013,000 | ||
Fair Value Measured on a Recurring Basis | Other Current Assets [Member] | Purchased Power Agreements [Member] | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | 33,028,000 | [1] | 32,717,000 | [1] |
Fair Value Measured on a Recurring Basis | Other Current Assets [Member] | Designated as Hedging Instrument [Member] | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | 59,659,000 | 36,296,000 | ||
Fair Value Measured on a Recurring Basis | Other Current Assets [Member] | Designated as Hedging Instrument [Member] | Vehicle Fuel And Other Commodity [Member] | Cash Flow Hedges [Member] | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | 72,000 | 95,000 | ||
Fair Value Measured on a Recurring Basis | Other Current Assets [Member] | Designated as Hedging Instrument [Member] | Commodity Trading | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | 16,764,000 | 20,320,000 | ||
Fair Value Measured on a Recurring Basis | Other Current Assets [Member] | Designated as Hedging Instrument [Member] | Electric Commodity [Member] | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | 38,380,000 | 15,881,000 | ||
Fair Value Measured on a Recurring Basis | Other Current Assets [Member] | Designated as Hedging Instrument [Member] | Natural Gas Commodity [Member] | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | 4,443,000 | 0 | ||
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets [Member] | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | 95,894,000 | 126,297,000 | ||
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets [Member] | Purchased Power Agreements [Member] | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | 66,610,000 | [1] | 89,061,000 | [1] |
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets [Member] | Designated as Hedging Instrument [Member] | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | 29,284,000 | 37,236,000 | ||
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets [Member] | Designated as Hedging Instrument [Member] | Vehicle Fuel And Other Commodity [Member] | Cash Flow Hedges [Member] | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | 12,000 | 39,000 | ||
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets [Member] | Designated as Hedging Instrument [Member] | Commodity Trading | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | 29,272,000 | 37,197,000 | ||
Fair Value Measured on a Recurring Basis | Other Current Liabilities [Member] | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Fair Value, Gross Liability | 26,729,000 | 32,482,000 | ||
Fair Value Measured on a Recurring Basis | Other Current Liabilities [Member] | Purchased Power Agreements [Member] | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Fair Value, Gross Liability | 23,103,000 | [1] | 22,880,000 | [1] |
Fair Value Measured on a Recurring Basis | Other Current Liabilities [Member] | Designated as Hedging Instrument [Member] | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Fair Value, Gross Liability | 3,626,000 | 9,602,000 | ||
Fair Value Measured on a Recurring Basis | Other Current Liabilities [Member] | Designated as Hedging Instrument [Member] | Commodity Trading | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Fair Value, Gross Liability | 3,626,000 | 9,511,000 | ||
Fair Value Measured on a Recurring Basis | Other Current Liabilities [Member] | Designated as Hedging Instrument [Member] | Electric Commodity [Member] | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Fair Value, Gross Liability | 0 | 0 | ||
Fair Value Measured on a Recurring Basis | Other Current Liabilities [Member] | Designated as Hedging Instrument [Member] | Natural Gas Commodity [Member] | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Fair Value, Gross Liability | 91,000 | |||
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities [Member] | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Fair Value, Gross Liability | 217,027,000 | 242,866,000 | ||
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities [Member] | Purchased Power Agreements [Member] | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Fair Value, Gross Liability | 209,581,000 | [1] | 225,659,000 | [1] |
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities [Member] | Designated as Hedging Instrument [Member] | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Fair Value, Gross Liability | 7,446,000 | 17,207,000 | ||
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities [Member] | Designated as Hedging Instrument [Member] | Commodity Trading | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Fair Value, Gross Liability | 7,446,000 | 17,207,000 | ||
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets [Member] | Designated as Hedging Instrument [Member] | ||||
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 [Member] | Designated as Hedging Instrument [Member] | Vehicle Fuel And Other Commodity [Member] | Cash Flow Hedges [Member] | ||||
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 [Member] | Designated as Hedging Instrument [Member] | Commodity Trading | ||||
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 [Member] | Designated as Hedging Instrument [Member] | Electric Commodity [Member] | ||||
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 [Member] | Designated as Hedging Instrument [Member] | Natural Gas Commodity [Member] | ||||
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 [Member] | Designated as Hedging Instrument [Member] | ||||
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 [Member] | Designated as Hedging Instrument [Member] | Vehicle Fuel And Other Commodity [Member] | Cash Flow Hedges [Member] | ||||
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 [Member] | Designated as Hedging Instrument [Member] | Commodity Trading | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 | ||
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities [Member] | Designated as Hedging Instrument [Member] | ||||
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 [Member] | Designated as Hedging Instrument [Member] | Commodity Trading | ||||
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 [Member] | Designated as Hedging Instrument [Member] | Electric Commodity [Member] | ||||
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 [Member] | Designated as Hedging Instrument [Member] | Natural Gas Commodity [Member] | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Fair Value, Gross Liability | 0 | |||
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Liabilities [Member] | Designated as Hedging Instrument [Member] | ||||
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 [Member] | Designated as Hedging Instrument [Member] | Commodity Trading | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Fair Value, Gross Liability | 0 | 0 | ||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets [Member] | Designated as Hedging Instrument [Member] | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | 27,627,000 | 26,405,000 | ||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets [Member] | Designated as Hedging Instrument [Member] | Vehicle Fuel And Other Commodity [Member] | Cash Flow Hedges [Member] | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | 72,000 | 95,000 | ||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets [Member] | Designated as Hedging Instrument [Member] | Commodity Trading | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | 23,112,000 | 26,303,000 | ||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets [Member] | Designated as Hedging Instrument [Member] | Electric Commodity [Member] | ||||
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 [Member] | Designated as Hedging Instrument [Member] | Natural Gas Commodity [Member] | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | 4,443,000 | 7,000 | ||
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Assets [Member] | Designated as Hedging Instrument [Member] | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | 33,889,000 | 41,368,000 | ||
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Assets [Member] | Designated as Hedging Instrument [Member] | Vehicle Fuel And Other Commodity [Member] | Cash Flow Hedges [Member] | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | 27,000 | 86,000 | ||
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Assets [Member] | Designated as Hedging Instrument [Member] | Commodity Trading | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | 33,862,000 | 41,282,000 | ||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities [Member] | Designated as Hedging Instrument [Member] | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Fair Value, Gross Liability | 13,607,000 | 18,720,000 | ||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities [Member] | Designated as Hedging Instrument [Member] | Commodity Trading | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Fair Value, Gross Liability | 13,607,000 | 18,622,000 | ||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities [Member] | Designated as Hedging Instrument [Member] | Electric Commodity [Member] | ||||
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 [Member] | Designated as Hedging Instrument [Member] | Natural Gas Commodity [Member] | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Fair Value, Gross Liability | 98,000 | |||
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Liabilities [Member] | Designated as Hedging Instrument [Member] | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Fair Value, Gross Liability | 14,767,000 | 21,417,000 | ||
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Liabilities [Member] | Designated as Hedging Instrument [Member] | Commodity Trading | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Fair Value, Gross Liability | 14,767,000 | 21,417,000 | ||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets [Member] | Designated as Hedging Instrument [Member] | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | 43,194,000 | 17,416,000 | ||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets [Member] | Designated as Hedging Instrument [Member] | Vehicle Fuel And Other Commodity [Member] | Cash Flow Hedges [Member] | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 | ||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets [Member] | Designated as Hedging Instrument [Member] | Commodity Trading | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | 2,142,000 | 692,000 | ||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets [Member] | Designated as Hedging Instrument [Member] | Electric Commodity [Member] | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | 41,052,000 | 16,724,000 | ||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets [Member] | Designated as Hedging Instrument [Member] | Natural Gas Commodity [Member] | ||||
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 [Member] | Designated as Hedging Instrument [Member] | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | 2,716,000 | 77,000 | ||
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Assets [Member] | Designated as Hedging Instrument [Member] | Vehicle Fuel And Other Commodity [Member] | Cash Flow Hedges [Member] | ||||
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 [Member] | Designated as Hedging Instrument [Member] | Commodity Trading | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | 2,716,000 | 77,000 | ||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities [Member] | Designated as Hedging Instrument [Member] | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Fair Value, Gross Liability | 4,442,000 | 844,000 | ||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities [Member] | Designated as Hedging Instrument [Member] | Commodity Trading | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Fair Value, Gross Liability | 1,770,000 | 1,000 | ||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities [Member] | Designated as Hedging Instrument [Member] | Electric Commodity [Member] | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Fair Value, Gross Liability | 2,672,000 | 843,000 | ||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities [Member] | Designated as Hedging Instrument [Member] | Natural Gas Commodity [Member] | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Fair Value, Gross Liability | 0 | |||
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Liabilities [Member] | Designated as Hedging Instrument [Member] | ||||
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 [Member] | Designated as Hedging Instrument [Member] | Commodity Trading | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Fair Value, Gross Liability | 0 | 0 | ||
Fair Value Measured on a Recurring Basis | Fair Value Total [Member] | Other Current Assets [Member] | Designated as Hedging Instrument [Member] | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | 70,821,000 | 43,821,000 | ||
Fair Value Measured on a Recurring Basis | Fair Value Total [Member] | Other Current Assets [Member] | Designated as Hedging Instrument [Member] | Vehicle Fuel And Other Commodity [Member] | Cash Flow Hedges [Member] | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | 72,000 | 95,000 | ||
Fair Value Measured on a Recurring Basis | Fair Value Total [Member] | Other Current Assets [Member] | Designated as Hedging Instrument [Member] | Commodity Trading | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | 25,254,000 | 26,995,000 | ||
Fair Value Measured on a Recurring Basis | Fair Value Total [Member] | Other Current Assets [Member] | Designated as Hedging Instrument [Member] | Electric Commodity [Member] | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | 41,052,000 | 16,724,000 | ||
Fair Value Measured on a Recurring Basis | Fair Value Total [Member] | Other Current Assets [Member] | Designated as Hedging Instrument [Member] | Natural Gas Commodity [Member] | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | 4,443,000 | 7,000 | ||
Fair Value Measured on a Recurring Basis | Fair Value Total [Member] | Other Noncurrent Assets [Member] | Designated as Hedging Instrument [Member] | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | 36,605,000 | 41,445,000 | ||
Fair Value Measured on a Recurring Basis | Fair Value Total [Member] | Other Noncurrent Assets [Member] | Designated as Hedging Instrument [Member] | Vehicle Fuel And Other Commodity [Member] | Cash Flow Hedges [Member] | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | 27,000 | 86,000 | ||
Fair Value Measured on a Recurring Basis | Fair Value Total [Member] | Other Noncurrent Assets [Member] | Designated as Hedging Instrument [Member] | Commodity Trading | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | 36,578,000 | 41,359,000 | ||
Fair Value Measured on a Recurring Basis | Fair Value Total [Member] | Other Current Liabilities [Member] | Designated as Hedging Instrument [Member] | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Fair Value, Gross Liability | 18,049,000 | 19,564,000 | ||
Fair Value Measured on a Recurring Basis | Fair Value Total [Member] | Other Current Liabilities [Member] | Designated as Hedging Instrument [Member] | Commodity Trading | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Fair Value, Gross Liability | 15,377,000 | 18,623,000 | ||
Fair Value Measured on a Recurring Basis | Fair Value Total [Member] | Other Current Liabilities [Member] | Designated as Hedging Instrument [Member] | Electric Commodity [Member] | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Fair Value, Gross Liability | 2,672,000 | 843,000 | ||
Fair Value Measured on a Recurring Basis | Fair Value Total [Member] | Other Current Liabilities [Member] | Designated as Hedging Instrument [Member] | Natural Gas Commodity [Member] | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Fair Value, Gross Liability | 98,000 | |||
Fair Value Measured on a Recurring Basis | Fair Value Total [Member] | Other Noncurrent Liabilities [Member] | Designated as Hedging Instrument [Member] | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Fair Value, Gross Liability | 14,767,000 | 21,417,000 | ||
Fair Value Measured on a Recurring Basis | Fair Value Total [Member] | Other Noncurrent Liabilities [Member] | Designated as Hedging Instrument [Member] | Commodity Trading | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Fair Value, Gross Liability | 14,767,000 | 21,417,000 | ||
Fair Value Measured on a Recurring Basis | Counterparty Netting [Member] | Other Current Assets [Member] | Designated as Hedging Instrument [Member] | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | -11,162,000 | [2] | -7,525,000 | [3] |
Fair Value Measured on a Recurring Basis | Counterparty Netting [Member] | Other Current Assets [Member] | Designated as Hedging Instrument [Member] | Vehicle Fuel And Other Commodity [Member] | Cash Flow Hedges [Member] | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | 0 | [2] | 0 | [3] |
Fair Value Measured on a Recurring Basis | Counterparty Netting [Member] | Other Current Assets [Member] | Designated as Hedging Instrument [Member] | Commodity Trading | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | -8,490,000 | [2] | -6,675,000 | [3] |
Fair Value Measured on a Recurring Basis | Counterparty Netting [Member] | Other Current Assets [Member] | Designated as Hedging Instrument [Member] | Electric Commodity [Member] | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | -2,672,000 | [2] | -843,000 | [3] |
Fair Value Measured on a Recurring Basis | Counterparty Netting [Member] | Other Current Assets [Member] | Designated as Hedging Instrument [Member] | Natural Gas Commodity [Member] | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | 0 | [2] | -7,000 | [3] |
Fair Value Measured on a Recurring Basis | Counterparty Netting [Member] | Other Noncurrent Assets [Member] | Designated as Hedging Instrument [Member] | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | -7,321,000 | [2] | -4,209,000 | [3] |
Fair Value Measured on a Recurring Basis | Counterparty Netting [Member] | Other Noncurrent Assets [Member] | Designated as Hedging Instrument [Member] | Vehicle Fuel And Other Commodity [Member] | Cash Flow Hedges [Member] | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | -15,000 | [2] | -47,000 | [3] |
Fair Value Measured on a Recurring Basis | Counterparty Netting [Member] | Other Noncurrent Assets [Member] | Designated as Hedging Instrument [Member] | Commodity Trading | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | -7,306,000 | [2] | -4,162,000 | [3] |
Fair Value Measured on a Recurring Basis | Counterparty Netting [Member] | Other Current Liabilities [Member] | Designated as Hedging Instrument [Member] | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Fair Value, Gross Liability | -14,423,000 | [2] | -9,962,000 | [3] |
Fair Value Measured on a Recurring Basis | Counterparty Netting [Member] | Other Current Liabilities [Member] | Designated as Hedging Instrument [Member] | Commodity Trading | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Fair Value, Gross Liability | -11,751,000 | [2] | -9,112,000 | [3] |
Fair Value Measured on a Recurring Basis | Counterparty Netting [Member] | Other Current Liabilities [Member] | Designated as Hedging Instrument [Member] | Electric Commodity [Member] | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Fair Value, Gross Liability | -2,672,000 | [2] | -843,000 | [3] |
Fair Value Measured on a Recurring Basis | Counterparty Netting [Member] | Other Current Liabilities [Member] | Designated as Hedging Instrument [Member] | Natural Gas Commodity [Member] | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Fair Value, Gross Liability | -7,000 | [3] | ||
Fair Value Measured on a Recurring Basis | Counterparty Netting [Member] | Other Noncurrent Liabilities [Member] | Designated as Hedging Instrument [Member] | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Fair Value, Gross Liability | -7,321,000 | [2] | -4,210,000 | [3] |
Fair Value Measured on a Recurring Basis | Counterparty Netting [Member] | Other Noncurrent Liabilities [Member] | Designated as Hedging Instrument [Member] | Commodity Trading | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Fair Value, Gross Liability | ($7,321,000) | [2] | ($4,210,000) | [3] |
[1] | In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, Xcel Energy began recording several long-term purchased power agreements 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. | |||
[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 Sept. 30, 2013. At Sept. 30, 2013, derivative assets and liabilities include obligations to return cash collateral of $0.4 million and rights to reclaim cash collateral of $3.6 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] | 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, 2012. At Dec. 31, 2012, derivative assets and liabilities include obligations to return cash collateral of $0.6 million and rights to reclaim cash collateral of $3.0 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. |
Recovered_Sheet1
Fair Value of Financial Assets and Liabilities, Changes in Level 3 Commodity Derivatives (Details) (Commodity Derivatives, Net [Member], USD $) | 3 Months Ended | 9 Months Ended | ||||||
Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | |||||
Commodity Derivatives, Net [Member] | ||||||||
Changes in Level 3 Commodity Derivatives [Roll Forward] | ||||||||
Balance at beginning of period | $47,218,000 | $33,789,000 | $16,649,000 | $12,417,000 | ||||
Purchases | 155,000 | 0 | 51,541,000 | 37,296,000 | ||||
Settlements | -9,342,000 | -12,649,000 | -30,294,000 | -34,209,000 | ||||
Net transactions recorded during the period: | ||||||||
Gains recognized in earnings | 4,008,000 | [1] | 13,000 | [1] | 3,729,000 | [1] | 5,000 | [1] |
(Losses) gains recognized as regulatory assets and liabilities | -571,000 | 4,629,000 | -157,000 | 10,273,000 | ||||
Balance at end of period | 41,468,000 | 25,782,000 | 41,468,000 | 25,782,000 | ||||
Transfers into Level 3 | 0 | 0 | 0 | 0 | ||||
Transfers out of Level 3 | $0 | $0 | $0 | $0 | ||||
[1] | These amounts relate to commodity derivatives held at the end of the period. |
Recovered_Sheet2
Fair Value of Financial Assets and Liabilities, Fair Value of Long-Term Debt (Details) (USD $) | Sep. 30, 2013 | Dec. 31, 2012 |
In Thousands, unless otherwise specified | ||
Carrying Amount | ||
Financial Liabilities, Balance Sheet Groupings [Abstract] | ||
Long-term debt, including current portion | $11,194,811 | $10,402,060 |
Fair Value | ||
Financial Liabilities, Balance Sheet Groupings [Abstract] | ||
Long-term debt, including current portion | $12,007,389 | $12,207,866 |
Other_Expense_Income_Net_Detai
Other (Expense) Income, Net (Details) (USD $) | 3 Months Ended | 9 Months Ended | ||
In Thousands, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 |
Other Income and Expenses [Abstract] | ||||
Interest income | $1,304 | $1,820 | $7,615 | $8,323 |
Other nonoperating income | 739 | 714 | 2,494 | 2,793 |
Insurance policy expense | -2,386 | -2,042 | -5,932 | -5,902 |
Other nonoperating expense | -61 | -4 | -246 | -261 |
Other (expense) income, net | ($404) | $488 | $3,931 | $4,953 |
Segment_Information_Details
Segment Information (Details) (USD $) | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Dec. 31, 2012 | |
Segment Reporting Information [Line Items] | |||||
Equity investments in unconsolidated subsidiaries | $87,800,000 | $87,800,000 | $91,200,000 | ||
Operating revenues | 2,822,338,000 | 2,724,341,000 | 8,184,100,000 | 7,577,088,000 | |
Income (loss) from continuing operations | 364,536,000 | 398,147,000 | 798,006,000 | 764,991,000 | |
Regulated Electric | |||||
Segment Reporting Information [Line Items] | |||||
Operating revenues | 2,600,271,000 | 2,532,996,000 | 6,912,953,000 | 6,507,206,000 | |
Income (loss) from continuing operations | 365,156,000 | 400,185,000 | 740,347,000 | 733,557,000 | |
Regulated Natural Gas | |||||
Segment Reporting Information [Line Items] | |||||
Equity investments in unconsolidated subsidiaries | 87,800,000 | 87,800,000 | 91,200,000 | ||
Operating revenues | 206,464,000 | 174,974,000 | 1,218,438,000 | 1,018,040,000 | |
Income (loss) from continuing operations | -174,000 | 4,296,000 | 80,698,000 | 60,688,000 | |
All Other | |||||
Segment Reporting Information [Line Items] | |||||
Operating revenues | 17,055,000 | 17,119,000 | 55,827,000 | 53,907,000 | |
Income (loss) from continuing operations | -446,000 | -6,334,000 | -23,039,000 | -29,254,000 | |
Operating Segments | |||||
Segment Reporting Information [Line Items] | |||||
Operating revenues | 2,822,338,000 | 2,724,341,000 | 8,184,100,000 | 7,577,088,000 | |
Operating Segments | Regulated Electric | |||||
Segment Reporting Information [Line Items] | |||||
Operating revenues | 2,599,925,000 | 2,532,709,000 | 6,911,998,000 | 6,506,320,000 | |
Operating Segments | Regulated Natural Gas | |||||
Segment Reporting Information [Line Items] | |||||
Operating revenues | 205,358,000 | 174,513,000 | 1,216,275,000 | 1,016,861,000 | |
Operating Segments | All Other | |||||
Segment Reporting Information [Line Items] | |||||
Operating revenues | 17,055,000 | 17,119,000 | 55,827,000 | 53,907,000 | |
Intersegment Eliminations | |||||
Segment Reporting Information [Line Items] | |||||
Operating revenues | -1,452,000 | -748,000 | -3,118,000 | -2,065,000 | |
Intersegment Eliminations | Regulated Electric | |||||
Segment Reporting Information [Line Items] | |||||
Operating revenues | 346,000 | 287,000 | 955,000 | 886,000 | |
Intersegment Eliminations | Regulated Natural Gas | |||||
Segment Reporting Information [Line Items] | |||||
Operating revenues | 1,106,000 | 461,000 | 2,163,000 | 1,179,000 | |
Intersegment Eliminations | All Other | |||||
Segment Reporting Information [Line Items] | |||||
Operating revenues | $0 | $0 | $0 | $0 |
Earnings_Per_Share_Details
Earnings Per Share (Details) (USD $) | 3 Months Ended | 9 Months Ended | ||
In Thousands, except Per Share data, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 |
Dilutive Impact of Common Stock Equivalents on Earnings per Share (Abstract] | ||||
Net income | $364,752 | $398,106 | $798,179 | $765,059 |
Basic earnings per share [Abstract] | ||||
Earnings available to common shareholders | 364,752 | 398,106 | 798,179 | 765,059 |
Weighted average common shares outstanding - basic (in shares) | 498,149 | 488,084 | 495,256 | 487,722 |
Earnings available to common shareholders - basic (in dollars per share) | $0.73 | $0.82 | $1.61 | $1.57 |
Effect of dilutive securities [Abstract] | ||||
401(k) equity awards (in shares) | 492 | 494 | 511 | 476 |
Diluted earnings per share [Abstract] | ||||
Earnings available to common shareholders | $364,752 | $398,106 | $798,179 | $765,059 |
Weighted average common shares outstanding - diluted (in shares) | 498,641 | 488,578 | 495,767 | 488,198 |
Earnings available to common shareholders - diluted (in dollars per share) | $0.73 | $0.81 | $1.61 | $1.57 |
Benefit_Plans_and_Other_Postre2
Benefit Plans and Other Postretirement Benefits (Details) (USD $) | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | |
Plan | Plan | |||
Pension Benefits | ||||
Components of Net Periodic Benefit Cost [Abstract] | ||||
Service cost | $24,071,000 | $21,591,000 | $72,212,000 | $64,773,000 |
Interest cost | 35,173,000 | 39,043,000 | 105,518,000 | 117,131,000 |
Expected return on plan assets | -49,613,000 | -51,774,000 | -148,839,000 | -155,322,000 |
Amortization of transition obligation | 0 | 0 | 0 | 0 |
Amortization of prior service cost (credit) | 1,468,000 | 5,266,000 | 4,404,000 | 15,799,000 |
Amortization of net loss | 36,038,000 | 26,893,000 | 108,114,000 | 80,678,000 |
Net periodic benefit cost | 47,137,000 | 41,019,000 | 141,409,000 | 123,059,000 |
Costs not recognized and additional cost recognized due to the effects of regulation | -12,986,000 | -9,645,000 | -27,922,000 | -28,936,000 |
Net benefit cost recognized for financial reporting | 34,151,000 | 31,374,000 | 113,487,000 | 94,123,000 |
Total contributions to Xcel Energy's pension plans during the period | 192,200,000 | |||
Number of pension plans to which contributions were made | 4 | 4 | ||
Postretirement Health Care Benefits | ||||
Components of Net Periodic Benefit Cost [Abstract] | ||||
Service cost | 1,182,000 | 1,050,000 | 3,546,000 | 3,152,000 |
Interest cost | 8,417,000 | 9,465,000 | 25,251,000 | 28,396,000 |
Expected return on plan assets | -8,253,000 | -7,102,000 | -24,759,000 | -21,307,000 |
Amortization of transition obligation | 206,000 | 3,580,000 | 618,000 | 10,740,000 |
Amortization of prior service cost (credit) | -2,438,000 | -1,888,000 | -7,314,000 | -5,664,000 |
Amortization of net loss | 5,646,000 | 4,228,000 | 16,938,000 | 12,680,000 |
Net periodic benefit cost | 4,760,000 | 9,333,000 | 14,280,000 | 27,997,000 |
Costs not recognized and additional cost recognized due to the effects of regulation | 0 | 972,000 | 0 | 2,918,000 |
Net benefit cost recognized for financial reporting | $4,760,000 | $10,305,000 | $14,280,000 | $30,915,000 |
Other_Comprehensive_Income_Det
Other Comprehensive Income (Details) (USD $) | 1 Months Ended | 3 Months Ended | 9 Months Ended | ||||
In Thousands, unless otherwise specified | 31-May-13 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | ||
Accumulated Other Comprehensive Income [Roll Forward] | |||||||
Accumulated other comprehensive loss at beginning of period | ($111,835) | ($112,653) | |||||
Other comprehensive gain (loss) before reclassifications | 137 | 70 | |||||
Losses reclassified from net accumulated other comprehensive loss | 1,718 | 2,603 | |||||
Net current period other comprehensive income | 1,855 | 2,673 | |||||
Accumulated other comprehensive loss at end of period | -109,980 | -109,980 | |||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||||||
Interest charges | 6,300 | 144,758 | 153,719 | 431,199 | 457,470 | ||
Operating and maintenance expenses | -575,305 | -531,480 | -1,667,093 | -1,576,178 | |||
Total, pre-tax | -557,885 | -600,992 | -1,208,682 | -1,145,152 | |||
Tax benefit | 193,349 | 202,845 | 410,676 | 380,161 | |||
Total, net of tax | -364,536 | -398,147 | -798,006 | -764,991 | |||
Amounts Reclassified from Accumulated Other Comprehensive Loss [Member] | |||||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||||||
Total, net of tax | 1,718 | 2,603 | |||||
Gains and Losses on Cash Flow Hedges [Member] | |||||||
Accumulated Other Comprehensive Income [Roll Forward] | |||||||
Accumulated other comprehensive loss at beginning of period | -60,883 | -61,241 | |||||
Other comprehensive gain (loss) before reclassifications | 22 | -9 | |||||
Losses reclassified from net accumulated other comprehensive loss | 539 | 928 | |||||
Net current period other comprehensive income | 561 | 919 | |||||
Accumulated other comprehensive loss at end of period | -60,322 | -60,322 | |||||
Gains and Losses on Cash Flow Hedges [Member] | Amounts Reclassified from Accumulated Other Comprehensive Loss [Member] | |||||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||||||
Total, pre-tax | 805 | 3,073 | |||||
Tax benefit | -266 | -2,145 | |||||
Total, net of tax | 539 | 928 | |||||
Gains and Losses on Cash Flow Hedges [Member] | Interest Rate Derivatives [Member] | Amounts Reclassified from Accumulated Other Comprehensive Loss [Member] | |||||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||||||
Interest charges | 829 | [1] | 3,140 | [1] | |||
Gains and Losses on Cash Flow Hedges [Member] | Vehicle Fuel And Other Commodity Derivatives [Member] | Amounts Reclassified from Accumulated Other Comprehensive Loss [Member] | |||||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||||||
Operating and maintenance expenses | 24 | [2] | 67 | [2] | |||
Unrealized Gains and Losses on Marketable Securities [Member] | |||||||
Accumulated Other Comprehensive Income [Roll Forward] | |||||||
Accumulated other comprehensive loss at beginning of period | -135 | -99 | |||||
Other comprehensive gain (loss) before reclassifications | 115 | 79 | |||||
Losses reclassified from net accumulated other comprehensive loss | 0 | 0 | |||||
Net current period other comprehensive income | 115 | 79 | |||||
Accumulated other comprehensive loss at end of period | -20 | -20 | |||||
Defined Benefit Pension and Postretirement Items [Member] | |||||||
Accumulated Other Comprehensive Income [Roll Forward] | |||||||
Accumulated other comprehensive loss at beginning of period | -50,817 | -51,313 | |||||
Other comprehensive gain (loss) before reclassifications | 0 | 0 | |||||
Losses reclassified from net accumulated other comprehensive loss | 1,179 | 1,675 | |||||
Net current period other comprehensive income | 1,179 | 1,675 | |||||
Accumulated other comprehensive loss at end of period | -49,638 | -49,638 | |||||
Defined Benefit Pension and Postretirement Items [Member] | Amounts Reclassified from Accumulated Other Comprehensive Loss [Member] | |||||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||||||
Amortization of net loss | 1,770 | [3] | 5,308 | [3] | |||
Prior service cost | 93 | [3] | 279 | [3] | |||
Transition obligation | 2 | [3] | 6 | [3] | |||
Total, pre-tax | 1,865 | 5,593 | |||||
Tax benefit | -686 | -3,918 | |||||
Total, net of tax | $1,179 | $1,675 | |||||
[1] | Included in interest charges. | ||||||
[2] | Included in O&M expenses. | ||||||
[3] | Included in the computation of net periodic pension and post retirement benefit costs. See Note 12 for details regarding these benefit plans. |