Document_and_Entity_Informatio
Document and Entity Information | 9 Months Ended | |
Sep. 30, 2014 | Oct. 24, 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 | ' | 505,685,923 |
Document Fiscal Year Focus | '2014 | ' |
Document Fiscal Period Focus | 'Q3 | ' |
Document Type | '10-Q | ' |
Amendment Flag | 'false | ' |
Document Period End Date | 30-Sep-14 | ' |
CONSOLIDATED_STATEMENTS_OF_INC
CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) (USD $) | 3 Months Ended | 9 Months Ended | ||
In Thousands, except Per Share data, unless otherwise specified | Sep. 30, 2014 | Sep. 30, 2013 | Sep. 30, 2014 | Sep. 30, 2013 |
Operating revenues | ' | ' | ' | ' |
Electric | $2,616,351 | $2,599,925 | $7,215,699 | $6,911,998 |
Natural gas | 236,649 | 205,358 | 1,485,464 | 1,216,275 |
Other | 16,807 | 17,055 | 56,344 | 55,827 |
Total operating revenues | 2,869,807 | 2,822,338 | 8,757,507 | 8,184,100 |
Operating expenses | ' | ' | ' | ' |
Electric fuel and purchased power | 1,079,855 | 1,097,944 | 3,188,498 | 3,034,031 |
Cost of natural gas sold and transported | 99,344 | 74,847 | 934,073 | 702,987 |
Cost of sales — other | 8,012 | 7,540 | 24,783 | 23,832 |
Operating and maintenance expenses | 568,391 | 575,305 | 1,714,138 | 1,667,093 |
Conservation and demand side management program expenses | 75,172 | 67,811 | 223,552 | 192,288 |
Depreciation and amortization | 255,395 | 228,491 | 756,645 | 721,131 |
Taxes (other than income taxes) | 117,958 | 105,287 | 358,938 | 320,765 |
Total operating expenses | 2,204,127 | 2,157,225 | 7,200,627 | 6,662,127 |
Operating income | 665,680 | 665,113 | 1,556,880 | 1,521,973 |
Other income (expense), net | 1,404 | -404 | 4,687 | 3,931 |
Equity earnings of unconsolidated subsidiaries | 7,401 | 7,273 | 22,650 | 22,379 |
Allowance for funds used during construction — equity | 23,337 | 21,284 | 68,852 | 63,147 |
Interest charges and financing costs | ' | ' | ' | ' |
Interest charges — includes other financing costs of $5,737, $6,020, $17,144 and $24,058, respectively | 143,219 | 144,542 | 421,713 | 431,026 |
Allowance for funds used during construction — debt | -9,948 | -9,377 | -29,609 | -28,451 |
Total interest charges and financing costs | 133,271 | 135,165 | 392,104 | 402,575 |
Income before income taxes | 564,551 | 558,101 | 1,260,965 | 1,208,855 |
Income taxes | 195,969 | 193,349 | 435,998 | 410,676 |
Net income | $368,582 | $364,752 | $824,967 | $798,179 |
Weighted average common shares outstanding: | ' | ' | ' | ' |
Basic (in shares) | 506,082 | 498,149 | 502,983 | 495,256 |
Diluted (in shares) | 506,365 | 498,641 | 503,213 | 495,767 |
Earnings per average common share: | ' | ' | ' | ' |
Basic (in dollars per share) | $0.73 | $0.73 | $1.64 | $1.61 |
Diluted (in dollars per share) | $0.73 | $0.73 | $1.64 | $1.61 |
Cash dividends declared per common share (in dollars per share) | $0.30 | $0.28 | $0.90 | $0.83 |
CONSOLIDATED_STATEMENTS_OF_INC1
CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) (Parenthetical) (USD $) | 3 Months Ended | 9 Months Ended | ||
In Thousands, unless otherwise specified | Sep. 30, 2014 | Sep. 30, 2013 | Sep. 30, 2014 | Sep. 30, 2013 |
Interest charges and financing costs | ' | ' | ' | ' |
Other financing costs | $5,737 | $6,020 | $17,144 | $24,058 |
CONSOLIDATED_STATEMENTS_OF_COM
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) (USD $) | 3 Months Ended | 9 Months Ended | ||
In Thousands, unless otherwise specified | Sep. 30, 2014 | Sep. 30, 2013 | Sep. 30, 2014 | Sep. 30, 2013 |
Comprehensive income: | ' | ' | ' | ' |
Net income | $368,582 | $364,752 | $824,967 | $798,179 |
Pension and retiree medical benefits: | ' | ' | ' | ' |
Amortization of losses included in net periodic benefit cost, net of tax of $567, $686, $1,666 and $3,918, respectively | 847 | 1,179 | 2,575 | 1,675 |
Derivative instruments: | ' | ' | ' | ' |
Net fair value (decrease) increase, net of tax of $(27), $14, $(22), and $(2), respectively | -42 | 22 | -34 | -9 |
Reclassification of losses to net income, net of tax of $393, $266, $1,115 and $2,145, respectively | 558 | 539 | 1,693 | 928 |
Total derivative instruments, net of tax | 516 | 561 | 1,659 | 919 |
Marketable securities: | ' | ' | ' | ' |
Net fair value increase, net of tax of $1, $73, $26 and $56, respectively | 2 | 115 | 40 | 79 |
Other comprehensive income | 1,365 | 1,855 | 4,274 | 2,673 |
Comprehensive income | $369,947 | $366,607 | $829,241 | $800,852 |
CONSOLIDATED_STATEMENTS_OF_COM1
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) (Parenthetical) (USD $) | 3 Months Ended | 9 Months Ended | ||
In Thousands, unless otherwise specified | Sep. 30, 2014 | Sep. 30, 2013 | Sep. 30, 2014 | Sep. 30, 2013 |
Pension and retiree medical benefits: | ' | ' | ' | ' |
Amortization of losses included in net periodic benefit cost, tax | $567 | $686 | $1,666 | $3,918 |
Derivative instruments: | ' | ' | ' | ' |
Net fair value increase (decrease), tax | -27 | 14 | -22 | -2 |
Reclassification of losses to net income, tax | 393 | 266 | 1,115 | 2,145 |
Marketable securities: | ' | ' | ' | ' |
Net fair value increase (decrease), tax | $1 | $73 | $26 | $56 |
CONSOLIDATED_STATEMENTS_OF_CAS
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) (USD $) | 9 Months Ended | |
In Thousands, unless otherwise specified | Sep. 30, 2014 | Sep. 30, 2013 |
Operating activities | ' | ' |
Net income | $824,967 | $798,179 |
Adjustments to reconcile net income to cash provided by operating activities: | ' | ' |
Depreciation and amortization | 769,706 | 740,623 |
Conservation and demand side management program amortization | 4,582 | 5,024 |
Nuclear fuel amortization | 92,278 | 76,447 |
Deferred income taxes | 433,224 | 409,662 |
Amortization of investment tax credits | -4,329 | -4,973 |
Allowance for equity funds used during construction | -68,852 | -63,147 |
Equity earnings of unconsolidated subsidiaries | -22,650 | -22,379 |
Dividends from unconsolidated subsidiaries | 27,130 | 27,503 |
Share-based compensation expense | 16,536 | 28,362 |
Net realized and unrealized hedging and derivative transactions | -1,354 | -12,011 |
Changes in operating assets and liabilities: | ' | ' |
Accounts receivable | -16,080 | -108,488 |
Accrued unbilled revenues | 112,406 | 87,652 |
Inventories | -57,677 | -69,918 |
Other current assets | -25,901 | 6,060 |
Accounts payable | -155,788 | -3,297 |
Net regulatory assets and liabilities | 162,134 | 100,648 |
Other current liabilities | 14,683 | 129,984 |
Pension and other employee benefit obligations | -111,463 | -159,592 |
Change in other noncurrent assets | 44,009 | 26,537 |
Change in other noncurrent liabilities | -33,220 | 10,032 |
Net cash provided by operating activities | 2,004,341 | 2,002,908 |
Investing activities | ' | ' |
Utility capital/construction expenditures | -2,301,339 | -2,454,198 |
Proceeds from insurance recoveries | 6,000 | 90,000 |
Allowance for equity funds used during construction | 68,852 | 63,147 |
Purchases of investments in external decommissioning fund | -499,493 | -1,177,398 |
Proceeds from the sale of investments in external decommissioning fund | 494,554 | 1,172,597 |
Investment in WYCO Development LLC | -2,220 | -3,418 |
Other, net | -1,110 | -1,524 |
Net cash used in investing activities | -2,234,756 | -2,310,794 |
Financing activities | ' | ' |
Repayments of short-term borrowings, net | -62,000 | -300,000 |
Proceeds from issuance of long-term debt | 837,794 | 1,434,989 |
Repayments of long-term debt, including reacquisition premiums | -275,708 | -654,864 |
Proceeds from issuance of common stock | 178,639 | 229,420 |
Dividends paid | -417,586 | -382,148 |
Net cash provided by financing activities | 261,139 | 327,397 |
Net change in cash and cash equivalents | 30,724 | 19,511 |
Cash and cash equivalents at beginning of period | 107,144 | 82,323 |
Cash and cash equivalents at end of period | 137,868 | 101,834 |
Supplemental disclosure of cash flow information: | ' | ' |
Cash paid for interest (net of amounts capitalized) | -407,186 | -411,130 |
Cash (paid) received for income taxes, net | -4,950 | 16,851 |
Supplemental disclosure of non-cash investing and financing transactions: | ' | ' |
Property, plant and equipment additions in accounts payable | 407,706 | 299,209 |
Issuance of common stock for reinvested dividends and 401(k) plans | $42,772 | $54,963 |
CONSOLIDATED_BALANCE_SHEETS_UN
CONSOLIDATED BALANCE SHEETS (UNAUDITED) (USD $) | Sep. 30, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Current assets | ' | ' |
Cash and cash equivalents | $137,868 | $107,144 |
Accounts receivable, net | 760,213 | 744,160 |
Accrued unbilled revenues | 574,824 | 687,230 |
Inventories | 634,262 | 576,538 |
Regulatory assets | 415,197 | 417,801 |
Derivative instruments | 120,654 | 91,707 |
Deferred income taxes | 283,047 | 341,202 |
Prepayments and other | 270,529 | 252,258 |
Total current assets | 3,196,594 | 3,218,040 |
Property, plant and equipment, net | 27,630,363 | 26,122,159 |
Other assets | ' | ' |
Nuclear decommissioning fund and other investments | 1,816,962 | 1,755,990 |
Regulatory assets | 2,488,580 | 2,509,218 |
Derivative instruments | 53,577 | 84,842 |
Other | 177,365 | 217,241 |
Total other assets | 4,536,484 | 4,567,291 |
Total assets | 35,363,441 | 33,907,490 |
Current liabilities | ' | ' |
Current portion of long-term debt | 257,506 | 280,763 |
Short-term debt | 697,000 | 759,000 |
Accounts payable | 1,061,385 | 1,261,238 |
Regulatory liabilities | 379,824 | 274,769 |
Taxes accrued | 371,959 | 378,766 |
Accrued interest | 132,084 | 159,372 |
Dividends payable | 151,623 | 139,432 |
Derivative instruments | 22,924 | 23,382 |
Other | 396,564 | 377,776 |
Total current liabilities | 3,470,869 | 3,654,498 |
Deferred credits and other liabilities | ' | ' |
Deferred income taxes | 5,750,946 | 5,331,046 |
Deferred investment tax credits | 74,910 | 79,239 |
Regulatory liabilities | 1,140,619 | 1,059,395 |
Asset retirement obligations | 1,922,022 | 1,815,390 |
Derivative instruments | 187,445 | 209,224 |
Customer advances | 262,734 | 275,555 |
Pension and employee benefit obligations | 653,599 | 769,222 |
Other | 243,917 | 237,217 |
Total deferred credits and other liabilities | 10,236,192 | 9,776,288 |
Commitments and contingencies | ' | ' |
Capitalization | ' | ' |
Long-term debt | 11,501,720 | 10,910,754 |
Common stock — 1,000,000,000 shares authorized of $2.50 par value; 505,424,067 and 497,971,508 shares outstanding at Sept. 30, 2014 and Dec. 31, 2013, respectively | 1,263,560 | 1,244,929 |
Additional paid in capital | 5,815,714 | 5,619,313 |
Retained earnings | 3,177,387 | 2,807,983 |
Accumulated other comprehensive loss | -102,001 | -106,275 |
Total common stockholders’ equity | 10,154,660 | 9,565,950 |
Total liabilities and equity | $35,363,441 | $33,907,490 |
CONSOLIDATED_BALANCE_SHEETS_UN1
CONSOLIDATED BALANCE SHEETS (UNAUDITED) (Parenthetical) (USD $) | Sep. 30, 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) | 505,424,067 | 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 | 798,179 | ' | ' | 798,179 | ' |
Other comprehensive gain | 2,673 | ' | ' | ' | 2,673 |
Dividends declared on common stock | -414,509 | ' | ' | -414,509 | ' |
Issuances of common stock | 252,916 | 24,165 | 228,751 | ' | ' |
Issuances of common stock (in shares) | ' | 9,666,000 | ' | ' | ' |
Share-based compensation | 33,950 | ' | 33,950 | ' | ' |
Ending balance at Sep. 30, 2013 | 9,547,286 | 1,244,064 | 5,615,716 | 2,797,486 | -109,980 |
Balance (in shares) at Sep. 30, 2013 | ' | 497,626,000 | ' | ' | ' |
Beginning balance at Jun. 30, 2013 | 9,300,245 | 1,243,239 | 5,595,906 | 2,572,935 | -111,835 |
Balance (in shares) at Jun. 30, 2013 | ' | 497,296,000 | ' | ' | ' |
Increase (Decrease) in Stockholders' Equity | ' | ' | ' | ' | ' |
Net income | 364,752 | ' | ' | 364,752 | ' |
Other comprehensive gain | 1,855 | ' | ' | ' | 1,855 |
Dividends declared on common stock | -140,201 | ' | ' | -140,201 | ' |
Issuances of common stock | 9,791 | 825 | 8,966 | ' | ' |
Issuances of common stock (in shares) | ' | 330,000 | ' | ' | ' |
Share-based compensation | 10,844 | ' | 10,844 | ' | ' |
Ending balance at Sep. 30, 2013 | 9,547,286 | 1,244,064 | 5,615,716 | 2,797,486 | -109,980 |
Balance (in shares) at Sep. 30, 2013 | ' | 497,626,000 | ' | ' | ' |
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 | 824,967 | ' | ' | 824,967 | ' |
Other comprehensive gain | 4,274 | ' | ' | ' | 4,274 |
Dividends declared on common stock | -455,563 | ' | ' | -455,563 | ' |
Issuances of common stock | 194,591 | 18,631 | 175,960 | ' | ' |
Issuances of common stock (in shares) | ' | 7,452,000 | ' | ' | ' |
Share-based compensation | 20,441 | ' | 20,441 | ' | ' |
Ending balance at Sep. 30, 2014 | 10,154,660 | 1,263,560 | 5,815,714 | 3,177,387 | -102,001 |
Balance (in shares) at Sep. 30, 2014 | 505,424,067 | 505,424,000 | ' | ' | ' |
Beginning balance at Jun. 30, 2014 | 9,920,772 | 1,262,764 | 5,799,968 | 2,961,406 | -103,366 |
Balance (in shares) at Jun. 30, 2014 | ' | 505,106,000 | ' | ' | ' |
Increase (Decrease) in Stockholders' Equity | ' | ' | ' | ' | ' |
Net income | 368,582 | ' | ' | 368,582 | ' |
Other comprehensive gain | 1,365 | ' | ' | ' | 1,365 |
Dividends declared on common stock | -152,601 | ' | ' | -152,601 | ' |
Issuances of common stock | 9,931 | 796 | 9,135 | ' | ' |
Issuances of common stock (in shares) | ' | 318,000 | ' | ' | ' |
Share-based compensation | 6,611 | ' | 6,611 | ' | ' |
Ending balance at Sep. 30, 2014 | $10,154,660 | $1,263,560 | $5,815,714 | $3,177,387 | ($102,001) |
Balance (in shares) at Sep. 30, 2014 | 505,424,067 | 505,424,000 | ' | ' | ' |
Managements_Opinion
Management's Opinion | 9 Months Ended |
Sep. 30, 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 Sept. 30, 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 and nine months ended Sept. 30, 2014 and 2013; and its cash flows for the nine months ended Sept. 30, 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 Sept. 30, 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 | 9 Months Ended |
Sep. 30, 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 | 9 Months Ended |
Sep. 30, 2014 | |
New Accounting Pronouncements and Changes in Accounting Principles [Abstract] | ' |
Accounting Pronouncements | ' |
Accounting Pronouncements | |
Recently Issued | |
Revenue Recognition — In May 2014, the Financial Accounting Standards Board issued Revenue from Contracts with Customers, Topic 606 (Accounting Standards Update (ASU) No. 2014-09), which provides a framework for the recognition of revenue, with the objective that recognized revenues properly reflect amounts an entity is entitled to receive in exchange for goods and services. This guidance, which includes additional disclosure requirements regarding revenue, cash flows and obligations related to contracts with customers, will be effective for interim and annual reporting periods beginning after Dec. 15, 2016. Xcel Energy is currently evaluating the impact of adopting ASU 2014-09 on its consolidated financial statements. |
Selected_Balance_Sheet_Data
Selected Balance Sheet Data | 9 Months Ended | ||||||||
Sep. 30, 2014 | |||||||||
Balance Sheet Related Disclosures [Abstract] | ' | ||||||||
Selected Balance Sheet Data | ' | ||||||||
Selected Balance Sheet Data | |||||||||
(Thousands of Dollars) | Sept. 30, 2014 | Dec. 31, 2013 | |||||||
Accounts receivable, net | |||||||||
Accounts receivable | $ | 814,967 | $ | 797,267 | |||||
Less allowance for bad debts | (54,754 | ) | (53,107 | ) | |||||
$ | 760,213 | $ | 744,160 | ||||||
(Thousands of Dollars) | Sept. 30, 2014 | Dec. 31, 2013 | |||||||
Inventories | |||||||||
Materials and supplies | $ | 240,384 | $ | 225,308 | |||||
Fuel | 193,951 | 189,485 | |||||||
Natural gas | 199,927 | 161,745 | |||||||
$ | 634,262 | $ | 576,538 | ||||||
(Thousands of Dollars) | Sept. 30, 2014 | Dec. 31, 2013 | |||||||
Property, plant and equipment, net | |||||||||
Electric plant | $ | 32,122,904 | $ | 30,341,310 | |||||
Natural gas plant | 4,294,667 | 4,086,651 | |||||||
Common and other property | 1,483,063 | 1,485,547 | |||||||
Plant to be retired (a) | 77,922 | 101,279 | |||||||
Construction work in progress | 2,364,851 | 2,371,566 | |||||||
Total property, plant and equipment | 40,343,407 | 38,386,353 | |||||||
Less accumulated depreciation | (13,028,218 | ) | (12,608,305 | ) | |||||
Nuclear fuel | 2,250,140 | 2,186,799 | |||||||
Less accumulated amortization | (1,934,966 | ) | (1,842,688 | ) | |||||
$ | 27,630,363 | $ | 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 | 9 Months Ended | ||||||||
Sep. 30, 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 Sept. 30, 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 Sept. 30, 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 | 2010 | ||||||||
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 Sept. 30, 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) | Sept. 30, 2014 | Dec. 31, 2013 | |||||||
Unrecognized tax benefit — Permanent tax positions | $ | 7.5 | $ | 12.9 | |||||
Unrecognized tax benefit — Temporary tax positions | 32.9 | 28.3 | |||||||
Total unrecognized tax benefit | $ | 40.4 | $ | 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) | Sept. 30, 2014 | Dec. 31, 2013 | |||||||
NOL and tax credit carryforwards | $ | (28.1 | ) | $ | (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 Sept. 30, 2014 and Dec. 31, 2013 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of Sept. 30, 2014 or Dec. 31, 2013. |
Rate_Matters
Rate Matters | 9 Months Ended | ||||||||||||
Sep. 30, 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 initially reflected a requested 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 requested 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 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 (PI) EPU project. | |||||||||||||
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. | |||||||||||||
In August 2014, the evidentiary hearing was completed. As a result of discussions between NSP-Minnesota and intervening parties, the outstanding issues were further narrowed and the following were agreed upon: | |||||||||||||
• | NSP-Minnesota and the Minnesota Department of Commerce (DOC) have agreed to true-up the sales forecast to 12 months of actual weather normalized sales for 2014. | ||||||||||||
• | NSP-Minnesota and the DOC agreed to a property tax adjustment of $9 million, based on an assumed 2014 property tax forecast of $141 million. The parties also agreed to a limited true-up mechanism in which NSP-Minnesota would recover actual 2014 property taxes up to $145 million. | ||||||||||||
• | NSP-Minnesota agreed with the Minnesota Chamber of Commerce recommendation regarding deferral of the 2014 Monticello EPU depreciation expense and amortization of the depreciation over the remaining life of the plant. | ||||||||||||
NSP-Minnesota revised its requested rate increase to $142.2 million for 2014 and to $106.0 million for 2015, for a total combined increase of $248.2 million. | |||||||||||||
The following table summarizes the DOC’s and NSP-Minnesota’s recommendations and includes the estimated impact of certain agreed-upon true-up adjustments: | |||||||||||||
2014 Rate Request (Millions of Dollars) | DOC | NSP-Minnesota | |||||||||||
NSP-Minnesota’s filed rate request | $ | 192.7 | $ | 192.7 | |||||||||
Sales forecast | (43.2 | ) | (15.8 | ) | |||||||||
ROE | (36.2 | ) | — | ||||||||||
Monticello EPU cost recovery | (33.9 | ) | — | ||||||||||
Monticello EPU depreciation deferral | — | (12.2 | ) | ||||||||||
Property taxes | (9.0 | ) | (9.0 | ) | |||||||||
PI EPU | (5.1 | ) | (5.1 | ) | |||||||||
Health care, pension and other benefits | (11.4 | ) | (1.9 | ) | |||||||||
Other, net | (8.0 | ) | (6.5 | ) | |||||||||
Total recommendation 2014 — unadjusted | $ | 45.9 | $ | 142.2 | |||||||||
Estimated true-up adjustments: | |||||||||||||
Sales forecast | $ | 18.3 | $ | (9.1 | ) | ||||||||
Property taxes | 3.9 | 3.9 | |||||||||||
Total recommendation 2014 — adjusted | $ | 68.1 | $ | 137 | |||||||||
2015 Rate Request (Millions of Dollars) | DOC | NSP-Minnesota | |||||||||||
NSP-Minnesota’s filed rate request | $ | 98.5 | $ | 98.5 | |||||||||
Monticello EPU cost recovery | 29.1 | — | |||||||||||
Monticello EPU cost disallowance (a) | (10.2 | ) | — | ||||||||||
Excess depreciation reserve adjustment (b) | (22.7 | ) | — | ||||||||||
Depreciation | (17.5 | ) | — | ||||||||||
Monticello EPU depreciation deferral | — | 1.6 | |||||||||||
Monticello EPU step increase | — | 10.1 | |||||||||||
Property taxes | (3.3 | ) | (3.3 | ) | |||||||||
Production tax credits to be included in base rates | (11.1 | ) | (11.1 | ) | |||||||||
DOE settlement proceeds | 10.1 | 10.1 | |||||||||||
Emission chemicals | (1.6 | ) | (1.6 | ) | |||||||||
Other, net | (4.8 | ) | 1.7 | ||||||||||
Total recommendation 2015 step increase | $ | 66.5 | $ | 106 | |||||||||
Unadjusted cumulative total for 2014 and 2015 step increase | $ | 112.4 | $ | 248.2 | |||||||||
Estimated adjusted cumulative total for 2014 and 2015 step increase | $ | 134.6 | $ | 243 | |||||||||
(a) | In July 2014, the DOC recommended a disallowance of recovery of approximately $71.5 million of project costs on a Minnesota jurisdictional basis. This equates to a total NSP System disallowance of approximately $94 million. This would reduce NSP-Minnesota’s revenue requirement by approximately $10.2 million in 2015. | ||||||||||||
(b) | Adjustment is due to timing differences and/or methodology of accelerating amortization of the excess depreciation reserve over three years. | ||||||||||||
NSP-Minnesota’s revised rate request, moderation plan, interim rate adjustments and impacts on expenses are detailed below: | |||||||||||||
(Millions of Dollars) | 2014 | Percentage | 2015 | Percentage | |||||||||
Increase | Increase | ||||||||||||
Rebuttal pre-moderation deficiency | $ | 250.6 | $ | 67.8 | |||||||||
Evidentiary hearing adjustments | (27.3 | ) | 11 | ||||||||||
Revised pre-moderation deficiency | 223.3 | 78.8 | |||||||||||
Moderation plan: | |||||||||||||
Excess depreciation reserve | (81.1 | ) | 52.9 | ||||||||||
DOE settlement proceeds | — | (25.7 | ) | ||||||||||
Revised rate request | 142.2 | 5.10% | 106 | 3.80% | |||||||||
Interim rate adjustments | (65.3 | ) | 65.3 | ||||||||||
PI EPU | 4.8 | (4.8 | ) | ||||||||||
Revenue impact (a) | 81.7 | 166.5 | |||||||||||
Excess depreciation reserve | 81.1 | (45.7 | ) | ||||||||||
Sales forecast (b) | (9.1 | ) | — | ||||||||||
DOE settlement proceeds | — | 25.7 | |||||||||||
Estimated impact of request on operating income | $ | 153.7 | $ | 146.5 | |||||||||
(a) | NSP-Minnesota’s total revenue for 2014 is capped at the interim rate level of $127 million and pre-tax operating income is capped at $208 million. This table demonstrates the impact of reducing NSP-Minnesota’s rebuttal request. | ||||||||||||
(b) | NSP-Minnesota and the DOC have agreed to a sales true-up based on weather normalized sales for 2014, using standard weather coefficients. NSP-Minnesota periodically adjusts the coefficients in periods of extreme weather conditions to enhance weather impact estimates. As a result of the difference in the two methodologies, currently, approximately $9.1 million of revenue that NSP-Minnesota attributed to weather would be considered normal sales growth using the standard weather coefficients. The refund for the full year could vary from the estimate as of Sept. 30, 2014, depending on weather conditions. | ||||||||||||
NSP-Minnesota recorded a current regulatory liability representing the current best estimate of a refund obligation associated with interim rates as of Sept. 30, 2014. | |||||||||||||
The next step in the procedural schedule is expected to be the Administrative Law Judge (ALJ) Report on Dec. 26, 2014. The MPUC is expected to deliberate on March 26, 2015. A final MPUC order is anticipated in the second quarter of 2015. | |||||||||||||
NSP-Minnesota – Nuclear Project Prudence Investigation — In 2013, NSP-Minnesota completed the Monticello LCM/EPU project. The multi-year project extended the life of the facility and increased the capacity from 600 to 671 megawatts (MW). Monticello LCM/EPU project expenditures were approximately $665 million. Total capitalized costs were approximately $748 million, which includes allowance for funds used during construction (AFUDC). Project expenditures were initially estimated in 2008 at approximately $320 million, excluding AFUDC. | |||||||||||||
In 2013, the MPUC initiated an investigation to determine whether the final costs for the Monticello LCM/EPU project were prudent. | |||||||||||||
NSP-Minnesota filed a report to 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. | |||||||||||||
The cost deviation is in line with similar nuclear upgrade projects undertaken by other utilities. In addition, 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. As part of the review process, in October 2014 NSP-Minnesota received approval for ascension to higher EPU levels which is expected to recommence during the fourth quarter. | |||||||||||||
In July 2014, the DOC filed testimony and recommended a disallowance of recovery of approximately $71.5 million of project costs on a Minnesota jurisdictional basis. This equates to a total NSP System disallowance of approximately $94 million. | |||||||||||||
The DOC’s recommendation indicated that although the combined LCM/EPU project is cost effective, NSP-Minnesota should have done a better job of estimating initial project costs of the investments required to achieve 71 MW of additional capacity (i.e., EPU costs) as opposed to investments required to extend the life of the plant. They asserted that approximately 85 percent of the total $665 million in costs were associated with project components required solely to achieve the EPU. | |||||||||||||
In August 2014, the Office of Attorney General (OAG) filed rebuttal testimony and recommended a disallowance of recovery of $321 million for the entire NSP System (based on a total capitalized cost of $748 million), and no return on $107 million. The recommended disallowance is primarily based on criticism of NSP-Minnesota’s management of the project. | |||||||||||||
NSP-Minnesota believes the costs of the project were prudent and its decisions and actions do not warrant a disallowance. NSP-Minnesota’s testimony is summarized as follows: | |||||||||||||
• | The plant is cost-effective for customers; | ||||||||||||
• | The project benefits include providing carbon-free generation through a life extension and uprate of the plant for an installed capacity of about $1,000 per kilowatt; | ||||||||||||
• | The DOC was incorrect in its analysis that 85 percent of the expenditures were associated with the uprate; and | ||||||||||||
• | NSP-Minnesota made prudent decisions based on the information available at the time the decisions were made. | ||||||||||||
The next steps in the procedural schedule are expected to be as follows: | |||||||||||||
• | Initial Briefs — Oct. 31, 2014; | ||||||||||||
• | Reply Briefs — Nov. 21, 2014; | ||||||||||||
• | ALJ Report — Dec. 31, 2014; and | ||||||||||||
• | MPUC Deliberation — March 6, 2015. | ||||||||||||
A final MPUC order is anticipated in the second quarter of 2015. The MPUC decision for the Monticello prudence review is expected to be reflected in the final results of NSP-Minnesota’s pending Minnesota 2014 Multi-Year electric rate case. | |||||||||||||
Electric, Purchased Gas and Resource Adjustment Clauses | |||||||||||||
NSP-Minnesota – Gas Utility Infrastructure Cost (GUIC) Rider — In August 2014, NSP-Minnesota filed a GUIC rider with the MPUC for approval to recover the cost of natural gas infrastructure investments in Minnesota to improve safety and reliability. Costs include funding for pipeline assessment and system upgrades in 2015 and beyond, as well as deferred costs from NSP-Minnesota’s existing sewer separation and pipeline integrity management programs. Sewer separation costs stem from the inspection of sewer lines and the redirection of gas pipes in the event their paths are in conflict. NSP-Minnesota is requesting recovery of approximately $14.9 million from Minnesota gas utility customers beginning Jan. 1, 2015, including $4.8 million of deferred sewer separation and integrity management costs which is the 2015 portion of a five year amortization. In October 2014, the DOC recommended approval of NSP-Minnesota’s request for recovery of the GUIC rider, using the capital structure and cost of capital proposed in the current electric case and a five year amortization period for the deferred costs. An MPUC decision is anticipated by the end of 2014. | |||||||||||||
Pending Regulatory Proceedings — South Dakota Public Utilities Commission (SDPUC) | |||||||||||||
NSP-Minnesota – South Dakota 2015 Electric Rate Case — In June 2014, NSP-Minnesota filed a request with the SDPUC to increase South Dakota electric rates by $15.6 million annually, or 8.0 percent, effective Jan. 1, 2015. The request is based on a 2013 historic test year (HTY) adjusted for certain known and measurable changes for 2014 and 2015, a requested ROE of 10.25 percent, an average rate base of $433.2 million and an equity ratio of 53.86 percent. This request reflects NSP-Minnesota’s proposal to move recovery of approximately $9.0 million for certain Transmission Cost Recovery (TCR) rider and Infrastructure rider projects to base rates. | |||||||||||||
The major components of the request are as follows: | |||||||||||||
(Millions of Dollars) | Request | ||||||||||||
Nuclear investments and operating costs | $ | 13.4 | |||||||||||
Other production, transmission and distribution | 5 | ||||||||||||
Technology improvements | 2.1 | ||||||||||||
Pension and operating and maintenance (O&M) expenses | 1.6 | ||||||||||||
Wind generation facilities | 1.4 | ||||||||||||
Capital structure | 1.1 | ||||||||||||
Incremental increase to base rates | $ | 24.6 | |||||||||||
Infrastructure rider to be included in base rates | $ | (8.4 | ) | ||||||||||
TCR rider to be included in base rates | (0.6 | ) | |||||||||||
Net request | $ | 15.6 | |||||||||||
At this time, the case is in the discovery phase and further procedure scheduling may be established during the fourth quarter of 2014. In November 2014, NSP-Minnesota plans to file a request with the SDPUC for interim rates, effective Jan. 1, 2015. Final rates are anticipated to be effective in the first quarter of 2015. | |||||||||||||
NSP-Wisconsin | |||||||||||||
Pending Regulatory Proceedings — Public Service Commission of Wisconsin (PSCW) | |||||||||||||
NSP-Wisconsin – Wisconsin 2015 Electric Rate Case — In May 2014, NSP-Wisconsin filed a request with the PSCW to increase electric rates by $20.6 million, or 3.2 percent, effective Jan. 1, 2015. The request is for the limited purpose of updating 2015 electric rates to reflect anticipated increases in the production and transmission fixed charges and the fuel and purchased power components of the interchange agreement with NSP-Minnesota. No changes are being requested to the capital structure or the 10.2 percent ROE authorized by the PSCW in the 2014 rate case. As part of an agreement with stakeholders to limit the size and scope of the case, NSP-Wisconsin also agreed to an earnings cap for 2015 only, in which 100 percent of the earnings above the authorized ROE would be refunded to customers. | |||||||||||||
In October 2014, the PSCW Staff filed their direct testimony and recommended an electric rate increase of $16.1 million, or 2.5 percent. The majority of the PSCW Staff’s adjustments are related to the fuel cost forecast, and are primarily the result of more recent data than was available at the time the initial filing was prepared last spring. | |||||||||||||
In October 2014, NSP-Wisconsin, the PSCW Staff and other parties reached an agreement that resolved all contested issues in the case and accepted the PSCW staff recommendation to increase NSP-Wisconsin’s electric rates by approximately $16.1 million, effective January 2015. | |||||||||||||
The major cost components of the requested increase and the PSCW Staff recommendation are summarized below: | |||||||||||||
(Millions of Dollars) | NSP-Wisconsin | PSCW Staff Recommendation | |||||||||||
Request | |||||||||||||
Production and transmission fixed charges | $ | 28.1 | $ | 26.4 | |||||||||
Fuel and purchased power | 13.9 | 11.1 | |||||||||||
Sub-Total | $ | 42 | $ | 37.5 | |||||||||
NSP-Minnesota transmission depreciation reserve | $ | (16.2 | ) | $ | (16.2 | ) | |||||||
Monticello EPU deferral | (5.2 | ) | (5.2 | ) | |||||||||
Total | $ | 20.6 | $ | 16.1 | |||||||||
A final PSCW decision is anticipated by the end of 2014. | |||||||||||||
Pending Regulatory Proceedings — Federal Energy Regulatory Commission (FERC) | |||||||||||||
Midcontinent Independent System Operator, Inc. (MISO) ROE Complaint — In November 2013, a group of customers filed a complaint at the FERC against MISO transmission owners, including NSP-Minnesota and NSP-Wisconsin. The complaint argues for a reduction in the ROE applicable to transmission formula rates in the MISO region from 12.38 percent to 9.15 percent, a prohibition on capital structures in excess of 50 percent equity, and the removal of ROE adders (including those for regional transmission organization (RTO) membership and being an independent transmission company), effective Nov. 12, 2013. | |||||||||||||
In January 2014, Xcel Energy filed an answer to the complaint asserting that the 9.15 percent ROE would be unreasonable and that the complainants failed to demonstrate the NSP System equity capital structure was unreasonable. The MISO transmission owners separately answered the complaint, arguing the complaint should be dismissed. | |||||||||||||
In June 2014, the FERC issued an order in a different ROE proceeding adopting a new ROE methodology for electric utilities. The new ROE methodology requires electric utilities to use a two-step discounted cash flow analysis to estimate cost of equity that incorporates both short-term and long-term growth projections. | |||||||||||||
In October 2014, the FERC upheld the determination of the long term growth rate to be used together with a short term growth rate in its new ROE methodology. The FERC separately set the ROE complaint against the MISO transmission owners for settlement judge and hearing procedures, which are expected to begin later this year. The FERC directed parties to apply this methodology, but denied the complaints related to equity capital structures and ROE adders. The FERC established a Nov. 12, 2013 refund effective date. NSP-Minnesota recorded a current regulatory liability representing the current best estimate of a refund obligation associated with the new ROE as of Sept. 30, 2014. The new FERC ROE methodology is estimated to reduce transmission revenue, net of expense, between $5 million and $7 million annually for NSP-Minnesota and NSP-Wisconsin. | |||||||||||||
PSCo | |||||||||||||
Pending and Recently Concluded Regulatory Proceedings — CPUC | |||||||||||||
PSCo – Colorado 2014 Electric Rate Case — In 2014, PSCo filed an electric rate case with the CPUC requesting an increase in annual revenue of approximately $136.0 million, or 4.83 percent. The requested 2015 rate increase reflects approximately $100.9 million for recovery of costs associated with the CACJA project. The case also requests the initiation of a CACJA rider for 2016 and 2017, which is anticipated to increase revenue recovery by approximately $34.2 million in 2016 and then decline to approximately $29.9 million in 2017. PSCo’s objective is to establish a multi-year regulatory plan that provides certainty for PSCo and its customers. | |||||||||||||
The rate filing is based on a 2015 test year, a requested ROE of 10.35 percent, an electric rate base of $6.39 billion and an equity ratio of 56 percent. As part of the filing, PSCo will transfer approximately $19.9 million from the transmission rider to base rates, which will not impact customer bills. The CACJA rider is projected to recover incremental investment and expenses, based on a comprehensive plan to retire certain coal plants, add pollution control equipment to other existing coal units and add natural gas generation. The CACJA project investment is expected to be completed by 2017. | |||||||||||||
The next steps in the procedural schedule are expected to be as follows: | |||||||||||||
• | Answer Testimony — Nov. 7, 2014; | ||||||||||||
• | Rebuttal Testimony — Dec. 17, 2014; | ||||||||||||
• | Evidentiary Hearing — Jan. 26 - Feb. 4, 2015; | ||||||||||||
• | Interim rates are scheduled to be effective on Feb. 13, 2015, subject to refund; and | ||||||||||||
• | A decision as well as implementation of final rates are anticipated in the second quarter of 2015. | ||||||||||||
PSCo – Manufacturer’s Sales Tax Refund — PSCo defers 2012-2014 annual property taxes in excess of $76.7 million as part of its multi-year rate plan with the CPUC. To the extent that PSCo was successful in the manufacturer’s sales tax refund lawsuit against the Colorado Department of Revenue, PSCo was to credit such refunds first against certain legal fees, and then against the unamortized deferred property tax balance at the end of 2014. | |||||||||||||
On June 30, 2014, the Colorado Supreme Court ruled against PSCo’s claim that it was due refunds for the payment of sales taxes on purchases of certain equipment from December 1998 to December 2001. As a result of the adverse ruling, PSCo is required to reduce its 2014 property tax deferral by $10 million, as this amount will not be recovered in electric rates. This impact is reflected in PSCo’s pending electric rate case before the CPUC. | |||||||||||||
PSCo – Annual Electric Earnings Test — As part of an annual earnings test, PSCo must share with customers a portion of any annual earnings that exceed PSCo’s authorized ROE threshold of 10 percent for 2012-2014. In April 2014, PSCo filed its 2013 earnings test with the CPUC proposing a refund obligation of $45.7 million to electric customers to be returned between August 2014 and July 2015. This tariff was approved by the CPUC in July 2014 and became effective Aug. 1, 2014. As of Sept. 30, 2014, PSCo has also recognized management’s best estimate of an accrual for the 2014 earnings test of $52.4 million. | |||||||||||||
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 Sept. 30, 2014. For the three months ended Sept. 30, 2013, PSCo credited the RESA regulatory asset balance $6.1 million. The cumulative credit to the RESA regulatory asset balance was $104.7 million and $104.5 million at Sept. 30, 2014 and Dec. 31, 2013, respectively. The credits include the customers’ share of REC trading margins and the unspent share of carbon offset funds. | |||||||||||||
In May 2014, PSCo filed with the CPUC to continue this sharing mechanism for 2015 and beyond, but remove the step increase in the sharing allocation of hybrid REC trades on margins in excess of $20 million. In July 2014, the CPUC sent the proceeding to an ALJ. On Sept. 5, 2014, PSCo, the CPUC Staff, and intervenors filed a settlement agreement to extend the current sharing mechanism without modification through 2017. On Sept. 18, 2014 the ALJ issued a final decision approving the settlement agreement. | |||||||||||||
Recently Concluded Regulatory Proceedings — FERC | |||||||||||||
PSCo Transmission Formula Rate Cases — In April 2012, PSCo filed with the FERC to revise the wholesale transmission formula rates from an 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 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. In October 2012, the FERC consolidated this complaint with the April 2012 formula rate change filing. | |||||||||||||
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 does not materially increase 2014 transmission revenues. | |||||||||||||
In June 2014, PSCo and its transmission customers reached a settlement in principle to resolve the ROE issue in the transmission rate filing and complaint. The settlement was filed in September 2014, and in October 2014, the FERC ALJ granted PSCo a motion to place interim rates into effect using the settlement ROE beginning Oct. 1, 2014. The FERC approved the settlement in October 2014, providing a 9.72 percent ROE effective retroactive to July 1, 2012 for the PSCo transmission formula rate. PSCo recorded a current liability for the refund obligation based on the settlement terms as of Sept. 30, 2014. | |||||||||||||
PSCo – Production Formula Rate ROE Complaint — In August 2013, PSCo’s wholesale production customers filed a complaint with the FERC, and requested it reduce the stated ROEs ranging from 10.1 percent through 10.4 percent to 9.04 percent in the PSCo production sales formula rates effective Sept. 1, 2013. In June 2014, PSCo and its wholesale customers reached a settlement in principle to resolve the complaint along with the pending transmission formula rate ROE matters. The settlement was filed in September 2014, and in October 2014, the FERC ALJ granted PSCo a motion to place interim rates into effect using the settlement ROE beginning Oct. 1, 2014. The FERC approved the settlement in October 2014, providing a 9.72 percent ROE effective for the PSCo production formula rate. PSCo recorded a current liability for the refund obligation based on the settlement terms as Sept. 30, 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. In April 2014, SPS revised its request to a net increase of $48.1 million. | |||||||||||||
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 September 2014, SPS, PUCT staff, and intervenors filed a non-unanimous settlement agreement, subject to PUCT approval, which would increase SPS’ rates by $37 million, or 3.5 percent, retroactive to June 1, 2014. Starting Oct. 1, 2014, SPS began collecting the rate increase through interim rates subject to refund. SPS expects to recover the rate increase for the months of June through September through a separate surcharge to be implemented by the first quarter of 2015. Based on the anticipated outcome of the rate case, SPS recognized approximately $13.3 million of revenue in the third quarter of 2014 for the surcharge. | |||||||||||||
The settlement includes an ROE of 9.7 percent solely for the purpose of calculating the AFUDC and determining baselines in future filings for the TCRF. In October 2014, the ALJs approved the stipulation and recommended that SPS file to implement the surcharge following the PUCT's final order. The PUCT is expected to rule on the settlement in 2014. | |||||||||||||
Although the parties to the settlement agreement have not prepared a calculation of the $37 million increase and do not agree about which specific costs are included, or not, in the agreed settlement revenue requirement, SPS’ reconciliation of its original request to the settlement increase is as follows: | |||||||||||||
(Millions of Dollars) | Settlement Agreement | ||||||||||||
Base rate increase request, January 2014 | $ | 81.5 | |||||||||||
Revisions for updated information | (4.6 | ) | |||||||||||
Revised request, April 2014 | 76.9 | ||||||||||||
Remove proposed increase in depreciation | (16.0 | ) | |||||||||||
Remove adjustment allocators for certain wholesale load reduction | (12.0 | ) | |||||||||||
Revised amortizations (rate case expenses, pension and other post-employment benefits expense and gain on sale to Lubbock) | (9.0 | ) | |||||||||||
Non-specified settlement adjustments | (2.9 | ) | |||||||||||
Settlement base rate increase | $ | 37 | |||||||||||
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 was $13 million. The PUCT issued an order allowing the TCRF to go into effect on an interim basis effective Jan. 1, 2014. In May 2014, the ALJ terminated the interim TCRF due to a settlement in principle being reached with intervenors and the PUCT staff in the pending Texas electric rate case. In July 2014, the PUCT approved the settlement agreement between the parties allowing SPS to recover $4 million annually through the TCRF. In September 2014, SPS filed a proposal with the PUCT to refund approximately $3.7 million during November 2014 for interim rates collected in excess of the final rates approved. PUCT approval of the refund is pending. As of Sept. 30, 2014, SPS had recorded an accrual for the proposed refund. | |||||||||||||
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 forecast test year, 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. The request reflected 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 reflects a base rate increase of $12.7 million and rider recovery of $18.1 million for renewable energy costs, both based on an ROE of 9.96 percent and an equity ratio of 53.89 percent. Final rates were effective April 5, 2014. In April 2014, the New Mexico Attorney General (NMAG) filed a request for rehearing. The rehearing request was denied by the NMPRC. In June 2014, the NMAG filed an appeal of the NMPRC’s denial to the New Mexico Supreme Court. A decision is expected by the second quarter of 2016. | |||||||||||||
Pending Regulatory Proceedings — FERC | |||||||||||||
SPS – Wholesale Rate Complaints — In April 2012, Golden Spread Electric Cooperative, Inc. (Golden Spread), a wholesale cooperative customer, filed a rate complaint alleging that the base ROE included in the SPS production formula rate of 10.25 percent, and the SPS transmission base formula rate ROE of 10.77 percent, are unjust and unreasonable. In July 2013, Golden Spread filed a second complaint, again asking that the base ROE in the SPS production and transmission formula rates be reduced to 9.15 and 9.65 percent, respectively. | |||||||||||||
In addition to the FERC order issued for the MISO ROE complaint previously mentioned, the FERC issued orders in June 2014 consolidating the Golden Spread ROE complaints and setting them for settlement judge procedures and hearings and indicated the parties should apply the new ROE methodology to the proceedings. The FERC established effective dates for the refunds as April 20, 2012 and July 19, 2013. The complaints remain in settlement judge proceedings. | |||||||||||||
Golden Spread, along with certain New Mexico cooperatives and the West Texas Municipal Power Agency, filed a third rate complaint on Oct. 20, 2014, requesting that the base ROE in the SPS production and transmission formula rates be reduced to 8.61 percent and 9.11 percent, respectively. The complainants requested a refund effective date of Oct. 20, 2014, and that the new complaint be consolidated with the two prior complaints. FERC action is pending. | |||||||||||||
SPS – 2004 FERC Complaint Case Orders — In August 2013, the FERC issued an order on rehearing related to a 2004 complaint case brought by Golden Spread and Public Service Company of New Mexico (PNM) and an Order on Initial Decision in a subsequent 2006 production rate case filed by SPS. | |||||||||||||
The original complaint included two key components: 1) PNM’s claim regarding inappropriate allocation of fuel costs and 2) a base rate complaint, including the appropriate demand-related cost allocator. The FERC previously determined that the allocation of fuel costs and the demand-related cost allocator utilized by SPS was appropriate. | |||||||||||||
In the August 2013 Orders, the FERC clarified its previous ruling on the allocation of fuel costs and reaffirmed that the refunds in question should only apply to firm requirements customers and not PNM’s contractual load. The FERC also reversed its prior demand-related cost allocator decision. The FERC stated that it had erred in its initial analysis and concluded that the SPS system was a 3 coincident peak (CP) rather than a 12CP system. | |||||||||||||
In September 2013, SPS filed a request for rehearing of the FERC ruling on the CP allocation and refund decisions. SPS asserted that the FERC applied an improper burden of proof and that precedent did not support retroactive refunds. PNM also requested rehearing of the FERC decision not to reverse its prior ruling. | |||||||||||||
In October 2013, the FERC issued orders further considering the requests for rehearing. These matters are currently pending the FERC’s action. If unsuccessful in its rehearing request, SPS will have the opportunity to file rate cases with the FERC and its retail jurisdictions seeking to change all customers to a 3CP allocation method. | |||||||||||||
As of Dec. 31, 2013, SPS had accrued $44.5 million related to the August 2013 Orders and an additional $4.0 million of principal and interest was accrued during the first nine months of 2014. Pending the timing and resolution of this matter, the annual impact to revenues through 2014 could be up to $6 million and decreasing to $4 million on June 1, 2015. |
Commitments_and_Contingencies
Commitments and Contingencies | 9 Months Ended | ||||||||
Sep. 30, 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 MW and 3,338 MW of capacity under long-term PPAs as of Sept. 30, 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 2033. | |||||||||
Guarantees and Indemnifications | |||||||||
Xcel Energy Inc. and its subsidiaries provide guarantees and bond indemnities under specified agreements or transactions. The guarantees and bond indemnities issued by Xcel Energy Inc. guarantee payment or performance by its subsidiaries. As a result, Xcel Energy Inc.’s exposure under the guarantees and bond indemnities is based upon the net liability of the relevant subsidiary under the specified agreements or transactions. Most of the guarantees and bond indemnities issued by Xcel Energy Inc. and its subsidiaries limit the exposure to a maximum amount stated in the guarantees and bond indemnities. As of Sept. 30, 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) | Sept. 30, 2014 | Dec. 31, 2013 | |||||||
Guarantees issued and outstanding | $ | 14.6 | $ | 19.4 | |||||
Current exposure under these guarantees | 0.2 | 0.3 | |||||||
Bonds with indemnity protection | 32.1 | 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 Sept. 30, 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 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. 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 commenced in May 2014. A preliminary design for the groundwater remedy was also submitted to the EPA in April 2014 and those activities are expected to commence in 2015. Based on these updated designs, the cost estimate for the cleanup of the Phase I Project Area is approximately $52 million, of which approximately $21 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. 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 for or perform the cleanup of the Sediments and what remedy will be implemented at the site to address the Sediments. It is NSP-Wisconsin’s view that 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. In November 2013, NSP-Wisconsin submitted a revised Wet Dredge pilot study work plan proposal to the EPA. In May 2014, NSP-Wisconsin entered into a final administrative order on consent for the Wet Dredge pilot study with the EPA. In September 2014, the EPA granted an extension of time to perform the pilot in 2015. | |||||||||
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 Sept. 30, 2014 and Dec. 31, 2013, NSP-Wisconsin had recorded a liability of $106.9 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 $25.4 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 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 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. | |||||||||
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) — Section 316(b) of 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. The EPA published the final 316(b) rule in August 2014. The rule prescribes technology for protecting fish that get stuck on plant intake screens (known as impingement) and describes a process for site-specific determinations by each state for sites that must protect the small aquatic organisms that pass through the intake screens into the plant cooling systems (known as entrainment). For Xcel Energy, these requirements will primarily impact plants within the NSP-Minnesota service territory. The timing of compliance with the requirements will vary from plant-to-plant since the new rule does not have a final compliance deadline. Xcel Energy estimates the likely cost for complying with impingement requirements is approximately $46 million with the majority needed for NSP-Minnesota. Xcel Energy believes at least four NSP-Minnesota plants could be required by state regulators to make improvements to reduce entrainment. The exact cost of the entrainment improvements is uncertain, but could be up to $180 million depending on the outcome of certain entrainment studies and cost-benefit analyses. Xcel Energy anticipates these costs will be fully recoverable in rates. | |||||||||
Federal CWA Waters of the United States Rule — In April 2014, the EPA and the U.S. Army Corps of Engineers issued a proposed rule that significantly expands the types of water bodies regulated under the CWA. If finalized as proposed, this rule could delay the siting of new pipelines, transmission lines and distribution lines, increase project costs and expand permitting and reporting requirements. The ultimate impact of the proposed rule will depend on the specific requirements of the final rule and cannot be determined at this time. A final rule is not anticipated before the first quarter of 2015. | |||||||||
Air | |||||||||
EPA Greenhouse Gas (GHG) Permitting — In 2011, new EPA permitting requirements became effective for GHG emissions of new and modified large stationary sources, which were applicable to the construction of new power plants or power plant modifications that increase emissions above a certain threshold. These rules were upheld by the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit), but in June 2014 the U.S. Supreme Court reversed the EPA’s GHG emission thresholds for this program. The Supreme Court decided the EPA could not adopt GHG thresholds that would require permitting for new and modified large stationary sources. However, the Supreme Court also decided if a new or modified stationary source becomes subject to the permitting requirements by exceeding emission thresholds for other pollutants, then GHG emissions may be evaluated as part of the permitting process. Xcel Energy is unable to determine the cost of compliance with these new EPA requirements as it is not clear whether these requirements will apply to future changes at Xcel Energy’s power plants. | |||||||||
GHG Emission Standard for Existing Sources — In June 2014, the EPA published its proposed rule on GHG emission standards for existing power plants. Comments are due to the EPA on Dec. 1, 2014 and a final rule is anticipated in June 2015. Following adoption of the final rule, states must develop implementation plans by June 2016, with the possibility of an extension to June 2017 (June 2018 if submitting a joint plan with other states). Among other things, the proposed rule would require that state plans include enforceable measures to ensure emissions from existing power plants in the state achieve the EPA’s state-specific interim (2020-2029) and final (2030 and thereafter) emission performance targets. The plan will likely require additional emission reductions in states in which Xcel Energy operates. It is not possible to evaluate the impact of existing source standards until the EPA promulgates a final rule and states have adopted their applicable state plans. | |||||||||
GHG New Source Performance Standard (NSPS) Proposal — In January 2014, the EPA re-proposed a GHG NSPS for newly constructed power plants which would set performance standards (maximum carbon dioxide emission rates) for coal- and natural gas-fired power plants. For coal power plants, the NSPS requires an emissions level equivalent to partial carbon capture and storage (CCS) technology; for gas-fired power plants, the NSPS reflects emissions levels from combined cycle technology with no CCS. The EPA continues to propose that the NSPS not apply to modified or reconstructed existing power plants. In addition, installation of control equipment on existing plants would not constitute a “modification” to those plants under the NSPS program. It is not possible to evaluate the impact of the re-proposed NSPS until its final requirements are known. | |||||||||
GHG NSPS for Modified and Reconstructed Power Plants — In June 2014, the EPA published a proposed NSPS that would apply to GHG emissions from power plants that are modified or reconstructed. A final rule is anticipated in June 2015. A modification is a change to an existing source that increases the maximum achievable hourly rate of emissions. A reconstruction involves the replacement of components at a unit to the extent that the capital cost of the new components exceeds 50 percent of the capital cost of an entirely new comparable unit. The proposed standards would not require installation of CCS technology. Instead, the proposed standard for coal-fired power plants would require a combination of best operating practices and equipment upgrades. The proposal for gas-fired power plants would require emissions standards based on efficient combined cycle technology. It is not possible to evaluate the impact of these proposed standards until the final requirements are known. In addition, it is not clear whether these requirements, once adopted, would apply to future changes at Xcel Energy’s power plants. | |||||||||
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 set more stringent requirements than the proposed Clean Air Transport Rule and requires plants in Texas to reduce their SO2 and annual NOx emissions. The rule also creates an emissions trading program. | |||||||||
In August 2012, the 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 Supreme 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. In June 2014, the EPA filed a motion with the D.C. Circuit asking it to lift the stay of the CSAPR. The EPA requested the CSAPR’s 2012 compliance obligations be imposed starting in January 2015. The D.C. Circuit granted the EPA’s motion in October 2014. In addition, the D.C. Circuit set a briefing schedule and plans to hear arguments on the remaining issues in the case in March 2015. | |||||||||
Multiple changes to the SPS system since 2011 will substantially reduce estimated costs of complying with the CSAPR. These include the addition of 700 MW of wind power, the construction of Jones Units 3 and 4 to meet reserve requirements and provide quick start capability, reduced wholesale load and new PPAs, installation of NOx combustion controls on Tolk Units 1 and 2 and completion of certain transmission projects. As a result, SPS estimates compliance with the CSAPR in 2015 will cost approximately $7 million. | |||||||||
NSP-Minnesota can operate within its CSAPR emission allowance allocations, particularly given the cessation of coal operations at Black Dog Units 3 and 4 in early 2015. NSP-Wisconsin can operate within its CSAPR emission allowance allocation for SO2 due to cessation of coal combustion at Bay Front Unit 5. NSP-Wisconsin anticipates compliance with the CSAPR for NOx in 2015 through operational changes or allowance purchases. CSAPR compliance in 2015 is not expected to have a material impact on the results of operations, financial position or cash flows. | |||||||||
The EPA will begin to administer the CSAPR in 2015, which will replace the CAIR. In 2014, 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 and in 2014 on Tolk Unit 2. These installations will reduce or eliminate SPS’ need to purchase NOx emission allowances. At Sept. 30, 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. SPS has sufficient SO2 allowances to comply with the CAIR through 2015. | |||||||||
Regional Haze Rules — The regional haze program is designed to address widespread, regionally homogeneous haze that results from emissions from a multitude of sources. In 2005, the EPA amended the best available retrofit technology (BART) requirements of its regional haze rules, which require the installation and operation of emission controls for industrial facilities emitting air pollutants that reduce visibility in 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 $360.5 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. In September 2014, the EPA filed a request with the Court to remand the case to the EPA for additional explanation of the EPA’s decision approving the BART determination for Comanche Units 1 and 2. On Oct. 6, 2014, the Court granted the EPA’s request and vacated the current briefing schedule. The EPA must provide a status update to the Court within 30 days. | |||||||||
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 Minnesota Pollution Control Agency (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 $45.8 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 (Eighth Circuit). NSP-Minnesota and other regulated parties were denied intervention. In June 2013, the Eighth Circuit ordered this case to be held in abeyance until the U.S. Supreme Court decided the CSAPR case. In October 2014, the Eighth Circuit set a briefing schedule. The case will be briefed by early 2015. An argument date has not been set. 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, or the D.C. Circuit’s decision to lift its stay of the CSAPR, may impact the EPA’s approval of the BART requirements in the Texas SIP. | |||||||||
In May 2014, the EPA issued a request for information under the CAA related to SO2 control equipment at Tolk Units 1 and 2. The EPA stated it is conducting an analysis of the cost and feasibility of SO2 controls on certain sources, including the Tolk facility, as part of its review of the Texas SIP. The EPA has preliminarily identified Tolk as a contributor to haze in the Wichita Mountains Wildlife Refuge in Oklahoma, and is planning further analysis of SO2 control options. The EPA plans to make a proposal in November 2014 that could include SO2 emission controls at Tolk and anticipates issuing a final decision in August 2015. The costs and timing of potential additional SO2 controls at Tolk are dependent on the EPA’s proposal and final decision, neither of which is yet known. | |||||||||
Reasonably Attributable Visibility Impairment (RAVI) — RAVI is intended to address observable impairment from a specific source such as distinct, identifiable plumes from a source’s stack to a national park. 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 whether there is RAVI-type impairment in these parks and examine which sources may cause or contribute to any RAVI impact that is identified. After studying the national parks and evaluating multiple sources, if the EPA finds that Sherco Units 1 and 2 cause or contribute to RAVI in the national parks, the EPA would then evaluate 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. | |||||||||
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 District Court denied NSP-Minnesota’s motion to intervene in July 2013. NSP-Minnesota appealed this decision to the Eighth Circuit, which on July 23, 2014, reversed the District Court and found that NSP-Minnesota has standing and a right to intervene. | |||||||||
In June 2014, the EPA and the plaintiffs lodged a consent decree with the District Court. The consent decree recites it will be subject to public comment. The EPA will then evaluate comments and determine whether to enter the consent decree with the District Court. The consent decree establishes a schedule whereby the EPA would issue a proposal on Feb. 27, 2015, determining whether visibility impairment in the national parks is reasonably attributable to Sherco Units 1 and 2. If the EPA determines that it is, the consent decree requires the EPA to make a final RAVI BART determination for these units by Aug. 31, 2015. If the EPA determines that it is not, the EPA would not determine BART for Sherco Units 1 and 2. NSP-Minnesota filed comments opposing the proposed consent decree and will object to its entry given NSP-Minnesota’s right to intervene in the litigation and thus participate in the negotiation of any purported settlement of the case. | |||||||||
Revisions to National Ambient Air Quality Standards (NAAQS) for PM — In December 2012, the EPA lowered the primary health-based NAAQS for annual average fine PM and retained the current daily standard for fine PM. In areas where Xcel Energy operates power plants, current monitored air concentrations are below the level of the final annual primary standard. In August 2014, EPA issued its proposed designations, which did not include areas in any states in which Xcel Energy operates. The EPA is expected to finalize its designation of non-compliant locations by December 2014. States would then study the sources of the nonattainment and make emission reduction plans to attain the standards. It is not possible to evaluate the impact of this regulation further until the final designations have been made. | |||||||||
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 part on 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. In May 2011 enXco filed a lawsuit in the U.S. District Court in Minnesota seeking approximately $240 million for an alleged breach of contract. In April 2013, the U.S. District Court granted NSP-Minnesota’s motion for summary judgment and entered judgment in its favor. enXco subsequently appealed to the Eighth Circuit, which affirmed the U.S. District Court’s decision in July 2014. enXco has elected not to challenge this decision within the required time period which brings this matter to a close. | |||||||||
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. On Sept. 8, 2014, the Fifth Circuit Court of Appeals (Fifth Circuit) ruled that federal courts do not have jurisdiction to hear Exelon Wind’s challenge to the PUCT’s decision that Exelon Wind is ineligible to establish LEOs for the six wind facilities that were the subject of the PUCT’s order. The Fifth Circuit also ruled that the PUCT’s requirement that only QF’s providing firm energy are eligible to establish LEOs is valid. Exelon Wind filed a motion for rehearing with the Fifth Circuit on Sept. 22, 2014. On Oct. 10, 2014, the Fifth Circuit denied Exelon Wind’s motion for rehearing. 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 Court of Appeals (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 contested the FERC ALJ’s initial decision by filing a brief on exceptions to the FERC. PSCo filed a brief answering the City of Seattle’s exception. This matter is now pending a decision by 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, notwithstanding 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 additional cost reimbursement for certain transportation costs incurred since 2007, as well as reimbursement for similar costs in future periods. Fibrominn claims that it is entitled to reimbursement from NSP-Minnesota for past transportation costs of approximately $20 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 in rates. 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 DOE’s 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 Sept. 30, 2014. NSP-Minnesota’s next claim submission, in the amount of $33.6 million, was filed May 15, 2014, for costs incurred in 2013. In August 2014, the DOE accepted the claim for $32.8 million and NSP-Minnesota expects to receive payment in November 2014. Amounts received from the installments, except for approved reductions such as legal costs, will be subsequently returned to customers through a reduction of future rate increases or credited through another regulatory mechanism. |
Borrowings_and_Other_Financing
Borrowings and Other Financing Instruments | 9 Months Ended | ||||||||||||
Sep. 30, 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 | |||||||||||
Sept. 30, 2014 | Dec. 31, 2013 | ||||||||||||
Borrowing limit | $ | 2,450 | $ | 2,450 | |||||||||
Amount outstanding at period end | 697 | 759 | |||||||||||
Average amount outstanding | 730 | 481 | |||||||||||
Maximum amount outstanding | 894 | 1,160 | |||||||||||
Weighted average interest rate, computed on a daily basis | 0.33 | % | 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 Sept. 30, 2014 and Dec. 31, 2013, there were $71.4 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 Sept. 30, 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 | $ | 436 | $ | 364 | |||||||
PSCo | 700 | 259.5 | 440.5 | ||||||||||
NSP-Minnesota | 500 | 23.9 | 476.1 | ||||||||||
SPS | 300 | 41 | 259 | ||||||||||
NSP-Wisconsin | 150 | 8 | 142 | ||||||||||
Total | $ | 2,450.00 | $ | 768.4 | $ | 1,681.60 | |||||||
(a) | These credit facilities have been amended to expire in October 2019. | ||||||||||||
(b) | Includes outstanding commercial paper and letters of credit. | ||||||||||||
All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the respective credit facilities. Xcel Energy Inc. and its subsidiaries had no direct advances on the credit facilities outstanding at Sept. 30, 2014 and Dec. 31, 2013. | |||||||||||||
Amended Credit Agreements — On Oct. 14, 2014, Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS entered into amended five-year credit agreements with a syndicate of banks. The amended credit agreements have substantially the same terms and conditions as the prior credit agreements with an extension of maturity from July 2017 to October 2019. In addition, the borrowing limit for Xcel Energy Inc. has been increased to $1 billion from $800 million and the borrowing limit for SPS has been increased to $400 million from $300 million. As a result, the total borrowing limit under the amended credit agreements increased to $2.75 billion from $2.45 billion. The Eurodollar borrowing margins on these lines of credit range from 87.5 to 175 basis points per year based on applicable long-term credit ratings. The commitment fees, calculated on the unused portion of the lines of credit, range from 7.5 to 27.5 basis points per year, also based on applicable long-term credit ratings. | |||||||||||||
Xcel Energy Inc. and its utility subsidiaries, other than NSP-Wisconsin, have the right to request an extension of the revolving termination date for two additional one-year periods, and NSP-Wisconsin has the right to request an extension of the revolving termination date for an additional one-year period, each subject to majority bank group approval. | |||||||||||||
Long-Term Borrowings and Other Financing Instruments | |||||||||||||
During the nine months ended Sept. 30, 2014, Xcel Energy Inc. and its utility subsidiaries completed the following bond issuances: | |||||||||||||
• | In March 2014, PSCo issued $300 million of 4.30 percent first mortgage bonds due March 15, 2044; | ||||||||||||
• | In May 2014, NSP-Minnesota issued $300 million of 4.125 percent first mortgage bonds due May 15, 2044; | ||||||||||||
• | In June 2014, SPS issued $150 million of 3.30 percent first mortgage bonds due June 15, 2024; and | ||||||||||||
• | In June 2014, NSP-Wisconsin issued $100 million of 3.30 percent first mortgage bonds due June 15, 2024. | ||||||||||||
In connection with SPS’ issuance of $150 million of 3.30 percent first mortgage bonds due June 15, 2024, SPS issued $250 million of collateral 8.75 percent first mortgage bonds due Dec. 1, 2018 to the trustee under its senior unsecured indenture in order to secure its previously issued Series G Senior Notes, 8.75 percent due Dec. 1, 2018, equally and ratably with SPS’ first mortgage bonds as required by the terms of such Series G Senior Notes. | |||||||||||||
Issuances of Common Stock — Xcel Energy Inc. issued approximately 5.7 million shares of common stock through an at-the-market (ATM) program and received cash proceeds of $172.7 million net of $1.9 million in fees and commissions during the first six months of 2014. During the year ended Dec. 31, 2013, Xcel Energy Inc. issued approximately 7.7 million shares of common stock through this program and received cash proceeds of $222.7 million net of $2.7 million in fees and commissions. Xcel Energy completed its ATM program as of June 30, 2014. 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. |
Fair_Value_of_Financial_Assets
Fair Value of Financial Assets and Liabilities | 9 Months Ended | ||||||||||||||||||||||||
Sep. 30, 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 may include transmission congestion instruments purchased from 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 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 PI nuclear generating plants. The fund contains cash equivalents, debt securities, equity securities and other investments – all classified as available-for-sale. NSP-Minnesota plans to reinvest matured securities until decommissioning begins. NSP-Minnesota uses the MPUC approved asset allocation for the escrow and investment targets by asset class for both the escrow and qualified trust. | |||||||||||||||||||||||||
NSP-Minnesota recognizes the costs of funding the decommissioning of its nuclear generating plants over the lives of the plants, assuming rate recovery of all costs. 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 $287.5 million and $240.3 million at Sept. 30, 2014 and Dec. 31, 2013, respectively, and unrealized losses and amounts recorded as other-than-temporary impairments were $58.8 million and $58.5 million at Sept. 30, 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 Sept. 30, 2014 and Dec. 31, 2013: | |||||||||||||||||||||||||
Sept. 30, 2014 | |||||||||||||||||||||||||
Fair Value | |||||||||||||||||||||||||
(Thousands of Dollars) | Cost | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||
Nuclear decommissioning fund (a) | |||||||||||||||||||||||||
Cash equivalents | $ | 14,972 | $ | 14,972 | $ | — | $ | — | $ | 14,972 | |||||||||||||||
Commingled funds | 469,608 | — | 471,388 | — | 471,388 | ||||||||||||||||||||
International equity funds | 78,812 | — | 85,856 | — | 85,856 | ||||||||||||||||||||
Private equity investments | 74,222 | — | — | 97,004 | 97,004 | ||||||||||||||||||||
Real estate | 45,075 | — | — | 63,973 | 63,973 | ||||||||||||||||||||
Debt securities: | |||||||||||||||||||||||||
Government securities | 34,379 | — | 29,726 | — | 29,726 | ||||||||||||||||||||
U.S. corporate bonds | 80,196 | — | 79,248 | — | 79,248 | ||||||||||||||||||||
International corporate bonds | 17,696 | — | 17,613 | — | 17,613 | ||||||||||||||||||||
Municipal bonds | 235,751 | — | 240,907 | — | 240,907 | ||||||||||||||||||||
Asset-backed securities | 9,226 | — | 9,347 | — | 9,347 | ||||||||||||||||||||
Mortgage-backed securities | 23,554 | — | 23,696 | — | 23,696 | ||||||||||||||||||||
Equity securities: | |||||||||||||||||||||||||
Common stock | 377,287 | 555,711 | — | — | 555,711 | ||||||||||||||||||||
Total | $ | 1,460,778 | $ | 570,683 | $ | 957,781 | $ | 160,977 | $ | 1,689,441 | |||||||||||||||
(a) | Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $84.5 million of equity investments in unconsolidated subsidiaries and $43.0 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 and nine months ended Sept. 30, 2014 and 2013: | |||||||||||||||||||||||||
(Thousands of Dollars) | 1-Jul-14 | Purchases | Settlements | Gains Recognized as | Transfers Out of Level 3 | Sept. 30, 2014 | |||||||||||||||||||
Regulatory Liabilities | |||||||||||||||||||||||||
Private equity investments | $ | 81,123 | $ | 11,125 | $ | — | $ | 4,756 | $ | — | $ | 97,004 | |||||||||||||
Real estate | 65,658 | 1,530 | (5,876 | ) | 2,661 | — | 63,973 | ||||||||||||||||||
Total | $ | 146,781 | $ | 12,655 | $ | (5,876 | ) | $ | 7,417 | $ | — | $ | 160,977 | ||||||||||||
(Thousands of Dollars) | 1-Jul-13 | Purchases | Settlements | Gains Recognized as | Transfers Out of Level 3 | Sept. 30, 2013 | |||||||||||||||||||
Regulatory Liabilities | |||||||||||||||||||||||||
Private equity investments | $ | 45,590 | $ | 6,790 | $ | — | $ | 94 | $ | — | $ | 52,474 | |||||||||||||
Real estate | 38,140 | 11,288 | — | 1,928 | — | 51,356 | |||||||||||||||||||
Total | $ | 83,730 | $ | 18,078 | $ | — | $ | 2,022 | $ | — | $ | 103,830 | |||||||||||||
(Thousands of Dollars) | Jan. 1, 2014 | Purchases | Settlements | Gains Recognized as | Transfers Out of Level 3 | Sept. 30, 2014 | |||||||||||||||||||
Regulatory Liabilities | |||||||||||||||||||||||||
Private equity investments | $ | 62,696 | $ | 22,078 | $ | — | $ | 12,230 | $ | — | $ | 97,004 | |||||||||||||
Real estate | 57,368 | 5,386 | (5,876 | ) | 7,095 | — | 63,973 | ||||||||||||||||||
Total | $ | 120,064 | $ | 27,464 | $ | (5,876 | ) | $ | 19,325 | $ | — | $ | 160,977 | ||||||||||||
(Thousands of Dollars) | Jan. 1, 2013 | Purchases | Settlements | Gains Recognized as | Transfers Out of Level 3 (a) | Sept. 30, 2013 | |||||||||||||||||||
Regulatory Liabilities | |||||||||||||||||||||||||
Private equity investments | $ | 33,250 | $ | 15,344 | $ | — | $ | 3,880 | $ | — | $ | 52,474 | |||||||||||||
Real estate | 39,074 | 18,106 | (9,022 | ) | 3,198 | — | 51,356 | ||||||||||||||||||
Asset-backed securities | 2,067 | — | — | — | (2,067 | ) | — | ||||||||||||||||||
Mortgage-backed securities | 30,209 | — | — | — | (30,209 | ) | — | ||||||||||||||||||
Total | $ | 104,600 | $ | 33,450 | $ | (9,022 | ) | $ | 7,078 | $ | (32,276 | ) | $ | 103,830 | |||||||||||
(a) | Transfers out of Level 3 into Level 2 were principally due to diminished use of unobservable inputs that were previously significant to these fair value measurements. | ||||||||||||||||||||||||
The following table summarizes the final contractual maturity dates of the debt securities in the nuclear decommissioning fund, by asset class, at Sept. 30, 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 | $ | — | $ | — | $ | — | $ | 29,726 | $ | 29,726 | |||||||||||||||
U.S. corporate bonds | 303 | 15,878 | 62,985 | 82 | 79,248 | ||||||||||||||||||||
International corporate bonds | — | 4,266 | 13,347 | — | 17,613 | ||||||||||||||||||||
Municipal bonds | 807 | 34,188 | 41,744 | 164,168 | 240,907 | ||||||||||||||||||||
Asset-backed securities | — | — | 3,546 | 5,801 | 9,347 | ||||||||||||||||||||
Mortgage-backed securities | — | — | — | 23,696 | 23,696 | ||||||||||||||||||||
Debt securities | $ | 1,110 | $ | 54,332 | $ | 121,622 | $ | 223,473 | $ | 400,537 | |||||||||||||||
Derivative Instruments Fair Value Measurements | |||||||||||||||||||||||||
Xcel Energy enters into derivative instruments, including forward contracts, futures, swaps and options, for trading purposes and to manage risk in connection with changes in interest rates, utility commodity prices and vehicle fuel prices. | |||||||||||||||||||||||||
Interest Rate Derivatives — Xcel Energy enters into various instruments that effectively fix the interest payments on certain floating rate debt obligations or effectively fix the yield or price on a specified benchmark interest rate for an anticipated debt issuance for a specific period. These derivative instruments are generally designated as cash flow hedges for accounting purposes. | |||||||||||||||||||||||||
At Sept. 30, 2014, accumulated other comprehensive losses related to interest rate derivatives included $2.4 million of net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings, including forecasted amounts for 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, vehicle fuel and weather. | |||||||||||||||||||||||||
At Sept. 30, 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 and nine months ended Sept. 30, 2014 and 2013. | |||||||||||||||||||||||||
At Sept. 30, 2014, net gains related to commodity derivative cash flow hedges recorded as a component of accumulated other comprehensive losses included an immaterial amount of net gains expected to be reclassified into earnings during the next 12 months as the hedged transactions occur. | |||||||||||||||||||||||||
Additionally, Xcel Energy enters into commodity derivative instruments for trading purposes not directly related to commodity price risks associated with serving its electric and natural gas customers. Changes in the fair value of these commodity derivatives are recorded in electric operating revenues, net of amounts credited to customers under margin-sharing mechanisms. | |||||||||||||||||||||||||
The following table details the gross notional amounts of commodity forwards, options and FTRs at Sept. 30, 2014 and Dec. 31, 2013: | |||||||||||||||||||||||||
(Amounts in Thousands) (a)(b) | Sept. 30, 2014 | Dec. 31, 2013 | |||||||||||||||||||||||
Megawatt hours of electricity | 74,912 | 58,423 | |||||||||||||||||||||||
Million British thermal units of natural gas | 18,482 | 9,854 | |||||||||||||||||||||||
Gallons of vehicle fuel | 332 | 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 and nine months ended Sept. 30, 2014 and 2013, on accumulated other comprehensive loss, regulatory assets and liabilities, and income: | |||||||||||||||||||||||||
Three Months Ended Sept. 30, 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 | |||||||||||||||||||||||
(Thousands of Dollars) | Accumulated Other | Regulatory | Accumulated Other | Regulatory | During the Period in Income | ||||||||||||||||||||
Comprehensive Loss | (Assets) and Liabilities | Comprehensive Loss | Assets and (Liabilities) | ||||||||||||||||||||||
Derivatives designated as cash flow hedges | |||||||||||||||||||||||||
Interest rate | $ | — | $ | — | $ | 967 | (a) | $ | — | $ | — | ||||||||||||||
Vehicle fuel and other commodity | (69 | ) | — | (16 | ) | (b) | — | — | |||||||||||||||||
Total | $ | (69 | ) | $ | — | $ | 951 | $ | — | $ | — | ||||||||||||||
Other derivative instruments | |||||||||||||||||||||||||
Commodity trading | $ | — | $ | — | $ | — | $ | — | $ | (1,656 | ) | (c) | |||||||||||||
Electric commodity | — | (3,391 | ) | — | 6,629 | (d) | — | ||||||||||||||||||
Natural gas commodity | — | (2,455 | ) | — | — | (209 | ) | (d) | |||||||||||||||||
Total | $ | — | $ | (5,846 | ) | $ | — | $ | 6,629 | $ | (1,865 | ) | |||||||||||||
Nine Months Ended Sept. 30, 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 | |||||||||||||||||||||||
(Thousands of Dollars) | Accumulated Other | Regulatory | Accumulated Other | Regulatory | During the Period in Income | ||||||||||||||||||||
Comprehensive Loss | (Assets) and Liabilities | Comprehensive Loss | Assets and (Liabilities) | ||||||||||||||||||||||
Derivatives designated as cash flow hedges | |||||||||||||||||||||||||
Interest rate | $ | — | $ | — | $ | 2,869 | (a) | $ | — | $ | — | ||||||||||||||
Vehicle fuel and other commodity | (56 | ) | — | (61 | ) | (b) | — | — | |||||||||||||||||
Total | $ | (56 | ) | $ | — | $ | 2,808 | $ | — | $ | — | ||||||||||||||
Other derivative instruments | |||||||||||||||||||||||||
Commodity trading | $ | — | $ | — | $ | — | $ | — | $ | 1,266 | (c) | ||||||||||||||
Electric commodity | — | (17,240 | ) | — | (18,641 | ) | (d) | — | |||||||||||||||||
Natural gas commodity | — | 13,603 | — | (18,840 | ) | (e) | (5,575 | ) | (e) | ||||||||||||||||
Other commodity | — | — | — | — | 643 | (c) | |||||||||||||||||||
Total | $ | — | $ | (3,637 | ) | $ | — | $ | (37,481 | ) | $ | (3,666 | ) | ||||||||||||
Three Months Ended Sept. 30, 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 Recognized | |||||||||||||||||||||||
(Thousands of Dollars) | Accumulated Other | Regulatory | Accumulated Other | Regulatory | During the Period in Income | ||||||||||||||||||||
Comprehensive Loss | (Assets) and Liabilities | Comprehensive Loss | Assets and (Liabilities) | ||||||||||||||||||||||
Derivatives designated as cash flow hedges | |||||||||||||||||||||||||
Interest rate | $ | — | $ | — | $ | 829 | (a) | $ | — | $ | — | ||||||||||||||
Vehicle fuel and other commodity | 36 | — | (24 | ) | (b) | — | — | ||||||||||||||||||
Total | $ | 36 | $ | — | $ | 805 | $ | — | $ | — | |||||||||||||||
Other derivative instruments | |||||||||||||||||||||||||
Commodity trading | $ | — | $ | — | $ | — | $ | — | $ | 7,094 | (c) | ||||||||||||||
Electric commodity | — | 921 | — | (9,823 | ) | (d) | — | ||||||||||||||||||
Natural gas commodity | — | (1,967 | ) | — | — | 12 | (d) | ||||||||||||||||||
Total | $ | — | $ | (1,046 | ) | $ | — | $ | (9,823 | ) | $ | 7,106 | |||||||||||||
Nine Months Ended Sept. 30, 2013 | |||||||||||||||||||||||||
Pre-Tax Fair Value Gains (Losses) Recognized During the Period in: | Pre-Tax (Gains) Losses Reclassified into Income During the Period from: | Pre-Tax Gains (Losses) Recognized | |||||||||||||||||||||||
(Thousands of Dollars) | Accumulated Other | Regulatory | Accumulated Other | Regulatory | During the Period in Income | ||||||||||||||||||||
Comprehensive Loss | (Assets) and Liabilities | Comprehensive Loss | Assets and (Liabilities) | ||||||||||||||||||||||
Derivatives designated as cash flow hedges | |||||||||||||||||||||||||
Interest rate | $ | — | $ | — | $ | 3,140 | (a) | $ | — | $ | — | ||||||||||||||
Vehicle fuel and other commodity | (11 | ) | — | (67 | ) | (b) | — | — | |||||||||||||||||
Total | $ | (11 | ) | $ | — | $ | 3,073 | $ | — | $ | — | ||||||||||||||
Other derivative instruments | |||||||||||||||||||||||||
Commodity trading | $ | — | $ | — | $ | — | $ | — | $ | 9,372 | (c) | ||||||||||||||
Electric commodity | — | 61,314 | — | (38,816 | ) | (d) | — | ||||||||||||||||||
Natural gas commodity | — | (5,341 | ) | — | 9 | (e) | (216 | ) | (d) | ||||||||||||||||
Total | $ | — | $ | 55,973 | $ | — | $ | (38,807 | ) | $ | 9,156 | ||||||||||||||
(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 nine months ended Sept. 30, 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 nine months ended Sept. 30, 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 and nine months ended Sept. 30, 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 Sept. 30, 2014, four of Xcel Energy’s 10 most significant counterparties for these activities, comprising $48.8 million or 16 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 $75.0 million or 25 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 contracts and therefore not reflected on the balance sheet, may require the posting of collateral or settlement of the contracts for various reasons, including if the applicable utility subsidiary is unable to maintain its credit ratings. At Sept. 30, 2014, there were no derivative instruments in a liability position that would have required the posting of collateral or settlement of applicable outstanding contracts if the credit ratings of Xcel Energy Inc.’s utility subsidiaries were downgraded below investment grade. If the credit ratings of Xcel Energy Inc.’s utility subsidiaries were downgraded below investment grade at Dec. 31, 2013, derivative instruments reflected in a $1.4 million gross liability position on the consolidated balance sheets at Dec. 31, 2013, 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 $1.4 million. At Sept. 30, 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 Sept. 30, 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 Sept. 30, 2014: | |||||||||||||||||||||||||
Sept. 30, 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 | $ | — | $ | 4 | $ | — | $ | 4 | $ | (3 | ) | $ | 1 | ||||||||||||
Other derivative instruments: | |||||||||||||||||||||||||
Commodity trading | — | 18,912 | 4,609 | 23,521 | (5,395 | ) | 18,126 | ||||||||||||||||||
Electric commodity | — | — | 86,708 | 86,708 | (17,685 | ) | 69,023 | ||||||||||||||||||
Natural gas commodity | — | 10,051 | — | 10,051 | (74 | ) | 9,977 | ||||||||||||||||||
Total current derivative assets | $ | — | $ | 28,967 | $ | 91,317 | $ | 120,284 | $ | (23,157 | ) | 97,127 | |||||||||||||
PPAs (a) | 23,527 | ||||||||||||||||||||||||
Current derivative instruments | $ | 120,654 | |||||||||||||||||||||||
Noncurrent derivative assets | |||||||||||||||||||||||||
Derivatives designated as cash flow hedges: | |||||||||||||||||||||||||
Other derivative instruments: | |||||||||||||||||||||||||
Commodity trading | $ | — | $ | 13,269 | $ | — | $ | 13,269 | $ | (2,408 | ) | $ | 10,861 | ||||||||||||
Total noncurrent derivative assets | $ | — | $ | 13,269 | $ | — | $ | 13,269 | $ | (2,408 | ) | 10,861 | |||||||||||||
PPAs (a) | 42,716 | ||||||||||||||||||||||||
Noncurrent derivative instruments | $ | 53,577 | |||||||||||||||||||||||
Current derivative liabilities | |||||||||||||||||||||||||
Derivatives designated as cash flow hedges: | |||||||||||||||||||||||||
Vehicle fuel and other commodity | $ | — | $ | 3 | $ | — | $ | 3 | $ | (3 | ) | $ | — | ||||||||||||
Other derivative instruments: | |||||||||||||||||||||||||
Commodity trading | — | 9,759 | — | 9,759 | (9,337 | ) | 422 | ||||||||||||||||||
Electric commodity | — | — | 17,685 | 17,685 | (17,685 | ) | — | ||||||||||||||||||
Natural gas commodity | — | 74 | — | 74 | (74 | ) | — | ||||||||||||||||||
Total current derivative liabilities | $ | — | $ | 9,836 | $ | 17,685 | $ | 27,521 | $ | (27,099 | ) | 422 | |||||||||||||
PPAs (a) | 22,502 | ||||||||||||||||||||||||
Current derivative instruments | $ | 22,924 | |||||||||||||||||||||||
Noncurrent derivative liabilities | |||||||||||||||||||||||||
Derivatives designated as cash flow hedges: | |||||||||||||||||||||||||
Vehicle fuel and other commodity | $ | — | $ | 5 | $ | — | $ | 5 | $ | — | $ | 5 | |||||||||||||
Other derivative instruments: | |||||||||||||||||||||||||
Commodity trading | — | 3,066 | — | 3,066 | (2,408 | ) | 658 | ||||||||||||||||||
Natural gas commodity | — | 71 | — | 71 | — | 71 | |||||||||||||||||||
Total noncurrent derivative liabilities | $ | — | $ | 3,142 | $ | — | $ | 3,142 | $ | (2,408 | ) | 734 | |||||||||||||
PPAs (a) | 186,711 | ||||||||||||||||||||||||
Noncurrent derivative instruments | $ | 187,445 | |||||||||||||||||||||||
(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 Sept. 30, 2014. At Sept. 30, 2014, derivative assets and liabilities include no obligations to return cash collateral and the rights to reclaim cash collateral of $3.9 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 the 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 and nine months ended Sept. 30, 2014 and 2013: | |||||||||||||||||||||||||
Three Months Ended Sept. 30 | |||||||||||||||||||||||||
(Thousands of Dollars) | 2014 | 2013 | |||||||||||||||||||||||
Balance at July 1 | $ | 105,394 | $ | 47,218 | |||||||||||||||||||||
Purchases | 5,588 | 155 | |||||||||||||||||||||||
Settlements | (20,032 | ) | (9,342 | ) | |||||||||||||||||||||
Transfers out of Level 3 | (1,093 | ) | — | ||||||||||||||||||||||
Net transactions recorded during the period: | |||||||||||||||||||||||||
Gains recognized in earnings (a) | 1,480 | 4,008 | |||||||||||||||||||||||
Losses recognized as regulatory assets and liabilities | (17,705 | ) | (571 | ) | |||||||||||||||||||||
Balance at Sept. 30 | $ | 73,632 | $ | 41,468 | |||||||||||||||||||||
Nine Months Ended Sept. 30 | |||||||||||||||||||||||||
(Thousands of Dollars) | 2014 | 2013 | |||||||||||||||||||||||
Balance at Jan. 1 | $ | 41,660 | $ | 16,649 | |||||||||||||||||||||
Purchases | 126,752 | 51,541 | |||||||||||||||||||||||
Settlements | (107,451 | ) | (30,294 | ) | |||||||||||||||||||||
Transfers out of Level 3 | (1,093 | ) | — | ||||||||||||||||||||||
Net transactions recorded during the period: | |||||||||||||||||||||||||
Gains recognized in earnings (a) | 8,917 | 3,729 | |||||||||||||||||||||||
Gains (losses) recognized as regulatory assets and liabilities | 4,847 | (157 | ) | ||||||||||||||||||||||
Balance at Sept. 30 | $ | 73,632 | $ | 41,468 | |||||||||||||||||||||
(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. The transfer of amounts from Level 3 to Level 2 in the three and nine months ended Sept. 30, 2014 was due to the valuation of certain long-term derivative contracts for which observable commodity pricing forecasts became a more significant input during the period. There were no transfers of amounts between levels for derivative instruments for the three and nine months ended Sept. 30, 2013. | |||||||||||||||||||||||||
Fair Value of Long-Term Debt | |||||||||||||||||||||||||
As of Sept. 30, 2014 and Dec. 31, 2013, other financial instruments for which the carrying amount did not equal fair value were as follows: | |||||||||||||||||||||||||
Sept. 30, 2014 | Dec. 31, 2013 | ||||||||||||||||||||||||
(Thousands of Dollars) | Carrying Amount | Fair Value | Carrying Amount | Fair Value | |||||||||||||||||||||
Long-term debt, including current portion | $ | 11,759,226 | $ | 12,990,348 | $ | 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 Sept. 30, 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_Expense_Net
Other Income (Expense), Net | 9 Months Ended | ||||||||||||||||
Sep. 30, 2014 | |||||||||||||||||
Other Income and Expenses [Abstract] | ' | ||||||||||||||||
Other Income (Expense), Net | ' | ||||||||||||||||
Other Income (Expense), Net | |||||||||||||||||
Other income (expense), net consisted of the following: | |||||||||||||||||
Three Months Ended Sept. 30 | Nine Months Ended Sept. 30 | ||||||||||||||||
(Thousands of Dollars) | 2014 | 2013 | 2014 | 2013 | |||||||||||||
Interest income | $ | 1,139 | $ | 1,304 | $ | 6,324 | $ | 7,615 | |||||||||
Other nonoperating income | 682 | 739 | 3,042 | 2,494 | |||||||||||||
Insurance policy expense | (417 | ) | (2,386 | ) | (4,663 | ) | (5,932 | ) | |||||||||
Other nonoperating expense | — | (61 | ) | (16 | ) | (246 | ) | ||||||||||
Other income (expense), net | $ | 1,404 | $ | (404 | ) | $ | 4,687 | $ | 3,931 | ||||||||
Segment_Information
Segment Information | 9 Months Ended | ||||||||||||||||||||
Sep. 30, 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 primarily in portions of Minnesota, Wisconsin, Michigan, North Dakota, South Dakota, Colorado, Texas and New Mexico. In addition, this segment includes sales for resale and provides wholesale transmission service to various entities in the United States. Regulated electric utility also includes commodity trading operations. | ||||||||||||||||||||
• | Xcel Energy’s regulated natural gas utility segment transports, stores and distributes natural gas primarily in portions of Minnesota, Wisconsin, North Dakota, Michigan and Colorado. | ||||||||||||||||||||
• | Revenues from operating segments not included above are below the necessary quantitative thresholds and are therefore included in the all other category. Those primarily include steam revenue, appliance repair services, nonutility real estate activities, revenues associated with processing solid waste into refuse-derived fuel and investments in rental housing projects that qualify for low-income housing tax credits. | ||||||||||||||||||||
Xcel Energy had equity investments in unconsolidated subsidiaries of $84.5 million and $87.1 million as of Sept. 30, 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 Sept. 30, 2014 | |||||||||||||||||||||
Operating revenues from external customers | $ | 2,616,351 | $ | 236,649 | $ | 16,807 | $ | — | $ | 2,869,807 | |||||||||||
Intersegment revenues | 472 | 597 | — | (1,069 | ) | — | |||||||||||||||
Total revenues | $ | 2,616,823 | $ | 237,246 | $ | 16,807 | $ | (1,069 | ) | $ | 2,869,807 | ||||||||||
Net income | $ | 360,656 | $ | 3,996 | $ | 3,930 | $ | — | $ | 368,582 | |||||||||||
(Thousands of Dollars) | Regulated Electric | Regulated Natural Gas | All Other | Reconciling Eliminations | Consolidated Total | ||||||||||||||||
Three Months Ended Sept. 30, 2013 | |||||||||||||||||||||
Operating revenues from external customers | $ | 2,599,925 | $ | 205,358 | $ | 17,055 | $ | — | $ | 2,822,338 | |||||||||||
Intersegment revenues | 346 | 1,106 | — | (1,452 | ) | — | |||||||||||||||
Total revenues | $ | 2,600,271 | $ | 206,464 | $ | 17,055 | $ | (1,452 | ) | $ | 2,822,338 | ||||||||||
Net income (loss) | $ | 365,156 | $ | (174 | ) | $ | (230 | ) | $ | — | $ | 364,752 | |||||||||
(Thousands of Dollars) | Regulated Electric | Regulated Natural Gas | All Other | Reconciling Eliminations | Consolidated Total | ||||||||||||||||
Nine Months Ended Sept. 30, 2014 | |||||||||||||||||||||
Operating revenues from external customers | $ | 7,215,699 | $ | 1,485,464 | $ | 56,344 | $ | — | $ | 8,757,507 | |||||||||||
Intersegment revenues | 1,262 | 4,967 | — | (6,229 | ) | — | |||||||||||||||
Total revenues | $ | 7,216,961 | $ | 1,490,431 | $ | 56,344 | $ | (6,229 | ) | $ | 8,757,507 | ||||||||||
Net income (loss) | $ | 731,766 | $ | 96,629 | $ | (3,428 | ) | $ | — | $ | 824,967 | ||||||||||
(Thousands of Dollars) | Regulated Electric | Regulated Natural Gas | All Other | Reconciling Eliminations | Consolidated Total | ||||||||||||||||
Nine Months Ended Sept. 30, 2013 | |||||||||||||||||||||
Operating revenues from external customers | $ | 6,911,998 | $ | 1,216,275 | $ | 55,827 | $ | — | $ | 8,184,100 | |||||||||||
Intersegment revenues | 955 | 2,163 | — | (3,118 | ) | — | |||||||||||||||
Total revenues | $ | 6,912,953 | $ | 1,218,438 | $ | 55,827 | $ | (3,118 | ) | $ | 8,184,100 | ||||||||||
Net income (loss) | $ | 740,347 | $ | 80,698 | $ | (22,866 | ) | $ | — | $ | 798,179 | ||||||||||
Earnings_Per_Share
Earnings Per Share | 9 Months Ended | ||||||||||||||||||||||
Sep. 30, 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 using the treasury stock method. | |||||||||||||||||||||||
Common Stock Equivalents — Xcel Energy Inc. currently has common stock equivalents related to certain equity awards in share-based compensation arrangements. | |||||||||||||||||||||||
Common stock equivalents causing dilutive impact to EPS include commitments to issue common stock related to time based equity compensation awards and time based employer matching contributions to certain 401(k) plan participants. In October 2013, Xcel Energy determined that it would settle 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 Sept. 30, 2014 | Three Months Ended Sept. 30, 2013 | ||||||||||||||||||||||
(Amounts in thousands, except per share data) | Income | Shares | Per Share | Income | Shares | Per Share | |||||||||||||||||
Amount | Amount | ||||||||||||||||||||||
Net income | $ | 368,582 | $ | 364,752 | |||||||||||||||||||
Basic EPS: | |||||||||||||||||||||||
Earnings available to common shareholders | 368,582 | 506,082 | $ | 0.73 | 364,752 | 498,149 | $ | 0.73 | |||||||||||||||
Effect of dilutive securities: | |||||||||||||||||||||||
Time based equity awards | — | 283 | — | 492 | |||||||||||||||||||
Diluted EPS: | |||||||||||||||||||||||
Earnings available to common shareholders | $ | 368,582 | 506,365 | $ | 0.73 | $ | 364,752 | 498,641 | $ | 0.73 | |||||||||||||
Nine Months Ended Sept. 30, 2014 | Nine Months Ended Sept. 30, 2013 | ||||||||||||||||||||||
(Amounts in thousands, except per share data) | Income | Shares | Per Share | Income | Shares | Per Share | |||||||||||||||||
Amount | Amount | ||||||||||||||||||||||
Net income | $ | 824,967 | $ | 798,179 | |||||||||||||||||||
Basic EPS: | |||||||||||||||||||||||
Earnings available to common shareholders | 824,967 | 502,983 | $ | 1.64 | 798,179 | 495,256 | $ | 1.61 | |||||||||||||||
Effect of dilutive securities: | |||||||||||||||||||||||
Time based equity awards | — | 230 | — | 511 | |||||||||||||||||||
Diluted EPS: | |||||||||||||||||||||||
Earnings available to common shareholders | $ | 824,967 | 503,213 | $ | 1.64 | $ | 798,179 | 495,767 | $ | 1.61 | |||||||||||||
Benefit_Plans_and_Other_Postre
Benefit Plans and Other Postretirement Benefits | 9 Months Ended | ||||||||||||||||
Sep. 30, 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 Sept. 30 | |||||||||||||||||
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 | 35,173 | 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 | 47,137 | 1,145 | 4,760 | |||||||||||||
Costs not recognized due to the effects of regulation | (6,605 | ) | (12,986 | ) | — | — | |||||||||||
Net benefit cost recognized for financial reporting | $ | 31,589 | $ | 34,151 | $ | 1,145 | $ | 4,760 | |||||||||
Nine Months Ended Sept. 30 | |||||||||||||||||
2014 | 2013 | 2014 | 2013 | ||||||||||||||
(Thousands of Dollars) | Pension Benefits | Postretirement Health | |||||||||||||||
Care Benefits | |||||||||||||||||
Service cost | $ | 66,257 | $ | 72,212 | $ | 2,592 | $ | 3,546 | |||||||||
Interest cost | 117,465 | 105,518 | 25,521 | 25,251 | |||||||||||||
Expected return on plan assets | (155,403 | ) | (148,839 | ) | (25,466 | ) | (24,759 | ) | |||||||||
Amortization of transition obligation | — | — | — | 618 | |||||||||||||
Amortization of prior service (credit) cost | (1,310 | ) | 4,404 | (8,016 | ) | (7,314 | ) | ||||||||||
Amortization of net loss | 87,572 | 108,114 | 8,805 | 16,938 | |||||||||||||
Net periodic benefit cost | 114,581 | 141,409 | 3,436 | 14,280 | |||||||||||||
Costs not recognized due to the effects of regulation | (20,261 | ) | (27,922 | ) | — | — | |||||||||||
Net benefit cost recognized for financial reporting | $ | 94,320 | $ | 113,487 | $ | 3,436 | $ | 14,280 | |||||||||
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 | 9 Months Ended | ||||||||||||||||
Sep. 30, 2014 | |||||||||||||||||
Stockholders' Equity Note [Abstract] | ' | ||||||||||||||||
Other Comprehensive Income | ' | ||||||||||||||||
Other Comprehensive Income | |||||||||||||||||
Changes in accumulated other comprehensive income (loss), net of tax, for the three and nine months ended Sept. 30, 2014 and 2013 were as follows: | |||||||||||||||||
Three Months Ended Sept. 30, 2014 | |||||||||||||||||
(Thousands of Dollars) | Gains and Losses | Unrealized Gains and Losses | Defined Benefit Pension and | Total | |||||||||||||
on Cash Flow Hedges | on Marketable Securities | Postretirement Items | |||||||||||||||
Accumulated other comprehensive (loss) income at July 1 | $ | (58,610 | ) | $ | 115 | $ | (44,871 | ) | $ | (103,366 | ) | ||||||
Other comprehensive (loss) income before reclassifications | (42 | ) | 2 | — | (40 | ) | |||||||||||
Losses reclassified from net accumulated other comprehensive loss | 558 | — | 847 | 1,405 | |||||||||||||
Net current period other comprehensive income | 516 | 2 | 847 | 1,365 | |||||||||||||
Accumulated other comprehensive (loss) income at Sept. 30 | $ | (58,094 | ) | $ | 117 | $ | (44,024 | ) | $ | (102,001 | ) | ||||||
Three Months Ended Sept. 30, 2013 | |||||||||||||||||
(Thousands of Dollars) | Gains and Losses | Unrealized Gains and Losses | Defined Benefit Pension and | Total | |||||||||||||
on Cash Flow Hedges | on Marketable Securities | Postretirement Items | |||||||||||||||
Accumulated other comprehensive loss at July 1 | $ | (60,883 | ) | $ | (135 | ) | $ | (50,817 | ) | $ | (111,835 | ) | |||||
Other comprehensive income before reclassifications | 22 | 115 | — | 137 | |||||||||||||
Losses reclassified from net accumulated other comprehensive loss | 539 | — | 1,179 | 1,718 | |||||||||||||
Net current period other comprehensive income | 561 | 115 | 1,179 | 1,855 | |||||||||||||
Accumulated other comprehensive loss at Sept. 30 | $ | (60,322 | ) | $ | (20 | ) | $ | (49,638 | ) | $ | (109,980 | ) | |||||
Nine Months Ended Sept. 30, 2014 | |||||||||||||||||
(Thousands of Dollars) | Gains and Losses | Unrealized Gains and Losses | Defined Benefit Pension and | Total | |||||||||||||
on Cash Flow Hedges | on Marketable Securities | Postretirement Items | |||||||||||||||
Accumulated other comprehensive (loss) income at Jan. 1 | $ | (59,753 | ) | $ | 77 | $ | (46,599 | ) | $ | (106,275 | ) | ||||||
Other comprehensive (loss) income before reclassifications | (34 | ) | 40 | — | 6 | ||||||||||||
Losses reclassified from net accumulated other comprehensive loss | 1,693 | — | 2,575 | 4,268 | |||||||||||||
Net current period other comprehensive income | 1,659 | 40 | 2,575 | 4,274 | |||||||||||||
Accumulated other comprehensive (loss) income at Sept. 30 | $ | (58,094 | ) | $ | 117 | $ | (44,024 | ) | $ | (102,001 | ) | ||||||
Nine Months Ended Sept. 30, 2013 | |||||||||||||||||
(Thousands of Dollars) | Gains and Losses | Unrealized Gains and Losses | Defined Benefit Pension and | Total | |||||||||||||
on Cash Flow Hedges | on Marketable Securities | Postretirement Items | |||||||||||||||
Accumulated other comprehensive loss at Jan. 1 | $ | (61,241 | ) | $ | (99 | ) | $ | (51,313 | ) | $ | (112,653 | ) | |||||
Other comprehensive (loss) income before reclassifications | (9 | ) | 79 | — | 70 | ||||||||||||
Losses reclassified from net accumulated other comprehensive loss | 928 | — | 1,675 | 2,603 | |||||||||||||
Net current period other comprehensive income | 919 | 79 | 1,675 | 2,673 | |||||||||||||
Accumulated other comprehensive loss at Sept. 30 | $ | (60,322 | ) | $ | (20 | ) | $ | (49,638 | ) | $ | (109,980 | ) | |||||
Reclassifications from accumulated other comprehensive loss for the three and nine months ended Sept. 30, 2014 and 2013 were as follows: | |||||||||||||||||
Amounts Reclassified from Accumulated | |||||||||||||||||
Other Comprehensive Loss | |||||||||||||||||
(Thousands of Dollars) | Three Months Ended Sept. 30, 2014 | Three Months Ended Sept. 30, 2013 | |||||||||||||||
(Gains) losses on cash flow hedges: | |||||||||||||||||
Interest rate derivatives | $ | 967 | (a) | $ | 829 | (a) | |||||||||||
Vehicle fuel derivatives | (16 | ) | (b) | (24 | ) | (b) | |||||||||||
Total, pre-tax | 951 | 805 | |||||||||||||||
Tax benefit | (393 | ) | (266 | ) | |||||||||||||
Total, net of tax | 558 | 539 | |||||||||||||||
Defined benefit pension and postretirement (gains) losses: | |||||||||||||||||
Amortization of net loss | 1,500 | (c) | 1,770 | (c) | |||||||||||||
Prior service (credit) cost | (86 | ) | (c) | 93 | (c) | ||||||||||||
Transition obligation | — | (c) | 2 | (c) | |||||||||||||
Total, pre-tax | 1,414 | 1,865 | |||||||||||||||
Tax benefit | (567 | ) | (686 | ) | |||||||||||||
Total, net of tax | 847 | 1,179 | |||||||||||||||
Total amounts reclassified, net of tax | $ | 1,405 | $ | 1,718 | |||||||||||||
Amounts Reclassified from Accumulated | |||||||||||||||||
Other Comprehensive Loss | |||||||||||||||||
(Thousands of Dollars) | Nine Months Ended Sept. 30, 2014 | Nine Months Ended Sept. 30, 2013 | |||||||||||||||
(Gains) losses on cash flow hedges: | |||||||||||||||||
Interest rate derivatives | $ | 2,869 | (a) | $ | 3,140 | (a) | |||||||||||
Vehicle fuel derivatives | (61 | ) | (b) | (67 | ) | (b) | |||||||||||
Total, pre-tax | 2,808 | 3,073 | |||||||||||||||
Tax benefit | (1,115 | ) | (2,145 | ) | |||||||||||||
Total, net of tax | 1,693 | 928 | |||||||||||||||
Defined benefit pension and postretirement (gains) losses: | |||||||||||||||||
Amortization of net loss | 4,499 | (c) | 5,308 | (c) | |||||||||||||
Prior service (credit) cost | (258 | ) | (c) | 279 | (c) | ||||||||||||
Transition obligation | — | (c) | 6 | (c) | |||||||||||||
Total, pre-tax | 4,241 | 5,593 | |||||||||||||||
Tax benefit | (1,666 | ) | (3,918 | ) | |||||||||||||
Total, net of tax | 2,575 | 1,675 | |||||||||||||||
Total amounts reclassified, net of tax | $ | 4,268 | $ | 2,603 | |||||||||||||
(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) | 9 Months Ended | ||||||||
Sep. 30, 2014 | |||||||||
Balance Sheet Related Disclosures [Abstract] | ' | ||||||||
Accounts Receivable, Net | ' | ||||||||
(Thousands of Dollars) | Sept. 30, 2014 | Dec. 31, 2013 | |||||||
Accounts receivable, net | |||||||||
Accounts receivable | $ | 814,967 | $ | 797,267 | |||||
Less allowance for bad debts | (54,754 | ) | (53,107 | ) | |||||
$ | 760,213 | $ | 744,160 | ||||||
Inventories | ' | ||||||||
(Thousands of Dollars) | Sept. 30, 2014 | Dec. 31, 2013 | |||||||
Inventories | |||||||||
Materials and supplies | $ | 240,384 | $ | 225,308 | |||||
Fuel | 193,951 | 189,485 | |||||||
Natural gas | 199,927 | 161,745 | |||||||
$ | 634,262 | $ | 576,538 | ||||||
Property, Plant and Equipment, Net | ' | ||||||||
(Thousands of Dollars) | Sept. 30, 2014 | Dec. 31, 2013 | |||||||
Property, plant and equipment, net | |||||||||
Electric plant | $ | 32,122,904 | $ | 30,341,310 | |||||
Natural gas plant | 4,294,667 | 4,086,651 | |||||||
Common and other property | 1,483,063 | 1,485,547 | |||||||
Plant to be retired (a) | 77,922 | 101,279 | |||||||
Construction work in progress | 2,364,851 | 2,371,566 | |||||||
Total property, plant and equipment | 40,343,407 | 38,386,353 | |||||||
Less accumulated depreciation | (13,028,218 | ) | (12,608,305 | ) | |||||
Nuclear fuel | 2,250,140 | 2,186,799 | |||||||
Less accumulated amortization | (1,934,966 | ) | (1,842,688 | ) | |||||
$ | 27,630,363 | $ | 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) | 9 Months Ended | ||||||||
Sep. 30, 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 Sept. 30, 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 | 2010 | ||||||||
Reconciliation of Unrecognized Tax Benefits | ' | ||||||||
A reconciliation of the amount of unrecognized tax benefit is as follows: | |||||||||
(Millions of Dollars) | Sept. 30, 2014 | Dec. 31, 2013 | |||||||
Unrecognized tax benefit — Permanent tax positions | $ | 7.5 | $ | 12.9 | |||||
Unrecognized tax benefit — Temporary tax positions | 32.9 | 28.3 | |||||||
Total unrecognized tax benefit | $ | 40.4 | $ | 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) | Sept. 30, 2014 | Dec. 31, 2013 | |||||||
NOL and tax credit carryforwards | $ | (28.1 | ) | $ | (27.1 | ) |
Rate_Matters_Tables
Rate Matters (Tables) | 9 Months Ended | ||||||||||||
Sep. 30, 2014 | |||||||||||||
Public Utilities, General Disclosures [Abstract] | ' | ||||||||||||
NSP-Minnesota's 2014 Electric Rate Case [Table Text Block] | ' | ||||||||||||
The following table summarizes the DOC’s and NSP-Minnesota’s recommendations and includes the estimated impact of certain agreed-upon true-up adjustments: | |||||||||||||
2014 Rate Request (Millions of Dollars) | DOC | NSP-Minnesota | |||||||||||
NSP-Minnesota’s filed rate request | $ | 192.7 | $ | 192.7 | |||||||||
Sales forecast | (43.2 | ) | (15.8 | ) | |||||||||
ROE | (36.2 | ) | — | ||||||||||
Monticello EPU cost recovery | (33.9 | ) | — | ||||||||||
Monticello EPU depreciation deferral | — | (12.2 | ) | ||||||||||
Property taxes | (9.0 | ) | (9.0 | ) | |||||||||
PI EPU | (5.1 | ) | (5.1 | ) | |||||||||
Health care, pension and other benefits | (11.4 | ) | (1.9 | ) | |||||||||
Other, net | (8.0 | ) | (6.5 | ) | |||||||||
Total recommendation 2014 — unadjusted | $ | 45.9 | $ | 142.2 | |||||||||
Estimated true-up adjustments: | |||||||||||||
Sales forecast | $ | 18.3 | $ | (9.1 | ) | ||||||||
Property taxes | 3.9 | 3.9 | |||||||||||
Total recommendation 2014 — adjusted | $ | 68.1 | $ | 137 | |||||||||
2015 Rate Request (Millions of Dollars) | DOC | NSP-Minnesota | |||||||||||
NSP-Minnesota’s filed rate request | $ | 98.5 | $ | 98.5 | |||||||||
Monticello EPU cost recovery | 29.1 | — | |||||||||||
Monticello EPU cost disallowance (a) | (10.2 | ) | — | ||||||||||
Excess depreciation reserve adjustment (b) | (22.7 | ) | — | ||||||||||
Depreciation | (17.5 | ) | — | ||||||||||
Monticello EPU depreciation deferral | — | 1.6 | |||||||||||
Monticello EPU step increase | — | 10.1 | |||||||||||
Property taxes | (3.3 | ) | (3.3 | ) | |||||||||
Production tax credits to be included in base rates | (11.1 | ) | (11.1 | ) | |||||||||
DOE settlement proceeds | 10.1 | 10.1 | |||||||||||
Emission chemicals | (1.6 | ) | (1.6 | ) | |||||||||
Other, net | (4.8 | ) | 1.7 | ||||||||||
Total recommendation 2015 step increase | $ | 66.5 | $ | 106 | |||||||||
Unadjusted cumulative total for 2014 and 2015 step increase | $ | 112.4 | $ | 248.2 | |||||||||
Estimated adjusted cumulative total for 2014 and 2015 step increase | $ | 134.6 | $ | 243 | |||||||||
(a) | In July 2014, the DOC recommended a disallowance of recovery of approximately $71.5 million of project costs on a Minnesota jurisdictional basis. This equates to a total NSP System disallowance of approximately $94 million. This would reduce NSP-Minnesota’s revenue requirement by approximately $10.2 million in 2015. | ||||||||||||
(b) | Adjustment is due to timing differences and/or methodology of accelerating amortization of the excess depreciation reserve over three years. | ||||||||||||
NSP-Minnesota’s revised rate request, moderation plan, interim rate adjustments and impacts on expenses are detailed below: | |||||||||||||
(Millions of Dollars) | 2014 | Percentage | 2015 | Percentage | |||||||||
Increase | Increase | ||||||||||||
Rebuttal pre-moderation deficiency | $ | 250.6 | $ | 67.8 | |||||||||
Evidentiary hearing adjustments | (27.3 | ) | 11 | ||||||||||
Revised pre-moderation deficiency | 223.3 | 78.8 | |||||||||||
Moderation plan: | |||||||||||||
Excess depreciation reserve | (81.1 | ) | 52.9 | ||||||||||
DOE settlement proceeds | — | (25.7 | ) | ||||||||||
Revised rate request | 142.2 | 5.10% | 106 | 3.80% | |||||||||
Interim rate adjustments | (65.3 | ) | 65.3 | ||||||||||
PI EPU | 4.8 | (4.8 | ) | ||||||||||
Revenue impact (a) | 81.7 | 166.5 | |||||||||||
Excess depreciation reserve | 81.1 | (45.7 | ) | ||||||||||
Sales forecast (b) | (9.1 | ) | — | ||||||||||
DOE settlement proceeds | — | 25.7 | |||||||||||
Estimated impact of request on operating income | $ | 153.7 | $ | 146.5 | |||||||||
(a) | NSP-Minnesota’s total revenue for 2014 is capped at the interim rate level of $127 million and pre-tax operating income is capped at $208 million. This table demonstrates the impact of reducing NSP-Minnesota’s rebuttal request. | ||||||||||||
(b) | NSP-Minnesota and the DOC have agreed to a sales true-up based on weather normalized sales for 2014, using standard weather coefficients. NSP-Minnesota periodically adjusts the coefficients in periods of extreme weather conditions to enhance weather impact estimates. As a result of the difference in the two methodologies, currently, approximately $9.1 million of revenue that NSP-Minnesota attributed to weather would be considered normal sales growth using the standard weather coefficients. The refund for the full year could vary from the estimate as of Sept. 30, 2014, depending on weather conditions. | ||||||||||||
South Dakota 2015 Electric Rate Case [Table Text Block] | ' | ||||||||||||
The major components of the request are as follows: | |||||||||||||
(Millions of Dollars) | Request | ||||||||||||
Nuclear investments and operating costs | $ | 13.4 | |||||||||||
Other production, transmission and distribution | 5 | ||||||||||||
Technology improvements | 2.1 | ||||||||||||
Pension and operating and maintenance (O&M) expenses | 1.6 | ||||||||||||
Wind generation facilities | 1.4 | ||||||||||||
Capital structure | 1.1 | ||||||||||||
Incremental increase to base rates | $ | 24.6 | |||||||||||
Infrastructure rider to be included in base rates | $ | (8.4 | ) | ||||||||||
TCR rider to be included in base rates | (0.6 | ) | |||||||||||
Net request | $ | 15.6 | |||||||||||
NSP-Wisconsin 2015 Electric Rate Case [Table Text Block] | ' | ||||||||||||
(Millions of Dollars) | NSP-Wisconsin | PSCW Staff Recommendation | |||||||||||
Request | |||||||||||||
Production and transmission fixed charges | $ | 28.1 | $ | 26.4 | |||||||||
Fuel and purchased power | 13.9 | 11.1 | |||||||||||
Sub-Total | $ | 42 | $ | 37.5 | |||||||||
NSP-Minnesota transmission depreciation reserve | $ | (16.2 | ) | $ | (16.2 | ) | |||||||
Monticello EPU deferral | (5.2 | ) | (5.2 | ) | |||||||||
Total | $ | 20.6 | $ | 16.1 | |||||||||
SPS' Texas 2014 Electric Rate Case [Table Text Block] | ' | ||||||||||||
Although the parties to the settlement agreement have not prepared a calculation of the $37 million increase and do not agree about which specific costs are included, or not, in the agreed settlement revenue requirement, SPS’ reconciliation of its original request to the settlement increase is as follows: | |||||||||||||
(Millions of Dollars) | Settlement Agreement | ||||||||||||
Base rate increase request, January 2014 | $ | 81.5 | |||||||||||
Revisions for updated information | (4.6 | ) | |||||||||||
Revised request, April 2014 | 76.9 | ||||||||||||
Remove proposed increase in depreciation | (16.0 | ) | |||||||||||
Remove adjustment allocators for certain wholesale load reduction | (12.0 | ) | |||||||||||
Revised amortizations (rate case expenses, pension and other post-employment benefits expense and gain on sale to Lubbock) | (9.0 | ) | |||||||||||
Non-specified settlement adjustments | (2.9 | ) | |||||||||||
Settlement base rate increase | $ | 37 | |||||||||||
Commitments_and_Contingencies_
Commitments and Contingencies (Tables) | 9 Months Ended | ||||||||
Sep. 30, 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) | Sept. 30, 2014 | Dec. 31, 2013 | |||||||
Guarantees issued and outstanding | $ | 14.6 | $ | 19.4 | |||||
Current exposure under these guarantees | 0.2 | 0.3 | |||||||
Bonds with indemnity protection | 32.1 | 32.1 | |||||||
Borrowings_and_Other_Financing1
Borrowings and Other Financing Instruments (Tables) | 9 Months Ended | ||||||||||||
Sep. 30, 2014 | |||||||||||||
Debt Disclosure [Abstract] | ' | ||||||||||||
Short-Term Borrowings | ' | ||||||||||||
Commercial paper outstanding for Xcel Energy was as follows: | |||||||||||||
(Amounts in Millions, Except Interest Rates) | Three Months Ended | Twelve Months Ended | |||||||||||
Sept. 30, 2014 | Dec. 31, 2013 | ||||||||||||
Borrowing limit | $ | 2,450 | $ | 2,450 | |||||||||
Amount outstanding at period end | 697 | 759 | |||||||||||
Average amount outstanding | 730 | 481 | |||||||||||
Maximum amount outstanding | 894 | 1,160 | |||||||||||
Weighted average interest rate, computed on a daily basis | 0.33 | % | 0.31 | % | |||||||||
Weighted average interest rate at period end | 0.33 | 0.25 | |||||||||||
Credit Facilities | ' | ||||||||||||
At Sept. 30, 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 | $ | 436 | $ | 364 | |||||||
PSCo | 700 | 259.5 | 440.5 | ||||||||||
NSP-Minnesota | 500 | 23.9 | 476.1 | ||||||||||
SPS | 300 | 41 | 259 | ||||||||||
NSP-Wisconsin | 150 | 8 | 142 | ||||||||||
Total | $ | 2,450.00 | $ | 768.4 | $ | 1,681.60 | |||||||
(a) | These credit facilities have been amended to expire in October 2019. | ||||||||||||
(b) | Includes outstanding commercial paper and letters of credit. |
Fair_Value_of_Financial_Assets1
Fair Value of Financial Assets and Liabilities (Tables) | 9 Months Ended | ||||||||||||||||||||||||
Sep. 30, 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 Sept. 30, 2014 and Dec. 31, 2013: | |||||||||||||||||||||||||
Sept. 30, 2014 | |||||||||||||||||||||||||
Fair Value | |||||||||||||||||||||||||
(Thousands of Dollars) | Cost | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||
Nuclear decommissioning fund (a) | |||||||||||||||||||||||||
Cash equivalents | $ | 14,972 | $ | 14,972 | $ | — | $ | — | $ | 14,972 | |||||||||||||||
Commingled funds | 469,608 | — | 471,388 | — | 471,388 | ||||||||||||||||||||
International equity funds | 78,812 | — | 85,856 | — | 85,856 | ||||||||||||||||||||
Private equity investments | 74,222 | — | — | 97,004 | 97,004 | ||||||||||||||||||||
Real estate | 45,075 | — | — | 63,973 | 63,973 | ||||||||||||||||||||
Debt securities: | |||||||||||||||||||||||||
Government securities | 34,379 | — | 29,726 | — | 29,726 | ||||||||||||||||||||
U.S. corporate bonds | 80,196 | — | 79,248 | — | 79,248 | ||||||||||||||||||||
International corporate bonds | 17,696 | — | 17,613 | — | 17,613 | ||||||||||||||||||||
Municipal bonds | 235,751 | — | 240,907 | — | 240,907 | ||||||||||||||||||||
Asset-backed securities | 9,226 | — | 9,347 | — | 9,347 | ||||||||||||||||||||
Mortgage-backed securities | 23,554 | — | 23,696 | — | 23,696 | ||||||||||||||||||||
Equity securities: | |||||||||||||||||||||||||
Common stock | 377,287 | 555,711 | — | — | 555,711 | ||||||||||||||||||||
Total | $ | 1,460,778 | $ | 570,683 | $ | 957,781 | $ | 160,977 | $ | 1,689,441 | |||||||||||||||
(a) | Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $84.5 million of equity investments in unconsolidated subsidiaries and $43.0 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 and nine months ended Sept. 30, 2014 and 2013: | |||||||||||||||||||||||||
(Thousands of Dollars) | 1-Jul-14 | Purchases | Settlements | Gains Recognized as | Transfers Out of Level 3 | Sept. 30, 2014 | |||||||||||||||||||
Regulatory Liabilities | |||||||||||||||||||||||||
Private equity investments | $ | 81,123 | $ | 11,125 | $ | — | $ | 4,756 | $ | — | $ | 97,004 | |||||||||||||
Real estate | 65,658 | 1,530 | (5,876 | ) | 2,661 | — | 63,973 | ||||||||||||||||||
Total | $ | 146,781 | $ | 12,655 | $ | (5,876 | ) | $ | 7,417 | $ | — | $ | 160,977 | ||||||||||||
(Thousands of Dollars) | 1-Jul-13 | Purchases | Settlements | Gains Recognized as | Transfers Out of Level 3 | Sept. 30, 2013 | |||||||||||||||||||
Regulatory Liabilities | |||||||||||||||||||||||||
Private equity investments | $ | 45,590 | $ | 6,790 | $ | — | $ | 94 | $ | — | $ | 52,474 | |||||||||||||
Real estate | 38,140 | 11,288 | — | 1,928 | — | 51,356 | |||||||||||||||||||
Total | $ | 83,730 | $ | 18,078 | $ | — | $ | 2,022 | $ | — | $ | 103,830 | |||||||||||||
(Thousands of Dollars) | Jan. 1, 2014 | Purchases | Settlements | Gains Recognized as | Transfers Out of Level 3 | Sept. 30, 2014 | |||||||||||||||||||
Regulatory Liabilities | |||||||||||||||||||||||||
Private equity investments | $ | 62,696 | $ | 22,078 | $ | — | $ | 12,230 | $ | — | $ | 97,004 | |||||||||||||
Real estate | 57,368 | 5,386 | (5,876 | ) | 7,095 | — | 63,973 | ||||||||||||||||||
Total | $ | 120,064 | $ | 27,464 | $ | (5,876 | ) | $ | 19,325 | $ | — | $ | 160,977 | ||||||||||||
(Thousands of Dollars) | Jan. 1, 2013 | Purchases | Settlements | Gains Recognized as | Transfers Out of Level 3 (a) | Sept. 30, 2013 | |||||||||||||||||||
Regulatory Liabilities | |||||||||||||||||||||||||
Private equity investments | $ | 33,250 | $ | 15,344 | $ | — | $ | 3,880 | $ | — | $ | 52,474 | |||||||||||||
Real estate | 39,074 | 18,106 | (9,022 | ) | 3,198 | — | 51,356 | ||||||||||||||||||
Asset-backed securities | 2,067 | — | — | — | (2,067 | ) | — | ||||||||||||||||||
Mortgage-backed securities | 30,209 | — | — | — | (30,209 | ) | — | ||||||||||||||||||
Total | $ | 104,600 | $ | 33,450 | $ | (9,022 | ) | $ | 7,078 | $ | (32,276 | ) | $ | 103,830 | |||||||||||
(a) | Transfers out of Level 3 into Level 2 were principally due to diminished use of unobservable inputs that were previously significant to these fair value measurements. | ||||||||||||||||||||||||
Final Contractual Maturity Dates of Debt Securities in the Nuclear Decommissioning Fund by Asset Class | ' | ||||||||||||||||||||||||
The following table summarizes the final contractual maturity dates of the debt securities in the nuclear decommissioning fund, by asset class, at Sept. 30, 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 | $ | — | $ | — | $ | — | $ | 29,726 | $ | 29,726 | |||||||||||||||
U.S. corporate bonds | 303 | 15,878 | 62,985 | 82 | 79,248 | ||||||||||||||||||||
International corporate bonds | — | 4,266 | 13,347 | — | 17,613 | ||||||||||||||||||||
Municipal bonds | 807 | 34,188 | 41,744 | 164,168 | 240,907 | ||||||||||||||||||||
Asset-backed securities | — | — | 3,546 | 5,801 | 9,347 | ||||||||||||||||||||
Mortgage-backed securities | — | — | — | 23,696 | 23,696 | ||||||||||||||||||||
Debt securities | $ | 1,110 | $ | 54,332 | $ | 121,622 | $ | 223,473 | $ | 400,537 | |||||||||||||||
Gross Notional Amounts of Commodity Forwards, Options, and FTRs | ' | ||||||||||||||||||||||||
The following table details the gross notional amounts of commodity forwards, options and FTRs at Sept. 30, 2014 and Dec. 31, 2013: | |||||||||||||||||||||||||
(Amounts in Thousands) (a)(b) | Sept. 30, 2014 | Dec. 31, 2013 | |||||||||||||||||||||||
Megawatt hours of electricity | 74,912 | 58,423 | |||||||||||||||||||||||
Million British thermal units of natural gas | 18,482 | 9,854 | |||||||||||||||||||||||
Gallons of vehicle fuel | 332 | 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 and nine months ended Sept. 30, 2014 and 2013, on accumulated other comprehensive loss, regulatory assets and liabilities, and income: | |||||||||||||||||||||||||
Three Months Ended Sept. 30, 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 | |||||||||||||||||||||||
(Thousands of Dollars) | Accumulated Other | Regulatory | Accumulated Other | Regulatory | During the Period in Income | ||||||||||||||||||||
Comprehensive Loss | (Assets) and Liabilities | Comprehensive Loss | Assets and (Liabilities) | ||||||||||||||||||||||
Derivatives designated as cash flow hedges | |||||||||||||||||||||||||
Interest rate | $ | — | $ | — | $ | 967 | (a) | $ | — | $ | — | ||||||||||||||
Vehicle fuel and other commodity | (69 | ) | — | (16 | ) | (b) | — | — | |||||||||||||||||
Total | $ | (69 | ) | $ | — | $ | 951 | $ | — | $ | — | ||||||||||||||
Other derivative instruments | |||||||||||||||||||||||||
Commodity trading | $ | — | $ | — | $ | — | $ | — | $ | (1,656 | ) | (c) | |||||||||||||
Electric commodity | — | (3,391 | ) | — | 6,629 | (d) | — | ||||||||||||||||||
Natural gas commodity | — | (2,455 | ) | — | — | (209 | ) | (d) | |||||||||||||||||
Total | $ | — | $ | (5,846 | ) | $ | — | $ | 6,629 | $ | (1,865 | ) | |||||||||||||
Nine Months Ended Sept. 30, 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 | |||||||||||||||||||||||
(Thousands of Dollars) | Accumulated Other | Regulatory | Accumulated Other | Regulatory | During the Period in Income | ||||||||||||||||||||
Comprehensive Loss | (Assets) and Liabilities | Comprehensive Loss | Assets and (Liabilities) | ||||||||||||||||||||||
Derivatives designated as cash flow hedges | |||||||||||||||||||||||||
Interest rate | $ | — | $ | — | $ | 2,869 | (a) | $ | — | $ | — | ||||||||||||||
Vehicle fuel and other commodity | (56 | ) | — | (61 | ) | (b) | — | — | |||||||||||||||||
Total | $ | (56 | ) | $ | — | $ | 2,808 | $ | — | $ | — | ||||||||||||||
Other derivative instruments | |||||||||||||||||||||||||
Commodity trading | $ | — | $ | — | $ | — | $ | — | $ | 1,266 | (c) | ||||||||||||||
Electric commodity | — | (17,240 | ) | — | (18,641 | ) | (d) | — | |||||||||||||||||
Natural gas commodity | — | 13,603 | — | (18,840 | ) | (e) | (5,575 | ) | (e) | ||||||||||||||||
Other commodity | — | — | — | — | 643 | (c) | |||||||||||||||||||
Total | $ | — | $ | (3,637 | ) | $ | — | $ | (37,481 | ) | $ | (3,666 | ) | ||||||||||||
Three Months Ended Sept. 30, 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 Recognized | |||||||||||||||||||||||
(Thousands of Dollars) | Accumulated Other | Regulatory | Accumulated Other | Regulatory | During the Period in Income | ||||||||||||||||||||
Comprehensive Loss | (Assets) and Liabilities | Comprehensive Loss | Assets and (Liabilities) | ||||||||||||||||||||||
Derivatives designated as cash flow hedges | |||||||||||||||||||||||||
Interest rate | $ | — | $ | — | $ | 829 | (a) | $ | — | $ | — | ||||||||||||||
Vehicle fuel and other commodity | 36 | — | (24 | ) | (b) | — | — | ||||||||||||||||||
Total | $ | 36 | $ | — | $ | 805 | $ | — | $ | — | |||||||||||||||
Other derivative instruments | |||||||||||||||||||||||||
Commodity trading | $ | — | $ | — | $ | — | $ | — | $ | 7,094 | (c) | ||||||||||||||
Electric commodity | — | 921 | — | (9,823 | ) | (d) | — | ||||||||||||||||||
Natural gas commodity | — | (1,967 | ) | — | — | 12 | (d) | ||||||||||||||||||
Total | $ | — | $ | (1,046 | ) | $ | — | $ | (9,823 | ) | $ | 7,106 | |||||||||||||
Nine Months Ended Sept. 30, 2013 | |||||||||||||||||||||||||
Pre-Tax Fair Value Gains (Losses) Recognized During the Period in: | Pre-Tax (Gains) Losses Reclassified into Income During the Period from: | Pre-Tax Gains (Losses) Recognized | |||||||||||||||||||||||
(Thousands of Dollars) | Accumulated Other | Regulatory | Accumulated Other | Regulatory | During the Period in Income | ||||||||||||||||||||
Comprehensive Loss | (Assets) and Liabilities | Comprehensive Loss | Assets and (Liabilities) | ||||||||||||||||||||||
Derivatives designated as cash flow hedges | |||||||||||||||||||||||||
Interest rate | $ | — | $ | — | $ | 3,140 | (a) | $ | — | $ | — | ||||||||||||||
Vehicle fuel and other commodity | (11 | ) | — | (67 | ) | (b) | — | — | |||||||||||||||||
Total | $ | (11 | ) | $ | — | $ | 3,073 | $ | — | $ | — | ||||||||||||||
Other derivative instruments | |||||||||||||||||||||||||
Commodity trading | $ | — | $ | — | $ | — | $ | — | $ | 9,372 | (c) | ||||||||||||||
Electric commodity | — | 61,314 | — | (38,816 | ) | (d) | — | ||||||||||||||||||
Natural gas commodity | — | (5,341 | ) | — | 9 | (e) | (216 | ) | (d) | ||||||||||||||||
Total | $ | — | $ | 55,973 | $ | — | $ | (38,807 | ) | $ | 9,156 | ||||||||||||||
(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 nine months ended Sept. 30, 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 nine months ended Sept. 30, 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 Sept. 30, 2014: | |||||||||||||||||||||||||
Sept. 30, 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 | $ | — | $ | 4 | $ | — | $ | 4 | $ | (3 | ) | $ | 1 | ||||||||||||
Other derivative instruments: | |||||||||||||||||||||||||
Commodity trading | — | 18,912 | 4,609 | 23,521 | (5,395 | ) | 18,126 | ||||||||||||||||||
Electric commodity | — | — | 86,708 | 86,708 | (17,685 | ) | 69,023 | ||||||||||||||||||
Natural gas commodity | — | 10,051 | — | 10,051 | (74 | ) | 9,977 | ||||||||||||||||||
Total current derivative assets | $ | — | $ | 28,967 | $ | 91,317 | $ | 120,284 | $ | (23,157 | ) | 97,127 | |||||||||||||
PPAs (a) | 23,527 | ||||||||||||||||||||||||
Current derivative instruments | $ | 120,654 | |||||||||||||||||||||||
Noncurrent derivative assets | |||||||||||||||||||||||||
Derivatives designated as cash flow hedges: | |||||||||||||||||||||||||
Other derivative instruments: | |||||||||||||||||||||||||
Commodity trading | $ | — | $ | 13,269 | $ | — | $ | 13,269 | $ | (2,408 | ) | $ | 10,861 | ||||||||||||
Total noncurrent derivative assets | $ | — | $ | 13,269 | $ | — | $ | 13,269 | $ | (2,408 | ) | 10,861 | |||||||||||||
PPAs (a) | 42,716 | ||||||||||||||||||||||||
Noncurrent derivative instruments | $ | 53,577 | |||||||||||||||||||||||
Current derivative liabilities | |||||||||||||||||||||||||
Derivatives designated as cash flow hedges: | |||||||||||||||||||||||||
Vehicle fuel and other commodity | $ | — | $ | 3 | $ | — | $ | 3 | $ | (3 | ) | $ | — | ||||||||||||
Other derivative instruments: | |||||||||||||||||||||||||
Commodity trading | — | 9,759 | — | 9,759 | (9,337 | ) | 422 | ||||||||||||||||||
Electric commodity | — | — | 17,685 | 17,685 | (17,685 | ) | — | ||||||||||||||||||
Natural gas commodity | — | 74 | — | 74 | (74 | ) | — | ||||||||||||||||||
Total current derivative liabilities | $ | — | $ | 9,836 | $ | 17,685 | $ | 27,521 | $ | (27,099 | ) | 422 | |||||||||||||
PPAs (a) | 22,502 | ||||||||||||||||||||||||
Current derivative instruments | $ | 22,924 | |||||||||||||||||||||||
Noncurrent derivative liabilities | |||||||||||||||||||||||||
Derivatives designated as cash flow hedges: | |||||||||||||||||||||||||
Vehicle fuel and other commodity | $ | — | $ | 5 | $ | — | $ | 5 | $ | — | $ | 5 | |||||||||||||
Other derivative instruments: | |||||||||||||||||||||||||
Commodity trading | — | 3,066 | — | 3,066 | (2,408 | ) | 658 | ||||||||||||||||||
Natural gas commodity | — | 71 | — | 71 | — | 71 | |||||||||||||||||||
Total noncurrent derivative liabilities | $ | — | $ | 3,142 | $ | — | $ | 3,142 | $ | (2,408 | ) | 734 | |||||||||||||
PPAs (a) | 186,711 | ||||||||||||||||||||||||
Noncurrent derivative instruments | $ | 187,445 | |||||||||||||||||||||||
(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 Sept. 30, 2014. At Sept. 30, 2014, derivative assets and liabilities include no obligations to return cash collateral and the rights to reclaim cash collateral of $3.9 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 the 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 and nine months ended Sept. 30, 2014 and 2013: | |||||||||||||||||||||||||
Three Months Ended Sept. 30 | |||||||||||||||||||||||||
(Thousands of Dollars) | 2014 | 2013 | |||||||||||||||||||||||
Balance at July 1 | $ | 105,394 | $ | 47,218 | |||||||||||||||||||||
Purchases | 5,588 | 155 | |||||||||||||||||||||||
Settlements | (20,032 | ) | (9,342 | ) | |||||||||||||||||||||
Transfers out of Level 3 | (1,093 | ) | — | ||||||||||||||||||||||
Net transactions recorded during the period: | |||||||||||||||||||||||||
Gains recognized in earnings (a) | 1,480 | 4,008 | |||||||||||||||||||||||
Losses recognized as regulatory assets and liabilities | (17,705 | ) | (571 | ) | |||||||||||||||||||||
Balance at Sept. 30 | $ | 73,632 | $ | 41,468 | |||||||||||||||||||||
Nine Months Ended Sept. 30 | |||||||||||||||||||||||||
(Thousands of Dollars) | 2014 | 2013 | |||||||||||||||||||||||
Balance at Jan. 1 | $ | 41,660 | $ | 16,649 | |||||||||||||||||||||
Purchases | 126,752 | 51,541 | |||||||||||||||||||||||
Settlements | (107,451 | ) | (30,294 | ) | |||||||||||||||||||||
Transfers out of Level 3 | (1,093 | ) | — | ||||||||||||||||||||||
Net transactions recorded during the period: | |||||||||||||||||||||||||
Gains recognized in earnings (a) | 8,917 | 3,729 | |||||||||||||||||||||||
Gains (losses) recognized as regulatory assets and liabilities | 4,847 | (157 | ) | ||||||||||||||||||||||
Balance at Sept. 30 | $ | 73,632 | $ | 41,468 | |||||||||||||||||||||
(a) | These amounts relate to commodity derivatives held at the end of the period. | ||||||||||||||||||||||||
Carrying Amount and Fair Value of Long-term Debt | ' | ||||||||||||||||||||||||
As of Sept. 30, 2014 and Dec. 31, 2013, other financial instruments for which the carrying amount did not equal fair value were as follows: | |||||||||||||||||||||||||
Sept. 30, 2014 | Dec. 31, 2013 | ||||||||||||||||||||||||
(Thousands of Dollars) | Carrying Amount | Fair Value | Carrying Amount | Fair Value | |||||||||||||||||||||
Long-term debt, including current portion | $ | 11,759,226 | $ | 12,990,348 | $ | 11,191,517 | $ | 11,878,643 | |||||||||||||||||
Other_Income_Expense_Net_Table
Other Income (Expense), Net (Tables) | 9 Months Ended | ||||||||||||||||
Sep. 30, 2014 | |||||||||||||||||
Other Income and Expenses [Abstract] | ' | ||||||||||||||||
Other Income (Expense), Net | ' | ||||||||||||||||
Other income (expense), net consisted of the following: | |||||||||||||||||
Three Months Ended Sept. 30 | Nine Months Ended Sept. 30 | ||||||||||||||||
(Thousands of Dollars) | 2014 | 2013 | 2014 | 2013 | |||||||||||||
Interest income | $ | 1,139 | $ | 1,304 | $ | 6,324 | $ | 7,615 | |||||||||
Other nonoperating income | 682 | 739 | 3,042 | 2,494 | |||||||||||||
Insurance policy expense | (417 | ) | (2,386 | ) | (4,663 | ) | (5,932 | ) | |||||||||
Other nonoperating expense | — | (61 | ) | (16 | ) | (246 | ) | ||||||||||
Other income (expense), net | $ | 1,404 | $ | (404 | ) | $ | 4,687 | $ | 3,931 | ||||||||
Segment_Information_Tables
Segment Information (Tables) | 9 Months Ended | ||||||||||||||||||||
Sep. 30, 2014 | |||||||||||||||||||||
Segment Reporting [Abstract] | ' | ||||||||||||||||||||
Results by Reportable Segment | ' | ||||||||||||||||||||
(Thousands of Dollars) | Regulated Electric | Regulated Natural Gas | All Other | Reconciling Eliminations | Consolidated Total | ||||||||||||||||
Three Months Ended Sept. 30, 2014 | |||||||||||||||||||||
Operating revenues from external customers | $ | 2,616,351 | $ | 236,649 | $ | 16,807 | $ | — | $ | 2,869,807 | |||||||||||
Intersegment revenues | 472 | 597 | — | (1,069 | ) | — | |||||||||||||||
Total revenues | $ | 2,616,823 | $ | 237,246 | $ | 16,807 | $ | (1,069 | ) | $ | 2,869,807 | ||||||||||
Net income | $ | 360,656 | $ | 3,996 | $ | 3,930 | $ | — | $ | 368,582 | |||||||||||
(Thousands of Dollars) | Regulated Electric | Regulated Natural Gas | All Other | Reconciling Eliminations | Consolidated Total | ||||||||||||||||
Three Months Ended Sept. 30, 2013 | |||||||||||||||||||||
Operating revenues from external customers | $ | 2,599,925 | $ | 205,358 | $ | 17,055 | $ | — | $ | 2,822,338 | |||||||||||
Intersegment revenues | 346 | 1,106 | — | (1,452 | ) | — | |||||||||||||||
Total revenues | $ | 2,600,271 | $ | 206,464 | $ | 17,055 | $ | (1,452 | ) | $ | 2,822,338 | ||||||||||
Net income (loss) | $ | 365,156 | $ | (174 | ) | $ | (230 | ) | $ | — | $ | 364,752 | |||||||||
(Thousands of Dollars) | Regulated Electric | Regulated Natural Gas | All Other | Reconciling Eliminations | Consolidated Total | ||||||||||||||||
Nine Months Ended Sept. 30, 2014 | |||||||||||||||||||||
Operating revenues from external customers | $ | 7,215,699 | $ | 1,485,464 | $ | 56,344 | $ | — | $ | 8,757,507 | |||||||||||
Intersegment revenues | 1,262 | 4,967 | — | (6,229 | ) | — | |||||||||||||||
Total revenues | $ | 7,216,961 | $ | 1,490,431 | $ | 56,344 | $ | (6,229 | ) | $ | 8,757,507 | ||||||||||
Net income (loss) | $ | 731,766 | $ | 96,629 | $ | (3,428 | ) | $ | — | $ | 824,967 | ||||||||||
(Thousands of Dollars) | Regulated Electric | Regulated Natural Gas | All Other | Reconciling Eliminations | Consolidated Total | ||||||||||||||||
Nine Months Ended Sept. 30, 2013 | |||||||||||||||||||||
Operating revenues from external customers | $ | 6,911,998 | $ | 1,216,275 | $ | 55,827 | $ | — | $ | 8,184,100 | |||||||||||
Intersegment revenues | 955 | 2,163 | — | (3,118 | ) | — | |||||||||||||||
Total revenues | $ | 6,912,953 | $ | 1,218,438 | $ | 55,827 | $ | (3,118 | ) | $ | 8,184,100 | ||||||||||
Net income (loss) | $ | 740,347 | $ | 80,698 | $ | (22,866 | ) | $ | — | $ | 798,179 | ||||||||||
Earnings_Per_Share_Tables
Earnings Per Share (Tables) | 9 Months Ended | ||||||||||||||||||||||
Sep. 30, 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 Sept. 30, 2014 | Three Months Ended Sept. 30, 2013 | ||||||||||||||||||||||
(Amounts in thousands, except per share data) | Income | Shares | Per Share | Income | Shares | Per Share | |||||||||||||||||
Amount | Amount | ||||||||||||||||||||||
Net income | $ | 368,582 | $ | 364,752 | |||||||||||||||||||
Basic EPS: | |||||||||||||||||||||||
Earnings available to common shareholders | 368,582 | 506,082 | $ | 0.73 | 364,752 | 498,149 | $ | 0.73 | |||||||||||||||
Effect of dilutive securities: | |||||||||||||||||||||||
Time based equity awards | — | 283 | — | 492 | |||||||||||||||||||
Diluted EPS: | |||||||||||||||||||||||
Earnings available to common shareholders | $ | 368,582 | 506,365 | $ | 0.73 | $ | 364,752 | 498,641 | $ | 0.73 | |||||||||||||
Nine Months Ended Sept. 30, 2014 | Nine Months Ended Sept. 30, 2013 | ||||||||||||||||||||||
(Amounts in thousands, except per share data) | Income | Shares | Per Share | Income | Shares | Per Share | |||||||||||||||||
Amount | Amount | ||||||||||||||||||||||
Net income | $ | 824,967 | $ | 798,179 | |||||||||||||||||||
Basic EPS: | |||||||||||||||||||||||
Earnings available to common shareholders | 824,967 | 502,983 | $ | 1.64 | 798,179 | 495,256 | $ | 1.61 | |||||||||||||||
Effect of dilutive securities: | |||||||||||||||||||||||
Time based equity awards | — | 230 | — | 511 | |||||||||||||||||||
Diluted EPS: | |||||||||||||||||||||||
Earnings available to common shareholders | $ | 824,967 | 503,213 | $ | 1.64 | $ | 798,179 | 495,767 | $ | 1.61 | |||||||||||||
Benefit_Plans_and_Other_Postre1
Benefit Plans and Other Postretirement Benefits (Tables) | 9 Months Ended | ||||||||||||||||
Sep. 30, 2014 | |||||||||||||||||
Compensation and Retirement Disclosure [Abstract] | ' | ||||||||||||||||
Components of Net Periodic Benefit Cost | ' | ||||||||||||||||
Components of Net Periodic Benefit Cost | |||||||||||||||||
Three Months Ended Sept. 30 | |||||||||||||||||
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 | 35,173 | 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 | 47,137 | 1,145 | 4,760 | |||||||||||||
Costs not recognized due to the effects of regulation | (6,605 | ) | (12,986 | ) | — | — | |||||||||||
Net benefit cost recognized for financial reporting | $ | 31,589 | $ | 34,151 | $ | 1,145 | $ | 4,760 | |||||||||
Nine Months Ended Sept. 30 | |||||||||||||||||
2014 | 2013 | 2014 | 2013 | ||||||||||||||
(Thousands of Dollars) | Pension Benefits | Postretirement Health | |||||||||||||||
Care Benefits | |||||||||||||||||
Service cost | $ | 66,257 | $ | 72,212 | $ | 2,592 | $ | 3,546 | |||||||||
Interest cost | 117,465 | 105,518 | 25,521 | 25,251 | |||||||||||||
Expected return on plan assets | (155,403 | ) | (148,839 | ) | (25,466 | ) | (24,759 | ) | |||||||||
Amortization of transition obligation | — | — | — | 618 | |||||||||||||
Amortization of prior service (credit) cost | (1,310 | ) | 4,404 | (8,016 | ) | (7,314 | ) | ||||||||||
Amortization of net loss | 87,572 | 108,114 | 8,805 | 16,938 | |||||||||||||
Net periodic benefit cost | 114,581 | 141,409 | 3,436 | 14,280 | |||||||||||||
Costs not recognized due to the effects of regulation | (20,261 | ) | (27,922 | ) | — | — | |||||||||||
Net benefit cost recognized for financial reporting | $ | 94,320 | $ | 113,487 | $ | 3,436 | $ | 14,280 | |||||||||
Other_Comprehensive_Income_Tab
Other Comprehensive Income (Tables) | 9 Months Ended | ||||||||||||||||
Sep. 30, 2014 | |||||||||||||||||
Stockholders' Equity Note [Abstract] | ' | ||||||||||||||||
Changes in Accumulated Other Comprehensive Income (Loss), Net of Tax | ' | ||||||||||||||||
Changes in accumulated other comprehensive income (loss), net of tax, for the three and nine months ended Sept. 30, 2014 and 2013 were as follows: | |||||||||||||||||
Three Months Ended Sept. 30, 2014 | |||||||||||||||||
(Thousands of Dollars) | Gains and Losses | Unrealized Gains and Losses | Defined Benefit Pension and | Total | |||||||||||||
on Cash Flow Hedges | on Marketable Securities | Postretirement Items | |||||||||||||||
Accumulated other comprehensive (loss) income at July 1 | $ | (58,610 | ) | $ | 115 | $ | (44,871 | ) | $ | (103,366 | ) | ||||||
Other comprehensive (loss) income before reclassifications | (42 | ) | 2 | — | (40 | ) | |||||||||||
Losses reclassified from net accumulated other comprehensive loss | 558 | — | 847 | 1,405 | |||||||||||||
Net current period other comprehensive income | 516 | 2 | 847 | 1,365 | |||||||||||||
Accumulated other comprehensive (loss) income at Sept. 30 | $ | (58,094 | ) | $ | 117 | $ | (44,024 | ) | $ | (102,001 | ) | ||||||
Three Months Ended Sept. 30, 2013 | |||||||||||||||||
(Thousands of Dollars) | Gains and Losses | Unrealized Gains and Losses | Defined Benefit Pension and | Total | |||||||||||||
on Cash Flow Hedges | on Marketable Securities | Postretirement Items | |||||||||||||||
Accumulated other comprehensive loss at July 1 | $ | (60,883 | ) | $ | (135 | ) | $ | (50,817 | ) | $ | (111,835 | ) | |||||
Other comprehensive income before reclassifications | 22 | 115 | — | 137 | |||||||||||||
Losses reclassified from net accumulated other comprehensive loss | 539 | — | 1,179 | 1,718 | |||||||||||||
Net current period other comprehensive income | 561 | 115 | 1,179 | 1,855 | |||||||||||||
Accumulated other comprehensive loss at Sept. 30 | $ | (60,322 | ) | $ | (20 | ) | $ | (49,638 | ) | $ | (109,980 | ) | |||||
Nine Months Ended Sept. 30, 2014 | |||||||||||||||||
(Thousands of Dollars) | Gains and Losses | Unrealized Gains and Losses | Defined Benefit Pension and | Total | |||||||||||||
on Cash Flow Hedges | on Marketable Securities | Postretirement Items | |||||||||||||||
Accumulated other comprehensive (loss) income at Jan. 1 | $ | (59,753 | ) | $ | 77 | $ | (46,599 | ) | $ | (106,275 | ) | ||||||
Other comprehensive (loss) income before reclassifications | (34 | ) | 40 | — | 6 | ||||||||||||
Losses reclassified from net accumulated other comprehensive loss | 1,693 | — | 2,575 | 4,268 | |||||||||||||
Net current period other comprehensive income | 1,659 | 40 | 2,575 | 4,274 | |||||||||||||
Accumulated other comprehensive (loss) income at Sept. 30 | $ | (58,094 | ) | $ | 117 | $ | (44,024 | ) | $ | (102,001 | ) | ||||||
Nine Months Ended Sept. 30, 2013 | |||||||||||||||||
(Thousands of Dollars) | Gains and Losses | Unrealized Gains and Losses | Defined Benefit Pension and | Total | |||||||||||||
on Cash Flow Hedges | on Marketable Securities | Postretirement Items | |||||||||||||||
Accumulated other comprehensive loss at Jan. 1 | $ | (61,241 | ) | $ | (99 | ) | $ | (51,313 | ) | $ | (112,653 | ) | |||||
Other comprehensive (loss) income before reclassifications | (9 | ) | 79 | — | 70 | ||||||||||||
Losses reclassified from net accumulated other comprehensive loss | 928 | — | 1,675 | 2,603 | |||||||||||||
Net current period other comprehensive income | 919 | 79 | 1,675 | 2,673 | |||||||||||||
Accumulated other comprehensive loss at Sept. 30 | $ | (60,322 | ) | $ | (20 | ) | $ | (49,638 | ) | $ | (109,980 | ) | |||||
Reclassifications out of Accumulated Other Comprehensive Loss | ' | ||||||||||||||||
Reclassifications from accumulated other comprehensive loss for the three and nine months ended Sept. 30, 2014 and 2013 were as follows: | |||||||||||||||||
Amounts Reclassified from Accumulated | |||||||||||||||||
Other Comprehensive Loss | |||||||||||||||||
(Thousands of Dollars) | Three Months Ended Sept. 30, 2014 | Three Months Ended Sept. 30, 2013 | |||||||||||||||
(Gains) losses on cash flow hedges: | |||||||||||||||||
Interest rate derivatives | $ | 967 | (a) | $ | 829 | (a) | |||||||||||
Vehicle fuel derivatives | (16 | ) | (b) | (24 | ) | (b) | |||||||||||
Total, pre-tax | 951 | 805 | |||||||||||||||
Tax benefit | (393 | ) | (266 | ) | |||||||||||||
Total, net of tax | 558 | 539 | |||||||||||||||
Defined benefit pension and postretirement (gains) losses: | |||||||||||||||||
Amortization of net loss | 1,500 | (c) | 1,770 | (c) | |||||||||||||
Prior service (credit) cost | (86 | ) | (c) | 93 | (c) | ||||||||||||
Transition obligation | — | (c) | 2 | (c) | |||||||||||||
Total, pre-tax | 1,414 | 1,865 | |||||||||||||||
Tax benefit | (567 | ) | (686 | ) | |||||||||||||
Total, net of tax | 847 | 1,179 | |||||||||||||||
Total amounts reclassified, net of tax | $ | 1,405 | $ | 1,718 | |||||||||||||
Amounts Reclassified from Accumulated | |||||||||||||||||
Other Comprehensive Loss | |||||||||||||||||
(Thousands of Dollars) | Nine Months Ended Sept. 30, 2014 | Nine Months Ended Sept. 30, 2013 | |||||||||||||||
(Gains) losses on cash flow hedges: | |||||||||||||||||
Interest rate derivatives | $ | 2,869 | (a) | $ | 3,140 | (a) | |||||||||||
Vehicle fuel derivatives | (61 | ) | (b) | (67 | ) | (b) | |||||||||||
Total, pre-tax | 2,808 | 3,073 | |||||||||||||||
Tax benefit | (1,115 | ) | (2,145 | ) | |||||||||||||
Total, net of tax | 1,693 | 928 | |||||||||||||||
Defined benefit pension and postretirement (gains) losses: | |||||||||||||||||
Amortization of net loss | 4,499 | (c) | 5,308 | (c) | |||||||||||||
Prior service (credit) cost | (258 | ) | (c) | 279 | (c) | ||||||||||||
Transition obligation | — | (c) | 6 | (c) | |||||||||||||
Total, pre-tax | 4,241 | 5,593 | |||||||||||||||
Tax benefit | (1,666 | ) | (3,918 | ) | |||||||||||||
Total, net of tax | 2,575 | 1,675 | |||||||||||||||
Total amounts reclassified, net of tax | $ | 4,268 | $ | 2,603 | |||||||||||||
(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 $) | Sep. 30, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Accounts receivable, net | ' | ' |
Accounts receivable | $814,967 | $797,267 |
Less allowance for bad debts | -54,754 | -53,107 |
Accounts receivable, net | $760,213 | $744,160 |
Selected_Balance_Sheet_Data_Ba
Selected Balance Sheet Data Balance Sheet Related Disclosures, Inventories (Details) (USD $) | Sep. 30, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Public Utilities, Inventory [Line Items] | ' | ' |
Inventories | $634,262 | $576,538 |
Materials and supplies | ' | ' |
Public Utilities, Inventory [Line Items] | ' | ' |
Inventories | 240,384 | 225,308 |
Fuel | ' | ' |
Public Utilities, Inventory [Line Items] | ' | ' |
Inventories | 193,951 | 189,485 |
Natural gas | ' | ' |
Public Utilities, Inventory [Line Items] | ' | ' |
Inventories | $199,927 | $161,745 |
Selected_Balance_Sheet_Data_Ba1
Selected Balance Sheet Data Balance Sheet Related Disclosures, Property, Plant and Equipment (Details) (USD $) | Sep. 30, 2014 | Dec. 31, 2013 | ||
In Thousands, unless otherwise specified | ||||
Public Utility, Property, Plant and Equipment [Line Items] | ' | ' | ||
Property, plant and equipment, gross | $40,343,407 | $38,386,353 | ||
Less accumulated depreciation | -13,028,218 | -12,608,305 | ||
Property, plant and equipment, net | 27,630,363 | 26,122,159 | ||
Electric plant | ' | ' | ||
Public Utility, Property, Plant and Equipment [Line Items] | ' | ' | ||
Property, plant and equipment, gross | 32,122,904 | 30,341,310 | ||
Natural gas plant | ' | ' | ||
Public Utility, Property, Plant and Equipment [Line Items] | ' | ' | ||
Property, plant and equipment, gross | 4,294,667 | 4,086,651 | ||
Common and other property | ' | ' | ||
Public Utility, Property, Plant and Equipment [Line Items] | ' | ' | ||
Property, plant and equipment, gross | 1,483,063 | 1,485,547 | ||
Plant to be retired | ' | ' | ||
Public Utility, Property, Plant and Equipment [Line Items] | ' | ' | ||
Property, plant and equipment, gross | 77,922 | [1] | 101,279 | [1] |
Construction work in progress | ' | ' | ||
Public Utility, Property, Plant and Equipment [Line Items] | ' | ' | ||
Property, plant and equipment, gross | 2,364,851 | 2,371,566 | ||
Nuclear fuel | ' | ' | ||
Public Utility, Property, Plant and Equipment [Line Items] | ' | ' | ||
Property, plant and equipment, gross | 2,250,140 | 2,186,799 | ||
Less accumulated depreciation | ($1,934,966) | ($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 $) | 9 Months Ended | 12 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | ||||
Sep. 30, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Sep. 30, 2012 | Sep. 30, 2014 | Sep. 30, 2014 | Sep. 30, 2014 | Sep. 30, 2014 | Mar. 31, 2014 | Sep. 30, 2014 | |
Internal Revenue Service (IRS) | Internal Revenue Service (IRS) | Colorado | Minnesota | Texas | Wisconsin | 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) | ' | ' | ' | ' | ' | ' | ' |
Year(s) no longer subject to audit as statute of limitations has expired | ' | ' | ' | ' | '2008 | ' | ' | ' | ' | ' |
Earliest year subject to examination | ' | ' | ' | ' | '2009 | '2009 | '2009 | '2009 | ' | '2010 |
Year(s) under examination | ' | ' | ' | '2010 and 2011 | ' | ' | ' | ' | ' | ' |
Year of carryback claim under examination | ' | ' | ' | '2009 | ' | ' | ' | ' | ' | ' |
Potential Tax Adjustments | ' | ' | ' | ' | 10,000,000 | ' | ' | ' | ' | ' |
Tax year(s) for which income tax examination has been completed | ' | ' | ' | ' | ' | ' | ' | ' | '2009 through 2011 | ' |
Unrecognized Tax Benefits [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Unrecognized tax benefit — Permanent tax positions | 7,500,000 | 12,900,000 | ' | ' | ' | ' | ' | ' | ' | ' |
Unrecognized tax benefit — Temporary tax positions | 32,900,000 | 28,300,000 | ' | ' | ' | ' | ' | ' | ' | ' |
Total unrecognized tax benefit | 40,400,000 | 41,200,000 | ' | ' | ' | ' | ' | ' | ' | ' |
NOL and tax credit carryforwards | -28,100,000 | -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) (NSP-Minnesota, USD $) | 1 Months Ended | 9 Months Ended | 1 Months Ended | 9 Months Ended | 1 Months Ended | 9 Months Ended | 1 Months Ended | 9 Months Ended | 1 Months Ended | 9 Months Ended | 1 Months Ended | 9 Months Ended | 1 Months Ended | ||||||||||||||||||||
Dec. 31, 2013 | Nov. 30, 2013 | Sep. 30, 2014 | Oct. 31, 2013 | Sep. 30, 2014 | Aug. 31, 2014 | Jul. 31, 2014 | Nov. 30, 2013 | Sep. 30, 2014 | Aug. 31, 2014 | Jul. 31, 2014 | Nov. 30, 2013 | Sep. 30, 2014 | Jan. 31, 2014 | Nov. 30, 2013 | Aug. 31, 2014 | Jun. 30, 2014 | Dec. 31, 2013 | Aug. 31, 2014 | Jul. 31, 2014 | Aug. 31, 2014 | Jul. 31, 2014 | Aug. 31, 2014 | Jun. 30, 2014 | Aug. 31, 2014 | Oct. 31, 2014 | Sep. 30, 2014 | Sep. 30, 2014 | Aug. 31, 2014 | Sep. 30, 2014 | Sep. 30, 2014 | Aug. 31, 2014 | ||
MPUC Proceeding - Minnesota Electric Rate Case 2014 | MPUC Proceeding - Minnesota Electric Rate Case 2014 | MPUC Proceeding - Minnesota Electric Rate Case 2014 | MPUC Proceeding - Nuclear Project Prudency Investigation | MPUC Proceeding - Nuclear Project Prudency Investigation | MPUC Proceeding - Minnesota Electric Rate Case 2014, Rates 2014 [Member] | MPUC Proceeding - Minnesota Electric Rate Case 2014, Rates 2014 [Member] | MPUC Proceeding - Minnesota Electric Rate Case 2014, Rates 2014 [Member] | MPUC Proceeding - Minnesota Electric Rate Case 2014, Rates 2014 [Member] | MPUC Proceeding - Minnesota Electric Rate Case 2014, Rates 2015 [Member] | MPUC Proceeding - Minnesota Electric Rate Case 2014, Rates 2015 [Member] | MPUC Proceeding - Minnesota Electric Rate Case 2014, Rates 2015 [Member] | MPUC Proceeding - Minnesota Electric Rate Case 2014, Rates 2015 [Member] | FERC Proceeding, MISO ROE Complaint [Member] | FERC Proceeding, MISO ROE Complaint [Member] | MPUC Proceeding - Minnesota Gas Utility Infrastructure Cost Rider 2015 [Member] | SDPUC Proceeding - South Dakota Electric Rate Case 2015 | Minnesota Public Utilities Commission [Member] | Minnesota Department of Commerce [Member] | Minnesota Department of Commerce [Member] | Minnesota Department of Commerce [Member] | Minnesota Department of Commerce [Member] | Minnesota Department of Commerce [Member] | Federal Energy Regulatory Commission (FERC) | Office of Attorney General (OAG) [Member] | Subsequent Event | Minimum | Minimum | Minimum | Maximum | Maximum | Maximum | ||
MPUC Proceeding - Minnesota Electric Rate Case 2014 | MPUC Proceeding - Minnesota Electric Rate Case 2014 | MPUC Proceeding - Nuclear Project Prudency Investigation | MPUC Proceeding - Minnesota Electric Rate Case 2014, Rates 2014 [Member] | MPUC Proceeding - Minnesota Electric Rate Case 2014, Rates 2014 [Member] | MPUC Proceeding - Minnesota Electric Rate Case 2014, Rates 2015 [Member] | FERC Proceeding, MISO ROE Complaint [Member] | MPUC Proceeding - Nuclear Project Prudency Investigation | Minnesota Department of Commerce [Member] | MPUC Proceeding - Nuclear Project Prudency Investigation | FERC Proceeding, MISO ROE Complaint [Member] | Minnesota Department of Commerce [Member] | MPUC Proceeding - Nuclear Project Prudency Investigation | FERC Proceeding, MISO ROE Complaint [Member] | Minnesota Department of Commerce [Member] | |||||||||||||||||||
MW | MPUC Proceeding - Minnesota Gas Utility Infrastructure Cost Rider 2015 [Member] | MW | MPUC Proceeding - Minnesota Electric Rate Case 2014 | MW | MPUC Proceeding - Minnesota Electric Rate Case 2014 | ||||||||||||||||||||||||||||
Public Utilities, General Disclosures [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Public Utilities, number of years rate case is applicable for | ' | '2 years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Public Utility, Deferred sewer separation costs | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $4,800,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Number of years cost deferral is amortized | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 'five | ' | ' | ' | ' | ' | ' | |
Public Utilities, ROE applicable to transmission formula rates in the MISO region, upper bound | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 12.38% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Public Utilities, Adjustment to requested rate increase (decrease) requested by third parties related to an increase to sales forecast | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -43,200,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Public Utilities, Adjustment requested by public utility to rate increase (decrease) related to an increase to sales forecast | ' | ' | ' | ' | ' | -15,800,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Public Utilities, Adjustment to requested rate increase (decrease) recommended by third parties related to a lower return on equity | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -36,200,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Public Utilities, Adjustment to requested rate increase (decrease) recommended by public utility related to a lower return on equity | ' | ' | ' | ' | ' | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Public Utilities, Adjustment to requested rate increase (decrease) recommended by third parties related to health care, pension and other benefits | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -11,400,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Public Utilities, Adjustment to requested rate increase (decrease) recommended by public utility related to health care, pension and other benefits | ' | ' | ' | ' | ' | -1,900,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Public Utilities, Adjustment to requested rate increase (decrease) recommended by third parties related to property taxes | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -9,000,000 | ' | -9,000,000 | ' | -3,300,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Property tax forecast | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 141,000,000 | ' | ' | 145,000,000 | |
Amount of public utility's amended requested rate increase (decrease) with regulatory agency, unadjusted. | ' | ' | ' | ' | ' | 142,200,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Public Utilities, Adjustment to requested rate increase (decrease) recommended by public utility, property taxes true up. | ' | ' | ' | ' | ' | 3,900,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Public Utilities, Adjustment to requested rate increase (decrease) recommended by public utility related to property taxes | ' | ' | ' | ' | ' | -9,000,000 | ' | ' | ' | -3,300,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Public Utilities, Adjustment to requested rate increase (decrease) recommended by third parties related to PTCs moving to base rates | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -11,100,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Public Utilities, Adjustment to requested rate increase (decrease) recommended by public utility related to PTCs moving to base rates | ' | ' | ' | ' | ' | ' | ' | ' | ' | -11,100,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Public Utilities, Adjustment to requested rate increase (decrease) recommended by third parties related to DOE settlement proceeds | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10,100,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Public Utilities, Adjustment to requested rate increase (decrease) recommended by public utility related to DOE settlement proceeds | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10,100,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Public Utilities, Adjustment to requested rate increase (decrease) recommended by third parties related to emission chemicals | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -1,600,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Public Utilities, Adjustment to requested rate increase (decrease) recommended by public utility related to emission chemicals | ' | ' | ' | ' | ' | ' | ' | ' | ' | -1,600,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Public Utilities, Adjustment to requested rate increase (decrease) recommended by third parties related to amortization of Prairie Island EPU costs | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -5,100,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Public Utilities, Adjustment to requested rate increase (decrease) recommended by public utility related to amortization of Prairie Island EPU costs | ' | ' | ' | ' | ' | -5,100,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Public Utilities, Adjustment to requested rate increase (decrease) requested by third parties related to other costs | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -8,000,000 | ' | -4,800,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Public Utilities, Revenue deficiency based on a forecast test year | ' | ' | ' | ' | ' | ' | 250,600,000 | ' | ' | ' | 67,800,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Public Utilities, Adjustment to requested rate increase (decrease) by public utility related to the evidentiary hearing adjustments | ' | ' | ' | ' | ' | ' | -27,300,000 | ' | ' | ' | 11,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Public Utilities, Amended revenue deficiency based on a forecast test year | ' | ' | ' | ' | ' | ' | 223,300,000 | ' | ' | ' | 78,800,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Public Utilities, Adjustment to requested rate increase (decrease) by public utility related to the depreciation reserve | ' | ' | ' | ' | ' | ' | -81,100,000 | ' | ' | ' | 52,900,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Public Utilities, Adjustment to requested interim rate increase (decrease), amount | ' | ' | ' | ' | ' | ' | -65,300,000 | ' | ' | ' | 65,300,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Public Utilities, adjustment to requested rate increase (decrease) related to prairie island EPU | ' | ' | ' | ' | ' | ' | 4,800,000 | ' | ' | ' | -4,800,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Impact on revenue increase (decrease), amount | ' | ' | ' | ' | ' | ' | 81,700,000 | [1] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Impact on revenue increase (decrease) maximum range, amount | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 166,500,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Public Utilities, Adjustment to approved rate increase (decrease) related to depreciation expense | ' | ' | ' | ' | ' | ' | 81,100,000 | ' | ' | ' | -45,700,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Public utilities, Adjustment to requested rate increase (decrease) related to DOE settlement proceeds, amount | ' | ' | ' | ' | ' | ' | 0 | ' | ' | ' | -25,700,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Public Utilities, rebuttal request to increase (decrease) 2014 rates by public utility | ' | ' | ' | ' | ' | ' | 142,200,000 | ' | ' | ' | 106,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Public Utilities, Recommended rate increase (decrease) impact on pre-tax income, minimum range | ' | ' | ' | ' | ' | ' | 153,700,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Public Utilities, adjustment requested by public utility related to nuclear investments and operating costs | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 13,400,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Public Utilities, adjustment requested by public utility related to other production, transmission and distribution costs | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 5,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Public Utilities, adjustment to requested rate increase (decrease) requested by public utility related to technology improvements | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,100,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Public Utilities, adjustment to requested rate increase (decrease) requested by public utility related to pension and operating and maintenance expenses | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,600,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Public Utilities, adjustment to requested rate increase (decrease) requested by public utility related to wind generation facilities | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,400,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Public Utilities, adjustment to requested rate increase (decrease) requested by public utility related to capital structure | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,100,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Public Utilities, Incremental base revenue requested | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 24,600,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Public Utilities, adjustment to requested rate increase (decrease) requested by public utility related to infrastructure rider recovery moving to base rates | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -8,400,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Public Utilities, adjustment to requested rate increase (decrease) requested by public utility related to TCR rider recovery moving to base rates | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -600,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Rate Matters [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Public Utilities, Requested Rate Increase (Decrease), Amount | ' | ' | ' | ' | ' | 192,700,000 | ' | 193,000,000 | ' | 98,500,000 | ' | 98,000,000 | ' | ' | ' | ' | 15,600,000 | ' | ' | ' | 192,700,000 | ' | 98,500,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Public Utilities, Requested Rate Increase (Decrease), Percentage | ' | ' | ' | ' | ' | ' | ' | 6.90% | ' | ' | ' | 3.50% | ' | ' | ' | ' | 8.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Public Utilities, number of years excess depreciation reserve is amortized | ' | ' | '8 years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '3 years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Public Utilities, Requested Return on Equity, Percentage | ' | 10.25% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10.25% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Public Utilities, Requested Rate Base, Amount | ' | ' | ' | ' | ' | ' | ' | 6,670,000,000 | ' | ' | ' | 412,000,000 | ' | ' | ' | ' | 433,200,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Public Utilities, Requested Equity Capital Structure, Percentage | ' | 52.50% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 53.86% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Public Utilities, Interim Rate Increase (Decrease), Amount | 127,000,000 | ' | ' | ' | ' | ' | ' | ' | 127,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | 127,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Public Utilities, Interim Rate Increase (Decrease), Percentage | ' | ' | ' | ' | ' | ' | ' | ' | 4.60% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Public Utilities, Recommended rate increase (decrease) impact on pre-tax income, cap | ' | ' | ' | ' | ' | ' | ' | ' | 208,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Generating capacity | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 600 | ' | ' | 671 | ' | ' | |
Costs for nuclear project, Amount | ' | ' | ' | ' | 665,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 665,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Total capitalized nuclear project costs | ' | ' | ' | ' | 748,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 748,000,000 | ' | ' | ' | ' | ' | ' | ' | |
Amount of recoverable investment, without a return | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 107,000,000 | ' | ' | ' | ' | ' | ' | ' | |
Cost per kilowatt of installed capacity | ' | ' | ' | ' | 1,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Initial estimated nuclear project costs | ' | ' | ' | ' | 320,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount | ' | ' | ' | ' | ' | ' | ' | ' | ' | 106,000,000 | ' | ' | 164,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Public Utilities, Estimated adjusted cumulative total step increase (decrease) recommended by third parties. | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 134,600,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Public Utilities, Unadjusted cumulative total step increase (decrease) recommended by third parties. | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 112,400,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Amount of public utility's amended unadjusted cumulative total step up increase (decrease) with regulatory agency. | ' | ' | ' | ' | ' | ' | ' | ' | ' | 248,200,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Number of factors attributable to project cost increases | ' | ' | ' | 3 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Public Utilities, minimum number of years for the application process | ' | ' | ' | '5 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Public Utilities, Total cost disallowances recommended by third parties | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 71,500,000 | ' | ' | ' | ' | 321,000,000 | ' | ' | ' | ' | ' | ' | ' | |
Public Utilities, disallowance of project costs recommended by third parties impacting the NSP System | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 94,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Number of megawatts of additional capacity | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 71 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Percentage of total project costs associated with project components required to achieve the EPU | ' | ' | ' | ' | 85.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 85.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Number of sales forecast methodologies | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Number of months of actual weather normalized sales, true up adjustment | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '12 months | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Public Utilities, Requested increase (decrease) to rider revenue | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 14,900,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Public Utilities, Adjustment to requested rate increase (decrease) recommended by third parties related to depreciation expense | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -17,500,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Public Utilities, Adjustment to requested rate increase (decrease) by public utility related to depreciation expense | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Public Utilities, Adjustment to requested rate increase (decrease) recommended by third parties related to Monticello EPU costs | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -33,900,000 | ' | 29,100,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Public Utilities, Adjustment to requested rate increase (decrease) recommended by third parties related to excess depreciation reserve adjustment. | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -22,700,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Public Utilities, Adjustment to requested rate increase (decrease) recommended by public utility related to excess depreciation reserve adjustment. | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Public Utilities, Adjustment to requested rate increase (decrease) recommended by public utility related to Monticello EPU costs | ' | ' | ' | ' | ' | 0 | ' | ' | ' | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Public Utilities, Adjustment to requested rate increase (decrease) recommended by third parties related to Monticello EPU cost disallowance. | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -10,200,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Public Utilities, Adjustment to requested rate increase (decrease) recommended by public utility related to Monticello EPU cost disallowance. | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Public Utilities, Rider costs to be recovered through base rates, Amount | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 9,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Public Utilities, Requested Rate Increase (Decrease), Amended, Percentage | ' | ' | ' | ' | ' | ' | 5.10% | ' | ' | ' | 3.80% | ' | 5.60% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Public Utilities, Adjustment requested by public utility to rate increase (decrease) related to other costs | ' | ' | ' | ' | ' | -6,500,000 | ' | ' | ' | 1,700,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Amount of the rate increase (decrease) recommended by third parties, unadjusted. | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 45,900,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Public Utilities, Rate increase (decrease) recommended by third parties | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 66,500,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Public Utilities, ROE applicable to transmission formula rates in the MISO region, lower bound | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 9.15% | 9.15% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Public Utilities, maximum equity capital structure percentage allowed per the complaint | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 50.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Public Utilities, number of steps required for newly adopted ROE discounted cash flow methodology | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2 | ' | ' | ' | ' | ' | ' | ' | ' | |
Public Utilities, reduction of transmission revenue, net of expense due to the new ROE methodology | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 5,000,000 | ' | ' | 7,000,000 | ' | |
Public Utilities, Recommended rate increase (decrease) impact on pre-tax income, maximum range | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 146,500,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Public Utilities, Adjustment to requested rate increase (decrease) recommended by third parties related to Monticello EPU depreciation deferrals | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | ' | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Public Utilities, Adjustment to requested rate increase (decrease) recommended by public utility related to Monticello EPU depreciation deferrals | ' | ' | ' | ' | ' | -12,200,000 | ' | ' | ' | 1,600,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Public Utilities, Adjustment to requested rate increase (decrease) recommended by third parties related to Monticello EPU step increase. | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Public Utilities, Adjustment to requested rate increase (decrease) recommended by public utility related to Monticello EPU step increase. | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10,100,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Public Utilities, Adjustment to requested rate increase (decrease) recommended by third parties, sales forecast true up. | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 18,300,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Public Utilities, Adjustment to requested rate increase (decrease) recommended by Public Utility, sales forecast true up. | ' | ' | ' | ' | ' | -9,100,000 | -9,100,000 | [2] | ' | ' | ' | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -9,100,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Adjustment to requested rate increase (decrease) recommended by third party, property taxes true up. | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3,900,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Amount of the rate increase (decrease) recommended by third parties, adjusted. | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 68,100,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Amount of public utility's amended requested rate increase (decrease) with regulatory agency, adjusted. | ' | ' | ' | ' | ' | 137,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Amount of public utility's amended estimated adjusted cumulative total step up increase (decrease) with regulatory agency. | ' | ' | ' | ' | ' | ' | ' | ' | ' | $243,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
[1] | NSP-Minnesota’s total revenue for 2014 is capped at the interim rate level of $127 million and pre-tax operating income is capped at $208 million. This table demonstrates the impact of reducing NSP-Minnesota’s rebuttal request. | ||||||||||||||||||||||||||||||||
[2] | NSP-Minnesota and the DOC have agreed to a sales true-up based on weather normalized sales for 2014, using standard weather coefficients. NSP-Minnesota periodically adjusts the coefficients in periods of extreme weather conditions to enhance weather impact estimates. As a result of the difference in the two methodologies, currently, approximately $9.1 million of revenue that NSP-Minnesota attributed to weather would be considered normal sales growth using the standard weather coefficients. The refund for the full year could vary from the estimate as of Sept. 30, 2014, depending on weather conditions. |
Rate_Matters_Rate_Matters_NSPW
Rate Matters Rate Matters, NSP-WI (Details) (PSCW Proceeding - Wisconsin Electric Rate Case 2015 [Member], NSP-Wisconsin, USD $) | 1 Months Ended | |
31-May-14 | Oct. 31, 2014 | |
Subsequent Event | ||
Public Service Commission of Wisconsin (PSCW) [Member] | ||
NSP-WI 2015 Electric Rate Case [Line Items] | ' | ' |
Public Utilities, amount requested by public utility related to production and transmission fixed charges | $28,100,000 | ' |
Public Utilities, Adjustment to requested rate increase (decrease) recommended by third parties, related to production and transmission fixed charges | ' | 26,400,000 |
Public Utilities, Requested Rate Increase (Decrease), Amount | 20,600,000 | ' |
Public Utilities, Requested Rate Increase (Decrease), Percentage | 3.20% | ' |
Public Utilities, Requested Return on Equity, Percentage | 10.20% | ' |
Public Utilities, percentage of earnings above the authorized ROE that will be refunded to customers | 100.00% | ' |
Public Utilities, amount requested by public utility related to fuel and purchased power | 13,900,000 | ' |
Public Utilities, Adjustment to requested rate increase (decrease) related to fuel and purchased power | ' | 11,100,000 |
Public Utilities, requested base revenue increase (decrease) excluding NSP-Minnesota depreciation reserve and Monticello EPU deferral adjustments | 42,000,000 | ' |
Public Utilities, Adjustment to base revenue increase (decrease) recommended by third parties excluding NSP-Minnesota depreciation reserve and Monticello EPU deferrals | ' | 37,500,000 |
Public Utilities, Adjustment to requested rate increase (decrease) related to the NSP-Minnesota transmission depreciation reserve | -16,200,000 | ' |
Public Utilities, Adjustment to requested rate increase (decrease) recommended by third parties related to the NSP-Minnesota transmission depreciation reserve | ' | -16,200,000 |
Public Utilities, Adjustment to requested rate increase (decrease) related to the Monticello EPU deferral | -5,200,000 | ' |
Public Utilities, Adjustment to requested rate increase (decrease) recommended by third parties related to Monticello EPU depreciation deferrals | ' | -5,200,000 |
Public Utilities, Rate increase (decrease) recommended by third parties | ' | 16,100,000 |
Public utilities, Adjustment to requested rate increase (decrease) recommended by third parties, percentage | ' | 2.50% |
The rate increase (decrease) requested of a regulatory body through an agreement between a public utility and another party or parties | ' | $16,100,000 |
Rate_Matters_PSCo_Details
Rate Matters, PSCo (Details) (USD $) | Sep. 30, 2014 | Dec. 31, 2013 | Sep. 30, 2014 | Sep. 30, 2014 | Sep. 30, 2014 | Sep. 30, 2014 | Sep. 30, 2014 | Sep. 30, 2014 | Sep. 30, 2014 | 31-May-14 | Sep. 30, 2013 | Sep. 30, 2014 | Dec. 31, 2013 | Aug. 31, 2013 | Jul. 31, 2014 | Dec. 31, 2012 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2012 | Dec. 31, 2011 | Jun. 30, 2012 | Apr. 30, 2012 | Oct. 31, 2014 | Oct. 31, 2014 | Aug. 31, 2013 | Aug. 31, 2013 |
PSCo | PSCo | PSCo | PSCo | PSCo | PSCo | PSCo | PSCo | PSCo | PSCo | PSCo | PSCo | PSCo | PSCo | PSCo | PSCo | PSCo | PSCo | PSCo | PSCo | Subsequent Event | Subsequent Event | Minimum | Maximum | |||
CPUC Proceeding - Colorado 2014 Electric Rate Case | CPUC Proceeding - Colorado 2014 Electric Rate Case, Electric Rates 2015 | CPUC Proceeding - Colorado 2014 Electric Rate Case, Electric Rates 2016 | CPUC Proceeding - Colorado 2014 Electric Rate Case, Electric Rates 2017 | CPUC Proceeding - Manufacturer's Sales Tax Refund | CPUC Proceeding - Annual Electric Earnings Test | CPUC Proceeding - 2014 Electric Earnings Test | CPUC Proceeding - Renewable Energy Credit Sharing | CPUC Proceeding - Renewable Energy Credit Sharing | CPUC Proceeding - Renewable Energy Credit Sharing | CPUC Proceeding - Renewable Energy Credit Sharing | FERC Proceeding - Production Formula Rate ROE Complaint | 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) | PSCo | PSCo | PSCo | PSCo | |||
CPUC Proceeding - 2013 Electric Earnings Test | CPUC Proceeding - Renewable Energy Credit Sharing | CPUC Proceeding - Renewable Energy Credit Sharing | CPUC Proceeding - Renewable Energy Credit Sharing | CPUC Proceeding - Renewable Energy Credit Sharing | CPUC Proceeding - Renewable Energy Credit Sharing | FERC Proceeding - Transmission Formula Rate Cases | FERC Proceeding - Transmission Formula Rate Cases | Federal Energy Regulatory Commission (FERC) | Federal Energy Regulatory Commission (FERC) | FERC Proceeding - Production Formula Rate ROE Complaint | FERC Proceeding - Production Formula Rate ROE Complaint | |||||||||||||||
Shareholders | Shareholders | Customers | Customers | FERC Proceeding - Transmission Formula Rate Cases | FERC Proceeding - Production Formula Rate ROE Complaint | |||||||||||||||||||||
Rate Matters [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Requested Rate Increase (Decrease), Amount | ' | ' | $136,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $2,000,000 | ' | ' | ' | ' |
Public Utilities, Requested Rate Increase (Decrease), Percentage | ' | ' | 4.83% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Portion of requested rate increase (decrease) attributable to CACJA recovery | ' | ' | ' | 100,900,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Requested increase (decrease) to rider revenue | ' | ' | ' | ' | 34,200,000 | 29,900,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Requested Return on Equity, Percentage | ' | ' | 10.35% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10.25% | ' | ' | ' | ' | ' |
Public Utilities, Requested Rate Base, Amount | ' | ' | 6,390,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Requested Equity Capital Structure, Percentage | ' | ' | 56.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Rider costs to be recovered through base rates, Amount | ' | ' | 19,900,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Maximum annual amount of property taxes not subject to deferral | ' | ' | ' | ' | ' | ' | 76,700,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Reduction in current year property tax deferral | ' | ' | ' | ' | ' | ' | 10,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Return on equity threshold triggering earnings sharing, Percentage | ' | ' | ' | ' | ' | ' | ' | 10.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Refund Approved, Amount | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 45,700,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Regulatory Liability, Noncurrent | 1,140,619,000 | 1,059,395,000 | ' | ' | ' | ' | ' | ' | 52,400,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Ultimate margin sharing associated with stand alone REC transactions, Percentage | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10.00% | ' | 90.00% | ' | ' | ' | ' | ' | ' |
Public Utilities, Margin threshold determining percentage of margin sharing, Amount | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 20,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Percentage of margin on hybrid REC approved for first 20 million of margins | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 20.00% | ' | 80.00% | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Percentage of margin on hybrid REC approved for margins in excess of 20 million | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10.00% | ' | 90.00% | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Customers share of margins credited against RESA regulatory asset balance | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 6,100,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Cumulative credit against RESA regulatory asset balance | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 104,700,000 | 104,500,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Margin threshold proposed to be removed from sharing mechanism on hybrid REC trades, Amount | ' | ' | ' | ' | ' | ' | ' | ' | ' | $20,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Return on equity requested by third parties, Percentage | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 9.04% | ' | ' | ' | ' | ' | ' | 9.15% | ' | ' | ' | ' | ' |
Public Utilities, Approved Return on Equity, Percentage | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 9.72% | 9.72% | ' | ' |
Public Utilities, Base return on equity charged to customers through production formula rates, Percentage | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10.10% | 10.40% |
Rate_Matters_SPS_Details
Rate Matters, SPS (Details) (USD $) | Sep. 30, 2014 | Dec. 31, 2013 | Sep. 30, 2014 | Apr. 30, 2014 | Jan. 31, 2014 | Sep. 30, 2014 | Sep. 30, 2014 | Nov. 30, 2013 | Sep. 30, 2013 | Dec. 31, 2012 | Jul. 31, 2013 | Apr. 30, 2012 | Oct. 31, 2013 | Aug. 31, 2013 | Sep. 30, 2014 | Dec. 31, 2013 | Aug. 31, 2013 | Aug. 31, 2013 | Jul. 31, 2014 | Mar. 31, 2014 | Aug. 31, 2013 | Oct. 20, 2014 |
SPS | SPS | SPS | SPS | SPS | SPS | SPS | SPS | SPS | SPS | SPS | SPS | SPS | SPS | SPS | SPS | SPS | SPS | SPS | Subsequent Event | |||
PUCT Proceeding - Texas 2014 Electric Rate Case | PUCT Proceeding - Texas 2014 Electric Rate Case | PUCT Proceeding - Texas 2014 Electric Rate Case | PUCT Proceeding - Texas 2014 Electric Rate Case | PUCT Proceeding - Transmission Cost Recovery Factor (TCRF) Rider | PUCT Proceeding - Transmission Cost Recovery Factor (TCRF) Rider | NMPRC Proceeding - New Mexico 2014 Electric Rate Case | NMPRC Proceeding - New Mexico 2014 Electric Rate Case | FERC Proceeding - Wholesale Electric Rate Complaints | FERC Proceeding - Wholesale Electric Rate Complaints | FERC Proceeding - FERC Orders | FERC Proceeding - FERC Orders | FERC Proceeding - FERC Orders | FERC Proceeding - FERC Orders | FERC Proceeding - FERC Orders, Settlement Impact Through May 31, 2015 | FERC Proceeding - FERC Orders, Settlement Impact Effective June 1, 2015 | Public Utility Commission of Texas (PUCT) | New Mexico Public Regulation Commission (NMPRC) | Federal Energy Regulatory Commission (FERC) | SPS | |||
Factor | PUCT Proceeding - Transmission Cost Recovery Factor (TCRF) Rider | NMPRC Proceeding - New Mexico 2014 Electric Rate Case | FERC Proceeding - FERC Orders | FERC Proceeding - Wholesale Electric Rate Complaints | ||||||||||||||||||
Public Utilities, General Disclosures [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Requested Rate Increase (Decrease), Net Amount | ' | ' | ' | ' | $52,700,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Requested Rate Increase (Decrease), Percentage | ' | ' | ' | ' | 5.80% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Requested Rate Increase (Decrease), Amended, Net Amount | ' | ' | ' | 48,100,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Requested Return on Equity, Percentage | ' | ' | ' | ' | 10.40% | ' | ' | ' | ' | 10.65% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Requested Rate Base, Amount | ' | ' | ' | ' | 1,270,000,000 | ' | ' | ' | ' | 479,800,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Requested Equity Capital Structure, Percentage | ' | ' | ' | ' | 53.89% | ' | ' | ' | ' | 53.89% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Portion of requested rate increase (decrease) related to depreciation expense | ' | ' | ' | ' | 16,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Settlement Agreement, Requested Rate Increase (Decrease), Amount | ' | ' | 37,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Settlement Agreement, Requested Rate Increase (Decrease), Percentage | ' | ' | 3.50% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Revenue recognized through surcharge | ' | ' | ' | ' | ' | 13,300,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Settlement Agreement, Requested Return on Equity, Percentage | ' | ' | 9.70% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Requested Rate Increase (Decrease), Amount | ' | ' | ' | ' | 81,500,000 | ' | ' | ' | ' | 45,900,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Adjustment to requested rate increase (decrease) due to updated information | ' | ' | ' | -4,600,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount | ' | ' | ' | 76,900,000 | ' | ' | ' | ' | 32,500,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Adjustment to revised rate increase (decrease) request due to depreciation | ' | ' | -16,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Adjustment to revised rate increase (decrease) request due to allocators for wholesale load reduction | ' | ' | -12,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Adjustment to revised rate increase (decrease) request due to revised amortizations | ' | ' | -9,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Adjustment to revised rate increase (decrease) request due to non-specified settlement adjustments | ' | ' | -2,900,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Requested increase (decrease) to rider revenue | ' | ' | ' | ' | ' | ' | ' | 13,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Approved increase (decrease) to rider revenue | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 4,000,000 | ' | ' | ' |
Public Utilities, Interim Rate Refund, Amount | ' | ' | ' | ' | ' | ' | 3,700,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Requested Return on Equity, Amended, Percentage | ' | ' | ' | ' | ' | ' | ' | ' | 10.25% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, portion of revised rate increase (decrease) related to base and fuel revenue. | ' | ' | ' | ' | ' | ' | ' | ' | 20,900,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, portion of revised rate increase (decrease) related to rider revenue | ' | ' | ' | ' | ' | ' | ' | ' | 12,100,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, portion of revised rate increase (decrease) related to other costs | ' | ' | ' | ' | ' | ' | ' | ' | -500,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Approved Rate Increase (Decrease), Amount | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 33,100,000 | ' | ' |
Public Utilities, portion of approved rate increase (decrease) to be recovered in base revenue | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 12,700,000 | ' | ' |
Public Utilities, portion of approved rate increase (decrease) to be recovered through rider revenue | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 18,100,000 | ' | ' |
Public Utilities, Approved Return on Equity, Percentage | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 9.96% | ' | ' |
Public Utilities, Approved Equity Capital Structure, Percentage | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 53.89% | ' | ' |
Public Utilities, Base return on equity charged to customers through production formula rates, Percentage | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10.25% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Base return on equity charged to customers through transmission formula rates, Percentage | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10.77% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Base return on equity requested by customers to be charged through production formula rates, Percentage | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 9.15% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 8.61% |
Public Utilities, Base return on equity requested by customers to be charged through transmission formula rates, Percentage | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 9.65% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 9.11% |
Public Utilities, Number of prior complaints in a regulatory proceeding | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2 |
Number of components included in regulatory proceeding | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2 | ' | ' | ' | ' | ' | ' | ' | ' |
Number of coincident peaks used as demand allocator, revised | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3 | ' | ' | ' | ' | ' | ' | ' | 3 | ' |
Number of coincident peaks used as demand allocator, original | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 12 | ' |
Other Liabilities, Current | 396,564,000 | 377,776,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 44,500,000 | ' | ' | ' | ' | ' | ' |
Current year increase (decrease) to pre-tax earnings resulting from regulatory proceedings | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -4,000,000 | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Annual increase (decrease) in revenues resulting from regulatory proceeding | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ($6,000,000) | ($4,000,000) | ' | ' | ' | ' |
Commitments_and_Contingencies_1
Commitments and Contingencies, Purchased Power Agreements (Details) (Independent Power Producing Entities) | 3 Months Ended | |
Sep. 30, 2014 | Dec. 31, 2013 | |
MW | MW | |
Independent Power Producing Entities | ' | ' |
Purchased Power Agreements [Abstract] | ' | ' |
Generating capacity (in MW) | 3,698 | 3,338 |
Purchase Power Agreement Duration, Maximum (year) | '2033 | ' |
Commitments_and_Contingencies_2
Commitments and Contingencies, Guarantees and Indemnifications (Details) (USD $) | 3 Months Ended | |
Sep. 30, 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 |
Sharyland Indemnification Obligation Duration (year) | '2014 | ' |
Guarantor Obligations, Current Carrying Value | 400,000 | 400,000 |
Payment or Performance Guarantee | ' | ' |
Guarantees [Abstract] | ' | ' |
Guarantees issued and outstanding | 14,600,000 | 19,400,000 |
Current exposure under these guarantees | 200,000 | 300,000 |
Payment or Performance Guarantee | Surety Bonds | ' | ' |
Guarantees [Abstract] | ' | ' |
Guarantees issued and outstanding | $32,100,000 | $32,100,000 |
Commitments_and_Contingencies_3
Commitments and Contingencies, Environmental Contingencies - Site Contingencies (Details) (NSP-Wisconsin, USD $) | 9 Months Ended | |
In Millions, unless otherwise specified | Sep. 30, 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 | $106.90 | $104.60 |
Liability for estimated cost of remediating sites, current | 25.4 | 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 | 52 | ' |
Estimated amount spent on Phase I Project Area cleanup | 21 | ' |
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 $) | Jun. 30, 2014 | Apr. 30, 2014 | Dec. 31, 2010 | Sep. 30, 2014 | Sep. 30, 2014 | Sep. 30, 2014 | Sep. 30, 2014 | Sep. 30, 2014 | Sep. 30, 2014 |
In Millions, unless otherwise specified | Greenhouse Gas New Source Performance Standard for Modified and Reconstructed Power Plants | Cross-State Air Pollution Rule | PSCo | SPS | Capital Commitments | Capital Commitments | Capital Commitments | Capital Commitments | Capital Commitments |
Issue | Regional Haze Rules | Cross-State Air Pollution Rule | Federal Clean Water Act Section 316(b) | PSCo | NSP-Minnesota | NSP-Minnesota | SPS | ||
Kiln | MW | Regional Haze Rules | Federal Clean Water Act Section 316(b) | Regional Haze Rules | Cross-State Air Pollution Rule | ||||
Boiler | Plant | ||||||||
Group | |||||||||
Environmental Requirements [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Liability for estimated cost to comply with regulation | ' | ' | ' | ' | $46 | $360.50 | ' | $50 | $7 |
Minimum number of plants which could be required to make improvements to reduce entrainment | ' | ' | ' | ' | ' | ' | 4 | ' | ' |
Liability for estimated cost to comply with entrainment regulation | ' | ' | ' | ' | ' | ' | 180 | ' | ' |
Percentage of a comparable new plant's capital cost which would have to be exceeded to consider a project as a reconstruction under the proposed GHG NSPS for Modified and Reconstructed Power Plants (in hundredths) | 50.00% | ' | ' | ' | ' | ' | ' | ' | ' |
Number of issues on which the D.C. Circuit overturned the CSAPR | ' | 2 | ' | ' | ' | ' | ' | ' | ' |
Generating capacity (in MW) | ' | ' | ' | 700 | ' | ' | ' | ' | ' |
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 | ' | ' | ' | ' | ' | ' | ' | $45.80 | ' |
Commitments_and_Contingencies_5
Commitments and Contingencies, Legal Contingencies (Details) (USD $) | 3 Months Ended | 9 Months Ended | 1 Months Ended | 9 Months Ended | 9 Months Ended | 13 Months Ended | ||||||||||
Sep. 30, 2014 | Sep. 30, 2013 | Sep. 30, 2014 | Sep. 30, 2013 | 31-May-11 | Apr. 30, 2011 | Sep. 30, 2014 | Aug. 31, 2014 | Jul. 31, 2011 | Sep. 30, 2007 | Sep. 30, 2014 | 15-May-14 | Sep. 30, 2014 | Sep. 30, 2014 | Jun. 30, 2001 | Sep. 30, 2014 | |
NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | SPS | PSCo | PSCo | Public Utility Commission of Texas (PUCT) | |||||
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] | 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] | SPS | |||||
MW | Site | Factor | Exelon Wind Complaint [Member] | |||||||||||||
Dispute | Site | |||||||||||||||
Legal Contingencies [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Accrual for legal contingency | ' | ' | ' | ' | ' | ' | $0 | ' | ' | ' | ' | ' | $0 | $0 | ' | ' |
Generating capacity (in MW) | ' | ' | ' | ' | ' | 150 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Minimum amount of damages claimed by plaintiff | ' | ' | ' | ' | 240,000,000 | ' | 20,000,000 | ' | ' | ' | ' | ' | ' | 34,000,000 | ' | ' |
Number of main areas of dispute | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2 | ' | ' | ' |
Number of wind facilities | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 12 | ' | ' | 6 |
Sales to the City of Seattle | 2,869,807,000 | 2,822,338,000 | 8,757,507,000 | 8,184,100,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 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 | ' | ' | ' | ' | ' | ' | ' | 32,800,000 | ' | 116,500,000 | ' | ' | ' | ' | ' | ' |
Storage costs for spent nuclear fuel | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 100,000,000 | ' | ' | ' | ' | ' |
Cash payment received under settlement agreement | ' | ' | ' | ' | ' | ' | ' | ' | 100,000,000 | ' | 181,900,000 | ' | ' | ' | ' | ' |
Claim submitted for storage costs for spent nuclear fuel | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $33,600,000 | ' | ' | ' | ' |
Borrowings_and_Other_Financing2
Borrowings and Other Financing Instruments, Commercial Paper (Details) (USD $) | 3 Months Ended | 12 Months Ended |
Sep. 30, 2014 | Dec. 31, 2013 | |
Short-term Debt [Line Items] | ' | ' |
Amount outstanding at period end | $697,000,000 | $759,000,000 |
Commercial Paper | ' | ' |
Short-term Debt [Line Items] | ' | ' |
Borrowing limit | 2,450,000,000 | 2,450,000,000 |
Amount outstanding at period end | 697,000,000 | 759,000,000 |
Average amount outstanding | 730,000,000 | 481,000,000 |
Maximum amount outstanding | $894,000,000 | $1,160,000,000 |
Weighted average interest rate, computed on a daily basis (percentage) | 0.33% | 0.31% |
Weighted average interest rate at period end (percentage) | 0.33% | 0.25% |
Borrowings_and_Other_Financing3
Borrowings and Other Financing Instruments, Letters of Credit (Details) (USD $) | Sep. 30, 2014 | Dec. 31, 2013 | Sep. 30, 2014 | Dec. 31, 2013 | Sep. 30, 2014 |
In Thousands, unless otherwise specified | Letter of Credit | Letter of Credit | Letter of Credit | ||
Line of Credit Facility [Line Items] | ' | ' | ' | ' | ' |
Term of letters of credit (in years) | ' | ' | ' | ' | '1 year |
Amount outstanding at period end | $697,000 | $759,000 | $71,400 | $47,800 | ' |
Borrowings_and_Other_Financing4
Borrowings and Other Financing Instruments, Credit Facilities (Details) (Credit Facilities, USD $) | Sep. 30, 2014 | Dec. 31, 2013 | |
In Millions, unless otherwise specified | |||
Line of Credit Facility [Line Items] | ' | ' | |
Credit Facility | $2,450 | [1] | ' |
Drawn | 768.4 | [2] | ' |
Available | 1,681.60 | ' | |
Direct advances on the credit facility outstanding | 0 | 0 | |
Xcel Energy Inc. | ' | ' | |
Line of Credit Facility [Line Items] | ' | ' | |
Credit Facility | 800 | [1] | ' |
Drawn | 436 | [2] | ' |
Available | 364 | ' | |
PSCo | ' | ' | |
Line of Credit Facility [Line Items] | ' | ' | |
Credit Facility | 700 | [1] | ' |
Drawn | 259.5 | [2] | ' |
Available | 440.5 | ' | |
NSP-Minnesota | ' | ' | |
Line of Credit Facility [Line Items] | ' | ' | |
Credit Facility | 500 | [1] | ' |
Drawn | 23.9 | [2] | ' |
Available | 476.1 | ' | |
SPS | ' | ' | |
Line of Credit Facility [Line Items] | ' | ' | |
Credit Facility | 300 | [1] | ' |
Drawn | 41 | [2] | ' |
Available | 259 | ' | |
NSP-Wisconsin | ' | ' | |
Line of Credit Facility [Line Items] | ' | ' | |
Credit Facility | 150 | [1] | ' |
Drawn | 8 | [2] | ' |
Available | $142 | ' | |
[1] | These credit facilities have been amended to expire in October 2019. | ||
[2] | Includes outstanding commercial paper and letters of credit. |
Borrowings_and_Other_Financing5
Borrowings and Other Financing Instruments Borrowings and Other Financing Instruments, Amended Credit Agreements (Details) (Credit Facilities, Subsequent Event, USD $) | 1 Months Ended |
In Millions, unless otherwise specified | Oct. 31, 2014 |
Amended Credit Agreements [Line Items] | ' |
Amended Credit Facility, Maximum Borrowing Limit | $2,750 |
Original Credit Facility, Maximum Borrowing Limit | 2,450 |
Xcel Energy Inc. | ' |
Amended Credit Agreements [Line Items] | ' |
Amended Credit Agreements, Commencement Date | 14-Oct-14 |
Amended Term (in years) | '5 years |
Amended Credit Facility, Maximum Borrowing Limit | 1,000 |
Original Credit Facility, Maximum Borrowing Limit | 800 |
Number Of Additional Periods The Revolving Termination Date Can Be Extended, Subject To Majority Bank Group Approval | 2 |
Term Of Each Additional Period The Revolving Termination Date Can Be Extended, Subject To Majority Bank Group Approval (in years) | '1 year |
Xcel Energy Inc. | Minimum | ' |
Amended Credit Agreements [Line Items] | ' |
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage | 0.08% |
Xcel Energy Inc. | Maximum | ' |
Amended Credit Agreements [Line Items] | ' |
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage | 0.28% |
Xcel Energy Inc. | Eurodollar | Minimum | ' |
Amended Credit Agreements [Line Items] | ' |
Borrowing Margin Based On Long-Term Credit Ratings (percentage) | 0.88% |
Xcel Energy Inc. | Eurodollar | Maximum | ' |
Amended Credit Agreements [Line Items] | ' |
Borrowing Margin Based On Long-Term Credit Ratings (percentage) | 1.75% |
NSP-Minnesota | ' |
Amended Credit Agreements [Line Items] | ' |
Amended Credit Agreements, Commencement Date | 14-Oct-14 |
Amended Term (in years) | '5 years |
Number Of Additional Periods The Revolving Termination Date Can Be Extended, Subject To Majority Bank Group Approval | 2 |
Term Of Each Additional Period The Revolving Termination Date Can Be Extended, Subject To Majority Bank Group Approval (in years) | '1 year |
NSP-Minnesota | Minimum | ' |
Amended Credit Agreements [Line Items] | ' |
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage | 0.08% |
NSP-Minnesota | Maximum | ' |
Amended Credit Agreements [Line Items] | ' |
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage | 0.28% |
NSP-Minnesota | Eurodollar | Minimum | ' |
Amended Credit Agreements [Line Items] | ' |
Borrowing Margin Based On Long-Term Credit Ratings (percentage) | 0.88% |
NSP-Minnesota | Eurodollar | Maximum | ' |
Amended Credit Agreements [Line Items] | ' |
Borrowing Margin Based On Long-Term Credit Ratings (percentage) | 1.75% |
NSP-Wisconsin | ' |
Amended Credit Agreements [Line Items] | ' |
Amended Credit Agreements, Commencement Date | 14-Oct-14 |
Amended Term (in years) | '5 years |
Number Of Additional Periods The Revolving Termination Date Can Be Extended, Subject To Majority Bank Group Approval | 1 |
Term Of Each Additional Period The Revolving Termination Date Can Be Extended, Subject To Majority Bank Group Approval (in years) | '1 year |
NSP-Wisconsin | Minimum | ' |
Amended Credit Agreements [Line Items] | ' |
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage | 0.08% |
NSP-Wisconsin | Maximum | ' |
Amended Credit Agreements [Line Items] | ' |
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage | 0.28% |
NSP-Wisconsin | Eurodollar | Minimum | ' |
Amended Credit Agreements [Line Items] | ' |
Borrowing Margin Based On Long-Term Credit Ratings (percentage) | 0.88% |
NSP-Wisconsin | Eurodollar | Maximum | ' |
Amended Credit Agreements [Line Items] | ' |
Borrowing Margin Based On Long-Term Credit Ratings (percentage) | 1.75% |
PSCo | ' |
Amended Credit Agreements [Line Items] | ' |
Amended Credit Agreements, Commencement Date | 14-Oct-14 |
Amended Term (in years) | '5 years |
Number Of Additional Periods The Revolving Termination Date Can Be Extended, Subject To Majority Bank Group Approval | 2 |
Term Of Each Additional Period The Revolving Termination Date Can Be Extended, Subject To Majority Bank Group Approval (in years) | '1 year |
PSCo | Minimum | ' |
Amended Credit Agreements [Line Items] | ' |
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage | 0.08% |
PSCo | Maximum | ' |
Amended Credit Agreements [Line Items] | ' |
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage | 0.28% |
PSCo | Eurodollar | Minimum | ' |
Amended Credit Agreements [Line Items] | ' |
Borrowing Margin Based On Long-Term Credit Ratings (percentage) | 0.88% |
PSCo | Eurodollar | Maximum | ' |
Amended Credit Agreements [Line Items] | ' |
Borrowing Margin Based On Long-Term Credit Ratings (percentage) | 1.75% |
SPS | ' |
Amended Credit Agreements [Line Items] | ' |
Amended Credit Agreements, Commencement Date | 14-Oct-14 |
Amended Term (in years) | '5 years |
Amended Credit Facility, Maximum Borrowing Limit | 400 |
Original Credit Facility, Maximum Borrowing Limit | $300 |
Number Of Additional Periods The Revolving Termination Date Can Be Extended, Subject To Majority Bank Group Approval | 2 |
Term Of Each Additional Period The Revolving Termination Date Can Be Extended, Subject To Majority Bank Group Approval (in years) | '1 year |
SPS | Minimum | ' |
Amended Credit Agreements [Line Items] | ' |
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage | 0.08% |
SPS | Maximum | ' |
Amended Credit Agreements [Line Items] | ' |
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage | 0.28% |
SPS | Eurodollar | Minimum | ' |
Amended Credit Agreements [Line Items] | ' |
Borrowing Margin Based On Long-Term Credit Ratings (percentage) | 0.88% |
SPS | Eurodollar | Maximum | ' |
Amended Credit Agreements [Line Items] | ' |
Borrowing Margin Based On Long-Term Credit Ratings (percentage) | 1.75% |
Borrowings_and_Other_Financing6
Borrowings and Other Financing Instruments, Long-Term Borrowings and Other Financing Instruments (Details) (First Mortgage Bonds, USD $) | 1 Months Ended | |||||
Mar. 31, 2014 | 31-May-14 | Jun. 30, 2014 | Jun. 30, 2014 | Jun. 30, 2014 | Jun. 30, 2014 | |
PSCo | NSP-Minnesota | SPS | SPS | SPS | NSP-Wisconsin | |
Series Due March 15, 2044 | Series Due May 15, 2044 | Series No. 3 Due June 15, 2024 | Issued Collateral on Series G Senior Note Due Dec. 1, 2018 | Previously Issued Series G Senior Note Due Dec. 1, 2018 | Series Due June 15, 2024 | |
Long-Term Borrowings and Other Financing Instruments [Abstract] | ' | ' | ' | ' | ' | ' |
Face amount | $300,000,000 | $300,000,000 | $150,000,000 | $250,000,000 | ' | $100,000,000 |
Interest rate, stated percentage | 4.30% | 4.13% | 3.30% | 8.75% | 8.75% | 3.30% |
Maturity date | 15-Mar-44 | 15-May-44 | 15-Jun-24 | 1-Dec-18 | 1-Dec-18 | 15-Jun-24 |
Borrowings_and_Other_Financing7
Borrowings and Other Financing Instruments, Issuances of Common Stock (Details) (USD $) | 9 Months Ended | 12 Months Ended | 9 Months Ended | 12 Months Ended | ||
Share data in Thousands, unless otherwise specified | Sep. 30, 2014 | Sep. 30, 2013 | Sep. 30, 2014 | Dec. 31, 2013 | Sep. 30, 2014 | Dec. 31, 2013 |
At-the-Market Program | At-the-Market Program | At-the-Market Program | At-the-Market Program | |||
Common Stock | Common Stock | |||||
Class of Stock [Line Items] | ' | ' | ' | ' | ' | ' |
Issuances of common stock (in shares) | ' | ' | ' | ' | 5,700 | 7,700 |
Proceeds from issuance of common stock | $178,639,000 | $229,420,000 | $172,700,000 | $222,700,000 | ' | ' |
Fees and commissions from issuance of common stock | ' | ' | $1,900,000 | $2,700,000 | ' | ' |
Fair_Value_of_Financial_Assets2
Fair Value of Financial Assets and Liabilities (Details) | 9 Months Ended |
Sep. 30, 2014 | |
Minimum | Commingled Funds and International Equity Funds | ' |
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items] | ' |
Notice period for investment redemption (in days) | '1 day |
Minimum | Real Estate Funds | ' |
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items] | ' |
Notice period for investment redemption (in days) | '45 days |
Maximum | Commingled Funds and International Equity Funds | ' |
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items] | ' |
Notice period for investment redemption (in days) | '90 days |
Maximum | Real Estate Funds | ' |
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items] | ' |
Notice period for investment redemption (in days) | '90 days |
Fair_Value_of_Financial_Assets3
Fair Value of Financial Assets and Liabilities, Cost and Fair Value of Nuclear Decommissioning Fund (Details) (USD $) | 9 Months Ended | 12 Months Ended | ||
Sep. 30, 2014 | Dec. 31, 2013 | |||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Gross Unrealized Gain | $287,500,000 | $240,300,000 | ||
Available-for-sale Securities, Gross Unrealized Loss | 58,800,000 | 58,500,000 | ||
Investments [Abstract] | ' | ' | ||
Equity investments in unconsolidated subsidiaries | 84,500,000 | 87,100,000 | ||
Miscellaneous investments | 43,000,000 | 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 | 14,972,000 | 33,281,000 | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities | 1,460,778,000 | 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 | 469,608,000 | 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 | 74,222,000 | 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 | 45,075,000 | 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 | 34,379,000 | 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 | 80,196,000 | 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 | 17,696,000 | 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 | 235,751,000 | 241,112,000 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Asset-backed securities | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Debt Securities | 9,226,000 | ' | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Mortgage-backed securities | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Debt Securities | 23,554,000 | ' | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Common stock | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Equity Securities | 377,287,000 | 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 | 14,972,000 | 33,281,000 | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities | 1,689,441,000 | [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 | 471,388,000 | 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 | 85,856,000 | 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 | 97,004,000 | 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 | 63,973,000 | 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 | 29,726,000 | 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 | 79,248,000 | 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 | 17,613,000 | 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 | 240,907,000 | 232,016,000 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Asset-backed securities | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Debt Securities | 9,347,000 | ' | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Mortgage-backed securities | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Debt Securities | 23,696,000 | ' | ||
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 | 555,711,000 | 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 | 14,972,000 | 33,281,000 | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities | 570,683,000 | 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 | Asset-backed securities | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Debt Securities | 0 | ' | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Mortgage-backed securities | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Debt Securities | 0 | ' | ||
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 | 555,711,000 | 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 | 957,781,000 | 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 | 471,388,000 | 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 | 85,856,000 | 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 | 29,726,000 | 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 | 79,248,000 | 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 | 17,613,000 | 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 | 240,907,000 | 232,016,000 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Asset-backed securities | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Debt Securities | 9,347,000 | ' | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Mortgage-backed securities | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Debt Securities | 23,696,000 | ' | ||
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 | 160,977,000 | 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 | 97,004,000 | 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 | 63,973,000 | 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 | Asset-backed securities | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Debt Securities | 0 | ' | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Mortgage-backed securities | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Debt Securities | 0 | ' | ||
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 $84.5 million of equity investments in unconsolidated subsidiaries and $43.0 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 | 9 Months Ended | |||
In Thousands, unless otherwise specified | Sep. 30, 2014 | Sep. 30, 2013 | Sep. 30, 2014 | Sep. 30, 2013 | |
Changes in Level 3 Nuclear Decommissioning Fund Assets [Roll Forward] | ' | ' | ' | ' | |
Balance at beginning of period | $146,781 | $83,730 | $120,064 | $104,600 | |
Purchases | 12,655 | 18,078 | 27,464 | 33,450 | |
Settlements | -5,876 | 0 | -5,876 | -9,022 | |
Gains recognized as regulatory assets | 7,417 | 2,022 | 19,325 | 7,078 | |
Transfers out of Level 3 | 0 | 0 | 0 | -32,276 | [1] |
Balance at end of period | 160,977 | 103,830 | 160,977 | 103,830 | |
Private equity investments | ' | ' | ' | ' | |
Changes in Level 3 Nuclear Decommissioning Fund Assets [Roll Forward] | ' | ' | ' | ' | |
Balance at beginning of period | 81,123 | 45,590 | 62,696 | 33,250 | |
Purchases | 11,125 | 6,790 | 22,078 | 15,344 | |
Settlements | 0 | 0 | 0 | 0 | |
Gains recognized as regulatory assets | 4,756 | 94 | 12,230 | 3,880 | |
Transfers out of Level 3 | 0 | 0 | 0 | 0 | |
Balance at end of period | 97,004 | 52,474 | 97,004 | 52,474 | |
Real estate | ' | ' | ' | ' | |
Changes in Level 3 Nuclear Decommissioning Fund Assets [Roll Forward] | ' | ' | ' | ' | |
Balance at beginning of period | 65,658 | 38,140 | 57,368 | 39,074 | |
Purchases | 1,530 | 11,288 | 5,386 | 18,106 | |
Settlements | -5,876 | 0 | -5,876 | -9,022 | |
Gains recognized as regulatory assets | 2,661 | 1,928 | 7,095 | 3,198 | |
Transfers out of Level 3 | 0 | 0 | 0 | 0 | |
Balance at end of period | 63,973 | 51,356 | 63,973 | 51,356 | |
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 | ' | 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 | ' | $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 $) | Sep. 30, 2014 |
In Thousands, unless otherwise specified | |
Final Contractual Maturity [Abstract] | ' |
Due in 1 Year or Less | $1,110 |
Due in 1 to 5 Years | 54,332 |
Due in 5 to 10 Years | 121,622 |
Due after 10 Years | 223,473 |
Total | 400,537 |
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 | 29,726 |
Total | 29,726 |
U.S. corporate bonds | ' |
Final Contractual Maturity [Abstract] | ' |
Due in 1 Year or Less | 303 |
Due in 1 to 5 Years | 15,878 |
Due in 5 to 10 Years | 62,985 |
Due after 10 Years | 82 |
Total | 79,248 |
International corporate bonds | ' |
Final Contractual Maturity [Abstract] | ' |
Due in 1 Year or Less | 0 |
Due in 1 to 5 Years | 4,266 |
Due in 5 to 10 Years | 13,347 |
Due after 10 Years | 0 |
Total | 17,613 |
Municipal bonds | ' |
Final Contractual Maturity [Abstract] | ' |
Due in 1 Year or Less | 807 |
Due in 1 to 5 Years | 34,188 |
Due in 5 to 10 Years | 41,744 |
Due after 10 Years | 164,168 |
Total | 240,907 |
Asset-backed securities | ' |
Final Contractual Maturity [Abstract] | ' |
Due in 1 Year or Less | 0 |
Due in 1 to 5 Years | 0 |
Due in 5 to 10 Years | 3,546 |
Due after 10 Years | 5,801 |
Total | 9,347 |
Mortgage-backed securities | ' |
Final Contractual Maturity [Abstract] | ' |
Due in 1 Year or Less | 0 |
Due in 1 to 5 Years | 0 |
Due in 5 to 10 Years | 0 |
Due after 10 Years | 23,696 |
Total | $23,696 |
Fair_Value_of_Financial_Assets6
Fair Value of Financial Assets and Liabilities, Derivative Instruments (Details) (USD $) | Sep. 30, 2014 | Dec. 31, 2013 | ||
In Millions, unless otherwise specified | MWh | MWh | ||
Interest Rate Swap | ' | ' | ||
Interest Rate Derivatives [Abstract] | ' | ' | ||
Amount of accumulated other comprehensive gains (losses) related to interest rate derivatives expected to be reclassified into earnings within the next twelve months | -2.4 | ' | ||
Electric Commodity (in megawatt hours) | ' | ' | ||
Gross Notional Amounts of Commodity Forwards, Options and FTRs [Abstract] | ' | ' | ||
Notional amount | 74,912,000 | [1],[2] | 58,423,000 | [1],[2] |
Natural Gas Commodity (in million British thermal units) | ' | ' | ||
Gross Notional Amounts of Commodity Forwards, Options and FTRs [Abstract] | ' | ' | ||
Notional amount | 18,482,000 | [1],[2] | 9,854,000 | [1],[2] |
Vehicle Fuel Commodity (in gallons) | ' | ' | ||
Gross Notional Amounts of Commodity Forwards, Options and FTRs [Abstract] | ' | ' | ||
Notional amount | 332,000 | [1],[2] | 482,000 | [1],[2] |
[1] | Amounts are not reflective of net positions in the underlying commodities. | |||
[2] | Notional amounts for options are included on a gross basis, but are weighted for the probability of exercise. |
Fair_Value_of_Financial_Assets7
Fair Value of Financial Assets and Liabilities, Impact of Derivative Activity (Details) (USD $) | 3 Months Ended | 9 Months Ended | ||||||
Sep. 30, 2014 | Sep. 30, 2013 | Sep. 30, 2014 | Sep. 30, 2013 | |||||
Financial Impact of Qualifying Fair Value Hedges on Earnings [Abstract] | ' | ' | ' | ' | ||||
Derivative instruments designated as fair value hedges | $0 | $0 | $0 | $0 | ||||
Recognized gains (losses) from fair value hedges or related hedged transactions | 0 | 0 | 0 | 0 | ||||
Cash Flow Hedges | ' | ' | ' | ' | ||||
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 | -69,000 | 36,000 | -56,000 | -11,000 | ||||
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities | 0 | 0 | 0 | 0 | ||||
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss | 951,000 | 805,000 | 2,808,000 | 3,073,000 | ||||
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities) | 0 | 0 | 0 | 0 | ||||
Pre-tax gains (losses) recognized during the period in income | 0 | 0 | 0 | 0 | ||||
Cash Flow Hedges | Interest Rate | ' | ' | ' | ' | ||||
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract] | ' | ' | ' | ' | ||||
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss | 0 | 0 | 0 | 0 | ||||
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities | 0 | 0 | 0 | 0 | ||||
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss | 967,000 | [1] | 829,000 | [1] | 2,869,000 | [1] | 3,140,000 | [1] |
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities) | 0 | 0 | 0 | 0 | ||||
Pre-tax gains (losses) recognized during the period in income | 0 | 0 | 0 | 0 | ||||
Cash Flow Hedges | Vehicle Fuel And Other Commodity | ' | ' | ' | ' | ||||
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract] | ' | ' | ' | ' | ||||
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss | -69,000 | 36,000 | -56,000 | -11,000 | ||||
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities | 0 | 0 | 0 | 0 | ||||
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss | -16,000 | [2] | -24,000 | [2] | -61,000 | [2] | -67,000 | [2] |
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities) | 0 | 0 | 0 | 0 | ||||
Pre-tax gains (losses) recognized during the period in income | 0 | 0 | 0 | 0 | ||||
Other Derivative Instrument | ' | ' | ' | ' | ||||
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract] | ' | ' | ' | ' | ||||
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss | 0 | 0 | 0 | 0 | ||||
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities | -5,846,000 | -1,046,000 | -3,637,000 | 55,973,000 | ||||
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss | 0 | 0 | 0 | 0 | ||||
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities) | 6,629,000 | -9,823,000 | -37,481,000 | -38,807,000 | ||||
Pre-tax gains (losses) recognized during the period in income | -1,865,000 | 7,106,000 | -3,666,000 | 9,156,000 | ||||
Other Derivative Instrument | Commodity Trading | ' | ' | ' | ' | ||||
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract] | ' | ' | ' | ' | ||||
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss | 0 | 0 | 0 | 0 | ||||
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities | 0 | 0 | 0 | 0 | ||||
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss | 0 | 0 | 0 | 0 | ||||
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities) | 0 | 0 | 0 | 0 | ||||
Pre-tax gains (losses) recognized during the period in income | -1,656,000 | [3] | 7,094,000 | [3] | 1,266,000 | [3] | 9,372,000 | [3] |
Other Derivative Instrument | Electric Commodity | ' | ' | ' | ' | ||||
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract] | ' | ' | ' | ' | ||||
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss | 0 | 0 | 0 | 0 | ||||
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities | -3,391,000 | 921,000 | -17,240,000 | 61,314,000 | ||||
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss | 0 | 0 | 0 | 0 | ||||
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities) | 6,629,000 | [4] | -9,823,000 | [4] | -18,641,000 | [4] | -38,816,000 | [4] |
Pre-tax gains (losses) recognized during the period in income | 0 | 0 | 0 | 0 | ||||
Other Derivative Instrument | Natural Gas Commodity | ' | ' | ' | ' | ||||
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract] | ' | ' | ' | ' | ||||
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss | 0 | 0 | 0 | 0 | ||||
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities | -2,455,000 | -1,967,000 | 13,603,000 | -5,341,000 | ||||
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss | 0 | 0 | 0 | 0 | ||||
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities) | 0 | 0 | -18,840,000 | [5] | 9,000 | [5] | ||
Pre-tax gains (losses) recognized during the period in income | -209,000 | [4] | 12,000 | [4] | -5,575,000 | [5] | -216,000 | [4] |
Other Derivative Instrument | Other Commodity | ' | ' | ' | ' | ||||
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract] | ' | ' | ' | ' | ||||
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss | ' | ' | 0 | ' | ||||
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities | ' | ' | 0 | ' | ||||
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss | ' | ' | 0 | ' | ||||
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities) | ' | ' | 0 | ' | ||||
Pre-tax gains (losses) recognized during the period in income | ' | ' | $643,000 | [3] | ' | |||
[1] | Amounts are recorded to interest charges. | |||||||
[2] | Amounts are recorded to O&M expenses. | |||||||
[3] | Amounts are recorded to electric operating revenues. Portions of these gains and losses are subject to sharing with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate. | |||||||
[4] | Amounts are recorded to electric fuel and purchased power. These derivative settlement gain and loss amounts are shared with electric customers through fuel and purchased energy cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate. | |||||||
[5] | Amounts for the nine months ended Sept. 30, 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 nine months ended Sept. 30, 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, Counterparty Credit Risk (Details) (Credit Concentration Risk, USD $) | Sep. 30, 2014 |
In Millions, unless otherwise specified | Counterparty |
Consideration of Credit Risk and Concentrations [Abstract] | ' |
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure | 10 |
Investment Grade Ratings from Standard & Poor's, Moody's, or Fitch Ratings | ' |
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 | 48.8 |
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties | 16.00% |
No Investment Grade Ratings from External Credit Rating Agencies | ' |
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 | 75 |
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties | 25.00% |
Fair_Value_of_Financial_Assets9
Fair Value of Financial Assets and Liabilities, Credit Related Contingent Features (Details) (USD $) | Sep. 30, 2014 | Dec. 31, 2013 |
Fair Value Disclosures [Abstract] | ' | ' |
Derivative instruments in a gross liability position | $0 | $1,400,000 |
Payments required if credit ratings were downgraded below investment grade | 0 | 1,400,000 |
Collateral posted on derivative instruments | 0 | 0 |
Collateral posted related to adequate assurance clauses in derivative contracts | $0 | $0 |
Recovered_Sheet1
Fair Value of Financial Assets and Liabilities, Derivative Assets and Liabilities at Fair Value (Details) (USD $) | Sep. 30, 2014 | Dec. 31, 2013 | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Collateral, Obligation to Return Cash, Offset | $0 | $200,000 | ||
Derivative Liability, Collateral, Right to Reclaim Cash, Offset | 3,900,000 | 4,200,000 | ||
Other Current Assets | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 120,654,000 | 91,707,000 | ||
Other Noncurrent Assets | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 53,577,000 | 84,842,000 | ||
Other Current Liabilities | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 22,924,000 | 23,382,000 | ||
Other Noncurrent Liabilities | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 187,445,000 | 209,224,000 | ||
Fair Value Measured on a Recurring Basis | Other Current Assets | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 97,127,000 | 58,679,000 | ||
Fair Value Measured on a Recurring Basis | Other Current Assets | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 1,000 | 88,000 | ||
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instrument | Commodity Trading | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 18,126,000 | 13,783,000 | ||
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instrument | Electric Commodity | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 69,023,000 | 38,902,000 | ||
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instrument | Natural Gas Commodity | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 9,977,000 | 5,906,000 | ||
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 10,861,000 | 26,411,000 | ||
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | ' | 13,000 | ||
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Other Derivative Instrument | Commodity Trading | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 10,861,000 | 26,398,000 | ||
Fair Value Measured on a Recurring Basis | Other Current Liabilities | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 422,000 | 348,000 | ||
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 0 | ' | ||
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instrument | Commodity Trading | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 422,000 | 348,000 | ||
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instrument | Electric Commodity | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 0 | 0 | ||
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instrument | Natural Gas Commodity | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 0 | ' | ||
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 734,000 | 5,295,000 | ||
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 5,000 | ' | ||
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Other Derivative Instrument | Commodity Trading | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 658,000 | 5,295,000 | ||
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Other Derivative Instrument | Natural Gas Commodity | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 71,000 | ' | ||
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets | ' | ' | ||
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 | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 | ||
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets | Other Derivative Instrument | 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 | Other Derivative Instrument | Electric Commodity | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 | ||
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets | Other Derivative Instrument | Natural Gas Commodity | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 | ||
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Assets | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 | ||
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Assets | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | ' | 0 | ||
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Assets | Other Derivative Instrument | 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 | ' | ' | ||
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 | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 0 | ' | ||
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities | Other Derivative Instrument | 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 | Other Derivative Instrument | Electric Commodity | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 0 | 0 | ||
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities | Other Derivative Instrument | Natural Gas Commodity | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 0 | ' | ||
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Liabilities | ' | ' | ||
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 | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 0 | ' | ||
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Liabilities | Other Derivative Instrument | 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 Noncurrent Liabilities | Other Derivative Instrument | Natural Gas Commodity | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 0 | ' | ||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 28,967,000 | 26,604,000 | ||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 4,000 | 88,000 | ||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets | Other Derivative Instrument | Commodity Trading | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 18,912,000 | 20,610,000 | ||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets | Other Derivative Instrument | Electric Commodity | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 | ||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets | Other Derivative Instrument | Natural Gas Commodity | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 10,051,000 | 5,906,000 | ||
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Assets | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 13,269,000 | 32,103,000 | ||
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Assets | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | ' | 29,000 | ||
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Assets | Other Derivative Instrument | Commodity Trading | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 13,269,000 | 32,074,000 | ||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 9,836,000 | 10,546,000 | ||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 3,000 | ' | ||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities | Other Derivative Instrument | Commodity Trading | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 9,759,000 | 10,546,000 | ||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities | Other Derivative Instrument | Electric Commodity | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 0 | 0 | ||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities | Other Derivative Instrument | Natural Gas Commodity | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 74,000 | ' | ||
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Liabilities | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 3,142,000 | 14,382,000 | ||
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Liabilities | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 5,000 | ' | ||
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Liabilities | Other Derivative Instrument | Commodity Trading | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 3,066,000 | 14,382,000 | ||
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Liabilities | Other Derivative Instrument | Natural Gas Commodity | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 71,000 | ' | ||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 91,317,000 | 48,279,000 | ||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges | ' | ' | ||
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 | Other Derivative Instrument | Commodity Trading | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 4,609,000 | 1,167,000 | ||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets | Other Derivative Instrument | Electric Commodity | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 86,708,000 | 47,112,000 | ||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets | Other Derivative Instrument | Natural Gas Commodity | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 | ||
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Assets | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 0 | 3,395,000 | ||
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Assets | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | ' | 0 | ||
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Assets | Other Derivative Instrument | Commodity Trading | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 0 | 3,395,000 | ||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 17,685,000 | 10,014,000 | ||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 0 | ' | ||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities | Other Derivative Instrument | Commodity Trading | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 0 | 1,804,000 | ||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities | Other Derivative Instrument | Electric Commodity | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 17,685,000 | 8,210,000 | ||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities | Other Derivative Instrument | Natural Gas Commodity | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 0 | ' | ||
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Liabilities | ' | ' | ||
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 | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 0 | ' | ||
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Liabilities | Other Derivative Instrument | Commodity Trading | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 0 | 0 | ||
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Liabilities | Other Derivative Instrument | Natural Gas Commodity | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 0 | ' | ||
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Assets | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 120,284,000 | 74,883,000 | ||
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Assets | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 4,000 | 88,000 | ||
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Assets | Other Derivative Instrument | Commodity Trading | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 23,521,000 | 21,777,000 | ||
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Assets | Other Derivative Instrument | Electric Commodity | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 86,708,000 | 47,112,000 | ||
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Assets | Other Derivative Instrument | Natural Gas Commodity | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 10,051,000 | 5,906,000 | ||
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Noncurrent Assets | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 13,269,000 | 35,498,000 | ||
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Noncurrent Assets | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | ' | 29,000 | ||
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Noncurrent Assets | Other Derivative Instrument | Commodity Trading | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 13,269,000 | 35,469,000 | ||
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Liabilities | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 27,521,000 | 20,560,000 | ||
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Liabilities | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 3,000 | ' | ||
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Liabilities | Other Derivative Instrument | Commodity Trading | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 9,759,000 | 12,350,000 | ||
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Liabilities | Other Derivative Instrument | Electric Commodity | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 17,685,000 | 8,210,000 | ||
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Liabilities | Other Derivative Instrument | Natural Gas Commodity | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 74,000 | ' | ||
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Noncurrent Liabilities | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 3,142,000 | 14,382,000 | ||
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Noncurrent Liabilities | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 5,000 | ' | ||
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Noncurrent Liabilities | Other Derivative Instrument | Commodity Trading | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 3,066,000 | 14,382,000 | ||
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Noncurrent Liabilities | Other Derivative Instrument | Natural Gas Commodity | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 71,000 | ' | ||
Fair Value Measured on a Recurring Basis | Counterparty Netting | Other Current Assets | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | -23,157,000 | [1] | -16,204,000 | [2] |
Fair Value Measured on a Recurring Basis | Counterparty Netting | Other Current Assets | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | -3,000 | [1] | 0 | [2] |
Fair Value Measured on a Recurring Basis | Counterparty Netting | Other Current Assets | Other Derivative Instrument | Commodity Trading | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | -5,395,000 | [1] | -7,994,000 | [2] |
Fair Value Measured on a Recurring Basis | Counterparty Netting | Other Current Assets | Other Derivative Instrument | Electric Commodity | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | -17,685,000 | [1] | -8,210,000 | [2] |
Fair Value Measured on a Recurring Basis | Counterparty Netting | Other Current Assets | Other Derivative Instrument | Natural Gas Commodity | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | -74,000 | [1] | 0 | [2] |
Fair Value Measured on a Recurring Basis | Counterparty Netting | Other Noncurrent Assets | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | -2,408,000 | [1] | -9,087,000 | [2] |
Fair Value Measured on a Recurring Basis | Counterparty Netting | Other Noncurrent Assets | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | ' | -16,000 | [2] | |
Fair Value Measured on a Recurring Basis | Counterparty Netting | Other Noncurrent Assets | Other Derivative Instrument | Commodity Trading | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | -2,408,000 | [1] | -9,071,000 | [2] |
Fair Value Measured on a Recurring Basis | Counterparty Netting | Other Current Liabilities | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | -27,099,000 | [1] | -20,212,000 | [2] |
Fair Value Measured on a Recurring Basis | Counterparty Netting | Other Current Liabilities | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | -3,000 | [1] | ' | |
Fair Value Measured on a Recurring Basis | Counterparty Netting | Other Current Liabilities | Other Derivative Instrument | Commodity Trading | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | -9,337,000 | [1] | -12,002,000 | [2] |
Fair Value Measured on a Recurring Basis | Counterparty Netting | Other Current Liabilities | Other Derivative Instrument | Electric Commodity | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | -17,685,000 | [1] | -8,210,000 | [2] |
Fair Value Measured on a Recurring Basis | Counterparty Netting | Other Current Liabilities | Other Derivative Instrument | Natural Gas Commodity | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | -74,000 | [1] | ' | |
Fair Value Measured on a Recurring Basis | Counterparty Netting | Other Noncurrent Liabilities | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | -2,408,000 | [1] | -9,087,000 | [2] |
Fair Value Measured on a Recurring Basis | Counterparty Netting | Other Noncurrent Liabilities | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 0 | [1] | ' | |
Fair Value Measured on a Recurring Basis | Counterparty Netting | Other Noncurrent Liabilities | Other Derivative Instrument | Commodity Trading | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | -2,408,000 | [1] | -9,087,000 | [2] |
Fair Value Measured on a Recurring Basis | Counterparty Netting | Other Noncurrent Liabilities | Other Derivative Instrument | Natural Gas Commodity | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 0 | [1] | ' | |
Fair Value, Measurements, Nonrecurring | Other Current Assets | Purchased Power Agreements | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 23,527,000 | [3] | 33,028,000 | [3] |
Fair Value, Measurements, Nonrecurring | Other Noncurrent Assets | Purchased Power Agreements | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 42,716,000 | [3] | 58,431,000 | [3] |
Fair Value, Measurements, Nonrecurring | Other Current Liabilities | Purchased Power Agreements | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 22,502,000 | [3] | 23,034,000 | [3] |
Fair Value, Measurements, Nonrecurring | Other Noncurrent Liabilities | Purchased Power Agreements | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | $186,711,000 | [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 Sept. 30, 2014. At Sept. 30, 2014, derivative assets and liabilities include no obligations to return cash collateral and the rights to reclaim cash collateral of $3.9 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 the 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_Sheet2
Fair Value of Financial Assets and Liabilities, Changes in Level 3 Commodity Derivatives (Details) (Commodity Contract, USD $) | 3 Months Ended | 9 Months Ended | ||||||
Sep. 30, 2014 | Sep. 30, 2013 | Sep. 30, 2014 | Sep. 30, 2013 | |||||
Commodity Contract | ' | ' | ' | ' | ||||
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward] | ' | ' | ' | ' | ||||
Balance at beginning of period | $105,394,000 | $47,218,000 | $41,660,000 | $16,649,000 | ||||
Purchases | 5,588,000 | 155,000 | 126,752,000 | 51,541,000 | ||||
Settlements | -20,032,000 | -9,342,000 | -107,451,000 | -30,294,000 | ||||
Transfers out of Level 3 | -1,093,000 | 0 | -1,093,000 | 0 | ||||
Gains recognized in earnings | 1,480,000 | [1] | 4,008,000 | [1] | 8,917,000 | [1] | 3,729,000 | [1] |
(Losses) gains recognized as regulatory assets and liabilities | -17,705,000 | -571,000 | 4,847,000 | -157,000 | ||||
Balance at end of period | 73,632,000 | 41,468,000 | 73,632,000 | 41,468,000 | ||||
Transfers into Level 3 | $0 | $0 | $0 | $0 | ||||
[1] | These amounts relate to commodity derivatives held at the end of the period. |
Recovered_Sheet3
Fair Value of Financial Assets and Liabilities, Fair Value of Long-Term Debt (Details) (USD $) | Sep. 30, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Carrying Amount | ' | ' |
Financial Liabilities, Balance Sheet Groupings [Abstract] | ' | ' |
Long-term debt, including current portion | $11,759,226 | $11,191,517 |
Fair Value | ' | ' |
Financial Liabilities, Balance Sheet Groupings [Abstract] | ' | ' |
Long-term debt, including current portion | $12,990,348 | $11,878,643 |
Other_Income_Expense_Net_Detai
Other Income (Expense), Net (Details) (USD $) | 3 Months Ended | 9 Months Ended | ||
In Thousands, unless otherwise specified | Sep. 30, 2014 | Sep. 30, 2013 | Sep. 30, 2014 | Sep. 30, 2013 |
Other Income and Expenses [Abstract] | ' | ' | ' | ' |
Interest income | $1,139 | $1,304 | $6,324 | $7,615 |
Other nonoperating income | 682 | 739 | 3,042 | 2,494 |
Insurance policy expense | -417 | -2,386 | -4,663 | -5,932 |
Other Nonoperating Expense | 0 | -61 | -16 | -246 |
Other income (expense), net | $1,404 | ($404) | $4,687 | $3,931 |
Segment_Information_Details
Segment Information (Details) (USD $) | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2014 | Sep. 30, 2013 | Sep. 30, 2014 | Sep. 30, 2013 | Dec. 31, 2013 | |
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' |
Equity investments in unconsolidated subsidiaries | $84,500,000 | ' | $84,500,000 | ' | $87,100,000 |
Operating revenues | 2,869,807,000 | 2,822,338,000 | 8,757,507,000 | 8,184,100,000 | ' |
Net income (loss) | 368,582,000 | 364,752,000 | 824,967,000 | 798,179,000 | ' |
Regulated Electric | ' | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' |
Operating revenues | 2,616,823,000 | 2,600,271,000 | 7,216,961,000 | 6,912,953,000 | ' |
Net income (loss) | 360,656,000 | 365,156,000 | 731,766,000 | 740,347,000 | ' |
Regulated Natural Gas | ' | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' |
Equity investments in unconsolidated subsidiaries | 84,500,000 | ' | 84,500,000 | ' | 87,100,000 |
Operating revenues | 237,246,000 | 206,464,000 | 1,490,431,000 | 1,218,438,000 | ' |
Net income (loss) | 3,996,000 | -174,000 | 96,629,000 | 80,698,000 | ' |
All Other | ' | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' |
Operating revenues | 16,807,000 | 17,055,000 | 56,344,000 | 55,827,000 | ' |
Net income (loss) | 3,930,000 | -230,000 | -3,428,000 | -22,866,000 | ' |
Operating Segments | ' | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' |
Operating revenues | 2,869,807,000 | 2,822,338,000 | 8,757,507,000 | 8,184,100,000 | ' |
Operating Segments | Regulated Electric | ' | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' |
Operating revenues | 2,616,351,000 | 2,599,925,000 | 7,215,699,000 | 6,911,998,000 | ' |
Operating Segments | Regulated Natural Gas | ' | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' |
Operating revenues | 236,649,000 | 205,358,000 | 1,485,464,000 | 1,216,275,000 | ' |
Operating Segments | All Other | ' | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' |
Operating revenues | 16,807,000 | 17,055,000 | 56,344,000 | 55,827,000 | ' |
Intersegment Eliminations | ' | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' |
Operating revenues | -1,069,000 | -1,452,000 | -6,229,000 | -3,118,000 | ' |
Intersegment Eliminations | Regulated Electric | ' | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' |
Operating revenues | 472,000 | 346,000 | 1,262,000 | 955,000 | ' |
Intersegment Eliminations | Regulated Natural Gas | ' | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' |
Operating revenues | 597,000 | 1,106,000 | 4,967,000 | 2,163,000 | ' |
Intersegment Eliminations | All Other | ' | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' |
Operating revenues | $0 | $0 | $0 | $0 | ' |
Earnings_Per_Share_Details
Earnings Per Share (Details) (USD $) | 3 Months Ended | 9 Months Ended | ||
In Thousands, except Per Share data, unless otherwise specified | Sep. 30, 2014 | Sep. 30, 2013 | Sep. 30, 2014 | Sep. 30, 2013 |
Dilutive Impact of Common Stock Equivalents on Earnings per Share (Abstract] | ' | ' | ' | ' |
Net income | $368,582 | $364,752 | $824,967 | $798,179 |
Basic earnings per share [Abstract] | ' | ' | ' | ' |
Earnings available to common shareholders | 368,582 | 364,752 | 824,967 | 798,179 |
Weighted average common shares outstanding - basic (in shares) | 506,082 | 498,149 | 502,983 | 495,256 |
Earnings available to common shareholders - basic (in dollars per share) | $0.73 | $0.73 | $1.64 | $1.61 |
Effect of dilutive securities [Abstract] | ' | ' | ' | ' |
Time based equity awards | 283 | 492 | 230 | 511 |
Diluted earnings per share [Abstract] | ' | ' | ' | ' |
Earnings available to common shareholders | $368,582 | $364,752 | $824,967 | $798,179 |
Weighted average common shares outstanding - diluted (in shares) | 506,365 | 498,641 | 503,213 | 495,767 |
Earnings available to common shareholders - diluted (in dollars per share) | $0.73 | $0.73 | $1.64 | $1.61 |
Benefit_Plans_and_Other_Postre2
Benefit Plans and Other Postretirement Benefits (Details) (USD $) | 1 Months Ended | 3 Months Ended | 9 Months Ended | ||
Jan. 31, 2014 | Sep. 30, 2014 | Sep. 30, 2013 | Sep. 30, 2014 | Sep. 30, 2013 | |
Plan | |||||
Pension Benefits | ' | ' | ' | ' | ' |
Components of Net Periodic Benefit Cost [Abstract] | ' | ' | ' | ' | ' |
Service cost | ' | $22,086,000 | $24,071,000 | $66,257,000 | $72,212,000 |
Interest cost | ' | 39,155,000 | 35,173,000 | 117,465,000 | 105,518,000 |
Expected return on plan assets | ' | -51,801,000 | -49,613,000 | -155,403,000 | -148,839,000 |
Amortization of transition obligation | ' | 0 | 0 | 0 | 0 |
Amortization of prior service (credit) cost | ' | -437,000 | 1,468,000 | -1,310,000 | 4,404,000 |
Amortization of net loss | ' | 29,191,000 | 36,038,000 | 87,572,000 | 108,114,000 |
Net periodic benefit cost | ' | 38,194,000 | 47,137,000 | 114,581,000 | 141,409,000 |
Costs not recognized due to the effects of regulation | ' | -6,605,000 | -12,986,000 | -20,261,000 | -27,922,000 |
Net benefit cost recognized for financial reporting | ' | 31,589,000 | 34,151,000 | 94,320,000 | 113,487,000 |
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 | 2,592,000 | 3,546,000 |
Interest cost | ' | 8,507,000 | 8,417,000 | 25,521,000 | 25,251,000 |
Expected return on plan assets | ' | -8,489,000 | -8,253,000 | -25,466,000 | -24,759,000 |
Amortization of transition obligation | ' | 0 | 206,000 | 0 | 618,000 |
Amortization of prior service (credit) cost | ' | -2,672,000 | -2,438,000 | -8,016,000 | -7,314,000 |
Amortization of net loss | ' | 2,935,000 | 5,646,000 | 8,805,000 | 16,938,000 |
Net periodic benefit cost | ' | 1,145,000 | 4,760,000 | 3,436,000 | 14,280,000 |
Costs not recognized due to the effects of regulation | ' | 0 | 0 | 0 | 0 |
Net benefit cost recognized for financial reporting | ' | $1,145,000 | $4,760,000 | $3,436,000 | $14,280,000 |
Other_Comprehensive_Income_Det
Other Comprehensive Income (Details) (USD $) | 3 Months Ended | 9 Months Ended | ||||||
In Thousands, unless otherwise specified | Sep. 30, 2014 | Sep. 30, 2013 | Sep. 30, 2014 | Sep. 30, 2013 | ||||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | ' | ' | ' | ' | ||||
Accumulated other comprehensive income (loss) at beginning of period | ($103,366) | ($111,835) | ($106,275) | ($112,653) | ||||
Other comprehensive income (loss) before reclassifications | -40 | 137 | 6 | 70 | ||||
(Gains) losses reclassified from net accumulated other comprehensive loss | 1,405 | 1,718 | 4,268 | 2,603 | ||||
Net current period other comprehensive income (loss) | 1,365 | 1,855 | 4,274 | 2,673 | ||||
Accumulated other comprehensive income (loss) at end of period | -102,001 | -109,980 | -102,001 | -109,980 | ||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | ' | ' | ' | ' | ||||
Operating and maintenance expenses | 568,391 | 575,305 | 1,714,138 | 1,667,093 | ||||
Total, pre-tax | -564,551 | -558,101 | -1,260,965 | -1,208,855 | ||||
Tax benefit | 195,969 | 193,349 | 435,998 | 410,676 | ||||
Amounts Reclassified from Accumulated Other Comprehensive Loss | ' | ' | ' | ' | ||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | ' | ' | ' | ' | ||||
Total, net of tax | 1,405 | 1,718 | 4,268 | 2,603 | ||||
Gains and Losses on Cash Flow Hedges | ' | ' | ' | ' | ||||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | ' | ' | ' | ' | ||||
Accumulated other comprehensive income (loss) at beginning of period | -58,610 | -60,883 | -59,753 | -61,241 | ||||
Other comprehensive income (loss) before reclassifications | -42 | 22 | -34 | -9 | ||||
(Gains) losses reclassified from net accumulated other comprehensive loss | 558 | 539 | 1,693 | 928 | ||||
Net current period other comprehensive income (loss) | 516 | 561 | 1,659 | 919 | ||||
Accumulated other comprehensive income (loss) at end of period | -58,094 | -60,322 | -58,094 | -60,322 | ||||
Gains and Losses on Cash Flow Hedges | Amounts Reclassified from Accumulated Other Comprehensive Loss | ' | ' | ' | ' | ||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | ' | ' | ' | ' | ||||
Total, pre-tax | 951 | 805 | 2,808 | 3,073 | ||||
Tax benefit | -393 | -266 | -1,115 | -2,145 | ||||
Total, net of tax | 558 | 539 | 1,693 | 928 | ||||
Gains and Losses on Cash Flow Hedges | Interest Rate Derivatives | Amounts Reclassified from Accumulated Other Comprehensive Loss | ' | ' | ' | ' | ||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | ' | ' | ' | ' | ||||
Interest charges | 967 | [1] | 829 | [1] | 2,869 | [1] | 3,140 | [1] |
Gains and Losses on Cash Flow Hedges | Vehicle Fuel Derivatives | Amounts Reclassified from Accumulated Other Comprehensive Loss | ' | ' | ' | ' | ||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | ' | ' | ' | ' | ||||
Operating and maintenance expenses | -16 | [2] | -24 | [2] | -61 | [2] | -67 | [2] |
Unrealized Gains and Losses on Marketable Securities | ' | ' | ' | ' | ||||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | ' | ' | ' | ' | ||||
Accumulated other comprehensive income (loss) at beginning of period | 115 | -135 | 77 | -99 | ||||
Other comprehensive income (loss) before reclassifications | 2 | 115 | 40 | 79 | ||||
(Gains) losses reclassified from net accumulated other comprehensive loss | 0 | 0 | 0 | 0 | ||||
Net current period other comprehensive income (loss) | 2 | 115 | 40 | 79 | ||||
Accumulated other comprehensive income (loss) at end of period | 117 | -20 | 117 | -20 | ||||
Defined Benefit Pension and Postretirement Items | ' | ' | ' | ' | ||||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | ' | ' | ' | ' | ||||
Accumulated other comprehensive income (loss) at beginning of period | -44,871 | -50,817 | -46,599 | -51,313 | ||||
Other comprehensive income (loss) before reclassifications | 0 | 0 | 0 | 0 | ||||
(Gains) losses reclassified from net accumulated other comprehensive loss | 847 | 1,179 | 2,575 | 1,675 | ||||
Net current period other comprehensive income (loss) | 847 | 1,179 | 2,575 | 1,675 | ||||
Accumulated other comprehensive income (loss) at end of period | -44,024 | -49,638 | -44,024 | -49,638 | ||||
Defined Benefit Pension and Postretirement Items | Amounts Reclassified from Accumulated Other Comprehensive Loss | ' | ' | ' | ' | ||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | ' | ' | ' | ' | ||||
Amortization of net loss | 1,500 | [3] | 1,770 | [3] | 4,499 | [3] | 5,308 | [3] |
Prior service (credit) cost | -86 | [3] | 93 | [3] | -258 | [3] | 279 | [3] |
Transition obligation | 0 | [3] | 2 | [3] | 0 | [3] | 6 | [3] |
Total, pre-tax | 1,414 | 1,865 | 4,241 | 5,593 | ||||
Tax benefit | -567 | -686 | -1,666 | -3,918 | ||||
Total, net of tax | $847 | $1,179 | $2,575 | $1,675 | ||||
[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. |