Document_and_Entity_Informatio
Document and Entity Information | 3 Months Ended | |
Mar. 31, 2014 | Apr. 28, 2014 | |
Document and Entity Information [Abstract] | ' | ' |
Entity Registrant Name | 'XCEL ENERGY INC | ' |
Entity Central Index Key | '0000072903 | ' |
Current Fiscal Year End Date | '--12-31 | ' |
Entity Well-known Seasoned Issuer | 'Yes | ' |
Entity Voluntary Filers | 'No | ' |
Entity Current Reporting Status | 'Yes | ' |
Entity Filer Category | 'Large Accelerated Filer | ' |
Entity Common Stock, Shares Outstanding | ' | 501,969,728 |
Document Fiscal Year Focus | '2014 | ' |
Document Fiscal Period Focus | 'Q1 | ' |
Document Type | '10-Q | ' |
Amendment Flag | 'false | ' |
Document Period End Date | 31-Mar-14 | ' |
CONSOLIDATED_STATEMENTS_OF_INC
CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) (USD $) | 3 Months Ended | |
In Thousands, except Per Share data, unless otherwise specified | Mar. 31, 2014 | Mar. 31, 2013 |
Operating revenues | ' | ' |
Electric | $2,301,710 | $2,092,196 |
Natural gas | 879,688 | 669,596 |
Other | 21,206 | 21,057 |
Total operating revenues | 3,202,604 | 2,782,849 |
Operating expenses | ' | ' |
Electric fuel and purchased power | 1,067,321 | 925,043 |
Cost of natural gas sold and transported | 623,828 | 439,375 |
Cost of sales — other | 9,129 | 8,411 |
Operating and maintenance expenses | 560,143 | 529,231 |
Conservation and demand side management program expenses | 77,546 | 64,032 |
Depreciation and amortization | 245,943 | 248,706 |
Taxes (other than income taxes) | 124,702 | 113,427 |
Total operating expenses | 2,708,612 | 2,328,225 |
Operating income | 493,992 | 454,624 |
Other income, net | 3,201 | 3,922 |
Equity earnings of unconsolidated subsidiaries | 7,438 | 7,577 |
Allowance for funds used during construction — equity | 21,907 | 19,754 |
Interest charges and financing costs | ' | ' |
Interest charges — includes other financing costs of $5,792 and $5,809, respectively | 139,094 | 139,631 |
Allowance for funds used during construction — debt | -9,548 | -8,758 |
Total interest charges and financing costs | 129,546 | 130,873 |
Income before income taxes | 396,992 | 355,004 |
Income taxes | 135,771 | 118,434 |
Net income | $261,221 | $236,570 |
Weighted average common shares outstanding: | ' | ' |
Basic (in shares) | 499,523 | 489,781 |
Diluted (in shares) | 499,746 | 490,531 |
Earnings per average common share: | ' | ' |
Basic (in dollars per share) | $0.52 | $0.48 |
Diluted (in dollars per share) | $0.52 | $0.48 |
Cash dividends declared per common share (in dollars per share) | $0.30 | $0.27 |
CONSOLIDATED_STATEMENTS_OF_INC1
CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) (Parenthetical) (USD $) | 3 Months Ended | |
In Thousands, unless otherwise specified | Mar. 31, 2014 | Mar. 31, 2013 |
Interest charges and financing costs | ' | ' |
Other financing costs | $5,792 | $5,809 |
CONSOLIDATED_STATEMENTS_OF_COM
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) (USD $) | 3 Months Ended | |
In Thousands, unless otherwise specified | Mar. 31, 2014 | Mar. 31, 2013 |
Comprehensive income: | ' | ' |
Net income | $261,221 | $236,570 |
Pension and retiree medical benefits: | ' | ' |
Amortization of losses (gains) included in net periodic benefit cost, net of tax of $550 and $2,503, respectively | 864 | -639 |
Derivative instruments: | ' | ' |
Net fair value (decrease) increase, net of tax of $(5) and $12, respectively | -7 | 13 |
Reclassification of losses (gains) to net income, net of tax of $358 and $1,429, respectively | 560 | -305 |
Total derivative instruments, net of tax | 553 | -292 |
Marketable securities: | ' | ' |
Net fair value increase (decrease), net of tax of $24 and $(18), respectively | 38 | -36 |
Other comprehensive income (loss) | 1,455 | -967 |
Comprehensive income | $262,676 | $235,603 |
CONSOLIDATED_STATEMENTS_OF_COM1
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) (Parenthetical) (USD $) | 3 Months Ended | |
In Thousands, unless otherwise specified | Mar. 31, 2014 | Mar. 31, 2013 |
Pension and retiree medical benefits: | ' | ' |
Amortization of losses (gains) included in net periodic benefit cost, tax | $550 | $2,503 |
Derivative instruments: | ' | ' |
Net fair value (decrease) increase, tax | -5 | 12 |
Reclassification of losses (gains) to net income, tax | 358 | 1,429 |
Marketable securities: | ' | ' |
Net fair value increase (decrease), tax | $24 | ($18) |
CONSOLIDATED_STATEMENTS_OF_CAS
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) (USD $) | 3 Months Ended | |
In Thousands, unless otherwise specified | Mar. 31, 2014 | Mar. 31, 2013 |
Operating activities | ' | ' |
Net income | $261,221 | $236,570 |
Adjustments to reconcile net income to cash provided by operating activities: | ' | ' |
Depreciation and amortization | 250,343 | 253,004 |
Conservation and demand side management program amortization | 1,555 | 1,712 |
Nuclear fuel amortization | 28,862 | 27,522 |
Deferred income taxes | 150,464 | 130,662 |
Amortization of investment tax credits | -1,443 | -1,657 |
Allowance for equity funds used during construction | -21,907 | -19,754 |
Equity earnings of unconsolidated subsidiaries | -7,438 | -7,577 |
Dividends from unconsolidated subsidiaries | 8,850 | 9,539 |
Share-based compensation expense | 5,370 | 8,167 |
Net realized and unrealized hedging and derivative transactions | 7,384 | 217 |
Changes in operating assets and liabilities: | ' | ' |
Accounts receivable | -140,962 | -72,205 |
Accrued unbilled revenues | 111,417 | 76,602 |
Inventories | 140,301 | 87,865 |
Other current assets | -66,320 | -51,203 |
Accounts payable | -37,730 | 5,311 |
Net regulatory assets and liabilities | -253 | 88,572 |
Other current liabilities | 1,008 | 20,318 |
Pension and other employee benefit obligations | -125,780 | -181,091 |
Change in other noncurrent assets | 48,054 | 24,594 |
Change in other noncurrent liabilities | -20,347 | 5,160 |
Net cash provided by operating activities | 592,649 | 642,328 |
Investing activities | ' | ' |
Utility capital/construction expenditures | -822,628 | -752,251 |
Proceeds from insurance recoveries | 4,260 | 23,500 |
Allowance for equity funds used during construction | 21,907 | 19,754 |
Purchases of investments in external decommissioning fund | -229,548 | -586,239 |
Proceeds from the sale of investments in external decommissioning fund | 227,901 | 584,948 |
Investment in WYCO Development LLC | -1,161 | -231 |
Other, net | -1,501 | -2,745 |
Net cash used in investing activities | -800,770 | -713,264 |
Financing activities | ' | ' |
Proceeds from (repayments of) short-term borrowings, net | 6,000 | -177,000 |
Proceeds from issuance of long-term debt | 295,999 | 494,282 |
Repayments of long-term debt, including reacquisition premiums | -224 | -251,367 |
Proceeds from issuance of common stock | 63,548 | 160,084 |
Dividends paid | -132,033 | -124,426 |
Net cash provided by financing activities | 233,290 | 101,573 |
Net change in cash and cash equivalents | 25,169 | 30,637 |
Cash and cash equivalents at beginning of period | 107,144 | 82,323 |
Cash and cash equivalents at end of period | 132,313 | 112,960 |
Supplemental disclosure of cash flow information: | ' | ' |
Cash paid for interest (net of amounts capitalized) | -152,522 | -153,498 |
Cash (paid) received for income taxes, net | -164 | 17,939 |
Supplemental disclosure of non-cash investing and financing transactions: | ' | ' |
Property, plant and equipment additions in accounts payable | 290,058 | 256,530 |
Issuance of common stock for reinvested dividends and 401(k) plans | $14,525 | $18,791 |
CONSOLIDATED_BALANCE_SHEETS_UN
CONSOLIDATED BALANCE SHEETS (UNAUDITED) (USD $) | Mar. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Current assets | ' | ' |
Cash and cash equivalents | $132,313 | $107,144 |
Accounts receivable, net | 885,098 | 744,160 |
Accrued unbilled revenues | 575,813 | 687,230 |
Inventories | 436,237 | 576,538 |
Regulatory assets | 481,473 | 417,801 |
Derivative instruments | 70,275 | 91,707 |
Deferred income taxes | 252,658 | 341,202 |
Prepayments and other | 295,479 | 252,258 |
Total current assets | 3,129,346 | 3,218,040 |
Property, plant and equipment, net | 26,541,482 | 26,122,159 |
Other assets | ' | ' |
Nuclear decommissioning fund and other investments | 1,793,067 | 1,755,990 |
Regulatory assets | 2,497,280 | 2,509,218 |
Derivative instruments | 67,513 | 84,842 |
Other | 170,064 | 217,241 |
Total other assets | 4,527,924 | 4,567,291 |
Total assets | 34,198,752 | 33,907,490 |
Current liabilities | ' | ' |
Current portion of long-term debt | 282,133 | 280,763 |
Short-term debt | 765,000 | 759,000 |
Accounts payable | 1,061,874 | 1,261,238 |
Regulatory liabilities | 258,946 | 274,769 |
Taxes accrued | 461,520 | 378,766 |
Accrued interest | 132,589 | 159,372 |
Dividends payable | 150,250 | 139,432 |
Derivative instruments | 22,358 | 23,382 |
Other | 333,078 | 377,776 |
Total current liabilities | 3,467,748 | 3,654,498 |
Deferred credits and other liabilities | ' | ' |
Deferred income taxes | 5,412,381 | 5,331,046 |
Deferred investment tax credits | 77,796 | 79,239 |
Regulatory liabilities | 1,090,733 | 1,059,395 |
Asset retirement obligations | 1,838,521 | 1,815,390 |
Derivative instruments | 199,578 | 209,224 |
Customer advances | 272,583 | 275,555 |
Pension and employee benefit obligations | 642,126 | 769,222 |
Other | 244,543 | 237,217 |
Total deferred credits and other liabilities | 9,778,261 | 9,776,288 |
Commitments and contingencies | ' | ' |
Capitalization | ' | ' |
Long-term debt | 11,205,319 | 10,910,754 |
Common stock — 1,000,000,000 shares authorized of $2.50 par value; 501,151,619 and 497,971,508 shares outstanding at March 31, 2014 and Dec. 31, 2013, respectively | 1,252,879 | 1,244,929 |
Additional paid in capital | 5,681,150 | 5,619,313 |
Retained earnings | 2,918,215 | 2,807,983 |
Accumulated other comprehensive loss | -104,820 | -106,275 |
Total common stockholders’ equity | 9,747,424 | 9,565,950 |
Total liabilities and equity | $34,198,752 | $33,907,490 |
CONSOLIDATED_BALANCE_SHEETS_UN1
CONSOLIDATED BALANCE SHEETS (UNAUDITED) (Parenthetical) (USD $) | Mar. 31, 2014 | Dec. 31, 2013 |
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) | 501,151,619 | 497,971,508 |
CONSOLIDATED_STATEMENTS_OF_COM2
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY (UNAUDITED) (USD $) | Total | Common Stock | Additional Paid In Capital | Retained Earnings | Accumulated Other Comprehensive Loss |
In Thousands, except Share data, unless otherwise specified | |||||
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 | ' | 487,960,000 | ' | ' | ' |
Increase (Decrease) in Stockholders' Equity | ' | ' | ' | ' | ' |
Net income | 236,570 | ' | ' | 236,570 | ' |
Other comprehensive income (loss) | -967 | ' | ' | ' | -967 |
Dividends declared on common stock | -134,054 | ' | ' | -134,054 | ' |
Issuances of common stock | 168,834 | 16,989 | 151,845 | ' | ' |
Issuances of common stock (in shares) | ' | 6,795,000 | ' | ' | ' |
Share-based compensation | 10,653 | ' | 10,653 | ' | ' |
Ending balance at Mar. 31, 2013 | 9,155,113 | 1,236,888 | 5,515,513 | 2,516,332 | -113,620 |
Balance (in shares) at Mar. 31, 2013 | ' | 494,755,000 | ' | ' | ' |
Beginning balance at Dec. 31, 2013 | 9,565,950 | 1,244,929 | 5,619,313 | 2,807,983 | -106,275 |
Balance (in shares) at Dec. 31, 2013 | 497,971,508 | 497,972,000 | ' | ' | ' |
Increase (Decrease) in Stockholders' Equity | ' | ' | ' | ' | ' |
Net income | 261,221 | ' | ' | 261,221 | ' |
Other comprehensive income (loss) | 1,455 | ' | ' | ' | 1,455 |
Dividends declared on common stock | -150,989 | ' | ' | -150,989 | ' |
Issuances of common stock | 63,722 | 7,950 | 55,772 | ' | ' |
Issuances of common stock (in shares) | ' | 3,180,000 | ' | ' | ' |
Share-based compensation | 6,065 | ' | 6,065 | ' | ' |
Ending balance at Mar. 31, 2014 | $9,747,424 | $1,252,879 | $5,681,150 | $2,918,215 | ($104,820) |
Balance (in shares) at Mar. 31, 2014 | 501,151,619 | 501,152,000 | ' | ' | ' |
Managements_Opinion
Management's Opinion | 3 Months Ended |
Mar. 31, 2014 | |
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 March 31, 2014 and Dec. 31, 2013; the results of its operations, including the components of net income and comprehensive income, and changes in stockholders’ equity for the three months ended March 31, 2014 and 2013; and its cash flows for the three months ended March 31, 2014 and 2013. All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after March 31, 2014 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, 2013 balance sheet information has been derived from the audited 2013 consolidated financial statements included in the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, 2013. 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, 2013, filed with the SEC on Feb. 21, 2014. 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 | 3 Months Ended |
Mar. 31, 2014 | |
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, 2013, appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference. |
Accounting_Pronouncements
Accounting Pronouncements | 3 Months Ended |
Mar. 31, 2014 | |
New Accounting Pronouncements and Changes in Accounting Principles [Abstract] | ' |
Accounting Pronouncements | ' |
Accounting Pronouncements | |
Recently issued accounting pronouncements that have been adopted in the current period did not materially impact the consolidated financial statements, and no material impact is expected from accounting pronouncements issued and pending implementation. |
Selected_Balance_Sheet_Data
Selected Balance Sheet Data | 3 Months Ended | ||||||||
Mar. 31, 2014 | |||||||||
Balance Sheet Related Disclosures [Abstract] | ' | ||||||||
Selected Balance Sheet Data | ' | ||||||||
Selected Balance Sheet Data | |||||||||
(Thousands of Dollars) | March 31, 2014 | Dec. 31, 2013 | |||||||
Accounts receivable, net | |||||||||
Accounts receivable | $ | 939,228 | $ | 797,267 | |||||
Less allowance for bad debts | (54,130 | ) | (53,107 | ) | |||||
$ | 885,098 | $ | 744,160 | ||||||
(Thousands of Dollars) | March 31, 2014 | Dec. 31, 2013 | |||||||
Inventories | |||||||||
Materials and supplies | $ | 229,299 | $ | 225,308 | |||||
Fuel | 149,190 | 189,485 | |||||||
Natural gas | 57,748 | 161,745 | |||||||
$ | 436,237 | $ | 576,538 | ||||||
(Thousands of Dollars) | March 31, 2014 | Dec. 31, 2013 | |||||||
Property, plant and equipment, net | |||||||||
Electric plant | $ | 30,562,428 | $ | 30,341,310 | |||||
Natural gas plant | 4,156,606 | 4,086,651 | |||||||
Common and other property | 1,477,531 | 1,485,547 | |||||||
Plant to be retired (a) | 92,050 | 101,279 | |||||||
Construction work in progress | 2,672,049 | 2,371,566 | |||||||
Total property, plant and equipment | 38,960,664 | 38,386,353 | |||||||
Less accumulated depreciation | (12,741,176 | ) | (12,608,305 | ) | |||||
Nuclear fuel | 2,193,544 | 2,186,799 | |||||||
Less accumulated amortization | (1,871,550 | ) | (1,842,688 | ) | |||||
$ | 26,541,482 | $ | 26,122,159 | ||||||
(a) | As a result of the 2010 Colorado Public Utilities Commission (CPUC) approval of PSCo’s Clean Air Clean Jobs Act (CACJA) compliance plan and the December 2013 approval of PSCo’s preferred plans for applicable generating resources, PSCo has received approval for early retirement of Cherokee Unit 3 and Valmont Unit 5 between 2015 and 2017. Amounts are presented net of accumulated depreciation. |
Income_Taxes
Income Taxes | 3 Months Ended | ||||||||
Mar. 31, 2014 | |||||||||
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, 2013 appropriately represent, in all material respects, the current status of other income tax matters, and are incorporated herein by reference. | |||||||||
Federal Tax Loss Carryback Claims — In 2012 and 2013, Xcel Energy identified certain expenses related to 2009, 2010, 2011 and 2013 that qualify for an extended carryback beyond the typical two-year carryback period. As a result of a higher tax rate in prior years, Xcel Energy recognized a tax benefit of approximately $15 million in 2012 and $12 million in 2013. | |||||||||
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, including the 2009 carryback claim. As of March 31, 2014, the IRS had proposed an adjustment to the federal tax loss carryback claims that would result in $10 million of income tax expense for the 2009 through 2011 claims and the anticipated claim for 2013. Xcel Energy is continuing to work through the audit process, but the outcome and timing of a resolution is uncertain. | |||||||||
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 March 31, 2014, Xcel Energy’s earliest open tax years that are subject to examination by state taxing authorities in its major operating jurisdictions were as follows: | |||||||||
State | Year | ||||||||
Colorado | 2009 | ||||||||
Minnesota | 2009 | ||||||||
Texas | 2009 | ||||||||
Wisconsin | 2009 | ||||||||
In the first quarter of 2014, the state of Wisconsin completed an examination of tax years 2009 through 2011. No material adjustments were proposed for those tax years. As of March 31, 2014, there were no 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) | March 31, 2014 | Dec. 31, 2013 | |||||||
Unrecognized tax benefit — Permanent tax positions | $ | 7.4 | $ | 12.9 | |||||
Unrecognized tax benefit — Temporary tax positions | 27.8 | 28.3 | |||||||
Total unrecognized tax benefit | $ | 35.2 | $ | 41.2 | |||||
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) | March 31, 2014 | Dec. 31, 2013 | |||||||
NOL and tax credit carryforwards | $ | (23.0 | ) | $ | (27.1 | ) | |||
It is reasonably possible that Xcel Energy’s amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS audit progresses and state audits resume. As the IRS examination moves closer to completion, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $8 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 March 31, 2014 and Dec. 31, 2013 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of March 31, 2014 or Dec. 31, 2013. |
Rate_Matters
Rate Matters | 3 Months Ended | ||||||||||||
Mar. 31, 2014 | |||||||||||||
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, 2013 appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference. | |||||||||||||
NSP-Minnesota | |||||||||||||
Pending Regulatory Proceedings — Minnesota Public Utilities Commission (MPUC) | |||||||||||||
NSP Minnesota – Minnesota 2014 Multi-Year Electric Rate Case — In November 2013, NSP-Minnesota filed a two-year electric rate case with the MPUC. The rate case is based on a requested return on equity (ROE) of 10.25 percent, a 52.5 percent equity ratio, a 2014 average electric rate base of $6.67 billion and an additional average rate base of $412 million in 2015. | |||||||||||||
The NSP-Minnesota electric rate case reflects an overall increase in revenues of approximately $193 million or 6.9 percent in 2014 and an additional $98 million or 3.5 percent in 2015. The request includes a proposed rate moderation plan for 2014 and 2015. After reflecting interim rate adjustments, NSP-Minnesota is requesting a rate increase of $127 million or 4.6 percent in 2014 and an incremental rate increase of $164 million or 5.6 percent in 2015. | |||||||||||||
NSP-Minnesota’s moderation plan includes the acceleration of the eight-year amortization of the excess depreciation reserve which the MPUC approved in NSP-Minnesota’s last electric rate case and the use of expected funds from the U.S. Department of Energy (DOE) for settlement of certain claims. These DOE refunds would be in excess of amounts needed to fund NSP-Minnesota’s decommissioning expense. The interim rate adjustments are primarily associated with ROE, Monticello life cycle management (LCM)/extended power uprate (EPU) project costs and NSP-Minnesota’s request to amortize amounts associated with the canceled Prairie Island EPU project. NSP-Minnesota may file a petition for deferred accounting regarding these Monticello costs later in 2014. | |||||||||||||
The rate request, moderation plan, interim rate adjustments, customer bill impacts and certain impacts on expenses are detailed in the table below: | |||||||||||||
(Millions of Dollars) | 2014 | Percentage | 2015 | Percentage | |||||||||
Increase | Increase | ||||||||||||
Pre-moderation deficiency | $ | 274 | $ | 81 | |||||||||
Moderation change compared to prior year: | |||||||||||||
Depreciation reserve | (81 | ) | 53 | ||||||||||
DOE settlement proceeds | — | (36 | ) | ||||||||||
Filed rate request | 193 | 6.90% | 98 | 3.50% | |||||||||
Interim rate adjustments | (66 | ) | 66 | ||||||||||
Impact on customer bill | 127 | 4.60% | 164 | 5.60% | |||||||||
Potential expense deferral | 16 | — | |||||||||||
Depreciation expense - reduction/(increase) | 81 | (46 | ) | ||||||||||
Recognition of DOE settlement proceeds | — | 36 | |||||||||||
Pre-tax impact on operating income | $ | 224 | $ | 154 | |||||||||
In December 2013, the MPUC approved interim rates of $127 million effective Jan. 3, 2014, subject to refund. The MPUC determined that the costs of Sherco Unit 3 would be allowed in interim rates, and that NSP-Minnesota’s request to accelerate the depreciation reserve amortization was a permissible adjustment to its interim rate request. | |||||||||||||
The next steps in the procedural schedule are expected to be as follows: | |||||||||||||
• | Direct Testimony — June 5, 2014; | ||||||||||||
• | Rebuttal Testimony — July 7, 2014; | ||||||||||||
• | Surrebuttal Testimony — Aug. 4, 2014; | ||||||||||||
• | Evidentiary Hearing — Aug. 11-18, 2014; | ||||||||||||
• | Reply Brief — Oct. 14, 2014; and | ||||||||||||
• | Administrative Law Judge (ALJ) Report — Dec. 22, 2014. | ||||||||||||
A final MPUC decision is anticipated in March 2015. | |||||||||||||
NSP-Minnesota – Nuclear Project Prudence Investigation — The MPUC has initiated an investigation to determine whether the costs in excess of the $320 million included in the certificate of need (CON) for NSP-Minnesota’s Monticello LCM/EPU project were prudent. The final costs for the Monticello LCM/EPU project were approximately $665 million. | |||||||||||||
In October 2013, NSP-Minnesota filed a report to further support the change 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. NSP-Minnesota has provided information that the cost deviation is in line with similar upgrade projects undertaken by other utilities and the project remains economically beneficial to customers. NSP-Minnesota has received all necessary licenses from the NRC for the Monticello EPU, and has begun the process to comply with the license requirements for higher power levels, subject to NRC oversight and review. | |||||||||||||
At the direction of the MPUC, the Minnesota Department of Commerce (DOC) has retained a consultant to assist in their review. The consultant, Global Energy and Water Consulting, LLC is covering the cost split between LCM and EPU; reasons for the cost increases; project management and oversight; and the prudence of scope changes among others. 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. The next steps in the procedural schedule are expected to be as follows: | |||||||||||||
• | Direct Testimony — July 2, 2014; | ||||||||||||
• | Rebuttal Testimony — Aug. 26, 2014; | ||||||||||||
• | Surrebuttal Testimony — Sept. 19, 2014; | ||||||||||||
• | Hearing — Sept. 29 - Oct. 3, 2014; | ||||||||||||
• | Reply Brief — Nov. 21, 2014; and | ||||||||||||
• | ALJ Report — Dec. 31, 2014. | ||||||||||||
A final MPUC decision is anticipated in the first quarter of 2015. | |||||||||||||
Recently Concluded 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 was based on a 2013 forecast test year (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 February 2014, the NDPSC approved a four-year rate plan settlement. The approved plan will provide increased revenues of approximately $7.4 million, $9.4 million and $10.1 million, an annual rate increase of 4.9 percent for 2013, 2014 and 2015 respectively, with no increase in 2016. Additionally, the rate plan includes a gradually increasing ROE of 9.75, 10.0, 10.0 and 10.25 percent for 2013 through 2016, respectively. Final rates for 2013 and the 2014 rate increase went into effect May 1, 2014. The 2015 rate increase will take effect Jan. 1, 2015. | |||||||||||||
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 was based on a 2013 FTY, a 10.5 percent ROE, a rate base of $1.3 billion and an equity ratio of 56 percent. Interim rates, subject to refund, went into effect in August 2013. | |||||||||||||
In April 2013, PSCo 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 included amounts to be transferred from the Pipeline System Integrity Adjustment (PSIA) rider mechanism. | |||||||||||||
In December 2013, the CPUC approved a natural gas base rate increase of approximately $15.8 million based on an ROE of 9.72 percent, a historic test year (HTY) with an end of year rate base and an equity ratio of 56 percent. | |||||||||||||
The following table summarizes the CPUC decision: | |||||||||||||
(Millions of Dollars) | CPUC Decision | ||||||||||||
PSCo deficiency based on a FTY | $ | 44.8 | |||||||||||
HTY adjustment | (5.4 | ) | |||||||||||
ROE and capital structure adjustments | (8.3 | ) | |||||||||||
Revenue adjustments | (1.4 | ) | |||||||||||
Other | (0.1 | ) | |||||||||||
Recommendation | 29.6 | ||||||||||||
PSIA — base rate transfer to rider mechanism | (13.8 | ) | |||||||||||
Incremental base revenue | $ | 15.8 | |||||||||||
Rates and conforming changes made to the PSIA were effective Jan. 1, 2014. In April 2014, the CPUC approved PSCo’s request to refund $6.6 million to customers, excluding amounts related to the PSIA rider mechanism. The refund represents the difference between the interim rates collected and the final approved rates and will be returned between April 2014 and March 2015. | |||||||||||||
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 was 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 Office of Consumer Counsel (OCC) and Colorado Energy Consumers filed a comprehensive settlement which tied the outcome of the steam rate case to key issues to be decided in the natural gas rate case, including ROE and capital structure. The settlement allowed the filed rates to be effective on Jan. 1, 2014, subject to refund. Final rates allowing a rate increase of $2.3 million annually were implemented on Feb. 1, 2014. | |||||||||||||
PSCo – Annual Electric Earnings Test — An earnings sharing mechanism is used to apply prospective electric rate adjustments for earnings in the prior year that exceed PSCo’s authorized ROE threshold of 10 percent. PSCo filed a tariff for the 2013 earnings test with the CPUC on April 30, 2014, proposing a refund obligation of $45.7 million to electric customers to be returned between August 2014 and July 2015. As of March 31, 2014, PSCo has also recognized management’s best estimate of an accrual for 2014. | |||||||||||||
Electric Commodity Adjustment (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 outages of certain jointly owned facilities were properly allocated between wholesale and retail customers. A decision is anticipated later in 2014. | |||||||||||||
2012 PSIA Report — In April 2013, PSCo filed its 2012 PSIA report, requesting $43.5 million for recovery of expenditures. The OCC and CPUC Staff requested that 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. In July 2013, the CPUC approved the request and assigned the matter to an ALJ. | |||||||||||||
In February 2014, PSCo, the CPUC Staff and the OCC agreed to a settlement amount of $43.4 million for recovery of 2012 expenditures, subject to final approval. This includes a one-time disallowance of approximately $0.1 million of operating and maintenance (O&M) expenditures in 2012 and an agreement not to disallow capital expenditures related to a pipeline replacement project. In March 2014, the ALJ waived the need for a hearing on the settlement. An ALJ recommended decision is anticipated later in 2014. | |||||||||||||
Electric, Purchased Gas and Resource Adjustment Clauses | |||||||||||||
Renewable Energy Credit (REC) Sharing — In 2011, the CPUC approved margin sharing on stand-alone REC transactions at 10 percent to PSCo and 90 percent to customers for 2014. In 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 renewable energy standard adjustment (RESA) regulatory asset balance. PSCo’s credit to the RESA regulatory asset balance was not material for the three months ended March 31, 2014. For the three months ended March 31, 2013, PSCo credited the RESA regulatory asset balance $4.0 million. The cumulative credit to the RESA regulatory asset balance was $104.6 million and $104.5 million at March 31, 2014 and Dec. 31, 2013, respectively. The credits include the customers’ share of REC trading margins and the unspent share of carbon offset funds. | |||||||||||||
This sharing mechanism will be effective through 2014. The CPUC is then expected to review the framework and evidence regarding actual deliveries before determining whether to continue the sharing mechanism. | |||||||||||||
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. 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. In 2014, the ALJ and the CPUC determined that the $26.2 million was prudently incurred and recommended full recovery through the ECA over a 12 month period with interest accrued at the ECA interest rate. The difference between the RESA interest rate and the ECA interest rate was a decrease of approximately 7.4 percent, or $4.3 million, and was reflected in 2013 earnings. | |||||||||||||
Pending Regulatory Proceedings — Federal Energy Regulatory Commission (FERC) | |||||||||||||
PSCo Transmission Formula Rate Cases — In April 2012, PSCo filed with the FERC to revise the wholesale transmission formula rates from a HTY formula rate to a forecast transmission formula rate and to establish formula ancillary services rates. PSCo proposed that the formula rates be updated annually to reflect changes in costs, subject to a true-up. The request would increase PSCo’s wholesale transmission and ancillary services revenue by approximately $2.0 million annually. Various transmission customers taking service under the tariff protested the filing. In June 2012, the FERC issued an order accepting the proposed transmission and ancillary services formula rates, suspending the increase to November 2012, subject to refund, and setting the case for settlement judge or hearing procedures. | |||||||||||||
In June 2012, several wholesale customers filed a complaint with the FERC seeking to have the transmission formula rate ROE reduced from 10.25 to 9.15 percent effective July 1, 2012. If implemented, the ROE reduction would reduce PSCo transmission and ancillary rate revenues by approximately $1.8 million annually. In October 2012, the FERC issued an order accepting the complaint, consolidating the complaint with the April 2012 formula rate change filing, establishing a refund effective date of July 1, 2012, and setting the complaint for settlement judge and hearing procedures. | |||||||||||||
In December 2013, the FERC approved a partial settlement resolving all issues related to the April 2012 transmission rate filing and June 2012 complaint other than ROE. The settlement is not expected to materially increase 2014 transmission revenues. The ROE issue is now subject to an evidentiary hearing process. | |||||||||||||
In March 2014, the FERC Staff filed testimony supporting an ROE of 8.91 percent for July 2012 to November 2012, and an ROE of 8.70 percent thereafter. The case is scheduled for a hearing before an ALJ in May 2014, with the ALJ recommended decision expected by September 2014. | |||||||||||||
SPS | |||||||||||||
Pending Regulatory Proceedings — Public Utility Commission of Texas (PUCT) | |||||||||||||
SPS – Texas 2014 Electric Rate Case — In January 2014, SPS filed a retail electric rate case in Texas with each of its Texas municipalities and the PUCT for a net increase in annual revenue of approximately $52.7 million, or 5.8 percent. The net increase reflected a base rate increase, revenue credits transferred from base rates to rate riders or the fuel clause, and resetting the Transmission Cost Recovery Factor (TCRF) to zero when the final base rates become effective. | |||||||||||||
The rate filing was based on a HTY ending June 2013, a requested ROE of 10.40 percent, an electric rate base of approximately $1.27 billion and an equity ratio of 53.89 percent. The requested rate increase reflected an increase in depreciation expense of approximately $16 million. | |||||||||||||
In April 2014, SPS revised its requested rate increase to approximately $48.1 million, or 5.3 percent, based on updated information. The following table summarizes SPS’ revised request: | |||||||||||||
(Millions of Dollars) | SPS Request | ||||||||||||
Adjusted base rate increase | $ | 76.9 | |||||||||||
Resetting TCRF | (12.9 | ) | |||||||||||
Credit to customers for gain on sale to Lubbock moved to a rider | (4.9 | ) | |||||||||||
Adjusted net increase in base revenue | 59.1 | ||||||||||||
Fuel clause offsets | (11.0 | ) | |||||||||||
Adjusted retail customer net bill impact | $ | 48.1 | |||||||||||
The PUCT has suspended SPS’ proposed rates through Oct. 31, 2014. If the PUCT has not issued a final order by July 11, 2014, then SPS’ current rates will not change, but final rates, when approved by the PUCT, will be made effective retroactive to July 12, 2014. SPS, intervenors and other parties have commenced settlement negotiations. | |||||||||||||
Next steps in the procedural schedule are as follows: | |||||||||||||
• | Intervenor testimony — May 22, 2014; | ||||||||||||
• | PUCT Staff testimony — May 29, 2014; | ||||||||||||
• | Cross-rebuttal testimony — June 12, 2014; | ||||||||||||
• | Rebuttal testimony — June 16, 2014; | ||||||||||||
• | Evidentiary hearing — June 25, 2014; and | ||||||||||||
• | A PUCT decision and implementation of final rates are anticipated in the third quarter of 2014. | ||||||||||||
Electric, Purchased Gas and Resource Adjustment Clauses | |||||||||||||
TCRF Rider — In November 2013, SPS filed with the PUCT to implement the TCRF for Texas retail customers. The requested increase in revenues is $13 million. The PUCT issued an order allowing the TCRF to go into effect on an interim basis effective Jan. 1, 2014. In April and May 2014, several parties including both intervenors and the PUCT Staff filed testimony recommending various reductions or modifications to the proposed TCRF. | |||||||||||||
Next steps in the procedural schedule are as follows: | |||||||||||||
• | SPS Rebuttal testimony — May 8, 2014; and | ||||||||||||
• | Evidentiary hearings — May 15 - May 16, 2014. | ||||||||||||
Recently Concluded 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 was based on a 2014 FTY, a requested ROE of 10.65 percent, an electric rate base of $479.8 million and an equity ratio of 53.89 percent. | |||||||||||||
In September 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. | |||||||||||||
In March 2014, the NMPRC approved an overall increase of approximately $33.1 million. The increase includes: an ROE of 9.96 percent, an equity ratio of 53.89 percent, allowance of the prepaid pension asset in rate base of approximately $2.4 million, allowance of certain non-labor operating and maintenance escalations and recovery of approximately $18.1 million of renewable energy costs through rider revenue instead of base revenue. As a result of a change in the amount of fuel costs recovered through base rates, SPS will no longer be required to credit customers for $2.3 million through the fuel clause adjustment (FCA). Final rates were effective April 5, 2014. On April 25, 2014, the New Mexico Attorney General filed a request for rehearing. The rehearing request is pending with the NMPRC, which has until May 15, 2014 to grant or deny the request. | |||||||||||||
The following table summarizes the NMPRC’s approval from SPS’ revised request: | |||||||||||||
(Millions of Dollars) | NMPRC Approval | ||||||||||||
SPS revised request, September 2013 | $ | 32.5 | |||||||||||
Fuel clause adjustment credit — non-renewable energy costs | 2.3 | ||||||||||||
SPS revised request, fuel adjusted | 34.8 | ||||||||||||
ROE (9.96 percent) | (1.2 | ) | |||||||||||
Rate rider adjustment — renewable energy costs | 6 | ||||||||||||
Base rate reduction for rate rider — renewable energy costs | (6.0 | ) | |||||||||||
Other, net | (0.5 | ) | |||||||||||
Approved increase, March 2014 | $ | 33.1 | |||||||||||
Means of recovery: | |||||||||||||
Base revenue | $ | 12.7 | |||||||||||
Rider revenue | 18.1 | ||||||||||||
Fuel clause | 2.3 | ||||||||||||
$ | 33.1 | ||||||||||||
Commitments_and_Contingencies
Commitments and Contingencies | 3 Months Ended | ||||||||
Mar. 31, 2014 | |||||||||
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, 2013, 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 (PPAs) | |||||||||
Under certain PPAs, NSP-Minnesota, PSCo and SPS purchase power from independent power producing entities for which the utility subsidiaries are required to reimburse natural gas or biomass fuel costs, or to participate in tolling arrangements under which the utility subsidiaries procure the natural gas required to produce the energy that they purchase. These specific PPAs create a variable interest in the associated independent power producing entity. | |||||||||
The Xcel Energy utility subsidiaries had approximately 3,698 megawatts (MW) and 3,338 MW of capacity under long-term PPAs as of March 31, 2014 and Dec. 31, 2013, 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 March 31, 2014 and Dec. 31, 2013, 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) | March 31, 2014 | Dec. 31, 2013 | |||||||
Guarantees issued and outstanding | $ | 18.3 | $ | 19.4 | |||||
Current exposure under these guarantees | 0.3 | 0.3 | |||||||
Bonds with indemnity protection | 32.4 | 32.1 | |||||||
Indemnification Agreements | |||||||||
In connection with the sale of certain Texas electric transmission assets to Sharyland Distribution and Transmission Services, LLC. in 2013, SPS agreed to indemnify the purchaser for losses arising out of any breach of the representations, warranties and covenants under the related asset purchase agreement and for losses arising out of certain other matters, including pre-closing liabilities. SPS’ indemnification obligation is capped at $37.1 million, in the aggregate. The indemnification provisions for most representations and warranties expire in December 2014. The remaining representations and warranties, which relate to due organization and transaction authorization, survive indefinitely. As of March 31, 2014 and Dec. 31, 2013, SPS has recorded a $0.4 million liability related to this indemnity. | |||||||||
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. For the Sediments at the Ashland Site, the ROD preferred remedy is a hybrid remedy involving both dry excavation and wet conventional dredging methodologies (the Hybrid Remedy). The ROD also identifies the possibility of a wet conventional dredging only remedy for the Sediments (the Wet Dredge), contingent upon the completion of a successful Wet Dredge pilot study. | |||||||||
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 settlement negotiations with NSP-Wisconsin, 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, 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 cleanup of the Phase I Project Area of $40 million. Demolition activities occurred at the Ashland site in 2013. The Final Design for the soil, including excavation and treatment, as well as containment wall remedies was submitted to the EPA in April 2014 and work is anticipated to begin in the second quarter of 2014. A Preliminary Design for the groundwater remedy was also submitted to the EPA in April 2014 and activities are expected to commence in 2015. Based on these updated designs, the updated cost estimate for the cleanup of the Phase I Project Area is approximately $51 million, of which $5 million has already been spent. 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 are ongoing between the EPA and NSP-Wisconsin regarding who will pay or perform the cleanup of the Sediments and what remedy will be implemented at the site to address the Sediments. 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 was received and reported to the EPA at the end of 2013. It is NSP-Wisconsin’s view that this data demonstrates the Hybrid Remedy is not safe or feasible to implement. The EPA’s ROD for the Ashland site includes estimates that the cost of the Hybrid Remedy is between $63 million and $77 million, with a potential deviation in such estimated costs of up to 50 percent higher to 30 percent lower. 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. In November 2013, NSP-Wisconsin submitted a revised Wet Dredge pilot study work plan proposal to the EPA. The EPA provided conditional approval of the Wet Dredge pilot study work plan in March 2014. NSP-Wisconsin is in the process of negotiating a final Administrative Order on Consent for the Wet Dredge pilot study for possible implementation of the pilot in late summer or early fall of 2014. | |||||||||
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 is scheduled 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 March 31, 2014 and Dec. 31, 2013, NSP-Wisconsin had recorded a liability of $115.2 million and $104.6 million, respectively, for the Ashland site based upon potential remediation and design costs together with estimated outside legal and consultant costs; of which $33.4 million and $25.2 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 Public Service Commission of Wisconsin (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 2013 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. In the 2014 rate case decision, the PSCW continued the cost recovery treatment established in the 2013 rate case, with respect to the 2013 and 2014 cleanup costs for the Phase I Project Area. The PSCW determined the timing of the cleanup of the Sediments was uncertain and declined NSP-Wisconsin’s request to begin cost recovery for this portion of the cleanup in 2014 rates. However, the PSCW allowed NSP-Wisconsin to increase its 2014 amortization expense related to the cleanup by an additional $1.1 million to offset the need for a rate decrease for the natural gas utility. The cost recovery treatment granted by the PSCW in the 2013 and 2014 rate cases will help mitigate the rate impact to natural gas customers and the risk to NSP-Wisconsin from a longer amortization period. | |||||||||
Environmental Requirements | |||||||||
Water and waste | |||||||||
Federal Clean Water Act (CWA) 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. The final rule is now expected in September 2015. 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. | |||||||||
Federal CWA Section 316 (b) — The federal CWA requires the EPA to regulate cooling water intake structures to assure that these structures reflect the best technology available for minimizing adverse environmental impacts to aquatic species. In 2011, the EPA published the proposed rule that sets standards for minimization of aquatic species impingement, but leaves entrainment reduction requirements at the discretion of the permit writer and the regional EPA office. A final rule is anticipated in May 2014. It is not possible to provide an accurate estimate of the overall cost of this rulemaking at this time due to the uncertainty of the final regulatory requirements. | |||||||||
NSP-Minnesota submitted its Black Dog CWA compliance plan for the Minnesota Pollution Control Agency’s (MPCA) review and approval in 2010. The MPCA is currently reviewing the proposal in consultation with the EPA. | |||||||||
Air | |||||||||
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 nitrous oxide (NOx) from utilities in the eastern half of the United States. For Xcel Energy, the rule would apply in Minnesota, Wisconsin and Texas. The CSAPR would set more stringent requirements than the proposed Clean Air Transport Rule and require plants in Texas to reduce their SO2 and annual NOx emissions. The rule would also create an emissions trading program. | |||||||||
In August 2012, the United States 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 the EPA must continue administering the Clean Air Interstate Rule (CAIR) pending adoption of a valid replacement. In April 2014, the U.S. Supreme Court reversed and remanded the case to the D.C. Circuit. The Court held that the EPA’s rule design did not violate the Clean Air Act (CAA) and that states had received adequate opportunity to develop their own plans. Because the D.C. Circuit overturned the CSAPR on two over-arching issues, there are many other issues the D.C. Circuit did not rule on that will now need to be considered on remand. Because it is not yet known how the litigation over the remaining issues will be resolved, it is not yet known what requirements may be imposed in the future, or their timing. | |||||||||
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 currently 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 2013 and plans to continue to purchase allowances in 2014 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 the second quarter of 2014. These installations will reduce or eliminate SPS’ need to purchase NOx emission allowances. SPS had sufficient SO2 allowances to comply with the CAIR in 2013 and has sufficient allowances through 2015. At March 31, 2014, 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. | |||||||||
Regional Haze Rules — In 2005, the EPA amended the best available retrofit technology (BART) requirements of its regional haze rules, which require the installation and operation of emission controls for industrial facilities emitting air pollutants that reduce visibility in certain national parks and wilderness areas. In their first regional haze state implementation plan (SIP), Colorado, Minnesota and Texas identified the Xcel Energy facilities that will have to reduce SO2, NOx and PM emissions under BART and set emissions limits for those facilities. | |||||||||
PSCo | |||||||||
In 2011, the Colorado Air Quality Control Commission approved a SIP (the Colorado SIP) that included the CACJA emission reduction plan as satisfying regional haze requirements for the facilities included in the CACJA plan. In addition, the Colorado SIP included a BART determination for Comanche Units 1 and 2. The EPA approved the Colorado SIP in 2012. Emission controls at the Hayden and Pawnee plants are projected to cost $359.7 million and are expected to be installed between 2014 and 2017. PSCo anticipates these costs will be fully recoverable in rates. | |||||||||
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 it will challenge the BART determination made for Comanche Units 1 and 2. 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 intervened in the case. The 10th Circuit is anticipated to hear argument in January 2015, following completion of the briefs in October 2014. | |||||||||
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 the Colorado BART rule is inadequate to satisfy the 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 MPCA approved a SIP (the Minnesota SIP) and submitted it to the EPA for approval. The MPCA’s source-specific BART limits for Sherco Units 1 and 2 require combustion controls for NOx and scrubber upgrades for SO2. The MPCA concluded SCRs should not be required because the minor visibility benefits derived from SCRs do not outweigh the substantial costs. The combustion controls have been installed and the scrubber upgrades, to be completed by January 2015, are underway. These emission controls are projected to cost approximately $50 million, of which $42.5 million has already been spent. NSP-Minnesota anticipates these costs will be fully recoverable in rates. | |||||||||
After the CSAPR was adopted in 2011, the MPCA supplemented its Minnesota SIP, determining that CSAPR meets BART requirements, but also implementing its source-specific BART determination for Sherco Units 1 and 2 from the 2009 Minnesota SIP. In June 2012, 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. NSP-Minnesota and other regulated parties were denied intervention. In June 2013, the Court ordered this case to be held in abeyance until the U.S. Supreme Court decides on the CSAPR. It is not yet known how the U.S. Supreme Court’s April 2014 decision on the CSAPR will impact the Eighth Circuit’s proceedings on the Minnesota SIP. If this litigation ultimately results in further EPA proceedings concerning the Minnesota SIP, such proceedings may consider whether SCRs should be required for Sherco Units 1 and 2. | |||||||||
SPS | |||||||||
Harrington Units 1 and 2 are potentially subject to BART. Texas 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 U.S. Supreme Court’s April 2014 decision on the CSAPR may impact the EPA’s approval of the Texas SIP. | |||||||||
Reasonably Attributable Visibility Impairment (RAVI) — Additional visibility rules relate to a program called the 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 has stated it 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 the EPA has failed to perform a nondiscretionary duty to determine BART for Sherco Units 1 and 2 under the RAVI program. The EPA filed an answer denying the allegations. 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. Oral arguments were held in March 2014. The court is expected to issue an opinion in the next few months. | |||||||||
Legal Contingencies | |||||||||
Xcel Energy is involved in various litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or is a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Management maintains accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss. For current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Xcel Energy’s financial statements. Unless otherwise required by GAAP, legal fees are expensed as incurred. | |||||||||
Employment, Tort and Commercial Litigation | |||||||||
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, including a pending appeal by SPS in the Fifth Circuit Court of Appeals. 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 hearing in this case was held before a FERC ALJ and concluded in October 2013. On March 28, 2014, the FERC ALJ issued an initial decision which rejected all of the City of Seattle’s claims against PSCo and other respondents. With respect to the period Jan. 1, 2000 through Dec. 24, 2000, the FERC ALJ rejected the City of Seattle’s assertion that any of the sales made to the City of Seattle resulted in an excessive burden to the City of Seattle, the applicable legal standard for the City of Seattle’s challenges during this period. With respect to the period Dec. 25, 2000 through June 20, 2001, the FERC ALJ concluded that the City of Seattle had failed to establish a causal link between any contracts and any claimed unlawful market activity, the standard required by the FERC in its remand order. The City of Seattle may contest the FERC ALJ’s initial decision by filing a brief on exceptions to the FERC. | |||||||||
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. | |||||||||
Biomass Fuel Handling Reimbursement — NSP-Minnesota has a PPA through which it procures energy from Fibrominn, LLC (Fibrominn). Under this agreement, NSP-Minnesota is charged for certain costs of transporting biomass fuels that are delivered to Fibrominn’s generation facility. Fibrominn has demanded that NSP-Minnesota provide additional cost reimbursement for the period from September 2007 through March 2014, totaling approximately $19 million. NSP-Minnesota has evaluated Fibrominn’s claim and based on the terms of the PPA with Fibrominn and its current understanding of the facts, NSP-Minnesota disputes the validity of Fibrominn’s claim, on the ground that, among other things, it seeks to impose contractual obligations on NSP-Minnesota that are neither supported by the terms nor the intent of the PPA. NSP-Minnesota has concluded that a loss is reasonably possible with respect to this matter; however, given the surrounding uncertainties, NSP-Minnesota is currently unable to determine the amount of reasonably possible loss. If a loss were sustained, NSP-Minnesota would attempt to recover these fuel-related costs. 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. In January 2014, the United States proposed, and NSP-Minnesota accepted, an extension to the settlement agreement which will allow NSP-Minnesota to recover spent fuel storage costs through 2016. The extension does not address costs for used fuel storage after 2016; such costs could be the subject of future litigation. NSP-Minnesota has received a total of $181.9 million of settlement proceeds as of March 31, 2014. Amounts received from the installments will be subsequently credited to customers, except for approved reductions such as legal costs and amounts set aside to be credited through another regulatory mechanism. |
Borrowings_and_Other_Financing
Borrowings and Other Financing Instruments | 3 Months Ended | ||||||||||||
Mar. 31, 2014 | |||||||||||||
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 | |||||||||||
March 31, 2014 | Dec. 31, 2013 | ||||||||||||
Borrowing limit | $ | 2,450 | $ | 2,450 | |||||||||
Amount outstanding at period end | 765 | 759 | |||||||||||
Average amount outstanding | 925 | 481 | |||||||||||
Maximum amount outstanding | 1,200 | 1,160 | |||||||||||
Weighted average interest rate, computed on a daily basis | 0.31 | % | 0.31 | % | |||||||||
Weighted average interest rate at period end | 0.33 | 0.25 | |||||||||||
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 March 31, 2014 and Dec. 31, 2013, there were $46.3 million and $47.8 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. | |||||||||||||
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 March 31, 2014, 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 | $ | 487 | $ | 313 | |||||||
PSCo | 700 | 6.5 | 693.5 | ||||||||||
NSP-Minnesota | 500 | 148.9 | 351.1 | ||||||||||
SPS | 300 | 90 | 210 | ||||||||||
NSP-Wisconsin | 150 | 79 | 71 | ||||||||||
Total | $ | 2,450.00 | $ | 811.4 | $ | 1,638.60 | |||||||
(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 March 31, 2014 and Dec. 31, 2013. | |||||||||||||
During the second quarter of 2014, Xcel Energy plans to work with its bank group to amend and extend the existing revolving credit agreements for Xcel Energy Inc. and each of the regulated subsidiaries. | |||||||||||||
Long-Term Borrowings and Other Financing Instruments | |||||||||||||
PSCo — In March 2014, PSCo issued $300 million of 4.30 percent first mortgage bonds due March 15, 2044. | |||||||||||||
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. During the three months ended March 31, 2014, Xcel Energy Inc. issued 2.1 million shares of common stock through this program and received cash proceeds of $62 million, net of $1 million in fees and commissions. During the year ended Dec. 31, 2013, 7.7 million shares of common stock were issued under the program and Xcel Energy Inc. received cash proceeds of $223 million, net of $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. | |||||||||||||
Xcel Energy Inc. had commitments not recognized on the consolidated balance sheet at March 31, 2014 to sell 0.5 million shares of common stock under sales transactions entered into during the last three trading days of March 2014. Subsequent to March 31, 2014, Xcel Energy Inc. issued shares to settle these transactions in exchange for cash proceeds of $16 million, net of $0.2 million in fees and commissions. |
Fair_Value_of_Financial_Assets
Fair Value of Financial Assets and Liabilities | 3 Months Ended | ||||||||||||||||||||||||
Mar. 31, 2014 | |||||||||||||||||||||||||
Fair Value Disclosures [Abstract] | ' | ||||||||||||||||||||||||
Fair Value of Financial Assets and Liabilities | ' | ||||||||||||||||||||||||
Fair Value of Financial Assets and Liabilities | |||||||||||||||||||||||||
Fair Value Measurements | |||||||||||||||||||||||||
The accounting guidance for fair value measurements and disclosures provides a single definition of fair value and requires certain disclosures about assets and liabilities measured at fair value. A hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value is established by this guidance. The three levels in the hierarchy are as follows: | |||||||||||||||||||||||||
Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices. | |||||||||||||||||||||||||
Level 2 — Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reporting date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, or priced with models using highly observable inputs. | |||||||||||||||||||||||||
Level 3 — Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 are those valued with models requiring significant management judgment or estimation. | |||||||||||||||||||||||||
Specific valuation methods include the following: | |||||||||||||||||||||||||
Cash equivalents — The fair values of cash equivalents are generally based on cost plus accrued interest; money market funds are measured using quoted 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 redemption rights, 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 transmission congestion instruments purchased from Midcontinent Independent Transmission System Operator, Inc. (MISO), PJM Interconnection, LLC (PJM), Electric Reliability Council of Texas (ERCOT), Southwest Power Pool, Inc. (SPP) and New York Independent System Operator, generally referred to as financial transmission rights (FTRs). Electric commodity derivatives held by SPS include FTRs purchased from SPP. FTRs purchased from a regional transmission organization (RTO) are financial instruments that entitle or obligate the holder to monthly revenues or charges based on transmission congestion across a given transmission path. The value of an FTR is derived from, and designed to offset, the cost of energy congestion, which is caused by 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. The valuation process for FTRs utilizes complex iterative modeling to predict the impacts of forecasted changes in these drivers of transmission system congestion on the historical pricing of FTR purchases. | |||||||||||||||||||||||||
If forecasted costs of electric transmission congestion increase or decrease for a given FTR path, the value of that particular FTR instrument will likewise increase or decrease. Given the limited observability of management’s forecasts for several of the inputs to this complex valuation model – 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 and purchased energy cost recovery mechanisms as applicable in each jurisdiction, and therefore changes in the fair value of the yet to be settled portions of most FTRs are deferred as a regulatory asset or liability. Given this regulatory treatment and the limited magnitude of FTRs relative to the electric utility operations of NSP-Minnesota and SPS, the numerous unobservable quantitative inputs to the complex model used for valuation of FTRs are insignificant to the consolidated financial statements of Xcel Energy. | |||||||||||||||||||||||||
Non-Derivative Instruments Fair Value Measurements | |||||||||||||||||||||||||
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. NSP-Minnesota uses the MPUC approved asset allocation for the escrow and investment targets by asset class for both the escrow and qualified trust. | |||||||||||||||||||||||||
NSP-Minnesota recognizes the costs of funding the decommissioning of its nuclear generating plants over the lives of the plants, assuming rate recovery of all costs. 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 $258.6 million and $240.3 million at March 31, 2014 and Dec. 31, 2013, respectively, and unrealized losses and amounts recorded as other-than-temporary impairments were $45.8 million and $58.5 million at March 31, 2014 and Dec. 31, 2013, 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 March 31, 2014 and Dec. 31, 2013: | |||||||||||||||||||||||||
March 31, 2014 | |||||||||||||||||||||||||
Fair Value | |||||||||||||||||||||||||
(Thousands of Dollars) | Cost | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||
Nuclear decommissioning fund (a) | |||||||||||||||||||||||||
Cash equivalents | $ | 15,854 | $ | 15,854 | $ | — | $ | — | $ | 15,854 | |||||||||||||||
Commingled funds | 476,011 | — | 483,409 | — | 483,409 | ||||||||||||||||||||
International equity funds | 78,812 | — | 82,710 | — | 82,710 | ||||||||||||||||||||
Private equity investments | 60,912 | — | — | 73,801 | 73,801 | ||||||||||||||||||||
Real estate | 49,224 | — | — | 62,954 | 62,954 | ||||||||||||||||||||
Debt securities: | |||||||||||||||||||||||||
Government securities | 34,176 | — | 28,822 | — | 28,822 | ||||||||||||||||||||
U.S. corporate bonds | 78,362 | — | 81,827 | — | 81,827 | ||||||||||||||||||||
International corporate bonds | 15,223 | — | 15,685 | — | 15,685 | ||||||||||||||||||||
Municipal bonds | 261,106 | — | 260,044 | — | 260,044 | ||||||||||||||||||||
Equity securities: | |||||||||||||||||||||||||
Common stock | 380,896 | 558,289 | — | — | 558,289 | ||||||||||||||||||||
Total | $ | 1,450,576 | $ | 574,143 | $ | 952,497 | $ | 136,755 | $ | 1,663,395 | |||||||||||||||
(a) | Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $86.3 million of equity investments in unconsolidated subsidiaries and $43.4 million of miscellaneous investments. | ||||||||||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||||||||||
Fair Value | |||||||||||||||||||||||||
(Thousands of Dollars) | Cost | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||
Nuclear decommissioning fund (a) | |||||||||||||||||||||||||
Cash equivalents | $ | 33,281 | $ | 33,281 | $ | — | $ | — | $ | 33,281 | |||||||||||||||
Commingled funds | 457,986 | — | 452,227 | — | 452,227 | ||||||||||||||||||||
International equity funds | 78,812 | — | 81,671 | — | 81,671 | ||||||||||||||||||||
Private equity investments | 52,143 | — | — | 62,696 | 62,696 | ||||||||||||||||||||
Real estate | 45,564 | — | — | 57,368 | 57,368 | ||||||||||||||||||||
Debt securities: | |||||||||||||||||||||||||
Government securities | 34,304 | — | 27,628 | — | 27,628 | ||||||||||||||||||||
U.S. corporate bonds | 80,275 | — | 83,538 | — | 83,538 | ||||||||||||||||||||
International corporate bonds | 15,025 | — | 15,358 | — | 15,358 | ||||||||||||||||||||
Municipal bonds | 241,112 | — | 232,016 | — | 232,016 | ||||||||||||||||||||
Equity securities: | |||||||||||||||||||||||||
Common stock | 406,695 | 581,243 | — | — | 581,243 | ||||||||||||||||||||
Total | $ | 1,445,197 | $ | 614,524 | $ | 892,438 | $ | 120,064 | $ | 1,627,026 | |||||||||||||||
(a) | Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $87.1 million of equity investments in unconsolidated subsidiaries and $41.9 million of miscellaneous investments. | ||||||||||||||||||||||||
The following tables present the changes in Level 3 nuclear decommissioning fund investments for the three months ended March 31, 2014 and 2013: | |||||||||||||||||||||||||
(Thousands of Dollars) | Jan. 1, 2014 | Purchases | Settlements | Gains Recognized as Regulatory Assets | Transfers Out of Level 3 | March 31, 2014 | |||||||||||||||||||
Private equity investments | $ | 62,696 | $ | 8,769 | $ | — | $ | 2,336 | $ | — | $ | 73,801 | |||||||||||||
Real estate | 57,368 | 3,660 | — | 1,926 | — | 62,954 | |||||||||||||||||||
Total | $ | 120,064 | $ | 12,429 | $ | — | $ | 4,262 | $ | — | $ | 136,755 | |||||||||||||
(Thousands of Dollars) | Jan. 1, 2013 | Purchases | Settlements | Gains Recognized as Regulatory Assets | Transfers Out of Level 3(a) | March 31, 2013 | |||||||||||||||||||
Private equity investments | $ | 33,250 | $ | 1,256 | $ | — | $ | — | $ | — | $ | 34,506 | |||||||||||||
Real estate | 39,074 | 4,786 | (4,299 | ) | 845 | — | 40,406 | ||||||||||||||||||
Asset-backed securities | 2,067 | — | — | — | (2,067 | ) | — | ||||||||||||||||||
Mortgage-backed securities | 30,209 | — | — | — | (30,209 | ) | — | ||||||||||||||||||
Total | $ | 104,600 | $ | 6,042 | $ | (4,299 | ) | $ | 845 | $ | (32,276 | ) | $ | 74,912 | |||||||||||
(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. | ||||||||||||||||||||||||
The following table summarizes the final contractual maturity dates of the debt securities in the nuclear decommissioning fund, by asset class, at March 31, 2014: | |||||||||||||||||||||||||
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 | $ | — | $ | — | $ | — | $ | 28,822 | $ | 28,822 | |||||||||||||||
U.S. corporate bonds | 311 | 15,816 | 64,341 | 1,359 | 81,827 | ||||||||||||||||||||
International corporate bonds | — | 3,762 | 11,923 | — | 15,685 | ||||||||||||||||||||
Municipal bonds | 3,088 | 25,410 | 38,770 | 192,776 | 260,044 | ||||||||||||||||||||
Debt securities | $ | 3,399 | $ | 44,988 | $ | 115,034 | $ | 222,957 | $ | 386,378 | |||||||||||||||
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 March 31, 2014, 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, FTRs and vehicle fuel. | |||||||||||||||||||||||||
At March 31, 2014, 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 months ended March 31, 2014 and 2013. | |||||||||||||||||||||||||
At March 31, 2014, 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 March 31, 2014 and Dec. 31, 2013: | |||||||||||||||||||||||||
(Amounts in Thousands) (a)(b) | March 31, 2014 | Dec. 31, 2013 | |||||||||||||||||||||||
Megawatt hours of electricity | 32,453 | 58,423 | |||||||||||||||||||||||
Million British thermal units of natural gas | — | 9,854 | |||||||||||||||||||||||
Gallons of vehicle fuel | 432 | 482 | |||||||||||||||||||||||
(a) | Amounts are not reflective of net positions in the underlying commodities. | ||||||||||||||||||||||||
(b) | Notional amounts for options are included on a gross basis, but are weighted for the probability of exercise. | ||||||||||||||||||||||||
The following tables detail the impact of derivative activity during the three months ended March 31, 2014 and 2013, on accumulated other comprehensive loss, regulatory assets and liabilities, and income: | |||||||||||||||||||||||||
Three Months Ended March 31, 2014 | |||||||||||||||||||||||||
Pre-Tax Fair Value Gains (Losses) Recognized During the Period in: | Pre-Tax (Gains) Losses Reclassified into Income During the Period from: | Pre-Tax Gains (Losses) Recognized During the Period in Income | |||||||||||||||||||||||
(Thousands of Dollars) | Accumulated Other Comprehensive Loss | Regulatory (Assets) and Liabilities | Accumulated Other Comprehensive Loss | Regulatory Assets and (Liabilities) | |||||||||||||||||||||
Derivatives designated as cash flow hedges | |||||||||||||||||||||||||
Interest rate | $ | — | $ | — | $ | 946 | (a) | $ | — | $ | — | ||||||||||||||
Vehicle fuel and other commodity | (12 | ) | — | (28 | ) | (b) | — | — | |||||||||||||||||
Total | $ | (12 | ) | $ | — | $ | 918 | $ | — | $ | — | ||||||||||||||
Other derivative instruments | |||||||||||||||||||||||||
Commodity trading | $ | — | $ | — | $ | — | $ | — | $ | (2,253 | ) | (c) | |||||||||||||
Electric commodity | — | 3,527 | — | (20,696 | ) | (d) | — | ||||||||||||||||||
Natural gas commodity | — | 18,506 | — | (18,840 | ) | (e) | (5,302 | ) | (e) | ||||||||||||||||
Total | $ | — | $ | 22,033 | $ | — | $ | (39,536 | ) | $ | (7,555 | ) | |||||||||||||
Three Months Ended March 31, 2013 | |||||||||||||||||||||||||
Pre-Tax Fair Value Gains (Losses) Recognized During the Period in: | Pre-Tax (Gains) Losses Reclassified into Income During the Period from: | Pre-Tax Gains (Losses) Recognized During the Period in Income | |||||||||||||||||||||||
(Thousands of Dollars) | Accumulated Other Comprehensive Loss | Regulatory (Assets) and Liabilities | Accumulated Other Comprehensive Loss | Regulatory Assets and (Liabilities) | |||||||||||||||||||||
Derivatives designated as cash flow hedges | |||||||||||||||||||||||||
Interest rate | $ | — | $ | — | $ | 1,150 | (a) | $ | — | $ | — | ||||||||||||||
Vehicle fuel and other commodity | 25 | — | (26 | ) | (b) | — | — | ||||||||||||||||||
Total | $ | 25 | $ | — | $ | 1,124 | $ | — | $ | — | |||||||||||||||
Other derivative instruments | |||||||||||||||||||||||||
Commodity trading | $ | — | $ | — | $ | — | $ | — | $ | 2,776 | (c) | ||||||||||||||
Electric commodity | — | 6,419 | — | (15,229 | ) | (d) | — | ||||||||||||||||||
Natural gas commodity | — | 54 | — | 9 | (e) | 16 | (e) | ||||||||||||||||||
Total | $ | — | $ | 6,473 | $ | — | $ | (15,220 | ) | $ | 2,792 | ||||||||||||||
(a) | Amounts are recorded to interest charges. | ||||||||||||||||||||||||
(b) | Amounts are recorded to O&M expenses. | ||||||||||||||||||||||||
(c) | Amounts are recorded to electric operating revenues. Portions of these gains and losses are subject to sharing with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate. | ||||||||||||||||||||||||
(d) | Amounts are recorded to electric fuel and purchased power. These derivative settlement gain and loss amounts are shared with electric customers through fuel and purchased energy cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate. | ||||||||||||||||||||||||
(e) | Amounts for the three months ended March 31, 2014 and 2013 included immaterial settlement losses on derivatives entered to mitigate natural gas price risk for electric generation, recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate. The remaining derivative settlement gains and losses for the three months ended March 31, 2014 and 2013 relate to natural gas operations and are recorded to cost of natural gas sold and transported. These gains and losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset or liability, as appropriate. | ||||||||||||||||||||||||
Xcel Energy had no derivative instruments designated as fair value hedges during the three months ended March 31, 2014 and 2013. Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for these periods. | |||||||||||||||||||||||||
Consideration of Credit Risk and Concentrations — Xcel Energy 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 and transmission activities. At March 31, 2014, four of Xcel Energy’s 10 most significant counterparties for these activities, comprising $41.2 million or 15 percent of this credit exposure, had investment grade credit ratings from Standard & Poor’s Ratings Services, Moody’s Investor Services (Moody’s) or Fitch Ratings. The remaining six significant counterparties, comprising $79.2 million or 29 percent of this credit exposure, were not rated by these agencies, but based on Xcel Energy’s internal analysis, had credit quality consistent with investment grade. All 10 of these significant counterparties are RTOs, municipal or cooperative electric entities or other utilities. | |||||||||||||||||||||||||
Credit Related Contingent Features — Contract provisions for derivative instruments that the utility subsidiaries enter, including those recorded to the consolidated balance sheet at fair value, as well as those accounted for as normal purchase-normal sale (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 $1.1 million and $1.4 million gross liability position on the consolidated balance sheets at March 31, 2014 and Dec. 31, 2013, respectively, would have required Xcel Energy Inc.’s utility subsidiaries to post collateral or settle applicable outstanding contracts, including other contracts subject to master netting agreements, which would have resulted in payments of $1.1 million and $1.4 million at March 31, 2014 and Dec. 31, 2013, respectively. At March 31, 2014 and Dec. 31, 2013, 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 March 31, 2014 and Dec. 31, 2013. | |||||||||||||||||||||||||
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 March 31, 2014: | |||||||||||||||||||||||||
March 31, 2014 | |||||||||||||||||||||||||
Fair Value | Fair Value Total | Counterparty Netting (b) | Total | ||||||||||||||||||||||
(Thousands of Dollars) | Level 1 | Level 2 | Level 3 | ||||||||||||||||||||||
Current derivative assets | |||||||||||||||||||||||||
Derivatives designated as cash flow hedges: | |||||||||||||||||||||||||
Vehicle fuel and other commodity | $ | — | $ | 58 | $ | — | $ | 58 | $ | — | $ | 58 | |||||||||||||
Other derivative instruments: | |||||||||||||||||||||||||
Commodity trading | — | 20,979 | 944 | 21,923 | (6,467 | ) | 15,456 | ||||||||||||||||||
Electric commodity | — | — | 26,640 | 26,640 | (4,907 | ) | 21,733 | ||||||||||||||||||
Total current derivative assets | $ | — | $ | 21,037 | $ | 27,584 | $ | 48,621 | $ | (11,374 | ) | 37,247 | |||||||||||||
PPAs (a) | 33,028 | ||||||||||||||||||||||||
Current derivative instruments | $ | 70,275 | |||||||||||||||||||||||
Noncurrent derivative assets | |||||||||||||||||||||||||
Derivatives designated as cash flow hedges: | |||||||||||||||||||||||||
Vehicle fuel and other commodity | $ | — | $ | 18 | $ | — | $ | 18 | $ | — | $ | 18 | |||||||||||||
Other derivative instruments: | |||||||||||||||||||||||||
Commodity trading | — | 15,718 | 1,932 | 17,650 | (407 | ) | 17,243 | ||||||||||||||||||
Total noncurrent derivative assets | $ | — | $ | 15,736 | $ | 1,932 | $ | 17,668 | $ | (407 | ) | 17,261 | |||||||||||||
PPAs (a) | 50,252 | ||||||||||||||||||||||||
Noncurrent derivative instruments | $ | 67,513 | |||||||||||||||||||||||
Current derivative liabilities | |||||||||||||||||||||||||
Other derivative instruments: | |||||||||||||||||||||||||
Commodity trading | $ | — | $ | 11,946 | $ | 392 | $ | 12,338 | $ | (12,338 | ) | $ | — | ||||||||||||
Electric commodity | — | — | 4,907 | 4,907 | (4,907 | ) | — | ||||||||||||||||||
Total current derivative liabilities | $ | — | $ | 11,946 | $ | 5,299 | $ | 17,245 | $ | (17,245 | ) | — | |||||||||||||
PPAs (a) | 22,358 | ||||||||||||||||||||||||
Current derivative instruments | $ | 22,358 | |||||||||||||||||||||||
Noncurrent derivative liabilities | |||||||||||||||||||||||||
Other derivative instruments: | |||||||||||||||||||||||||
Commodity trading | $ | — | $ | 1,707 | $ | — | $ | 1,707 | $ | (1,015 | ) | $ | 692 | ||||||||||||
Total noncurrent derivative liabilities | $ | — | $ | 1,707 | $ | — | $ | 1,707 | $ | (1,015 | ) | 692 | |||||||||||||
PPAs (a) | 198,886 | ||||||||||||||||||||||||
Noncurrent derivative instruments | $ | 199,578 | |||||||||||||||||||||||
(a) | In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, Xcel Energy began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, Xcel Energy qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities. | ||||||||||||||||||||||||
(b) | Xcel Energy nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at March 31, 2014. At March 31, 2014, derivative assets and liabilities include obligations to return cash collateral of $0.1 million and rights to reclaim cash collateral of $6.5 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, 2013: | |||||||||||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||||||||||
Fair Value | Fair Value Total | Counterparty Netting (b) | Total | ||||||||||||||||||||||
(Thousands of Dollars) | Level 1 | Level 2 | Level 3 | ||||||||||||||||||||||
Current derivative assets | |||||||||||||||||||||||||
Derivatives designated as cash flow hedges: | |||||||||||||||||||||||||
Vehicle fuel and other commodity | $ | — | $ | 88 | $ | — | $ | 88 | $ | — | $ | 88 | |||||||||||||
Other derivative instruments: | |||||||||||||||||||||||||
Commodity trading | — | 20,610 | 1,167 | 21,777 | (7,994 | ) | 13,783 | ||||||||||||||||||
Electric commodity | — | — | 47,112 | 47,112 | (8,210 | ) | 38,902 | ||||||||||||||||||
Natural gas commodity | — | 5,906 | — | 5,906 | — | 5,906 | |||||||||||||||||||
Total current derivative assets | $ | — | $ | 26,604 | $ | 48,279 | $ | 74,883 | $ | (16,204 | ) | 58,679 | |||||||||||||
PPAs (a) | 33,028 | ||||||||||||||||||||||||
Current derivative instruments | $ | 91,707 | |||||||||||||||||||||||
Noncurrent derivative assets | |||||||||||||||||||||||||
Derivatives designated as cash flow hedges: | |||||||||||||||||||||||||
Vehicle fuel and other commodity | $ | — | $ | 29 | $ | — | $ | 29 | $ | (16 | ) | $ | 13 | ||||||||||||
Other derivative instruments: | |||||||||||||||||||||||||
Commodity trading | — | 32,074 | 3,395 | 35,469 | (9,071 | ) | 26,398 | ||||||||||||||||||
Total noncurrent derivative assets | $ | — | $ | 32,103 | $ | 3,395 | $ | 35,498 | $ | (9,087 | ) | 26,411 | |||||||||||||
PPAs (a) | 58,431 | ||||||||||||||||||||||||
Noncurrent derivative instruments | $ | 84,842 | |||||||||||||||||||||||
Current derivative liabilities | |||||||||||||||||||||||||
Other derivative instruments: | |||||||||||||||||||||||||
Commodity trading | $ | — | $ | 10,546 | $ | 1,804 | $ | 12,350 | $ | (12,002 | ) | $ | 348 | ||||||||||||
Electric commodity | — | — | 8,210 | 8,210 | (8,210 | ) | — | ||||||||||||||||||
Total current derivative liabilities | $ | — | $ | 10,546 | $ | 10,014 | $ | 20,560 | $ | (20,212 | ) | 348 | |||||||||||||
PPAs (a) | 23,034 | ||||||||||||||||||||||||
Current derivative instruments | $ | 23,382 | |||||||||||||||||||||||
Noncurrent derivative liabilities | |||||||||||||||||||||||||
Other derivative instruments: | |||||||||||||||||||||||||
Commodity trading | $ | — | $ | 14,382 | $ | — | $ | 14,382 | $ | (9,087 | ) | $ | 5,295 | ||||||||||||
Total noncurrent derivative liabilities | $ | — | $ | 14,382 | $ | — | $ | 14,382 | $ | (9,087 | ) | 5,295 | |||||||||||||
PPAs (a) | 203,929 | ||||||||||||||||||||||||
Noncurrent derivative instruments | $ | 209,224 | |||||||||||||||||||||||
(a) | In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, Xcel Energy began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, Xcel Energy qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities. | ||||||||||||||||||||||||
(b) | Xcel Energy nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2013. At Dec. 31, 2013, derivative assets and liabilities include obligations to return cash collateral of $0.2 million and rights to reclaim cash collateral of $4.2 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 months ended March 31, 2014 and 2013: | |||||||||||||||||||||||||
Three Months Ended March 31 | |||||||||||||||||||||||||
(Thousands of Dollars) | 2014 | 2013 | |||||||||||||||||||||||
Balance at Jan. 1 | $ | 41,660 | $ | 16,649 | |||||||||||||||||||||
Purchases | 1,056 | — | |||||||||||||||||||||||
Settlements | (53,809 | ) | (12,449 | ) | |||||||||||||||||||||
Net transactions recorded during the period: | |||||||||||||||||||||||||
Gains (losses) recognized in earnings (a) | 999 | (62 | ) | ||||||||||||||||||||||
Gains recognized as regulatory assets and liabilities | 34,311 | 3,504 | |||||||||||||||||||||||
Balance at March 31 | $ | 24,217 | $ | 7,642 | |||||||||||||||||||||
(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 months ended March 31, 2014 and 2013. | |||||||||||||||||||||||||
Fair Value of Long-Term Debt | |||||||||||||||||||||||||
As of March 31, 2014 and Dec. 31, 2013, other financial instruments for which the carrying amount did not equal fair value were as follows: | |||||||||||||||||||||||||
March 31, 2014 | Dec. 31, 2013 | ||||||||||||||||||||||||
(Thousands of Dollars) | Carrying Amount | Fair Value | Carrying Amount | Fair Value | |||||||||||||||||||||
Long-term debt, including current portion | $ | 11,487,452 | $ | 12,511,410 | $ | 11,191,517 | $ | 11,878,643 | |||||||||||||||||
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 March 31, 2014 and Dec. 31, 2013, and given the observability of the inputs to these estimates, the fair values presented for long-term debt have been assigned a Level 2. |
Other_Income_Net
Other Income, Net | 3 Months Ended | ||||||||
Mar. 31, 2014 | |||||||||
Other Income and Expenses [Abstract] | ' | ||||||||
Other Income, Net | ' | ||||||||
Other Income, Net | |||||||||
Other income, net consisted of the following: | |||||||||
Three Months Ended March 31 | |||||||||
(Thousands of Dollars) | 2014 | 2013 | |||||||
Interest income | $ | 3,893 | $ | 4,806 | |||||
Other nonoperating income | 1,116 | 1,255 | |||||||
Insurance policy expense | (1,808 | ) | (2,139 | ) | |||||
Other income, net | $ | 3,201 | $ | 3,922 | |||||
Segment_Information
Segment Information | 3 Months Ended | ||||||||||||||||||||
Mar. 31, 2014 | |||||||||||||||||||||
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 $86.3 million and $87.1 million as of March 31, 2014 and Dec. 31, 2013, respectively, included in the regulated natural gas utility segment. | |||||||||||||||||||||
Asset and capital expenditure information is not provided for Xcel Energy’s reportable segments because as an integrated electric and natural gas utility, Xcel Energy operates significant assets that are not dedicated to a specific business segment, and reporting assets and capital expenditures by business segment would require arbitrary and potentially misleading allocations which may not necessarily reflect the assets that would be required for the operation of the business segments on a stand-alone basis. | |||||||||||||||||||||
To report income from operations for regulated electric and regulated natural gas utility segments, the majority of costs are directly assigned to each segment. However, some costs, such as common depreciation, common O&M expenses and interest expense are allocated based on cost causation allocators. A general allocator is used for certain general and administrative expenses, including office supplies, rent, property insurance and general advertising. | |||||||||||||||||||||
(Thousands of Dollars) | Regulated Electric | Regulated Natural Gas | All Other | Reconciling Eliminations | Consolidated Total | ||||||||||||||||
Three Months Ended March 31, 2014 | |||||||||||||||||||||
Operating revenues from external customers | $ | 2,301,710 | $ | 879,688 | $ | 21,206 | $ | — | $ | 3,202,604 | |||||||||||
Intersegment revenues | 353 | 3,252 | — | (3,605 | ) | — | |||||||||||||||
Total revenues | $ | 2,302,063 | $ | 882,940 | $ | 21,206 | $ | (3,605 | ) | $ | 3,202,604 | ||||||||||
Net income (loss) | $ | 185,433 | $ | 77,336 | $ | (1,548 | ) | $ | — | $ | 261,221 | ||||||||||
(Thousands of Dollars) | Regulated Electric | Regulated Natural Gas | All Other | Reconciling Eliminations | Consolidated Total | ||||||||||||||||
Three Months Ended March 31, 2013 | |||||||||||||||||||||
Operating revenues from external customers | $ | 2,092,196 | $ | 669,596 | $ | 21,057 | $ | — | $ | 2,782,849 | |||||||||||
Intersegment revenues | 301 | 500 | — | (801 | ) | — | |||||||||||||||
Total revenues | $ | 2,092,497 | $ | 670,096 | $ | 21,057 | $ | (801 | ) | $ | 2,782,849 | ||||||||||
Net income (loss) | $ | 174,106 | $ | 64,910 | $ | (2,446 | ) | $ | — | $ | 236,570 | ||||||||||
Earnings_Per_Share
Earnings Per Share | 3 Months Ended | ||||||||||||||||||||||
Mar. 31, 2014 | |||||||||||||||||||||||
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 in share-based compensation arrangements. | |||||||||||||||||||||||
Common stock equivalents causing dilutive impact to EPS include commitments to issue common stock related to time based equity compensation awards and time based employer matching contributions to certain 401(k) plan participants. In October 2013, Xcel Energy determined that it would settle the 2013 401(k) employer matching contributions in cash instead of common stock for substantially all of its employees. Share-based compensation accounting for the impacted employee groups ceased in October 2013, and corresponding expense amounts recorded to equity were reclassified to a liability for expected cash settlements. | |||||||||||||||||||||||
Stock equivalent units granted to Xcel Energy Inc.’s Board of Directors are included in common shares outstanding upon grant date as there is no further service, performance or market condition associated with these awards. Restricted stock, granted to settle amounts due to certain employees under the Xcel Energy Inc. Executive Annual Incentive Award Plan, is included in common shares outstanding when granted. | |||||||||||||||||||||||
Share-based compensation arrangements for which there is currently no dilutive impact to EPS include the following: | |||||||||||||||||||||||
• | Equity awards subject to a performance condition; included in common shares outstanding when all necessary conditions for settlement have been satisfied by the end of the reporting period. | ||||||||||||||||||||||
• | Liability awards subject to a performance condition; any portions settled in shares are included in common shares outstanding upon settlement. | ||||||||||||||||||||||
The dilutive impact of common stock equivalents affecting EPS was as follows: | |||||||||||||||||||||||
Three Months Ended March 31, 2014 | Three Months Ended March 31, 2013 | ||||||||||||||||||||||
(Amounts in thousands, except per share data) | Income | Shares | Per Share | Income | Shares | Per Share | |||||||||||||||||
Amount | Amount | ||||||||||||||||||||||
Net income | $ | 261,221 | $ | 236,570 | |||||||||||||||||||
Basic EPS: | |||||||||||||||||||||||
Earnings available to common shareholders | 261,221 | 499,523 | $ | 0.52 | 236,570 | 489,781 | $ | 0.48 | |||||||||||||||
Effect of dilutive securities: | |||||||||||||||||||||||
Time based equity awards | — | 223 | — | 750 | |||||||||||||||||||
Diluted EPS: | |||||||||||||||||||||||
Earnings available to common shareholders | $ | 261,221 | 499,746 | $ | 0.52 | $ | 236,570 | 490,531 | $ | 0.48 | |||||||||||||
Benefit_Plans_and_Other_Postre
Benefit Plans and Other Postretirement Benefits | 3 Months Ended | ||||||||||||||||
Mar. 31, 2014 | |||||||||||||||||
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 March 31 | |||||||||||||||||
2014 | 2013 | 2014 | 2013 | ||||||||||||||
(Thousands of Dollars) | Pension Benefits | Postretirement Health Care Benefits | |||||||||||||||
Service cost | $ | 22,086 | $ | 24,071 | $ | 864 | $ | 1,182 | |||||||||
Interest cost | 39,155 | 35,172 | 8,507 | 8,417 | |||||||||||||
Expected return on plan assets | (51,801 | ) | (49,613 | ) | (8,489 | ) | (8,253 | ) | |||||||||
Amortization of transition obligation | — | — | — | 206 | |||||||||||||
Amortization of prior service (credit) cost | (437 | ) | 1,468 | (2,672 | ) | (2,438 | ) | ||||||||||
Amortization of net loss | 29,191 | 36,038 | 2,935 | 5,646 | |||||||||||||
Net periodic benefit cost | 38,194 | 47,136 | 1,145 | 4,760 | |||||||||||||
Costs not recognized due to the effects of regulation | (7,052 | ) | (7,847 | ) | — | — | |||||||||||
Net benefit cost recognized for financial reporting | $ | 31,142 | $ | 39,289 | $ | 1,145 | $ | 4,760 | |||||||||
In January 2014, contributions of $130.0 million were made across three of Xcel Energy’s pension plans. Xcel Energy does not expect additional pension contributions during 2014. |
Other_Comprehensive_Income
Other Comprehensive Income | 3 Months Ended | ||||||||||||||||
Mar. 31, 2014 | |||||||||||||||||
Stockholders' Equity Note [Abstract] | ' | ||||||||||||||||
Other Comprehensive Income | ' | ||||||||||||||||
Other Comprehensive Income | |||||||||||||||||
Changes in accumulated other comprehensive gain (loss), net of tax, for the three months ended March 31, 2014 and 2013 were as follows: | |||||||||||||||||
Three Months Ended March 31, 2014 | |||||||||||||||||
(Thousands of Dollars) | Gains and Losses on Cash Flow Hedges | Unrealized Gains and Losses on Marketable Securities | Defined Benefit Pension and Postretirement Items | Total | |||||||||||||
Accumulated other comprehensive gain (loss) at Jan. 1 | $ | (59,753 | ) | $ | 77 | $ | (46,599 | ) | $ | (106,275 | ) | ||||||
Other comprehensive gain (loss) before reclassifications | (7 | ) | 38 | — | 31 | ||||||||||||
Losses reclassified from net accumulated other comprehensive loss | 560 | — | 864 | 1,424 | |||||||||||||
Net current period other comprehensive income | 553 | 38 | 864 | 1,455 | |||||||||||||
Accumulated other comprehensive gain (loss) at March 31 | $ | (59,200 | ) | $ | 115 | $ | (45,735 | ) | $ | (104,820 | ) | ||||||
Three Months Ended March 31, 2013 | |||||||||||||||||
(Thousands of Dollars) | Gains and Losses on Cash Flow Hedges | Unrealized Gains and Losses on Marketable Securities | Defined Benefit Pension and Postretirement Items | Total | |||||||||||||
Accumulated other comprehensive loss at Jan. 1 | $ | (61,241 | ) | $ | (99 | ) | $ | (51,313 | ) | $ | (112,653 | ) | |||||
Other comprehensive gain (loss) before reclassifications | 13 | (36 | ) | — | (23 | ) | |||||||||||
Gains reclassified from net accumulated other comprehensive loss | (305 | ) | — | (639 | ) | (944 | ) | ||||||||||
Net current period other comprehensive loss | (292 | ) | (36 | ) | (639 | ) | (967 | ) | |||||||||
Accumulated other comprehensive loss at March 31 | $ | (61,533 | ) | $ | (135 | ) | $ | (51,952 | ) | $ | (113,620 | ) | |||||
Reclassifications from accumulated other comprehensive loss for the three months ended March 31, 2014 and 2013 were as follows: | |||||||||||||||||
Amounts Reclassified from Accumulated | |||||||||||||||||
Other Comprehensive Loss | |||||||||||||||||
(Thousands of Dollars) | Three Months Ended March 31, 2014 | Three Months Ended March 31, 2013 | |||||||||||||||
(Gains) losses on cash flow hedges: | |||||||||||||||||
Interest rate derivatives | $ | 946 | (a) | $ | 1,150 | (a) | |||||||||||
Vehicle fuel derivatives | (28 | ) | (b) | (26 | ) | (b) | |||||||||||
Total, pre-tax | 918 | 1,124 | |||||||||||||||
Tax benefit | (358 | ) | (1,429 | ) | |||||||||||||
Total, net of tax | 560 | (305 | ) | ||||||||||||||
Defined benefit pension and postretirement (gains) losses: | |||||||||||||||||
Amortization of net loss | 1,500 | (c) | 1,769 | (c) | |||||||||||||
Prior service (credit) cost | (86 | ) | (c) | 93 | (c) | ||||||||||||
Transition obligation | — | (c) | 2 | (c) | |||||||||||||
Total, pre-tax | 1,414 | 1,864 | |||||||||||||||
Tax benefit | (550 | ) | (2,503 | ) | |||||||||||||
Total, net of tax | 864 | (639 | ) | ||||||||||||||
Total amounts reclassified, net of tax | $ | 1,424 | $ | (944 | ) | ||||||||||||
(a) | Included in interest charges. | ||||||||||||||||
(b) | Included in O&M expenses. | ||||||||||||||||
(c) | Included in the computation of net periodic pension and postretirement benefit costs. See Note 12 for details regarding these benefit plans. |
Selected_Balance_Sheet_Data_Ta
Selected Balance Sheet Data (Tables) | 3 Months Ended | ||||||||
Mar. 31, 2014 | |||||||||
Balance Sheet Related Disclosures [Abstract] | ' | ||||||||
Accounts Receivable, Net | ' | ||||||||
(Thousands of Dollars) | March 31, 2014 | Dec. 31, 2013 | |||||||
Accounts receivable, net | |||||||||
Accounts receivable | $ | 939,228 | $ | 797,267 | |||||
Less allowance for bad debts | (54,130 | ) | (53,107 | ) | |||||
$ | 885,098 | $ | 744,160 | ||||||
Inventories | ' | ||||||||
(Thousands of Dollars) | March 31, 2014 | Dec. 31, 2013 | |||||||
Inventories | |||||||||
Materials and supplies | $ | 229,299 | $ | 225,308 | |||||
Fuel | 149,190 | 189,485 | |||||||
Natural gas | 57,748 | 161,745 | |||||||
$ | 436,237 | $ | 576,538 | ||||||
Property, Plant and Equipment, Net | ' | ||||||||
(Thousands of Dollars) | March 31, 2014 | Dec. 31, 2013 | |||||||
Property, plant and equipment, net | |||||||||
Electric plant | $ | 30,562,428 | $ | 30,341,310 | |||||
Natural gas plant | 4,156,606 | 4,086,651 | |||||||
Common and other property | 1,477,531 | 1,485,547 | |||||||
Plant to be retired (a) | 92,050 | 101,279 | |||||||
Construction work in progress | 2,672,049 | 2,371,566 | |||||||
Total property, plant and equipment | 38,960,664 | 38,386,353 | |||||||
Less accumulated depreciation | (12,741,176 | ) | (12,608,305 | ) | |||||
Nuclear fuel | 2,193,544 | 2,186,799 | |||||||
Less accumulated amortization | (1,871,550 | ) | (1,842,688 | ) | |||||
$ | 26,541,482 | $ | 26,122,159 | ||||||
(a) | As a result of the 2010 Colorado Public Utilities Commission (CPUC) approval of PSCo’s Clean Air Clean Jobs Act (CACJA) compliance plan and the December 2013 approval of PSCo’s preferred plans for applicable generating resources, PSCo has received approval for early retirement of Cherokee Unit 3 and Valmont Unit 5 between 2015 and 2017. Amounts are presented net of accumulated depreciation. |
Income_Taxes_Tables
Income Taxes (Tables) | 3 Months Ended | ||||||||
Mar. 31, 2014 | |||||||||
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 March 31, 2014, Xcel Energy’s earliest open tax years that are subject to examination by state taxing authorities in its major operating jurisdictions were as follows: | |||||||||
State | Year | ||||||||
Colorado | 2009 | ||||||||
Minnesota | 2009 | ||||||||
Texas | 2009 | ||||||||
Wisconsin | 2009 | ||||||||
Reconciliation of Unrecognized Tax Benefits | ' | ||||||||
A reconciliation of the amount of unrecognized tax benefit is as follows: | |||||||||
(Millions of Dollars) | March 31, 2014 | Dec. 31, 2013 | |||||||
Unrecognized tax benefit — Permanent tax positions | $ | 7.4 | $ | 12.9 | |||||
Unrecognized tax benefit — Temporary tax positions | 27.8 | 28.3 | |||||||
Total unrecognized tax benefit | $ | 35.2 | $ | 41.2 | |||||
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) | March 31, 2014 | Dec. 31, 2013 | |||||||
NOL and tax credit carryforwards | $ | (23.0 | ) | $ | (27.1 | ) |
Rate_Matters_Tables
Rate Matters (Tables) | 3 Months Ended | ||||||||||||
Mar. 31, 2014 | |||||||||||||
Public Utilities, General Disclosures [Abstract] | ' | ||||||||||||
NSP-Minnesota's 2014 Electric Rate Case [Table Text Block] | ' | ||||||||||||
The rate request, moderation plan, interim rate adjustments, customer bill impacts and certain impacts on expenses are detailed in the table below: | |||||||||||||
(Millions of Dollars) | 2014 | Percentage | 2015 | Percentage | |||||||||
Increase | Increase | ||||||||||||
Pre-moderation deficiency | $ | 274 | $ | 81 | |||||||||
Moderation change compared to prior year: | |||||||||||||
Depreciation reserve | (81 | ) | 53 | ||||||||||
DOE settlement proceeds | — | (36 | ) | ||||||||||
Filed rate request | 193 | 6.90% | 98 | 3.50% | |||||||||
Interim rate adjustments | (66 | ) | 66 | ||||||||||
Impact on customer bill | 127 | 4.60% | 164 | 5.60% | |||||||||
Potential expense deferral | 16 | — | |||||||||||
Depreciation expense - reduction/(increase) | 81 | (46 | ) | ||||||||||
Recognition of DOE settlement proceeds | — | 36 | |||||||||||
Pre-tax impact on operating income | $ | 224 | $ | 154 | |||||||||
CPUC decision in the PSCo Colorado 2013 Gas Rate Case | ' | ||||||||||||
The following table summarizes the CPUC decision: | |||||||||||||
(Millions of Dollars) | CPUC Decision | ||||||||||||
PSCo deficiency based on a FTY | $ | 44.8 | |||||||||||
HTY adjustment | (5.4 | ) | |||||||||||
ROE and capital structure adjustments | (8.3 | ) | |||||||||||
Revenue adjustments | (1.4 | ) | |||||||||||
Other | (0.1 | ) | |||||||||||
Recommendation | 29.6 | ||||||||||||
PSIA — base rate transfer to rider mechanism | (13.8 | ) | |||||||||||
Incremental base revenue | $ | 15.8 | |||||||||||
SPS' Texas 2014 Electric Rate Case | ' | ||||||||||||
In April 2014, SPS revised its requested rate increase to approximately $48.1 million, or 5.3 percent, based on updated information. The following table summarizes SPS’ revised request: | |||||||||||||
(Millions of Dollars) | SPS Request | ||||||||||||
Adjusted base rate increase | $ | 76.9 | |||||||||||
Resetting TCRF | (12.9 | ) | |||||||||||
Credit to customers for gain on sale to Lubbock moved to a rider | (4.9 | ) | |||||||||||
Adjusted net increase in base revenue | 59.1 | ||||||||||||
Fuel clause offsets | (11.0 | ) | |||||||||||
Adjusted retail customer net bill impact | $ | 48.1 | |||||||||||
SPS' New Mexico 2014 Electric Rate Case | ' | ||||||||||||
The following table summarizes the NMPRC’s approval from SPS’ revised request: | |||||||||||||
(Millions of Dollars) | NMPRC Approval | ||||||||||||
SPS revised request, September 2013 | $ | 32.5 | |||||||||||
Fuel clause adjustment credit — non-renewable energy costs | 2.3 | ||||||||||||
SPS revised request, fuel adjusted | 34.8 | ||||||||||||
ROE (9.96 percent) | (1.2 | ) | |||||||||||
Rate rider adjustment — renewable energy costs | 6 | ||||||||||||
Base rate reduction for rate rider — renewable energy costs | (6.0 | ) | |||||||||||
Other, net | (0.5 | ) | |||||||||||
Approved increase, March 2014 | $ | 33.1 | |||||||||||
Means of recovery: | |||||||||||||
Base revenue | $ | 12.7 | |||||||||||
Rider revenue | 18.1 | ||||||||||||
Fuel clause | 2.3 | ||||||||||||
$ | 33.1 | ||||||||||||
Commitments_and_Contingencies_
Commitments and Contingencies (Tables) | 3 Months Ended | ||||||||
Mar. 31, 2014 | |||||||||
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) | March 31, 2014 | Dec. 31, 2013 | |||||||
Guarantees issued and outstanding | $ | 18.3 | $ | 19.4 | |||||
Current exposure under these guarantees | 0.3 | 0.3 | |||||||
Bonds with indemnity protection | 32.4 | 32.1 | |||||||
Borrowings_and_Other_Financing1
Borrowings and Other Financing Instruments (Tables) | 3 Months Ended | ||||||||||||
Mar. 31, 2014 | |||||||||||||
Debt Disclosure [Abstract] | ' | ||||||||||||
Commercial Paper | ' | ||||||||||||
Commercial paper outstanding for Xcel Energy was as follows: | |||||||||||||
(Amounts in Millions, Except Interest Rates) | Three Months Ended | Twelve Months Ended | |||||||||||
March 31, 2014 | Dec. 31, 2013 | ||||||||||||
Borrowing limit | $ | 2,450 | $ | 2,450 | |||||||||
Amount outstanding at period end | 765 | 759 | |||||||||||
Average amount outstanding | 925 | 481 | |||||||||||
Maximum amount outstanding | 1,200 | 1,160 | |||||||||||
Weighted average interest rate, computed on a daily basis | 0.31 | % | 0.31 | % | |||||||||
Weighted average interest rate at period end | 0.33 | 0.25 | |||||||||||
Committed Credit Facilities Available | ' | ||||||||||||
At March 31, 2014, 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 | $ | 487 | $ | 313 | |||||||
PSCo | 700 | 6.5 | 693.5 | ||||||||||
NSP-Minnesota | 500 | 148.9 | 351.1 | ||||||||||
SPS | 300 | 90 | 210 | ||||||||||
NSP-Wisconsin | 150 | 79 | 71 | ||||||||||
Total | $ | 2,450.00 | $ | 811.4 | $ | 1,638.60 | |||||||
(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) | 3 Months Ended | ||||||||||||||||||||||||
Mar. 31, 2014 | |||||||||||||||||||||||||
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 March 31, 2014 and Dec. 31, 2013: | |||||||||||||||||||||||||
March 31, 2014 | |||||||||||||||||||||||||
Fair Value | |||||||||||||||||||||||||
(Thousands of Dollars) | Cost | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||
Nuclear decommissioning fund (a) | |||||||||||||||||||||||||
Cash equivalents | $ | 15,854 | $ | 15,854 | $ | — | $ | — | $ | 15,854 | |||||||||||||||
Commingled funds | 476,011 | — | 483,409 | — | 483,409 | ||||||||||||||||||||
International equity funds | 78,812 | — | 82,710 | — | 82,710 | ||||||||||||||||||||
Private equity investments | 60,912 | — | — | 73,801 | 73,801 | ||||||||||||||||||||
Real estate | 49,224 | — | — | 62,954 | 62,954 | ||||||||||||||||||||
Debt securities: | |||||||||||||||||||||||||
Government securities | 34,176 | — | 28,822 | — | 28,822 | ||||||||||||||||||||
U.S. corporate bonds | 78,362 | — | 81,827 | — | 81,827 | ||||||||||||||||||||
International corporate bonds | 15,223 | — | 15,685 | — | 15,685 | ||||||||||||||||||||
Municipal bonds | 261,106 | — | 260,044 | — | 260,044 | ||||||||||||||||||||
Equity securities: | |||||||||||||||||||||||||
Common stock | 380,896 | 558,289 | — | — | 558,289 | ||||||||||||||||||||
Total | $ | 1,450,576 | $ | 574,143 | $ | 952,497 | $ | 136,755 | $ | 1,663,395 | |||||||||||||||
(a) | Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $86.3 million of equity investments in unconsolidated subsidiaries and $43.4 million of miscellaneous investments. | ||||||||||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||||||||||
Fair Value | |||||||||||||||||||||||||
(Thousands of Dollars) | Cost | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||
Nuclear decommissioning fund (a) | |||||||||||||||||||||||||
Cash equivalents | $ | 33,281 | $ | 33,281 | $ | — | $ | — | $ | 33,281 | |||||||||||||||
Commingled funds | 457,986 | — | 452,227 | — | 452,227 | ||||||||||||||||||||
International equity funds | 78,812 | — | 81,671 | — | 81,671 | ||||||||||||||||||||
Private equity investments | 52,143 | — | — | 62,696 | 62,696 | ||||||||||||||||||||
Real estate | 45,564 | — | — | 57,368 | 57,368 | ||||||||||||||||||||
Debt securities: | |||||||||||||||||||||||||
Government securities | 34,304 | — | 27,628 | — | 27,628 | ||||||||||||||||||||
U.S. corporate bonds | 80,275 | — | 83,538 | — | 83,538 | ||||||||||||||||||||
International corporate bonds | 15,025 | — | 15,358 | — | 15,358 | ||||||||||||||||||||
Municipal bonds | 241,112 | — | 232,016 | — | 232,016 | ||||||||||||||||||||
Equity securities: | |||||||||||||||||||||||||
Common stock | 406,695 | 581,243 | — | — | 581,243 | ||||||||||||||||||||
Total | $ | 1,445,197 | $ | 614,524 | $ | 892,438 | $ | 120,064 | $ | 1,627,026 | |||||||||||||||
(a) | Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $87.1 million of equity investments in unconsolidated subsidiaries and $41.9 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 months ended March 31, 2014 and 2013: | |||||||||||||||||||||||||
(Thousands of Dollars) | Jan. 1, 2014 | Purchases | Settlements | Gains Recognized as Regulatory Assets | Transfers Out of Level 3 | March 31, 2014 | |||||||||||||||||||
Private equity investments | $ | 62,696 | $ | 8,769 | $ | — | $ | 2,336 | $ | — | $ | 73,801 | |||||||||||||
Real estate | 57,368 | 3,660 | — | 1,926 | — | 62,954 | |||||||||||||||||||
Total | $ | 120,064 | $ | 12,429 | $ | — | $ | 4,262 | $ | — | $ | 136,755 | |||||||||||||
(Thousands of Dollars) | Jan. 1, 2013 | Purchases | Settlements | Gains Recognized as Regulatory Assets | Transfers Out of Level 3(a) | March 31, 2013 | |||||||||||||||||||
Private equity investments | $ | 33,250 | $ | 1,256 | $ | — | $ | — | $ | — | $ | 34,506 | |||||||||||||
Real estate | 39,074 | 4,786 | (4,299 | ) | 845 | — | 40,406 | ||||||||||||||||||
Asset-backed securities | 2,067 | — | — | — | (2,067 | ) | — | ||||||||||||||||||
Mortgage-backed securities | 30,209 | — | — | — | (30,209 | ) | — | ||||||||||||||||||
Total | $ | 104,600 | $ | 6,042 | $ | (4,299 | ) | $ | 845 | $ | (32,276 | ) | $ | 74,912 | |||||||||||
(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. | ||||||||||||||||||||||||
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 March 31, 2014: | |||||||||||||||||||||||||
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 | $ | — | $ | — | $ | — | $ | 28,822 | $ | 28,822 | |||||||||||||||
U.S. corporate bonds | 311 | 15,816 | 64,341 | 1,359 | 81,827 | ||||||||||||||||||||
International corporate bonds | — | 3,762 | 11,923 | — | 15,685 | ||||||||||||||||||||
Municipal bonds | 3,088 | 25,410 | 38,770 | 192,776 | 260,044 | ||||||||||||||||||||
Debt securities | $ | 3,399 | $ | 44,988 | $ | 115,034 | $ | 222,957 | $ | 386,378 | |||||||||||||||
Gross Notional Amounts of Commodity Forwards, Options, and FTRs | ' | ||||||||||||||||||||||||
The following table details the gross notional amounts of commodity forwards, options and FTRs at March 31, 2014 and Dec. 31, 2013: | |||||||||||||||||||||||||
(Amounts in Thousands) (a)(b) | March 31, 2014 | Dec. 31, 2013 | |||||||||||||||||||||||
Megawatt hours of electricity | 32,453 | 58,423 | |||||||||||||||||||||||
Million British thermal units of natural gas | — | 9,854 | |||||||||||||||||||||||
Gallons of vehicle fuel | 432 | 482 | |||||||||||||||||||||||
(a) | Amounts are not reflective of net positions in the underlying commodities. | ||||||||||||||||||||||||
(b) | Notional amounts for options are included on a gross basis, but are weighted for the probability of exercise. | ||||||||||||||||||||||||
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income | ' | ||||||||||||||||||||||||
The following tables detail the impact of derivative activity during the three months ended March 31, 2014 and 2013, on accumulated other comprehensive loss, regulatory assets and liabilities, and income: | |||||||||||||||||||||||||
Three Months Ended March 31, 2014 | |||||||||||||||||||||||||
Pre-Tax Fair Value Gains (Losses) Recognized During the Period in: | Pre-Tax (Gains) Losses Reclassified into Income During the Period from: | Pre-Tax Gains (Losses) Recognized During the Period in Income | |||||||||||||||||||||||
(Thousands of Dollars) | Accumulated Other Comprehensive Loss | Regulatory (Assets) and Liabilities | Accumulated Other Comprehensive Loss | Regulatory Assets and (Liabilities) | |||||||||||||||||||||
Derivatives designated as cash flow hedges | |||||||||||||||||||||||||
Interest rate | $ | — | $ | — | $ | 946 | (a) | $ | — | $ | — | ||||||||||||||
Vehicle fuel and other commodity | (12 | ) | — | (28 | ) | (b) | — | — | |||||||||||||||||
Total | $ | (12 | ) | $ | — | $ | 918 | $ | — | $ | — | ||||||||||||||
Other derivative instruments | |||||||||||||||||||||||||
Commodity trading | $ | — | $ | — | $ | — | $ | — | $ | (2,253 | ) | (c) | |||||||||||||
Electric commodity | — | 3,527 | — | (20,696 | ) | (d) | — | ||||||||||||||||||
Natural gas commodity | — | 18,506 | — | (18,840 | ) | (e) | (5,302 | ) | (e) | ||||||||||||||||
Total | $ | — | $ | 22,033 | $ | — | $ | (39,536 | ) | $ | (7,555 | ) | |||||||||||||
Three Months Ended March 31, 2013 | |||||||||||||||||||||||||
Pre-Tax Fair Value Gains (Losses) Recognized During the Period in: | Pre-Tax (Gains) Losses Reclassified into Income During the Period from: | Pre-Tax Gains (Losses) Recognized During the Period in Income | |||||||||||||||||||||||
(Thousands of Dollars) | Accumulated Other Comprehensive Loss | Regulatory (Assets) and Liabilities | Accumulated Other Comprehensive Loss | Regulatory Assets and (Liabilities) | |||||||||||||||||||||
Derivatives designated as cash flow hedges | |||||||||||||||||||||||||
Interest rate | $ | — | $ | — | $ | 1,150 | (a) | $ | — | $ | — | ||||||||||||||
Vehicle fuel and other commodity | 25 | — | (26 | ) | (b) | — | — | ||||||||||||||||||
Total | $ | 25 | $ | — | $ | 1,124 | $ | — | $ | — | |||||||||||||||
Other derivative instruments | |||||||||||||||||||||||||
Commodity trading | $ | — | $ | — | $ | — | $ | — | $ | 2,776 | (c) | ||||||||||||||
Electric commodity | — | 6,419 | — | (15,229 | ) | (d) | — | ||||||||||||||||||
Natural gas commodity | — | 54 | — | 9 | (e) | 16 | (e) | ||||||||||||||||||
Total | $ | — | $ | 6,473 | $ | — | $ | (15,220 | ) | $ | 2,792 | ||||||||||||||
(a) | Amounts are recorded to interest charges. | ||||||||||||||||||||||||
(b) | Amounts are recorded to O&M expenses. | ||||||||||||||||||||||||
(c) | Amounts are recorded to electric operating revenues. Portions of these gains and losses are subject to sharing with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate. | ||||||||||||||||||||||||
(d) | Amounts are recorded to electric fuel and purchased power. These derivative settlement gain and loss amounts are shared with electric customers through fuel and purchased energy cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate. | ||||||||||||||||||||||||
(e) | Amounts for the three months ended March 31, 2014 and 2013 included immaterial settlement losses on derivatives entered to mitigate natural gas price risk for electric generation, recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate. The remaining derivative settlement gains and losses for the three months ended March 31, 2014 and 2013 relate to natural gas operations and are recorded to cost of natural gas sold and transported. These gains and losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset or liability, as appropriate. | ||||||||||||||||||||||||
Derivative Assets and Liabilities Measured at Fair Value on a Recurring Basis by Hierarchy Level | ' | ||||||||||||||||||||||||
Recurring Fair Value Measurements — The following table presents for each of the fair value hierarchy levels, Xcel Energy’s derivative assets and liabilities measured at fair value on a recurring basis at March 31, 2014: | |||||||||||||||||||||||||
March 31, 2014 | |||||||||||||||||||||||||
Fair Value | Fair Value Total | Counterparty Netting (b) | Total | ||||||||||||||||||||||
(Thousands of Dollars) | Level 1 | Level 2 | Level 3 | ||||||||||||||||||||||
Current derivative assets | |||||||||||||||||||||||||
Derivatives designated as cash flow hedges: | |||||||||||||||||||||||||
Vehicle fuel and other commodity | $ | — | $ | 58 | $ | — | $ | 58 | $ | — | $ | 58 | |||||||||||||
Other derivative instruments: | |||||||||||||||||||||||||
Commodity trading | — | 20,979 | 944 | 21,923 | (6,467 | ) | 15,456 | ||||||||||||||||||
Electric commodity | — | — | 26,640 | 26,640 | (4,907 | ) | 21,733 | ||||||||||||||||||
Total current derivative assets | $ | — | $ | 21,037 | $ | 27,584 | $ | 48,621 | $ | (11,374 | ) | 37,247 | |||||||||||||
PPAs (a) | 33,028 | ||||||||||||||||||||||||
Current derivative instruments | $ | 70,275 | |||||||||||||||||||||||
Noncurrent derivative assets | |||||||||||||||||||||||||
Derivatives designated as cash flow hedges: | |||||||||||||||||||||||||
Vehicle fuel and other commodity | $ | — | $ | 18 | $ | — | $ | 18 | $ | — | $ | 18 | |||||||||||||
Other derivative instruments: | |||||||||||||||||||||||||
Commodity trading | — | 15,718 | 1,932 | 17,650 | (407 | ) | 17,243 | ||||||||||||||||||
Total noncurrent derivative assets | $ | — | $ | 15,736 | $ | 1,932 | $ | 17,668 | $ | (407 | ) | 17,261 | |||||||||||||
PPAs (a) | 50,252 | ||||||||||||||||||||||||
Noncurrent derivative instruments | $ | 67,513 | |||||||||||||||||||||||
Current derivative liabilities | |||||||||||||||||||||||||
Other derivative instruments: | |||||||||||||||||||||||||
Commodity trading | $ | — | $ | 11,946 | $ | 392 | $ | 12,338 | $ | (12,338 | ) | $ | — | ||||||||||||
Electric commodity | — | — | 4,907 | 4,907 | (4,907 | ) | — | ||||||||||||||||||
Total current derivative liabilities | $ | — | $ | 11,946 | $ | 5,299 | $ | 17,245 | $ | (17,245 | ) | — | |||||||||||||
PPAs (a) | 22,358 | ||||||||||||||||||||||||
Current derivative instruments | $ | 22,358 | |||||||||||||||||||||||
Noncurrent derivative liabilities | |||||||||||||||||||||||||
Other derivative instruments: | |||||||||||||||||||||||||
Commodity trading | $ | — | $ | 1,707 | $ | — | $ | 1,707 | $ | (1,015 | ) | $ | 692 | ||||||||||||
Total noncurrent derivative liabilities | $ | — | $ | 1,707 | $ | — | $ | 1,707 | $ | (1,015 | ) | 692 | |||||||||||||
PPAs (a) | 198,886 | ||||||||||||||||||||||||
Noncurrent derivative instruments | $ | 199,578 | |||||||||||||||||||||||
(a) | In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, Xcel Energy began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, Xcel Energy qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities. | ||||||||||||||||||||||||
(b) | Xcel Energy nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at March 31, 2014. At March 31, 2014, derivative assets and liabilities include obligations to return cash collateral of $0.1 million and rights to reclaim cash collateral of $6.5 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, 2013: | |||||||||||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||||||||||
Fair Value | Fair Value Total | Counterparty Netting (b) | Total | ||||||||||||||||||||||
(Thousands of Dollars) | Level 1 | Level 2 | Level 3 | ||||||||||||||||||||||
Current derivative assets | |||||||||||||||||||||||||
Derivatives designated as cash flow hedges: | |||||||||||||||||||||||||
Vehicle fuel and other commodity | $ | — | $ | 88 | $ | — | $ | 88 | $ | — | $ | 88 | |||||||||||||
Other derivative instruments: | |||||||||||||||||||||||||
Commodity trading | — | 20,610 | 1,167 | 21,777 | (7,994 | ) | 13,783 | ||||||||||||||||||
Electric commodity | — | — | 47,112 | 47,112 | (8,210 | ) | 38,902 | ||||||||||||||||||
Natural gas commodity | — | 5,906 | — | 5,906 | — | 5,906 | |||||||||||||||||||
Total current derivative assets | $ | — | $ | 26,604 | $ | 48,279 | $ | 74,883 | $ | (16,204 | ) | 58,679 | |||||||||||||
PPAs (a) | 33,028 | ||||||||||||||||||||||||
Current derivative instruments | $ | 91,707 | |||||||||||||||||||||||
Noncurrent derivative assets | |||||||||||||||||||||||||
Derivatives designated as cash flow hedges: | |||||||||||||||||||||||||
Vehicle fuel and other commodity | $ | — | $ | 29 | $ | — | $ | 29 | $ | (16 | ) | $ | 13 | ||||||||||||
Other derivative instruments: | |||||||||||||||||||||||||
Commodity trading | — | 32,074 | 3,395 | 35,469 | (9,071 | ) | 26,398 | ||||||||||||||||||
Total noncurrent derivative assets | $ | — | $ | 32,103 | $ | 3,395 | $ | 35,498 | $ | (9,087 | ) | 26,411 | |||||||||||||
PPAs (a) | 58,431 | ||||||||||||||||||||||||
Noncurrent derivative instruments | $ | 84,842 | |||||||||||||||||||||||
Current derivative liabilities | |||||||||||||||||||||||||
Other derivative instruments: | |||||||||||||||||||||||||
Commodity trading | $ | — | $ | 10,546 | $ | 1,804 | $ | 12,350 | $ | (12,002 | ) | $ | 348 | ||||||||||||
Electric commodity | — | — | 8,210 | 8,210 | (8,210 | ) | — | ||||||||||||||||||
Total current derivative liabilities | $ | — | $ | 10,546 | $ | 10,014 | $ | 20,560 | $ | (20,212 | ) | 348 | |||||||||||||
PPAs (a) | 23,034 | ||||||||||||||||||||||||
Current derivative instruments | $ | 23,382 | |||||||||||||||||||||||
Noncurrent derivative liabilities | |||||||||||||||||||||||||
Other derivative instruments: | |||||||||||||||||||||||||
Commodity trading | $ | — | $ | 14,382 | $ | — | $ | 14,382 | $ | (9,087 | ) | $ | 5,295 | ||||||||||||
Total noncurrent derivative liabilities | $ | — | $ | 14,382 | $ | — | $ | 14,382 | $ | (9,087 | ) | 5,295 | |||||||||||||
PPAs (a) | 203,929 | ||||||||||||||||||||||||
Noncurrent derivative instruments | $ | 209,224 | |||||||||||||||||||||||
(a) | In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, Xcel Energy began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, Xcel Energy qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities. | ||||||||||||||||||||||||
(b) | Xcel Energy nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2013. At Dec. 31, 2013, derivative assets and liabilities include obligations to return cash collateral of $0.2 million and rights to reclaim cash collateral of $4.2 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 months ended March 31, 2014 and 2013: | |||||||||||||||||||||||||
Three Months Ended March 31 | |||||||||||||||||||||||||
(Thousands of Dollars) | 2014 | 2013 | |||||||||||||||||||||||
Balance at Jan. 1 | $ | 41,660 | $ | 16,649 | |||||||||||||||||||||
Purchases | 1,056 | — | |||||||||||||||||||||||
Settlements | (53,809 | ) | (12,449 | ) | |||||||||||||||||||||
Net transactions recorded during the period: | |||||||||||||||||||||||||
Gains (losses) recognized in earnings (a) | 999 | (62 | ) | ||||||||||||||||||||||
Gains recognized as regulatory assets and liabilities | 34,311 | 3,504 | |||||||||||||||||||||||
Balance at March 31 | $ | 24,217 | $ | 7,642 | |||||||||||||||||||||
(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 March 31, 2014 and Dec. 31, 2013, other financial instruments for which the carrying amount did not equal fair value were as follows: | |||||||||||||||||||||||||
March 31, 2014 | Dec. 31, 2013 | ||||||||||||||||||||||||
(Thousands of Dollars) | Carrying Amount | Fair Value | Carrying Amount | Fair Value | |||||||||||||||||||||
Long-term debt, including current portion | $ | 11,487,452 | $ | 12,511,410 | $ | 11,191,517 | $ | 11,878,643 | |||||||||||||||||
Other_Income_Net_Tables
Other Income, Net (Tables) | 3 Months Ended | ||||||||
Mar. 31, 2014 | |||||||||
Other Income and Expenses [Abstract] | ' | ||||||||
Other Income, Net | ' | ||||||||
Other income, net consisted of the following: | |||||||||
Three Months Ended March 31 | |||||||||
(Thousands of Dollars) | 2014 | 2013 | |||||||
Interest income | $ | 3,893 | $ | 4,806 | |||||
Other nonoperating income | 1,116 | 1,255 | |||||||
Insurance policy expense | (1,808 | ) | (2,139 | ) | |||||
Other income, net | $ | 3,201 | $ | 3,922 | |||||
Segment_Information_Tables
Segment Information (Tables) | 3 Months Ended | ||||||||||||||||||||
Mar. 31, 2014 | |||||||||||||||||||||
Segment Reporting [Abstract] | ' | ||||||||||||||||||||
Results from Continuing Operations by Reportable Segment | ' | ||||||||||||||||||||
(Thousands of Dollars) | Regulated Electric | Regulated Natural Gas | All Other | Reconciling Eliminations | Consolidated Total | ||||||||||||||||
Three Months Ended March 31, 2014 | |||||||||||||||||||||
Operating revenues from external customers | $ | 2,301,710 | $ | 879,688 | $ | 21,206 | $ | — | $ | 3,202,604 | |||||||||||
Intersegment revenues | 353 | 3,252 | — | (3,605 | ) | — | |||||||||||||||
Total revenues | $ | 2,302,063 | $ | 882,940 | $ | 21,206 | $ | (3,605 | ) | $ | 3,202,604 | ||||||||||
Net income (loss) | $ | 185,433 | $ | 77,336 | $ | (1,548 | ) | $ | — | $ | 261,221 | ||||||||||
(Thousands of Dollars) | Regulated Electric | Regulated Natural Gas | All Other | Reconciling Eliminations | Consolidated Total | ||||||||||||||||
Three Months Ended March 31, 2013 | |||||||||||||||||||||
Operating revenues from external customers | $ | 2,092,196 | $ | 669,596 | $ | 21,057 | $ | — | $ | 2,782,849 | |||||||||||
Intersegment revenues | 301 | 500 | — | (801 | ) | — | |||||||||||||||
Total revenues | $ | 2,092,497 | $ | 670,096 | $ | 21,057 | $ | (801 | ) | $ | 2,782,849 | ||||||||||
Net income (loss) | $ | 174,106 | $ | 64,910 | $ | (2,446 | ) | $ | — | $ | 236,570 | ||||||||||
Earnings_Per_Share_Tables
Earnings Per Share (Tables) | 3 Months Ended | ||||||||||||||||||||||
Mar. 31, 2014 | |||||||||||||||||||||||
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 March 31, 2014 | Three Months Ended March 31, 2013 | ||||||||||||||||||||||
(Amounts in thousands, except per share data) | Income | Shares | Per Share | Income | Shares | Per Share | |||||||||||||||||
Amount | Amount | ||||||||||||||||||||||
Net income | $ | 261,221 | $ | 236,570 | |||||||||||||||||||
Basic EPS: | |||||||||||||||||||||||
Earnings available to common shareholders | 261,221 | 499,523 | $ | 0.52 | 236,570 | 489,781 | $ | 0.48 | |||||||||||||||
Effect of dilutive securities: | |||||||||||||||||||||||
Time based equity awards | — | 223 | — | 750 | |||||||||||||||||||
Diluted EPS: | |||||||||||||||||||||||
Earnings available to common shareholders | $ | 261,221 | 499,746 | $ | 0.52 | $ | 236,570 | 490,531 | $ | 0.48 | |||||||||||||
Benefit_Plans_and_Other_Postre1
Benefit Plans and Other Postretirement Benefits (Tables) | 3 Months Ended | ||||||||||||||||
Mar. 31, 2014 | |||||||||||||||||
Compensation and Retirement Disclosure [Abstract] | ' | ||||||||||||||||
Components of Net Periodic Benefit Cost | ' | ||||||||||||||||
Components of Net Periodic Benefit Cost | |||||||||||||||||
Three Months Ended March 31 | |||||||||||||||||
2014 | 2013 | 2014 | 2013 | ||||||||||||||
(Thousands of Dollars) | Pension Benefits | Postretirement Health Care Benefits | |||||||||||||||
Service cost | $ | 22,086 | $ | 24,071 | $ | 864 | $ | 1,182 | |||||||||
Interest cost | 39,155 | 35,172 | 8,507 | 8,417 | |||||||||||||
Expected return on plan assets | (51,801 | ) | (49,613 | ) | (8,489 | ) | (8,253 | ) | |||||||||
Amortization of transition obligation | — | — | — | 206 | |||||||||||||
Amortization of prior service (credit) cost | (437 | ) | 1,468 | (2,672 | ) | (2,438 | ) | ||||||||||
Amortization of net loss | 29,191 | 36,038 | 2,935 | 5,646 | |||||||||||||
Net periodic benefit cost | 38,194 | 47,136 | 1,145 | 4,760 | |||||||||||||
Costs not recognized due to the effects of regulation | (7,052 | ) | (7,847 | ) | — | — | |||||||||||
Net benefit cost recognized for financial reporting | $ | 31,142 | $ | 39,289 | $ | 1,145 | $ | 4,760 | |||||||||
Other_Comprehensive_Income_Tab
Other Comprehensive Income (Tables) | 3 Months Ended | ||||||||||||||||
Mar. 31, 2014 | |||||||||||||||||
Stockholders' Equity Note [Abstract] | ' | ||||||||||||||||
Changes in Accumulated Other Comprehensive Gain (Loss), Net of Tax | ' | ||||||||||||||||
Changes in accumulated other comprehensive gain (loss), net of tax, for the three months ended March 31, 2014 and 2013 were as follows: | |||||||||||||||||
Three Months Ended March 31, 2014 | |||||||||||||||||
(Thousands of Dollars) | Gains and Losses on Cash Flow Hedges | Unrealized Gains and Losses on Marketable Securities | Defined Benefit Pension and Postretirement Items | Total | |||||||||||||
Accumulated other comprehensive gain (loss) at Jan. 1 | $ | (59,753 | ) | $ | 77 | $ | (46,599 | ) | $ | (106,275 | ) | ||||||
Other comprehensive gain (loss) before reclassifications | (7 | ) | 38 | — | 31 | ||||||||||||
Losses reclassified from net accumulated other comprehensive loss | 560 | — | 864 | 1,424 | |||||||||||||
Net current period other comprehensive income | 553 | 38 | 864 | 1,455 | |||||||||||||
Accumulated other comprehensive gain (loss) at March 31 | $ | (59,200 | ) | $ | 115 | $ | (45,735 | ) | $ | (104,820 | ) | ||||||
Three Months Ended March 31, 2013 | |||||||||||||||||
(Thousands of Dollars) | Gains and Losses on Cash Flow Hedges | Unrealized Gains and Losses on Marketable Securities | Defined Benefit Pension and Postretirement Items | Total | |||||||||||||
Accumulated other comprehensive loss at Jan. 1 | $ | (61,241 | ) | $ | (99 | ) | $ | (51,313 | ) | $ | (112,653 | ) | |||||
Other comprehensive gain (loss) before reclassifications | 13 | (36 | ) | — | (23 | ) | |||||||||||
Gains reclassified from net accumulated other comprehensive loss | (305 | ) | — | (639 | ) | (944 | ) | ||||||||||
Net current period other comprehensive loss | (292 | ) | (36 | ) | (639 | ) | (967 | ) | |||||||||
Accumulated other comprehensive loss at March 31 | $ | (61,533 | ) | $ | (135 | ) | $ | (51,952 | ) | $ | (113,620 | ) | |||||
Reclassifications out of Accumulated Other Comprehensive Loss | ' | ||||||||||||||||
Reclassifications from accumulated other comprehensive loss for the three months ended March 31, 2014 and 2013 were as follows: | |||||||||||||||||
Amounts Reclassified from Accumulated | |||||||||||||||||
Other Comprehensive Loss | |||||||||||||||||
(Thousands of Dollars) | Three Months Ended March 31, 2014 | Three Months Ended March 31, 2013 | |||||||||||||||
(Gains) losses on cash flow hedges: | |||||||||||||||||
Interest rate derivatives | $ | 946 | (a) | $ | 1,150 | (a) | |||||||||||
Vehicle fuel derivatives | (28 | ) | (b) | (26 | ) | (b) | |||||||||||
Total, pre-tax | 918 | 1,124 | |||||||||||||||
Tax benefit | (358 | ) | (1,429 | ) | |||||||||||||
Total, net of tax | 560 | (305 | ) | ||||||||||||||
Defined benefit pension and postretirement (gains) losses: | |||||||||||||||||
Amortization of net loss | 1,500 | (c) | 1,769 | (c) | |||||||||||||
Prior service (credit) cost | (86 | ) | (c) | 93 | (c) | ||||||||||||
Transition obligation | — | (c) | 2 | (c) | |||||||||||||
Total, pre-tax | 1,414 | 1,864 | |||||||||||||||
Tax benefit | (550 | ) | (2,503 | ) | |||||||||||||
Total, net of tax | 864 | (639 | ) | ||||||||||||||
Total amounts reclassified, net of tax | $ | 1,424 | $ | (944 | ) | ||||||||||||
(a) | Included in interest charges. | ||||||||||||||||
(b) | Included in O&M expenses. | ||||||||||||||||
(c) | Included in the computation of net periodic pension and postretirement benefit costs. See Note 12 for details regarding these benefit plans. |
Balance_Sheet_Data_Accounts_Re
Balance Sheet Data, Accounts Receivable (Details) (USD $) | Mar. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Accounts receivable, net | ' | ' |
Accounts receivable | $939,228 | $797,267 |
Less allowance for bad debts | -54,130 | -53,107 |
Accounts receivable, net | $885,098 | $744,160 |
Selected_Balance_Sheet_Data_Ba
Selected Balance Sheet Data Balance Sheet Related Disclosures, Inventories (Details) (USD $) | Mar. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Public Utilities, Inventory [Line Items] | ' | ' |
Inventories | $436,237 | $576,538 |
Materials and supplies | ' | ' |
Public Utilities, Inventory [Line Items] | ' | ' |
Inventories | 229,299 | 225,308 |
Fuel | ' | ' |
Public Utilities, Inventory [Line Items] | ' | ' |
Inventories | 149,190 | 189,485 |
Natural gas | ' | ' |
Public Utilities, Inventory [Line Items] | ' | ' |
Inventories | $57,748 | $161,745 |
Selected_Balance_Sheet_Data_Ba1
Selected Balance Sheet Data Balance Sheet Related Disclosures, Property, Plant and Equipment (Details) (USD $) | Mar. 31, 2014 | Dec. 31, 2013 | ||
In Thousands, unless otherwise specified | ||||
Public Utility, Property, Plant and Equipment [Line Items] | ' | ' | ||
Property, plant and equipment, gross | $38,960,664 | $38,386,353 | ||
Less accumulated depreciation | -12,741,176 | -12,608,305 | ||
Property, plant and equipment, net | 26,541,482 | 26,122,159 | ||
Electric plant | ' | ' | ||
Public Utility, Property, Plant and Equipment [Line Items] | ' | ' | ||
Property, plant and equipment, gross | 30,562,428 | 30,341,310 | ||
Natural gas plant | ' | ' | ||
Public Utility, Property, Plant and Equipment [Line Items] | ' | ' | ||
Property, plant and equipment, gross | 4,156,606 | 4,086,651 | ||
Common and other property | ' | ' | ||
Public Utility, Property, Plant and Equipment [Line Items] | ' | ' | ||
Property, plant and equipment, gross | 1,477,531 | 1,485,547 | ||
Plant to be retired | ' | ' | ||
Public Utility, Property, Plant and Equipment [Line Items] | ' | ' | ||
Property, plant and equipment, gross | 92,050 | [1] | 101,279 | [1] |
Construction work in progress | ' | ' | ||
Public Utility, Property, Plant and Equipment [Line Items] | ' | ' | ||
Property, plant and equipment, gross | 2,672,049 | 2,371,566 | ||
Nuclear fuel | ' | ' | ||
Public Utility, Property, Plant and Equipment [Line Items] | ' | ' | ||
Property, plant and equipment, gross | 2,193,544 | 2,186,799 | ||
Less accumulated depreciation | ($1,871,550) | ($1,842,688) | ||
[1] | As a result of the 2010 Colorado Public Utilities Commission (CPUC) approval of PSCo’s Clean Air Clean Jobs Act (CACJA) compliance plan and the December 2013 approval of PSCo’s preferred plans for applicable generating resources, PSCo has received approval for early retirement of Cherokee Unit 3 and Valmont Unit 5 between 2015 and 2017. Amounts are presented net of accumulated depreciation. |
Income_Taxes_Details
Income Taxes (Details) (USD $) | 3 Months Ended | 12 Months Ended | 3 Months Ended | ||||||
Mar. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Mar. 31, 2014 | Sep. 30, 2012 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | |
Internal Revenue Service (IRS) | Internal Revenue Service (IRS) | Colorado | Minnesota | Texas | Wisconsin | ||||
Tax Audits [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Number Of Years Of Tax Loss Carryback Period | '2 | ' | ' | ' | ' | ' | ' | ' | ' |
Tax Adjustments, Settlements, and Unusual Provisions | ' | ($12,000,000) | ($15,000,000) | $10,000,000 | ' | ' | ' | ' | ' |
Year(s) no longer subject to audit as statute of limitations has expired | ' | ' | ' | '2008 | ' | ' | ' | ' | ' |
Earliest year subject to examination | ' | ' | ' | '2009 | ' | '2009 | '2009 | '2009 | '2009 |
Year(s) under examination | ' | ' | ' | ' | '2010 and 2011 | ' | ' | ' | ' |
Tax year(s) for which income tax examination has been completed | ' | ' | ' | ' | ' | ' | ' | ' | '2009 through 2011 |
Unrecognized Tax Benefits [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Unrecognized tax benefit — Permanent tax positions | 7,400,000 | 12,900,000 | ' | ' | ' | ' | ' | ' | ' |
Unrecognized tax benefit — Temporary tax positions | 27,800,000 | 28,300,000 | ' | ' | ' | ' | ' | ' | ' |
Total unrecognized tax benefit | 35,200,000 | 41,200,000 | ' | ' | ' | ' | ' | ' | ' |
NOL and tax credit carryforwards | -23,000,000 | -27,100,000 | ' | ' | ' | ' | ' | ' | ' |
Upper bound of decrease in unrecognized tax benefit that is reasonably possible | -8,000,000 | ' | ' | ' | ' | ' | ' | ' | ' |
Amounts accrued for penalties related to unrecognized tax benefits | $0 | $0 | ' | ' | ' | ' | ' | ' | ' |
Rate_Matters_NSPMinnesota_Deta
Rate Matters, NSP-Minnesota (Details) (USD $) | 1 Months Ended | 3 Months Ended | 1 Months Ended | 3 Months Ended | 1 Months Ended | 3 Months Ended | 1 Months Ended | |||||||||||
In Millions, unless otherwise specified | Oct. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Nov. 30, 2013 | Nov. 30, 2013 | Mar. 31, 2014 | Nov. 30, 2013 | Mar. 31, 2014 | Feb. 28, 2014 | Jan. 31, 2013 | Dec. 31, 2012 | Feb. 28, 2014 | Feb. 28, 2014 | Feb. 28, 2014 | Feb. 28, 2014 | Feb. 28, 2014 | Feb. 28, 2014 | Feb. 28, 2014 |
Nuclear Project Prudency Investigation [Member] [Member] | 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 | NSP-Minnesota | NSP-Minnesota | |
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] | Minnesota Public Utilities Commission [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] | North Dakota Public Service Commission [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] | North Dakota Public Service Commission [Member] | |||
2014 Electric Rate Case | 2014 Electric Rate Case | Electric Rate Case 2014, Rates 2014 [Member] | Electric Rate Case 2014, Rates 2014 [Member] | Electric Rate Case 2014, Rates 2015 [Member] | Electric Rate Case 2014, Rates 2015 [Member] | Electric Rate Case 2013 [Member] | Electric Rate Case 2013 [Member] | Electric Rate Case 2013 [Member] | Electric Rate Case 2013, Rates 2013 | Electric Rate Case 2013, Rates 2014 [Member] | Electric Rate Case 2013, Rates 2015 [Member] | Electric Rate Case 2013, ROE 2013 [Member] | Electric Rate Case 2013, ROE 2014 [Member] | Electric Rate Case 2013, ROE 2015 [Member] | Electric Rate Case 2013, ROE 2016 [Member] | |||
Public Utilities, General Disclosures [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Revenue deficiency based on a forecast test year | ' | ' | ' | ' | $274 | ' | $81 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Rate Matters [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Requested Rate Increase (Decrease), Amount | ' | ' | ' | ' | 193 | 127 | 98 | 164 | ' | ' | 16.9 | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Requested Rate Increase (Decrease), Percentage | ' | ' | ' | ' | 6.90% | 4.60% | 3.50% | 5.60% | 4.90% | ' | 9.25% | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Impact on Customer Bill, Increase (Decrease), Percentage | ' | ' | ' | ' | 4.60% | ' | 5.60% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Requested Return on Equity, Percentage | ' | ' | ' | 10.25% | ' | ' | ' | ' | ' | ' | 10.60% | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Requested Rate Base, Amount | ' | ' | ' | ' | 6,670 | ' | 412 | ' | ' | ' | 377.6 | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Requested Equity Capital Structure, Percentage | ' | ' | ' | 52.50% | ' | ' | ' | ' | ' | ' | 52.56% | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Interim Rate Increase (Decrease), Amount | ' | ' | 127 | ' | ' | ' | ' | ' | ' | 14.7 | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Cost of project allowed for recovery | ' | 320 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Costs for nuclear project, Amount | ' | 665 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Adjustment requested by public utility to rate increase (decrease) related to depreciation reserve | ' | ' | ' | ' | -81 | ' | 53 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Number of factors attributable to project cost increases | 3 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Number of years for the application process | '5 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Recommended rate increase (decrease) impact on pre-tax income | ' | ' | ' | ' | 224 | ' | 154 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Approved Rate Increase (Decrease), Amount | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 7.4 | 9.4 | 10.1 | ' | ' | ' | ' |
Public Utilities, Approved Return on Equity, Percentage | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 9.75% | 10.00% | 10.00% | 10.25% |
Proposed duration of rate plan, years | ' | ' | ' | ' | ' | ' | ' | ' | '4 years | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public utilities, Adjustment to requested rate increase (decrease) related to DOE settlement proceeds, amount | ' | ' | ' | ' | 0 | ' | -36 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Adjustment to requested interim rate increase (decrease), amount | ' | ' | ' | ' | -66 | ' | 66 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Impact on Customer Bill, Increase (Decrease), Amount | ' | ' | ' | ' | 127 | ' | 164 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Amortization of Rate Deferral | ' | ' | ' | ' | 16 | ' | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Adjustment to approved rate increase (decrease) related to depreciation expense | ' | ' | ' | ' | $81 | ' | ($46) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Rate_Matters_PSCo_Details
Rate Matters, PSCo (Details) (PSCo, USD $) | 1 Months Ended | 3 Months Ended | 1 Months Ended | 3 Months Ended | 12 Months Ended | 12 Months Ended | 1 Months Ended | 3 Months Ended | 1 Months Ended | |||||||||||||||||||||||
In Millions, unless otherwise specified | Dec. 31, 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 | Feb. 28, 2014 | Dec. 31, 2012 | Dec. 31, 2012 | Dec. 31, 2012 | Dec. 31, 2012 | Mar. 31, 2014 | Feb. 28, 2014 | Apr. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2012 | Mar. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2012 | Dec. 31, 2011 | Jul. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2014 | Jun. 30, 2012 | Apr. 30, 2012 | Apr. 30, 2014 | Apr. 30, 2014 |
Colorado Public Utilities Commission (CPUC) | Colorado Public Utilities Commission (CPUC) | Colorado Public Utilities Commission (CPUC) | Colorado Public Utilities Commission (CPUC) | Colorado Public Utilities Commission (CPUC) | Colorado Public Utilities Commission (CPUC) | Colorado Public Utilities Commission (CPUC) | Colorado Public Utilities Commission (CPUC) | Colorado Public Utilities Commission (CPUC) | Colorado Public Utilities Commission (CPUC) | Colorado Public Utilities Commission (CPUC) | Colorado Public Utilities Commission (CPUC) | Colorado Public Utilities Commission (CPUC) | Colorado Public Utilities Commission (CPUC) | Colorado Public Utilities Commission (CPUC) | Colorado Public Utilities Commission (CPUC) | Colorado Public Utilities Commission (CPUC) | Colorado Public Utilities Commission (CPUC) | Colorado Public Utilities Commission (CPUC) | Colorado Public Utilities Commission (CPUC) | Colorado Public Utilities Commission (CPUC) | Colorado Public Utilities Commission (CPUC) | Colorado Public Utilities Commission (CPUC) | Colorado Public Utilities Commission (CPUC) | Colorado Public Utilities Commission (CPUC) | Colorado Public Utilities Commission (CPUC) | Colorado Public Utilities Commission (CPUC) | Federal Energy Regulatory Commission (FERC) | Federal Energy Regulatory Commission (FERC) | Federal Energy Regulatory Commission (FERC) | Subsequent Event | Subsequent Event | |
2013 Gas Rate Case | 2013 Gas Rate Case | 2013 Gas Rate Case | Gas Rate Case 2013, Gas Rates 2013 | Gas Rate Case 2013, Gas Rates 2013 | Gas Rate Case 2013, Gas Rates 2014 | Gas Rate Case 2013, Gas Rates 2014 | Gas Rate Case 2013, Gas Rates 2015 | Gas Rate Case 2013, Gas Rates 2015 | 2013 Steam Rate Case | 2013 Steam Rate Case | Steam Rate Case 2013, Steam Rates 2013 | Steam Rate Case 2013, Steam Rates 2014 | Steam Rate Case 2013, Steam Rates 2015 | Annual Electric Earnings Test | 2012 PSIA Report | 2012 PSIA Report | Renewable Energy Credit Sharing | Renewable Energy Credit Sharing | Renewable Energy Credit Sharing | Renewable Energy Credit Sharing | Renewable Energy Credit Sharing | Renewable Energy Credit Sharing | Renewable Energy Credit Sharing | Renewable Energy Credit Sharing | Electric Commodity Adjustment / RESA Adjustment | Electric Commodity Adjustment / RESA Adjustment | Transmission Formula Rate Case | Transmission Formula Rate Case | Transmission Formula Rate Case | Colorado Public Utilities Commission (CPUC) | Colorado Public Utilities Commission (CPUC) | |
Shareholders | Shareholders | Customers | Customers | 2013 Gas Rate Case | Annual Electric Earnings Test | |||||||||||||||||||||||||||
Rate Matters [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Requested Rate Increase (Decrease), Amount | ' | ' | ' | ' | $48.50 | ' | $9.90 | ' | $12.10 | ' | ' | $1.60 | $0.90 | $2.30 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $2 | ' | ' |
Public Utilities, Requested Return on Equity, Percentage | ' | 10.30% | 10.50% | ' | ' | ' | ' | ' | ' | ' | 10.50% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10.25% | ' | ' | ' |
Public Utilities, Requested Rate Base, Amount | ' | ' | 1,300 | ' | ' | ' | ' | ' | ' | ' | 21 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Requested Equity Capital Structure, Percentage | ' | ' | 56.00% | ' | ' | ' | ' | ' | ' | ' | 56.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount | ' | ' | ' | 44.8 | ' | 9 | ' | 10.9 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Approved Rate Increase (Decrease), Amount | 15.8 | ' | ' | ' | ' | ' | ' | ' | ' | 2.3 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Approved Return on Equity, Percentage | 9.72% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Approved Equity Capital Structure, Percentage | 56.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Adjustment for historic test year | -5.4 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Adjustment to requested rate increase (decrease) approved by third parties related to return on equity and capital structure adjustments | -8.3 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Adjustment to requested rate increase (decrease) approved by third parties related to revenue adjustments | -1.4 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Adjustment to requested rate increase (decrease) approved by third parties related to other costs | -0.1 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Rate increase (decrease) approved by third parties excluding PSIA adjustment | 29.6 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Adjustment to requested rate increase (decrease) approved by third parties related to neutralization of PSIA - base rate transfer | -13.8 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Interim Rate Refund, Amount | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 6.6 | ' |
Public Utilities, Return on equity used in weather normalized earnings test | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, refund to customers due to annual earnings test | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 45.7 |
Public Utilities, Requested increase (decrease) to rider revenue | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 43.5 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, proposed increase (decrease) to rider revenue pursuant to settlement agreement | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 43.4 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, total proposed disallowance pursuant to settlement agreement | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0.1 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
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 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
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 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 4 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Cumulative credit against RESA regulatory asset balance | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 104.6 | 104.5 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Proposed transfer between ECA and RESA deferred accounts | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 26.2 | ' | ' | ' | ' | ' | ' |
Proposed Amortization Period For Recovery Of Deferred Costs (in months) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '12 months | ' | ' | ' | ' | ' | ' |
Approved transfer between ECA and RESA deferred accounts | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 26.2 | ' | ' | ' | ' | ' |
Approved amortization period for recovery of deferred costs (in months) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '12 months | ' | ' | ' | ' | ' |
Approved increase (decrease) in interest rate | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -7.40% | ' | ' | ' | ' | ' |
Approved increase (decrease) in interest income resulting from a change in interest rates, Amount | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -4.3 | ' | ' | ' | ' | ' |
Public Utilities, Return on equity requested by third parties | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 9.15% | ' | ' | ' |
Public Utilities, Rate increase (decrease) requested by third parties | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ($1.80) | ' | ' | ' |
Public Utilities, Return on equity requested by third parties, July 2012 through November 2012 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 8.91% | ' | ' | ' | ' |
Public Utilities, Return on equity requested by third parties, after November 2012 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 8.70% | ' | ' | ' | ' |
Rate_Matters_SPS_Details
Rate Matters, SPS (Details) (SPS, USD $) | 1 Months Ended | |||||
In Millions, unless otherwise specified | Jan. 31, 2014 | Nov. 30, 2013 | Mar. 31, 2014 | Sep. 30, 2013 | Dec. 31, 2012 | Apr. 30, 2014 |
Public Utility Commission of Texas (PUCT) | Public Utility Commission of Texas (PUCT) | New Mexico Public Regulation Commission (NMPRC) | New Mexico Public Regulation Commission (NMPRC) | New Mexico Public Regulation Commission (NMPRC) | Subsequent Event | |
2014 Electric Rate Case | Transmission Cost Recovery Factor (TCRF) Rider | 2014 Electric Rate Case | 2014 Electric Rate Case | 2014 Electric Rate Case | Public Utility Commission of Texas (PUCT) | |
2014 Electric Rate Case | ||||||
Public Utilities, General Disclosures [Line Items] | ' | ' | ' | ' | ' | ' |
Public Utilities, Requested Rate Increase (Decrease), Net Amount | $52.70 | ' | ' | ' | ' | ' |
Public Utilities, Requested Rate Increase (Decrease), Percentage | 5.80% | ' | ' | ' | ' | ' |
Public Utilities, Requested Return on Equity, Percentage | 10.40% | ' | ' | 10.25% | 10.65% | ' |
Public Utilities, Requested Rate Base, Amount | 1,270 | ' | ' | ' | 479.8 | ' |
Public Utilities, Requested Equity Capital Structure, Percentage | 53.89% | ' | ' | ' | 53.89% | ' |
Public Utilities, Portion of requested rate increase (decrease) related to depreciation expense | 16 | ' | ' | ' | ' | ' |
Public Utilities, Requested Rate Increase (Decrease), Amended, Net Amount | ' | ' | ' | ' | ' | 48.1 |
Public Utilities, Requested Rate Increase (Decrease), Amended, Percentage | ' | ' | ' | ' | ' | 5.30% |
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount | ' | ' | ' | 32.5 | ' | 76.9 |
Public Utilities, Adjustment requested by public utility to rate increase (decrease) related to resetting TCRF to zero | ' | ' | ' | ' | ' | -12.9 |
Public Utilities, Adjustment requested by public utility to rate increase (decrease) related to customer credit for gain on sale | ' | ' | ' | ' | ' | -4.9 |
Public Utilities, Requested base revenue increase (decrease) excluding fuel clause offsets, Amended | ' | ' | ' | ' | ' | 59.1 |
Public Utilities, Adjustment requested by public utility to rate increase (decrease) related to fuel offsets | ' | ' | ' | ' | ' | -11 |
Public Utilities, Requested increase (decrease) to rider revenue | ' | 13 | ' | ' | ' | ' |
Public Utilities, Requested Rate Increase (Decrease), Amount | ' | ' | ' | ' | 45.9 | ' |
Public Utilities, portion of revised rate increase (decrease) related to base and fuel revenue. | ' | ' | ' | 20.9 | ' | ' |
Public Utilities, portion of revised rate increase (decrease) related to rider revenue | ' | ' | ' | 12.1 | ' | ' |
Public Utilities, portion of revised rate increase (decrease) related to other costs | ' | ' | ' | -0.5 | ' | ' |
Public Utilities, Approved Rate Increase (Decrease), Amount | ' | ' | 33.1 | ' | ' | ' |
Public Utilities, Approved Return on Equity, Percentage | ' | ' | 9.96% | ' | ' | ' |
Public Utilities, Approved Equity Capital Structure, Percentage | ' | ' | 53.89% | ' | ' | ' |
Public Utilities, Approved Rate Increase (Decrease) due to pension, Amount | ' | ' | 2.4 | ' | ' | ' |
Public Utilities, portion of approved rate increase (decrease) to be recovered through rider revenue | ' | ' | 18.1 | ' | ' | ' |
Public Utilities, portion of approved rate increase (decrease) to be recovered through fuel clause adjustment | ' | ' | 2.3 | ' | ' | ' |
Public Utilities, revised rate increase (decrease), fuel adjusted | ' | ' | 34.8 | ' | ' | ' |
Public Utilities, Approved Rate Increase (Decrease) due to return on equity, Amount | ' | ' | -1.2 | ' | ' | ' |
Public Utilities, approved rate increase (decrease) due to rider adjustment for renewable energy costs | ' | ' | 6 | ' | ' | ' |
Public Utilities, approved rate increase (decrease) due to base rate adjustment for renewable energy costs | ' | ' | -6 | ' | ' | ' |
Public Utilities, Approved Rate Increase (Decrease) due to other, Amount | ' | ' | -0.5 | ' | ' | ' |
Public Utilities, portion of approved rate increase (decrease) to be recovered in base revenue | ' | ' | $12.70 | ' | ' | ' |
Commitments_and_Contingencies_1
Commitments and Contingencies, Purchased Power Agreements (Details) (Independent Power Producing Entities) | Mar. 31, 2014 | Dec. 31, 2013 |
MW | MW | |
Independent Power Producing Entities | ' | ' |
Purchased Power Agreements [Abstract] | ' | ' |
Generating capacity (in MW) | 3,698 | 3,338 |
Commitments_and_Contingencies_2
Commitments and Contingencies, Guarantees and Indemnifications (Details) (USD $) | Mar. 31, 2014 | Dec. 31, 2013 |
Guarantees [Abstract] | ' | ' |
Assets held as collateral | $0 | $0 |
Indemnification Agreement | Obligations Under Sale Of Sharyland | ' | ' |
Guarantees [Abstract] | ' | ' |
Guarantees issued and outstanding | 37,100,000 | 37,100,000 |
Guarantor Obligations, Current Carrying Value | 400,000 | 400,000 |
Payment or Performance Guarantee | ' | ' |
Guarantees [Abstract] | ' | ' |
Guarantees issued and outstanding | 18,300,000 | 19,400,000 |
Current exposure under these guarantees | 300,000 | 300,000 |
Payment or Performance Guarantee | Surety Bonds | ' | ' |
Guarantees [Abstract] | ' | ' |
Guarantees issued and outstanding | $32,400,000 | $32,100,000 |
Commitments_and_Contingencies_3
Commitments and Contingencies, Environmental Contingencies - Site Contingencies (Details) (NSP-Wisconsin, USD $) | 3 Months Ended | |
In Millions, unless otherwise specified | Mar. 31, 2014 | Dec. 31, 2013 |
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 | $115.20 | $104.60 |
Liability for estimated cost of remediating sites, current | 33.4 | 25.2 |
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 as reflected in the settlement | 40 | ' |
Liability for estimated cost of remediating sites | 51 | ' |
Estimated amount spent on Phase I Project Area cleanup | 5 | ' |
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% | ' |
Approved increase (decrease) in amortization expense granted by a regulatory body | 1.1 | ' |
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 $) | Dec. 31, 2010 | Mar. 31, 2014 | Mar. 31, 2014 | Apr. 30, 2014 |
In Millions, unless otherwise specified | PSCo | Capital Commitments | Capital Commitments | Subsequent Event |
Regional Haze Rules | PSCo | NSP-Minnesota | Cross-State Air Pollution Rule | |
Group | Regional Haze Rules | Regional Haze Rules | ||
Boiler | ||||
Kiln | ||||
Environmental Requirements [Abstract] | ' | ' | ' | ' |
Number of issues on which the D.C. Circuit overturned the CSAPR | ' | ' | ' | 2 |
Liability for estimated cost to comply with regulation | ' | $359.70 | $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 | ' | ' | $42.50 | ' |
Commitments_and_Contingencies_5
Commitments and Contingencies, Legal Contingencies (Details) (USD $) | 3 Months Ended | 1 Months Ended | 3 Months Ended | 13 Months Ended | ||||||||||
Mar. 31, 2014 | Mar. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2014 | 31-May-11 | Apr. 30, 2011 | Mar. 31, 2011 | Mar. 31, 2014 | Jul. 31, 2011 | Sep. 30, 2007 | Mar. 31, 2014 | Mar. 31, 2014 | Jun. 30, 2001 | Mar. 31, 2014 | |
Pacific Northwest FERC Refund Proceeding [Member] | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | SPS | PSCo | PSCo | |||
Factor | Merricourt Wind Project Litigation [Member] | Merricourt Wind Project Litigation [Member] | Merricourt Wind Project Litigation [Member] | Merricourt Wind Project Litigation [Member] | Fibrominn Fuel Handling Dispute [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 |
Generating capacity (in MW) | ' | ' | ' | ' | ' | 150 | ' | ' | ' | ' | ' | ' | ' | ' |
Merricourt deposit | ' | ' | ' | ' | ' | ' | 101,000,000 | ' | ' | ' | ' | ' | ' | ' |
Minimum amount of damages claimed by plaintiff | ' | ' | ' | ' | 240,000,000 | ' | ' | 19,000,000 | ' | ' | ' | ' | ' | 34,000,000 |
Number of main areas of dispute | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2 | ' | ' |
Number of wind facilities | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 12 | ' | ' |
Sales to the City of Seattle | 3,202,604,000 | 2,782,849,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 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 | ' | ' | ' | ' | ' | ' | ' | ' | $100,000,000 | ' | $181,900,000 | ' | ' | ' |
Borrowings_and_Other_Financing2
Borrowings and Other Financing Instruments, Commercial Paper (Details) (USD $) | 3 Months Ended | 12 Months Ended |
Mar. 31, 2014 | Dec. 31, 2013 | |
Commercial Paper [Abstract] | ' | ' |
Borrowing limit | $2,450,000,000 | $2,450,000,000 |
Amount outstanding at period end | 765,000,000 | 759,000,000 |
Average amount outstanding | 925,000,000 | 481,000,000 |
Maximum amount outstanding | $1,200,000,000 | $1,160,000,000 |
Weighted average interest rate, computed on a daily basis (in hundredths) | 0.31% | 0.31% |
Weighted average interest rate at period end (in hundredths) | 0.33% | 0.25% |
Borrowings_and_Other_Financing3
Borrowings and Other Financing Instruments, Letters of Credit (Details) (USD $) | 3 Months Ended | |
In Millions, unless otherwise specified | Mar. 31, 2014 | Dec. 31, 2013 |
Letters of Credit [Abstract] | ' | ' |
Terms of letters of credit (in years) | '1 year | ' |
Letters of credit outstanding under credit facilities | $46.30 | $47.80 |
Borrowings_and_Other_Financing4
Borrowings and Other Financing Instruments, Credit Facilities (Details) (USD $) | Mar. 31, 2014 | Dec. 31, 2013 | |
Credit Facilities [Abstract] | ' | ' | |
Credit facility | $2,450,000,000 | [1] | ' |
Drawn | 811,400,000 | [2] | ' |
Available | 1,638,600,000 | ' | |
Credit facility bank borrowings outstanding | 0 | 0 | |
Xcel Energy Inc. | ' | ' | |
Credit Facilities [Abstract] | ' | ' | |
Credit facility | 800,000,000 | [1] | ' |
Drawn | 487,000,000 | [2] | ' |
Available | 313,000,000 | ' | |
PSCo | ' | ' | |
Credit Facilities [Abstract] | ' | ' | |
Credit facility | 700,000,000 | [1] | ' |
Drawn | 6,500,000 | [2] | ' |
Available | 693,500,000 | ' | |
NSP-Minnesota | ' | ' | |
Credit Facilities [Abstract] | ' | ' | |
Credit facility | 500,000,000 | [1] | ' |
Drawn | 148,900,000 | [2] | ' |
Available | 351,100,000 | ' | |
SPS | ' | ' | |
Credit Facilities [Abstract] | ' | ' | |
Credit facility | 300,000,000 | [1] | ' |
Drawn | 90,000,000 | [2] | ' |
Available | 210,000,000 | ' | |
NSP-Wisconsin | ' | ' | |
Credit Facilities [Abstract] | ' | ' | |
Credit facility | 150,000,000 | [1] | ' |
Drawn | 79,000,000 | [2] | ' |
Available | $71,000,000 | ' | |
[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) (PSCo, First Mortgage Bonds, Series Due March 15, 2044, USD $) | 3 Months Ended |
Mar. 31, 2014 | |
PSCo | First Mortgage Bonds | Series Due March 15, 2044 | ' |
Long-Term Borrowings and Other Financing Instruments [Abstract] | ' |
Face amount | $300,000,000 |
Interest rate, stated percentage (in hundredths) | 4.30% |
Maturity date | 15-Mar-44 |
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 | 12 Months Ended | 1 Months Ended |
Mar. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Apr. 30, 2014 | |
Subsequent Event | ||||
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) | ' | 2,100,000 | 7,700,000 | ' |
Net cash proceeds from issuance of common stock | ' | 62,000,000 | 223,000,000 | ' |
Fees and commissions from issuance of common stock | ' | 1,000,000 | 3,000,000 | ' |
Shares of common stock sold and recorded on a settlement date basis (in shares) | ' | ' | ' | 500,000 |
Net cash proceeds from sale of common stock recorded on a settlement date basis | ' | ' | ' | 16,000,000 |
Cumulative fees and commissions from common stock sold and recorded on settlement date basis | ' | ' | ' | $200,000 |
Fair_Value_of_Financial_Assets2
Fair Value of Financial Assets and Liabilities (Details) | 3 Months Ended |
Mar. 31, 2014 | |
Minimum [Member] | Commingled Funds and International Equity Funds [Member] | ' |
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items] | ' |
Notice period for investment redemption (in days) | '1 |
Minimum [Member] | Real Estate Funds [Member] | ' |
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items] | ' |
Notice period for investment redemption (in days) | '45 |
Maximum [Member] | Commingled Funds and International Equity Funds [Member] | ' |
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items] | ' |
Notice period for investment redemption (in days) | '90 |
Maximum [Member] | Real Estate Funds [Member] | ' |
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items] | ' |
Notice period for investment redemption (in days) | '90 |
Fair_Value_of_Financial_Assets3
Fair Value of Financial Assets and Liabilities, Cost and Fair Value of Nuclear Decommissioning Fund (Details) (USD $) | 3 Months Ended | 12 Months Ended | ||
Mar. 31, 2014 | Dec. 31, 2013 | |||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Gross Unrealized Gain | $258,600,000 | $240,300,000 | ||
Available-for-sale Securities, Gross Unrealized Loss | 45,800,000 | 58,500,000 | ||
Investments [Abstract] | ' | ' | ||
Equity investments in unconsolidated subsidiaries | 86,300,000 | 87,100,000 | ||
Miscellaneous investments | 43,400,000 | 41,900,000 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | ' | ' | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' | ||
Cash Equivalents | 15,854,000 | 33,281,000 | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities | 1,450,576,000 | 1,445,197,000 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Commingled funds | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities | 476,011,000 | 457,986,000 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | International equity funds | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities | 78,812,000 | 78,812,000 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Private equity investments | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities | 60,912,000 | 52,143,000 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Real estate | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities | 49,224,000 | 45,564,000 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Government securities | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Debt Securities | 34,176,000 | 34,304,000 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | U.S. corporate bonds | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Debt Securities | 78,362,000 | 80,275,000 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | International corporate bonds | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Debt Securities | 15,223,000 | 15,025,000 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Municipal bonds | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Debt Securities | 261,106,000 | 241,112,000 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Common stock | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Equity Securities | 380,896,000 | 406,695,000 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | ' | ' | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' | ||
Cash Equivalents | 15,854,000 | 33,281,000 | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities | 1,663,395,000 | [1] | 1,627,026,000 | [2] |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Commingled funds | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities | 483,409,000 | 452,227,000 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | International equity funds | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities | 82,710,000 | 81,671,000 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Private equity investments | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities | 73,801,000 | 62,696,000 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Real estate | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities | 62,954,000 | 57,368,000 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Government securities | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Debt Securities | 28,822,000 | 27,628,000 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | U.S. corporate bonds | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Debt Securities | 81,827,000 | 83,538,000 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | International corporate bonds | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Debt Securities | 15,685,000 | 15,358,000 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Municipal bonds | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Debt Securities | 260,044,000 | 232,016,000 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Common stock | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Equity Securities | 558,289,000 | 581,243,000 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | ' | ' | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' | ||
Cash Equivalents | 15,854,000 | 33,281,000 | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities | 574,143,000 | 614,524,000 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Commingled funds | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities | 0 | 0 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | International equity funds | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities | 0 | 0 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Private equity investments | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities | 0 | 0 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Real estate | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities | 0 | 0 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Government securities | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Debt Securities | 0 | 0 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | U.S. corporate bonds | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Debt Securities | 0 | 0 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | International corporate bonds | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Debt Securities | 0 | 0 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Municipal bonds | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Debt Securities | 0 | 0 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Common stock | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Equity Securities | 558,289,000 | 581,243,000 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | ' | ' | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' | ||
Cash Equivalents | 0 | 0 | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities | 952,497,000 | 892,438,000 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Commingled funds | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities | 483,409,000 | 452,227,000 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | International equity funds | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities | 82,710,000 | 81,671,000 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Private equity investments | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities | 0 | 0 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Real estate | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities | 0 | 0 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Government securities | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Debt Securities | 28,822,000 | 27,628,000 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | U.S. corporate bonds | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Debt Securities | 81,827,000 | 83,538,000 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | International corporate bonds | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Debt Securities | 15,685,000 | 15,358,000 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Municipal bonds | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Debt Securities | 260,044,000 | 232,016,000 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Common stock | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Equity Securities | 0 | 0 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | ' | ' | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' | ||
Cash Equivalents | 0 | 0 | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities | 136,755,000 | 120,064,000 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Commingled funds | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities | 0 | 0 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | International equity funds | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities | 0 | 0 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Private equity investments | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities | 73,801,000 | 62,696,000 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Real estate | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities | 62,954,000 | 57,368,000 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Government securities | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Debt Securities | 0 | 0 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | U.S. corporate bonds | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Debt Securities | 0 | 0 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | International corporate bonds | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Debt Securities | 0 | 0 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Municipal bonds | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Debt Securities | 0 | 0 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Common stock | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Equity Securities | $0 | $0 | ||
[1] | Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $86.3 million of equity investments in unconsolidated subsidiaries and $43.4 million of miscellaneous investments. | |||
[2] | Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $87.1 million of equity investments in unconsolidated subsidiaries and $41.9 million of miscellaneous investments. |
Fair_Value_of_Financial_Assets4
Fair Value of Financial Assets and Liabilities, Changes in Level 3 Nuclear Decommissioning Fund (Details) (USD $) | 3 Months Ended | ||
In Thousands, unless otherwise specified | Mar. 31, 2014 | Mar. 31, 2013 | |
Changes in Level 3 Nuclear Decommissioning Fund Assets [Roll Forward] | ' | ' | |
Balance at beginning of period | $120,064 | $104,600 | |
Purchases | 12,429 | 6,042 | |
Settlements | 0 | -4,299 | |
Gains recognized as regulatory assets | 4,262 | 845 | |
Transfers out of Level 3 | 0 | -32,276 | [1] |
Balance at end of period | 136,755 | 74,912 | |
Private equity investments | ' | ' | |
Changes in Level 3 Nuclear Decommissioning Fund Assets [Roll Forward] | ' | ' | |
Balance at beginning of period | 62,696 | 33,250 | |
Purchases | 8,769 | 1,256 | |
Settlements | 0 | 0 | |
Gains recognized as regulatory assets | 2,336 | 0 | |
Transfers out of Level 3 | 0 | 0 | |
Balance at end of period | 73,801 | 34,506 | |
Real estate | ' | ' | |
Changes in Level 3 Nuclear Decommissioning Fund Assets [Roll Forward] | ' | ' | |
Balance at beginning of period | 57,368 | 39,074 | |
Purchases | 3,660 | 4,786 | |
Settlements | 0 | -4,299 | |
Gains recognized as regulatory assets | 1,926 | 845 | |
Transfers out of Level 3 | 0 | 0 | |
Balance at end of period | 62,954 | 40,406 | |
Asset-backed Securities | ' | ' | |
Changes in Level 3 Nuclear Decommissioning Fund Assets [Roll Forward] | ' | ' | |
Balance at beginning of period | ' | 2,067 | |
Purchases | ' | 0 | |
Settlements | ' | 0 | |
Gains recognized as regulatory assets | ' | 0 | |
Transfers out of Level 3 | ' | -2,067 | [1] |
Balance at end of period | ' | 0 | |
Mortgage-backed Securities | ' | ' | |
Changes in Level 3 Nuclear Decommissioning Fund Assets [Roll Forward] | ' | ' | |
Balance at beginning of period | ' | 30,209 | |
Purchases | ' | 0 | |
Settlements | ' | 0 | |
Gains recognized as regulatory assets | ' | 0 | |
Transfers out of Level 3 | ' | -30,209 | [1] |
Balance at end of period | ' | $0 | |
[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_Assets5
Fair Value of Financial Assets and Liabilities, Final Contractual Maturity Dates of Debt Securities in Nuclear Decommissioning Fund (Details) (USD $) | Mar. 31, 2014 |
In Thousands, unless otherwise specified | |
Final Contractual Maturity [Abstract] | ' |
Due in 1 Year or Less | $3,399 |
Due in 1 to 5 Years | 44,988 |
Due in 5 to 10 Years | 115,034 |
Due after 10 Years | 222,957 |
Total | 386,378 |
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 | 28,822 |
Total | 28,822 |
U.S. corporate bonds | ' |
Final Contractual Maturity [Abstract] | ' |
Due in 1 Year or Less | 311 |
Due in 1 to 5 Years | 15,816 |
Due in 5 to 10 Years | 64,341 |
Due after 10 Years | 1,359 |
Total | 81,827 |
International corporate bonds | ' |
Final Contractual Maturity [Abstract] | ' |
Due in 1 Year or Less | 0 |
Due in 1 to 5 Years | 3,762 |
Due in 5 to 10 Years | 11,923 |
Due after 10 Years | 0 |
Total | 15,685 |
Municipal bonds | ' |
Final Contractual Maturity [Abstract] | ' |
Due in 1 Year or Less | 3,088 |
Due in 1 to 5 Years | 25,410 |
Due in 5 to 10 Years | 38,770 |
Due after 10 Years | 192,776 |
Total | $260,044 |
Fair_Value_of_Financial_Assets6
Fair Value of Financial Assets and Liabilities, Derivative Instruments (Details) (USD $) | Mar. 31, 2014 | Dec. 31, 2013 | ||
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 | 41.2 | ' | ||
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties | 15.00% | ' | ||
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 | 6 | ' | ||
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties | 79.2 | ' | ||
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties | 29.00% | ' | ||
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 | 32,453,000 | [1],[2] | 58,423,000 | [1],[2] |
Natural Gas Commodity [Member] | ' | ' | ||
Gross Notional Amounts of Commodity Forwards, Options and FTRs [Abstract] | ' | ' | ||
Notional amount | 0 | [1],[2] | 9,854,000 | [1],[2] |
Vehicle Fuel Commodity [Member] | ' | ' | ||
Gross Notional Amounts of Commodity Forwards, Options and FTRs [Abstract] | ' | ' | ||
Notional amount | 432,000 | [1],[2] | 482,000 | [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_Assets7
Fair Value of Financial Assets and Liabilities, Impact of Derivative Activity (Details) (USD $) | 3 Months Ended | |||
Mar. 31, 2014 | Mar. 31, 2013 | |||
Financial Impact of Qualifying Fair Value Hedges on Earnings [Abstract] | ' | ' | ||
Derivative instruments designated as fair value hedges | $0 | $0 | ||
Recognized gains (losses) from fair value hedges or related hedged transactions | 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 | -12,000 | 25,000 | ||
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities | 0 | 0 | ||
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss | 918,000 | 1,124,000 | ||
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities) | 0 | 0 | ||
Pre-tax gains (losses) recognized during the period in income | 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 | 0 | ||
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities | 0 | 0 | ||
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss | 946,000 | [1] | 1,150,000 | [1] |
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities) | 0 | 0 | ||
Pre-tax gains (losses) recognized during the period in income | 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 | -12,000 | 25,000 | ||
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities | 0 | 0 | ||
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss | -28,000 | [2] | -26,000 | [2] |
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities) | 0 | 0 | ||
Pre-tax gains (losses) recognized during the period in income | 0 | 0 | ||
Other Derivative Instrument [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 | ||
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities | 22,033,000 | 6,473,000 | ||
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss | 0 | 0 | ||
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities) | -39,536,000 | -15,220,000 | ||
Pre-tax gains (losses) recognized during the period in income | -7,555,000 | 2,792,000 | ||
Other Derivative Instrument [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 | ||
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities | 0 | 0 | ||
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss | 0 | 0 | ||
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities) | 0 | 0 | ||
Pre-tax gains (losses) recognized during the period in income | -2,253,000 | [3] | 2,776,000 | [3] |
Other Derivative Instrument [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 | ||
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities | 3,527,000 | 6,419,000 | ||
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss | 0 | 0 | ||
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities) | -20,696,000 | -15,229,000 | ||
Pre-tax gains (losses) recognized during the period in income | 0 | 0 | ||
Other Derivative Instrument [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 | ||
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities | 18,506,000 | 54,000 | ||
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss | 0 | 0 | ||
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities) | -18,840,000 | 9,000 | ||
Pre-tax gains (losses) recognized during the period in income | ($5,302,000) | [4] | $16,000 | [4] |
[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 for the three months ended March 31, 2014 and 2013 included immaterial settlement losses on derivatives entered to mitigate natural gas price risk for electric generation, recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate. The remaining derivative settlement gains and losses for the three months ended March 31, 2014 and 2013 relate to natural gas operations and are recorded to cost of natural gas sold and transported. These gains and losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset or liability, as appropriate. |
Fair_Value_of_Financial_Assets8
Fair Value of Financial Assets and Liabilities, Credit Related Contingent Features (Details) (USD $) | Mar. 31, 2014 | Dec. 31, 2013 |
Fair Value Disclosures [Abstract] | ' | ' |
Derivative instruments in a gross liability position | $1,100,000 | $1,400,000 |
Payments required if credit ratings were downgraded below investment grade | 1,100,000 | 1,400,000 |
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 $) | Mar. 31, 2014 | Dec. 31, 2013 | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Collateral, Obligation to Return Cash, Offset | $100,000 | $200,000 | ||
Derivative Liability, Collateral, Right to Reclaim Cash, Offset | 6,500,000 | 4,200,000 | ||
Other Current Assets [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 70,275,000 | 91,707,000 | ||
Other Noncurrent Assets [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 67,513,000 | 84,842,000 | ||
Other Current Liabilities [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 22,358,000 | 23,382,000 | ||
Other Noncurrent Liabilities [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 199,578,000 | 209,224,000 | ||
Fair Value Measured on a Recurring Basis | Other Current Assets [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 37,247,000 | 58,679,000 | ||
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 | 58,000 | 88,000 | ||
Fair Value Measured on a Recurring Basis | Other Current Assets [Member] | Other Derivative Instrument [Member] | Commodity Trading | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 15,456,000 | 13,783,000 | ||
Fair Value Measured on a Recurring Basis | Other Current Assets [Member] | Other Derivative Instrument [Member] | Electric Commodity [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 21,733,000 | 38,902,000 | ||
Fair Value Measured on a Recurring Basis | Other Current Assets [Member] | Other Derivative Instrument [Member] | Natural Gas Commodity [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | ' | 5,906,000 | ||
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 17,261,000 | 26,411,000 | ||
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 | 18,000 | 13,000 | ||
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets [Member] | Other Derivative Instrument [Member] | Commodity Trading | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 17,243,000 | 26,398,000 | ||
Fair Value Measured on a Recurring Basis | Other Current Liabilities [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 0 | 348,000 | ||
Fair Value Measured on a Recurring Basis | Other Current Liabilities [Member] | Other Derivative Instrument [Member] | Commodity Trading | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 0 | 348,000 | ||
Fair Value Measured on a Recurring Basis | Other Current Liabilities [Member] | Other Derivative 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 Noncurrent Liabilities [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 692,000 | 5,295,000 | ||
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities [Member] | Other Derivative Instrument [Member] | Commodity Trading | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 692,000 | 5,295,000 | ||
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets [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] | Other Derivative 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] | Other Derivative 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] | Other Derivative Instrument [Member] | Natural Gas Commodity [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | ' | 0 | ||
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Assets [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] | Other Derivative 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] | ' | ' | ||
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] | Other Derivative 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] | Other Derivative 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 Noncurrent Liabilities [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] | Other Derivative 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] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 21,037,000 | 26,604,000 | ||
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 | 58,000 | 88,000 | ||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets [Member] | Other Derivative Instrument [Member] | Commodity Trading | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 20,979,000 | 20,610,000 | ||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets [Member] | Other Derivative 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] | Other Derivative Instrument [Member] | Natural Gas Commodity [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | ' | 5,906,000 | ||
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Assets [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 15,736,000 | 32,103,000 | ||
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 | 18,000 | 29,000 | ||
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Assets [Member] | Other Derivative Instrument [Member] | Commodity Trading | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 15,718,000 | 32,074,000 | ||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 11,946,000 | 10,546,000 | ||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities [Member] | Other Derivative Instrument [Member] | Commodity Trading | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 11,946,000 | 10,546,000 | ||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities [Member] | Other Derivative 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 Noncurrent Liabilities [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 1,707,000 | 14,382,000 | ||
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Liabilities [Member] | Other Derivative Instrument [Member] | Commodity Trading | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 1,707,000 | 14,382,000 | ||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 27,584,000 | 48,279,000 | ||
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] | Other Derivative Instrument [Member] | Commodity Trading | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 944,000 | 1,167,000 | ||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets [Member] | Other Derivative Instrument [Member] | Electric Commodity [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 26,640,000 | 47,112,000 | ||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets [Member] | Other Derivative Instrument [Member] | Natural Gas Commodity [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | ' | 0 | ||
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Assets [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 1,932,000 | 3,395,000 | ||
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] | Other Derivative Instrument [Member] | Commodity Trading | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 1,932,000 | 3,395,000 | ||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 5,299,000 | 10,014,000 | ||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities [Member] | Other Derivative Instrument [Member] | Commodity Trading | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 392,000 | 1,804,000 | ||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities [Member] | Other Derivative Instrument [Member] | Electric Commodity [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 4,907,000 | 8,210,000 | ||
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Liabilities [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] | Other Derivative 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 | Other Current Assets [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 48,621,000 | 74,883,000 | ||
Fair Value Measured on a Recurring Basis | Fair Value Total | 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 | 58,000 | 88,000 | ||
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Assets [Member] | Other Derivative Instrument [Member] | Commodity Trading | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 21,923,000 | 21,777,000 | ||
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Assets [Member] | Other Derivative Instrument [Member] | Electric Commodity [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 26,640,000 | 47,112,000 | ||
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Assets [Member] | Other Derivative Instrument [Member] | Natural Gas Commodity [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | ' | 5,906,000 | ||
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Noncurrent Assets [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 17,668,000 | 35,498,000 | ||
Fair Value Measured on a Recurring Basis | Fair Value Total | 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 | 18,000 | 29,000 | ||
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Noncurrent Assets [Member] | Other Derivative Instrument [Member] | Commodity Trading | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 17,650,000 | 35,469,000 | ||
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Liabilities [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 17,245,000 | 20,560,000 | ||
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Liabilities [Member] | Other Derivative Instrument [Member] | Commodity Trading | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 12,338,000 | 12,350,000 | ||
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Liabilities [Member] | Other Derivative Instrument [Member] | Electric Commodity [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 4,907,000 | 8,210,000 | ||
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Noncurrent Liabilities [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 1,707,000 | 14,382,000 | ||
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Noncurrent Liabilities [Member] | Other Derivative Instrument [Member] | Commodity Trading | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 1,707,000 | 14,382,000 | ||
Fair Value Measured on a Recurring Basis | Counterparty Netting [Member] | Other Current Assets [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | -11,374,000 | [1] | -16,204,000 | [2] |
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 | [1] | 0 | [2] |
Fair Value Measured on a Recurring Basis | Counterparty Netting [Member] | Other Current Assets [Member] | Other Derivative Instrument [Member] | Commodity Trading | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | -6,467,000 | [1] | -7,994,000 | [2] |
Fair Value Measured on a Recurring Basis | Counterparty Netting [Member] | Other Current Assets [Member] | Other Derivative Instrument [Member] | Electric Commodity [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | -4,907,000 | [1] | -8,210,000 | [2] |
Fair Value Measured on a Recurring Basis | Counterparty Netting [Member] | Other Current Assets [Member] | Other Derivative Instrument [Member] | Natural Gas Commodity [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | ' | 0 | [2] | |
Fair Value Measured on a Recurring Basis | Counterparty Netting [Member] | Other Noncurrent Assets [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | -407,000 | [1] | -9,087,000 | [2] |
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 | 0 | [1] | -16,000 | [2] |
Fair Value Measured on a Recurring Basis | Counterparty Netting [Member] | Other Noncurrent Assets [Member] | Other Derivative Instrument [Member] | Commodity Trading | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | -407,000 | [1] | -9,071,000 | [2] |
Fair Value Measured on a Recurring Basis | Counterparty Netting [Member] | Other Current Liabilities [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | -17,245,000 | [1] | -20,212,000 | [2] |
Fair Value Measured on a Recurring Basis | Counterparty Netting [Member] | Other Current Liabilities [Member] | Other Derivative Instrument [Member] | Commodity Trading | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | -12,338,000 | [1] | -12,002,000 | [2] |
Fair Value Measured on a Recurring Basis | Counterparty Netting [Member] | Other Current Liabilities [Member] | Other Derivative Instrument [Member] | Electric Commodity [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | -4,907,000 | [1] | -8,210,000 | [2] |
Fair Value Measured on a Recurring Basis | Counterparty Netting [Member] | Other Noncurrent Liabilities [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | -1,015,000 | [1] | -9,087,000 | [2] |
Fair Value Measured on a Recurring Basis | Counterparty Netting [Member] | Other Noncurrent Liabilities [Member] | Other Derivative Instrument [Member] | Commodity Trading | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | -1,015,000 | [1] | -9,087,000 | [2] |
Fair Value, Measurements, Nonrecurring [Member] | Other Current Assets [Member] | Purchased Power Agreements [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 33,028,000 | [3] | 33,028,000 | [3] |
Fair Value, Measurements, Nonrecurring [Member] | Other Noncurrent Assets [Member] | Purchased Power Agreements [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 50,252,000 | [3] | 58,431,000 | [3] |
Fair Value, Measurements, Nonrecurring [Member] | Other Current Liabilities [Member] | Purchased Power Agreements [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 22,358,000 | [3] | 23,034,000 | [3] |
Fair Value, Measurements, Nonrecurring [Member] | Other Noncurrent Liabilities [Member] | Purchased Power Agreements [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | $198,886,000 | [3] | $203,929,000 | [3] |
[1] | Xcel Energy nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at March 31, 2014. At March 31, 2014, derivative assets and liabilities include obligations to return cash collateral of $0.1 million and rights to reclaim cash collateral of $6.5 million. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements. | |||
[2] | Xcel Energy nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2013. At Dec. 31, 2013, derivative assets and liabilities include obligations to return cash collateral of $0.2 million and rights to reclaim cash collateral of $4.2 million. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements. | |||
[3] | In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, Xcel Energy began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, Xcel Energy qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities. |
Recovered_Sheet1
Fair Value of Financial Assets and Liabilities, Changes in Level 3 Commodity Derivatives (Details) (Commodity Contract [Member], USD $) | 3 Months Ended | |
Mar. 31, 2014 | Mar. 31, 2013 | |
Commodity Contract [Member] | ' | ' |
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward] | ' | ' |
Balance at beginning of period | $41,660,000 | $16,649,000 |
Purchases | 1,056,000 | 0 |
Settlements | -53,809,000 | -12,449,000 |
Gains (losses) recognized in earnings | 999,000 | -62,000 |
Gains recognized as regulatory assets and liabilities | 34,311,000 | 3,504,000 |
Balance at end of period | 24,217,000 | 7,642,000 |
Transfers into Level 3 | 0 | 0 |
Transfers out of Level 3 | $0 | $0 |
Recovered_Sheet2
Fair Value of Financial Assets and Liabilities, Fair Value of Long-Term Debt (Details) (USD $) | Mar. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Carrying Amount | ' | ' |
Financial Liabilities, Balance Sheet Groupings [Abstract] | ' | ' |
Long-term debt, including current portion | $11,487,452 | $11,191,517 |
Fair Value | ' | ' |
Financial Liabilities, Balance Sheet Groupings [Abstract] | ' | ' |
Long-term debt, including current portion | $12,511,410 | $11,878,643 |
Other_Income_Net_Details
Other Income, Net (Details) (USD $) | 3 Months Ended | |
In Thousands, unless otherwise specified | Mar. 31, 2014 | Mar. 31, 2013 |
Other Income and Expenses [Abstract] | ' | ' |
Interest income | $3,893 | $4,806 |
Other nonoperating income | 1,116 | 1,255 |
Insurance policy expense | -1,808 | -2,139 |
Other income, net | $3,201 | $3,922 |
Segment_Information_Details
Segment Information (Details) (USD $) | 3 Months Ended | ||
Mar. 31, 2014 | Mar. 31, 2013 | Dec. 31, 2013 | |
Segment Reporting Information [Line Items] | ' | ' | ' |
Equity investments in unconsolidated subsidiaries | $86,300,000 | ' | $87,100,000 |
Operating revenues | 3,202,604,000 | 2,782,849,000 | ' |
Net income (loss) | 261,221,000 | 236,570,000 | ' |
Regulated Electric | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' |
Operating revenues | 2,302,063,000 | 2,092,497,000 | ' |
Net income (loss) | 185,433,000 | 174,106,000 | ' |
Regulated Natural Gas | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' |
Equity investments in unconsolidated subsidiaries | 86,300,000 | ' | 87,100,000 |
Operating revenues | 882,940,000 | 670,096,000 | ' |
Net income (loss) | 77,336,000 | 64,910,000 | ' |
All Other | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' |
Operating revenues | 21,206,000 | 21,057,000 | ' |
Net income (loss) | -1,548,000 | -2,446,000 | ' |
Operating Segments | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' |
Operating revenues | 3,202,604,000 | 2,782,849,000 | ' |
Operating Segments | Regulated Electric | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' |
Operating revenues | 2,301,710,000 | 2,092,196,000 | ' |
Operating Segments | Regulated Natural Gas | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' |
Operating revenues | 879,688,000 | 669,596,000 | ' |
Operating Segments | All Other | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' |
Operating revenues | 21,206,000 | 21,057,000 | ' |
Intersegment Eliminations | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' |
Operating revenues | -3,605,000 | -801,000 | ' |
Intersegment Eliminations | Regulated Electric | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' |
Operating revenues | 353,000 | 301,000 | ' |
Intersegment Eliminations | Regulated Natural Gas | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' |
Operating revenues | 3,252,000 | 500,000 | ' |
Intersegment Eliminations | All Other | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' |
Operating revenues | $0 | $0 | ' |
Earnings_Per_Share_Details
Earnings Per Share (Details) (USD $) | 3 Months Ended | |
In Thousands, except Per Share data, unless otherwise specified | Mar. 31, 2014 | Mar. 31, 2013 |
Dilutive Impact of Common Stock Equivalents on Earnings per Share (Abstract] | ' | ' |
Net income | $261,221 | $236,570 |
Basic earnings per share [Abstract] | ' | ' |
Earnings available to common shareholders | 261,221 | 236,570 |
Weighted average common shares outstanding - basic (in shares) | 499,523 | 489,781 |
Earnings available to common shareholders - basic (in dollars per share) | $0.52 | $0.48 |
Effect of dilutive securities [Abstract] | ' | ' |
Time based equity awards | 223 | 750 |
Diluted earnings per share [Abstract] | ' | ' |
Earnings available to common shareholders | $261,221 | $236,570 |
Weighted average common shares outstanding - diluted (in shares) | 499,746 | 490,531 |
Earnings available to common shareholders - diluted (in dollars per share) | $0.52 | $0.48 |
Benefit_Plans_and_Other_Postre2
Benefit Plans and Other Postretirement Benefits (Details) (USD $) | 1 Months Ended | 3 Months Ended | |
Jan. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2013 | |
Plan | |||
Pension Benefits | ' | ' | ' |
Components of Net Periodic Benefit Cost [Abstract] | ' | ' | ' |
Service cost | ' | $22,086,000 | $24,071,000 |
Interest cost | ' | 39,155,000 | 35,172,000 |
Expected return on plan assets | ' | -51,801,000 | -49,613,000 |
Amortization of transition obligation | ' | 0 | 0 |
Amortization of prior service (credit) cost | ' | -437,000 | 1,468,000 |
Amortization of net loss | ' | 29,191,000 | 36,038,000 |
Net periodic benefit cost | ' | 38,194,000 | 47,136,000 |
Costs not recognized due to the effects of regulation | ' | -7,052,000 | -7,847,000 |
Net benefit cost recognized for financial reporting | ' | 31,142,000 | 39,289,000 |
Total contributions to Xcel Energy's pension plans during the period | 130,000,000 | ' | ' |
Number of pension plans to which contributions were made | 3 | ' | ' |
Postretirement Health Care Benefits | ' | ' | ' |
Components of Net Periodic Benefit Cost [Abstract] | ' | ' | ' |
Service cost | ' | 864,000 | 1,182,000 |
Interest cost | ' | 8,507,000 | 8,417,000 |
Expected return on plan assets | ' | -8,489,000 | -8,253,000 |
Amortization of transition obligation | ' | 0 | 206,000 |
Amortization of prior service (credit) cost | ' | -2,672,000 | -2,438,000 |
Amortization of net loss | ' | 2,935,000 | 5,646,000 |
Net periodic benefit cost | ' | 1,145,000 | 4,760,000 |
Costs not recognized due to the effects of regulation | ' | 0 | 0 |
Net benefit cost recognized for financial reporting | ' | $1,145,000 | $4,760,000 |
Other_Comprehensive_Income_Det
Other Comprehensive Income (Details) (USD $) | 3 Months Ended | |||
In Thousands, unless otherwise specified | Mar. 31, 2014 | Mar. 31, 2013 | ||
Accumulated Other Comprehensive Income [Roll Forward] | ' | ' | ||
Accumulated other comprehensive gain (loss) at beginning of period | ($106,275) | ($112,653) | ||
Other comprehensive gain (loss) before reclassifications | 31 | -23 | ||
(Gains) losses reclassified from net accumulated other comprehensive loss | 1,424 | -944 | ||
Net current period other comprehensive income (loss) | 1,455 | -967 | ||
Accumulated other comprehensive gain (loss) at end of period | -104,820 | -113,620 | ||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | ' | ' | ||
Operating and maintenance expenses | 560,143 | 529,231 | ||
Total, pre-tax | -396,992 | -355,004 | ||
Tax benefit | 135,771 | 118,434 | ||
Amounts Reclassified from Accumulated Other Comprehensive Loss [Member] | ' | ' | ||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | ' | ' | ||
Total, net of tax | 1,424 | -944 | ||
Gains and Losses on Cash Flow Hedges [Member] | ' | ' | ||
Accumulated Other Comprehensive Income [Roll Forward] | ' | ' | ||
Accumulated other comprehensive gain (loss) at beginning of period | -59,753 | -61,241 | ||
Other comprehensive gain (loss) before reclassifications | -7 | 13 | ||
(Gains) losses reclassified from net accumulated other comprehensive loss | 560 | -305 | ||
Net current period other comprehensive income (loss) | 553 | -292 | ||
Accumulated other comprehensive gain (loss) at end of period | -59,200 | -61,533 | ||
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 | 918 | 1,124 | ||
Tax benefit | -358 | -1,429 | ||
Total, net of tax | 560 | -305 | ||
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 | 946 | [1] | 1,150 | [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 | -28 | [2] | -26 | [2] |
Unrealized Gains and Losses on Marketable Securities [Member] | ' | ' | ||
Accumulated Other Comprehensive Income [Roll Forward] | ' | ' | ||
Accumulated other comprehensive gain (loss) at beginning of period | 77 | -99 | ||
Other comprehensive gain (loss) before reclassifications | 38 | -36 | ||
(Gains) losses reclassified from net accumulated other comprehensive loss | 0 | 0 | ||
Net current period other comprehensive income (loss) | 38 | -36 | ||
Accumulated other comprehensive gain (loss) at end of period | 115 | -135 | ||
Defined Benefit Pension and Postretirement Items [Member] | ' | ' | ||
Accumulated Other Comprehensive Income [Roll Forward] | ' | ' | ||
Accumulated other comprehensive gain (loss) at beginning of period | -46,599 | -51,313 | ||
Other comprehensive gain (loss) before reclassifications | 0 | 0 | ||
(Gains) losses reclassified from net accumulated other comprehensive loss | 864 | -639 | ||
Net current period other comprehensive income (loss) | 864 | -639 | ||
Accumulated other comprehensive gain (loss) at end of period | -45,735 | -51,952 | ||
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 | 1,500 | [3] | 1,769 | [3] |
Prior service (credit) cost | -86 | [3] | 93 | [3] |
Transition obligation | 0 | [3] | 2 | [3] |
Total, pre-tax | 1,414 | 1,864 | ||
Tax benefit | -550 | -2,503 | ||
Total, net of tax | $864 | ($639) | ||
[1] | Included in interest charges. | |||
[2] | Included in O&M expenses. | |||
[3] | Included in the computation of net periodic pension and postretirement benefit costs. See Note 12 for details regarding these benefit plans. |