Document_and_Entity_Informatio
Document and Entity Information (USD $) | 12 Months Ended | |||
Dec. 31, 2013 | Feb. 17, 2014 | Jun. 30, 2013 | Dec. 31, 2012 | |
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 Public Float | ' | ' | $14,093,360,676 | ' |
Entity Common Stock, Shares Outstanding | ' | 498,288,164 | ' | ' |
Common Stock, Shares Outstanding (in shares) | 497,971,508 | ' | 497,295,719 | 487,959,516 |
Document Fiscal Year Focus | '2013 | ' | ' | ' |
Document Fiscal Period Focus | 'FY | ' | ' | ' |
Document Type | '10-K | ' | ' | ' |
Amendment Flag | 'false | ' | ' | ' |
Document Period End Date | 31-Dec-13 | ' | ' | ' |
CONSOLIDATED_STATEMENTS_OF_INC
CONSOLIDATED STATEMENTS OF INCOME (USD $) | 12 Months Ended | ||
In Thousands, except Per Share data, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Operating revenues | ' | ' | ' |
Electric | $9,034,045 | $8,517,296 | $8,766,593 |
Natural gas | 1,804,679 | 1,537,374 | 1,811,926 |
Other | 76,198 | 73,553 | 76,251 |
Total operating revenues | 10,914,922 | 10,128,223 | 10,654,770 |
Operating expenses | ' | ' | ' |
Electric fuel and purchased power | 4,018,672 | 3,623,935 | 3,991,786 |
Cost of natural gas sold and transported | 1,082,751 | 880,939 | 1,163,890 |
Cost of sales — other | 33,323 | 29,067 | 30,391 |
Operating and maintenance expenses | 2,273,532 | 2,176,095 | 2,140,289 |
Conservation and demand side management program expenses | 260,726 | 260,527 | 281,378 |
Depreciation and amortization | 977,863 | 926,053 | 890,619 |
Taxes (other than income taxes) | 420,500 | 408,924 | 374,815 |
Total operating expenses | 9,067,367 | 8,305,540 | 8,873,168 |
Operating income | 1,847,555 | 1,822,683 | 1,781,602 |
Other income, net | 2,972 | 6,175 | 9,255 |
Equity earnings of unconsolidated subsidiaries | 30,020 | 29,971 | 30,527 |
Allowance for funds used during construction — equity | 87,683 | 62,840 | 51,223 |
Interest charges and financing costs | ' | ' | ' |
Interest charges — includes other financing costs of $30,135, $24,087 and $24,019, respectively | 575,199 | 601,552 | 591,300 |
Allowance for funds used during construction — debt | -39,179 | -35,315 | -28,181 |
Total interest charges and financing costs | 536,020 | 566,237 | 563,119 |
Income before income taxes | 1,432,210 | 1,355,432 | 1,309,488 |
Income taxes | 483,976 | 450,203 | 468,316 |
Net income | 948,234 | 905,229 | 841,172 |
Dividend requirements on preferred stock | 0 | 0 | 3,534 |
Premium on redemption of preferred stock | 0 | 0 | 3,260 |
Earnings available to common shareholders | $948,234 | $905,229 | $834,378 |
Weighted average common shares outstanding: | ' | ' | ' |
Basic (in shares) | 496,073 | 487,899 | 485,039 |
Diluted (in shares) | 496,532 | 488,434 | 485,615 |
Earnings per average common share: | ' | ' | ' |
Basic (in dollars per share) | $1.91 | $1.86 | $1.72 |
Diluted (in dollars per share) | $1.91 | $1.85 | $1.72 |
Cash dividends declared per common share (in dollars per share) | $1.11 | $1.07 | $1.03 |
CONSOLIDATED_STATEMENTS_OF_INC1
CONSOLIDATED STATEMENTS OF INCOME (Parenthetical) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Interest charges and financing costs | ' | ' | ' |
Other financing costs | $30,135 | $24,087 | $24,019 |
CONSOLIDATED_STATEMENTS_OF_COM
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Comprehensive income: | ' | ' | ' |
Net income | $948,234 | $905,229 | $841,172 |
Pension and retiree medical benefits: | ' | ' | ' |
Net pension and retiree medical benefit gains (losses) arising during the period, net of tax of $1,746, $(4,898) and $(4,442), respectively | 1,408 | -7,005 | -6,367 |
Amortization of losses included in net periodic benefit cost, net of tax of $4,151, $2,567 and $2,195, respectively | 3,306 | 3,694 | 3,162 |
Total pension and retiree medical benefits, net of tax | 4,714 | -3,311 | -3,205 |
Derivative instruments: | ' | ' | ' |
Net fair value increase (decrease), net of tax of $17, $(12,593) and $(25,086), respectively | 12 | -19,200 | -38,292 |
Reclassification of losses to net income, net of tax of $2,541, $2,687 and $598, respectively | 1,476 | 3,697 | 648 |
Total derivative instruments, net of tax | 1,488 | -15,503 | -37,644 |
Marketable securities: | ' | ' | ' |
Net fair value increase (decrease), net of tax of $117, $135 and $(63), respectively | 176 | 196 | -93 |
Other comprehensive income (loss) | 6,378 | -18,618 | -40,942 |
Comprehensive income | $954,612 | $886,611 | $800,230 |
CONSOLIDATED_STATEMENTS_OF_COM1
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Pension and retiree medical benefits: | ' | ' | ' |
Net pension and retiree medical benefit gains (losses) arising during the period, tax | $1,746 | ($4,898) | ($4,442) |
Amortization of losses included in net periodic benefit cost, tax | 4,151 | 2,567 | 2,195 |
Derivative instruments: | ' | ' | ' |
Net fair value increase (decrease), tax | 17 | -12,593 | -25,086 |
Reclassification of losses to net income, tax | 2,541 | 2,687 | 598 |
Marketable securities: | ' | ' | ' |
Net fair value increase (decrease), tax | $117 | $135 | ($63) |
CONSOLIDATED_STATEMENTS_OF_CAS
CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Operating activities | ' | ' | ' |
Net income | $948,234 | $905,229 | $841,172 |
Adjustments to reconcile net income to cash provided by operating activities: | ' | ' | ' |
Depreciation and amortization | 1,001,843 | 943,702 | 908,853 |
Conservation and demand side management program amortization | 6,531 | 7,258 | 9,816 |
Nuclear fuel amortization | 98,089 | 102,651 | 100,902 |
Deferred income taxes | 515,062 | 508,094 | 466,567 |
Amortization of investment tax credits | -5,753 | -6,610 | -6,194 |
Allowance for equity funds used during construction | -87,683 | -62,840 | -51,223 |
Equity earnings of unconsolidated subsidiaries | -30,020 | -29,971 | -30,527 |
Dividends from unconsolidated subsidiaries | 36,416 | 33,470 | 34,034 |
Provision for bad debts | 37,627 | 33,808 | 44,521 |
Share-based compensation expense | 24,613 | 26,970 | 45,006 |
Gain on sale of transmission assets | -13,661 | 0 | 0 |
Prairie Island EPU and SmartGridCity | 0 | 20,766 | 0 |
Net realized and unrealized hedging and derivative transactions | -4,704 | -85,308 | 9,966 |
Changes in operating assets and liabilities: | ' | ' | ' |
Accounts receivable | -108,911 | -197,236 | -79,701 |
Accrued unbilled revenues | -23,867 | 25,377 | 19,951 |
Inventories | -43,588 | 82,658 | -57,432 |
Other current assets | -18,071 | -30,737 | 62,660 |
Accounts payable | 132,441 | -100,327 | 13,748 |
Net regulatory assets and liabilities | 141,325 | 5,866 | 149,282 |
Other current liabilities | 126,555 | 42,914 | 112,353 |
Pension and other employee benefit obligations | -156,369 | -183,922 | -150,717 |
Change in other noncurrent assets | -9,998 | -33,151 | 24,069 |
Change in other noncurrent liabilities | 17,925 | -3,905 | -61,584 |
Net cash provided by operating activities | 2,584,036 | 2,004,756 | 2,405,522 |
Investing activities | ' | ' | ' |
Utility capital/construction expenditures | -3,395,325 | -2,570,209 | -2,205,567 |
Proceeds from sale of transmission assets | 37,118 | 0 | 0 |
Proceeds from insurance recoveries | 90,000 | 97,835 | 0 |
Allowance for equity funds used during construction | 87,683 | 62,840 | 51,223 |
Merricourt refund | 0 | 0 | 101,261 |
Merricourt deposit | 0 | 0 | -90,833 |
Purchases of investments in external decommissioning fund | -1,481,881 | -1,102,025 | -2,098,642 |
Proceeds from the sale of investments in external decommissioning fund | 1,461,291 | 1,087,076 | 2,098,642 |
Investment in WYCO Development LLC | -7,504 | -980 | -2,446 |
Change in restricted cash | 0 | 95,287 | -95,287 |
Other, net | -4,766 | -2,766 | -6,152 |
Net cash used in investing activities | -3,213,384 | -2,332,942 | -2,247,801 |
Financing activities | ' | ' | ' |
Proceeds from (repayments of) short-term borrowings, net | 157,000 | 383,000 | -247,400 |
Proceeds from issuance of long-term debt | 1,431,895 | 1,790,131 | 688,598 |
Repayments of long-term debt, including reacquisition premiums | -652,451 | -1,302,763 | -105,623 |
Proceeds from issuance of common stock | 231,767 | 8,050 | 38,691 |
Repurchase of common stock | 0 | -18,529 | 0 |
Purchase of common stock for settlement of equity awards | 0 | -23,307 | 0 |
Redemption of preferred stock | 0 | 0 | -104,980 |
Dividends paid | -514,042 | -486,757 | -474,760 |
Net cash provided by (used in) financing activities | 654,169 | 349,825 | -205,474 |
Net change in cash and cash equivalents | 24,821 | 21,639 | -47,753 |
Cash and cash equivalents at beginning of period | 82,323 | 60,684 | 108,437 |
Cash and cash equivalents at end of period | 107,144 | 82,323 | 60,684 |
Supplemental disclosure of cash flow information: | ' | ' | ' |
Cash paid for interest (net of amounts capitalized) | -514,911 | -563,517 | -531,148 |
Cash received (paid) for income taxes, net | 17,188 | -9,570 | 55,764 |
Supplemental disclosure of non-cash investing and financing transactions: | ' | ' | ' |
Property, plant and equipment additions in accounts payable | 452,453 | 289,802 | 137,558 |
Issuance of common stock for reinvested dividends and 401(k) plans | $56,950 | $67,723 | $71,715 |
CONSOLIDATED_BALANCE_SHEETS
CONSOLIDATED BALANCE SHEETS (USD $) | Dec. 31, 2013 | Dec. 31, 2012 |
In Thousands, unless otherwise specified | ||
Current assets | ' | ' |
Cash and cash equivalents | $107,144 | $82,323 |
Accounts receivable, net | 744,160 | 718,046 |
Accrued unbilled revenues | 687,230 | 663,363 |
Inventories | 576,538 | 535,574 |
Regulatory assets | 417,801 | 352,977 |
Derivative instruments | 91,707 | 69,013 |
Deferred income taxes | 341,202 | 32,528 |
Prepayments and other | 252,258 | 171,315 |
Total current assets | 3,218,040 | 2,625,139 |
Property, plant and equipment, net | 26,122,159 | 23,809,348 |
Other assets | ' | ' |
Nuclear decommissioning fund and other investments | 1,755,990 | 1,617,865 |
Regulatory assets | 2,509,218 | 2,762,029 |
Derivative instruments | 84,842 | 126,297 |
Other | 217,241 | 200,008 |
Total other assets | 4,567,291 | 4,706,199 |
Total assets | 33,907,490 | 31,140,686 |
Current liabilities | ' | ' |
Current portion of long-term debt | 280,763 | 258,155 |
Short-term debt | 759,000 | 602,000 |
Accounts payable | 1,261,238 | 959,093 |
Regulatory liabilities | 274,769 | 168,858 |
Taxes accrued | 378,766 | 334,441 |
Accrued interest | 159,372 | 162,494 |
Dividends payable | 139,432 | 131,748 |
Derivative instruments | 23,382 | 32,482 |
Other | 377,776 | 287,802 |
Total current liabilities | 3,654,498 | 2,937,073 |
Deferred credits and other liabilities | ' | ' |
Deferred income taxes | 5,331,046 | 4,434,909 |
Deferred investment tax credits | 79,239 | 82,761 |
Regulatory liabilities | 1,059,395 | 1,059,939 |
Asset retirement obligations | 1,815,390 | 1,719,796 |
Derivative instruments | 209,224 | 242,866 |
Customer advances | 275,555 | 252,888 |
Pension and employee benefit obligations | 769,222 | 1,163,265 |
Other | 237,217 | 229,207 |
Total deferred credits and other liabilities | 9,776,288 | 9,185,631 |
Commitments and contingencies | ' | ' |
Capitalization | ' | ' |
Long-term debt | 10,910,754 | 10,143,905 |
Common stock — 1,000,000,000 shares authorized of $2.50 par value; 497,971,508 and 487,959,516 shares outstanding at Dec. 31, 2013 and 2012, respectively | 1,244,929 | 1,219,899 |
Additional paid in capital | 5,619,313 | 5,353,015 |
Retained earnings | 2,807,983 | 2,413,816 |
Accumulated other comprehensive loss | -106,275 | -112,653 |
Total common stockholders’ equity | 9,565,950 | 8,874,077 |
Total liabilities and equity | $33,907,490 | $31,140,686 |
CONSOLIDATED_BALANCE_SHEETS_Pa
CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $) | Dec. 31, 2013 | Jun. 30, 2013 | Dec. 31, 2012 |
Capitalization | ' | ' | ' |
Common stock, shares authorized (in shares) | 1,000,000,000 | ' | 1,000,000,000 |
Common stock, par value (in dollars per share) | $2.50 | ' | $2.50 |
Common stock, shares outstanding (in shares) | 497,971,508 | 497,295,719 | 487,959,516 |
CONSOLIDATED_STATEMENTS_OF_COM2
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY (USD $) | Total | Common stock | Additional Paid In Capital | Retained Earnings | Accumulated Other Comprehensive Loss |
In Thousands, except Share data, unless otherwise specified | |||||
Balance at Dec. 31, 2010 | $8,083,519 | $1,205,834 | $5,229,075 | $1,701,703 | ($53,093) |
Balance (in shares) at Dec. 31, 2010 | ' | 482,334,000 | ' | ' | ' |
Increase (Decrease) in Stockholders' Equity | ' | ' | ' | ' | ' |
Net income | 841,172 | ' | ' | 841,172 | ' |
Other comprehensive income (loss) | -40,942 | ' | ' | ' | -40,942 |
Dividends declared: | ' | ' | ' | ' | ' |
Dividends, Preferred Stock, Cash | -3,534 | ' | ' | -3,534 | ' |
Common stock | -503,525 | ' | ' | -503,525 | ' |
Preferred Stock Redemption Premium | -3,260 | ' | ' | -3,260 | ' |
Issuances of common stock | 64,914 | 10,400 | 54,514 | ' | ' |
Issuances of common stock (in shares) | ' | 4,160,000 | ' | ' | ' |
Share-based compensation | 43,854 | ' | 43,854 | ' | ' |
Balance at Dec. 31, 2011 | 8,482,198 | 1,216,234 | 5,327,443 | 2,032,556 | -94,035 |
Balance (in shares) at Dec. 31, 2011 | ' | 486,494,000 | ' | ' | ' |
Increase (Decrease) in Stockholders' Equity | ' | ' | ' | ' | ' |
Net income | 905,229 | ' | ' | 905,229 | ' |
Other comprehensive income (loss) | -18,618 | ' | ' | ' | -18,618 |
Dividends declared: | ' | ' | ' | ' | ' |
Common stock | -523,969 | ' | ' | -523,969 | ' |
Preferred Stock Redemption Premium | 0 | ' | ' | ' | ' |
Issuances of common stock | 33,634 | 5,415 | 28,219 | ' | ' |
Issuances of common stock (in shares) | ' | 2,166,000 | ' | ' | ' |
Repurchase of common stock | -18,529 | -1,750 | -16,779 | ' | ' |
Repurchase of common stock (in shares) | ' | -700,000 | ' | ' | ' |
Purchase of common stock for settlement of equity awards | -23,307 | ' | -23,307 | ' | ' |
Share-based compensation | 37,439 | ' | 37,439 | ' | ' |
Balance at Dec. 31, 2012 | 8,874,077 | 1,219,899 | 5,353,015 | 2,413,816 | -112,653 |
Balance (in shares) at Dec. 31, 2012 | 487,959,516 | 487,960,000 | ' | ' | ' |
Increase (Decrease) in Stockholders' Equity | ' | ' | ' | ' | ' |
Net income | 948,234 | ' | ' | 948,234 | ' |
Other comprehensive income (loss) | 6,378 | ' | ' | ' | 6,378 |
Dividends declared: | ' | ' | ' | ' | ' |
Common stock | -554,067 | ' | ' | -554,067 | ' |
Preferred Stock Redemption Premium | 0 | ' | ' | ' | ' |
Issuances of common stock | 262,701 | 25,030 | 237,671 | ' | ' |
Issuances of common stock (in shares) | ' | 10,012,000 | ' | ' | ' |
Share-based compensation | 28,627 | ' | 28,627 | ' | ' |
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 | ' | ' | ' |
CONSOLIDATED_STATEMENTS_OF_CAP
CONSOLIDATED STATEMENTS OF CAPITALIZATION (USD $) | Dec. 31, 2013 | Dec. 31, 2012 |
In Thousands, unless otherwise specified | ||
Schedule of Capitalization, Long-term Debt [Line Items] | ' | ' |
Less current maturities | $280,763 | $258,155 |
Long-term debt, noncurrent | 10,910,754 | 10,143,905 |
Common Stockholders' Equity | ' | ' |
Common stock — 1,000,000,000 shares authorized of $2.50 par value; 497,971,508 and 487,959,516 shares outstanding at Dec. 31, 2013 and 2012, respectively | 1,244,929 | 1,219,899 |
Additional paid in capital | 5,619,313 | 5,353,015 |
Retained earnings | 2,807,983 | 2,413,816 |
Accumulated other comprehensive loss | -106,275 | -112,653 |
Total common stockholders’ equity | 9,565,950 | 8,874,077 |
NSP-Minnesota | ' | ' |
Schedule of Capitalization, Long-term Debt [Line Items] | ' | ' |
Unamortized discount | -11,316 | -11,362 |
Long-term Debt | 3,888,732 | 3,488,640 |
Less current maturities | 2 | 2 |
Long-term debt, noncurrent | 3,888,730 | 3,488,638 |
NSP-Minnesota | First Mortgage Bonds | Series Due Aug. 15, 2015 [Member] | ' | ' |
Schedule of Capitalization, Long-term Debt [Line Items] | ' | ' |
Long-term Debt, Gross | 250,000 | 250,000 |
NSP-Minnesota | First Mortgage Bonds | Series Due March 1, 2018 [Member] | ' | ' |
Schedule of Capitalization, Long-term Debt [Line Items] | ' | ' |
Long-term Debt, Gross | 500,000 | 500,000 |
NSP-Minnesota | First Mortgage Bonds | Series Due Aug. 15, 2022 [Member] | ' | ' |
Schedule of Capitalization, Long-term Debt [Line Items] | ' | ' |
Long-term Debt, Gross | 300,000 | 300,000 |
NSP-Minnesota | First Mortgage Bonds | Series Due May 15, 2023 | ' | ' |
Schedule of Capitalization, Long-term Debt [Line Items] | ' | ' |
Long-term Debt, Gross | 400,000 | 0 |
NSP-Minnesota | First Mortgage Bonds | Series Due July 1, 2025 [Member] | ' | ' |
Schedule of Capitalization, Long-term Debt [Line Items] | ' | ' |
Long-term Debt, Gross | 250,000 | 250,000 |
NSP-Minnesota | First Mortgage Bonds | Series Due March 1, 2028 [Member] | ' | ' |
Schedule of Capitalization, Long-term Debt [Line Items] | ' | ' |
Long-term Debt, Gross | 150,000 | 150,000 |
NSP-Minnesota | First Mortgage Bonds | Series Due July 15, 2035 [Member] | ' | ' |
Schedule of Capitalization, Long-term Debt [Line Items] | ' | ' |
Long-term Debt, Gross | 250,000 | 250,000 |
NSP-Minnesota | First Mortgage Bonds | Series Due June 1, 2036 [Member] | ' | ' |
Schedule of Capitalization, Long-term Debt [Line Items] | ' | ' |
Long-term Debt, Gross | 400,000 | 400,000 |
NSP-Minnesota | First Mortgage Bonds | Series Due July 1, 2037 [Member] | ' | ' |
Schedule of Capitalization, Long-term Debt [Line Items] | ' | ' |
Long-term Debt, Gross | 350,000 | 350,000 |
NSP-Minnesota | First Mortgage Bonds | Series Due Nov. 1, 2039 [Member] | ' | ' |
Schedule of Capitalization, Long-term Debt [Line Items] | ' | ' |
Long-term Debt, Gross | 300,000 | 300,000 |
NSP-Minnesota | First Mortgage Bonds | Series Due Aug. 15, 2040 [Member] | ' | ' |
Schedule of Capitalization, Long-term Debt [Line Items] | ' | ' |
Long-term Debt, Gross | 250,000 | 250,000 |
NSP-Minnesota | First Mortgage Bonds | Series Due Aug. 15, 2042 | ' | ' |
Schedule of Capitalization, Long-term Debt [Line Items] | ' | ' |
Long-term Debt, Gross | 500,000 | 500,000 |
NSP-Minnesota | Other | ' | ' |
Schedule of Capitalization, Long-term Debt [Line Items] | ' | ' |
Long-term Debt, Gross | 48 | 2 |
PSCo | ' | ' |
Schedule of Capitalization, Long-term Debt [Line Items] | ' | ' |
Unamortized discount | -11,301 | -9,468 |
Total long-term debt | 3,872,643 | 3,630,773 |
Less current maturities | 282,143 | 256,297 |
Long-term debt, noncurrent | 3,590,500 | 3,374,476 |
PSCo | First Mortgage Bonds | Series Due March 1, 2013 [Member] | ' | ' |
Schedule of Capitalization, Long-term Debt [Line Items] | ' | ' |
Long-term Debt, Gross | 0 | 250,000 |
PSCo | First Mortgage Bonds | Series Due April 1, 2014 [Member] | ' | ' |
Schedule of Capitalization, Long-term Debt [Line Items] | ' | ' |
Long-term Debt, Gross | 275,000 | 275,000 |
PSCo | First Mortgage Bonds | Series Due Sept. 1, 2017 [Member] | ' | ' |
Schedule of Capitalization, Long-term Debt [Line Items] | ' | ' |
Long-term Debt, Gross | 129,500 | 129,500 |
PSCo | First Mortgage Bonds | Series Due Aug. 1, 2018 [Member] | ' | ' |
Schedule of Capitalization, Long-term Debt [Line Items] | ' | ' |
Long-term Debt, Gross | 300,000 | 300,000 |
PSCo | First Mortgage Bonds | Series Due June 1, 2019 [Member] | ' | ' |
Schedule of Capitalization, Long-term Debt [Line Items] | ' | ' |
Long-term Debt, Gross | 400,000 | 400,000 |
PSCo | First Mortgage Bonds | Series Due Nov. 15, 2020 [Member] | ' | ' |
Schedule of Capitalization, Long-term Debt [Line Items] | ' | ' |
Long-term Debt, Gross | 400,000 | 400,000 |
PSCo | First Mortgage Bonds | Series Due Sept. 15, 2022 | ' | ' |
Schedule of Capitalization, Long-term Debt [Line Items] | ' | ' |
Long-term Debt, Gross | 300,000 | 300,000 |
PSCo | First Mortgage Bonds | Series Due March 15, 2023 | ' | ' |
Schedule of Capitalization, Long-term Debt [Line Items] | ' | ' |
Long-term Debt, Gross | 250,000 | 0 |
PSCo | First Mortgage Bonds | Series Due Sept. 1, 2037 [Member] | ' | ' |
Schedule of Capitalization, Long-term Debt [Line Items] | ' | ' |
Long-term Debt, Gross | 350,000 | 350,000 |
PSCo | First Mortgage Bonds | Series Due Aug. 1, 2038 [Member] | ' | ' |
Schedule of Capitalization, Long-term Debt [Line Items] | ' | ' |
Long-term Debt, Gross | 300,000 | 300,000 |
PSCo | First Mortgage Bonds | Series Due Aug. 15, 2041 | ' | ' |
Schedule of Capitalization, Long-term Debt [Line Items] | ' | ' |
Long-term Debt, Gross | 250,000 | 250,000 |
PSCo | First Mortgage Bonds | Series Due Sept. 15, 2042 | ' | ' |
Schedule of Capitalization, Long-term Debt [Line Items] | ' | ' |
Long-term Debt, Gross | 500,000 | 500,000 |
PSCo | First Mortgage Bonds | Series Due March 15, 2043 | ' | ' |
Schedule of Capitalization, Long-term Debt [Line Items] | ' | ' |
Long-term Debt, Gross | 250,000 | 0 |
PSCo | Capital Lease Obligations [Member] | ' | ' |
Schedule of Capitalization, Long-term Debt [Line Items] | ' | ' |
Capital lease obligations | 179,444 | 185,741 |
SPS | ' | ' |
Schedule of Capitalization, Long-term Debt [Line Items] | ' | ' |
Unamortized discount | -135 | 3,684 |
Long-term Debt | 1,199,865 | 1,103,684 |
Less current maturities | 0 | 0 |
Long-term debt, noncurrent | 1,199,865 | 1,103,684 |
SPS | First Mortgage Bonds | Series Due Aug. 15, 2041 | ' | ' |
Schedule of Capitalization, Long-term Debt [Line Items] | ' | ' |
Long-term Debt, Gross | 400,000 | 300,000 |
SPS | Senior Unsecured Notes | Senior E Due Oct. 1, 2016 [Member] | ' | ' |
Schedule of Capitalization, Long-term Debt [Line Items] | ' | ' |
Long-term Debt, Gross | 200,000 | 200,000 |
SPS | Senior Unsecured Notes | Senior G Due Dec. 1, 2018 [Member] | ' | ' |
Schedule of Capitalization, Long-term Debt [Line Items] | ' | ' |
Long-term Debt, Gross | 250,000 | 250,000 |
SPS | Senior Unsecured Notes | Senior C and D Due Oct. 1, 2033 [Member] | ' | ' |
Schedule of Capitalization, Long-term Debt [Line Items] | ' | ' |
Long-term Debt, Gross | 100,000 | 100,000 |
SPS | Senior Unsecured Notes | Senior F Due Oct. 1, 2036 [Member] | ' | ' |
Schedule of Capitalization, Long-term Debt [Line Items] | ' | ' |
Long-term Debt, Gross | 250,000 | 250,000 |
NSP-Wisconsin | ' | ' |
Schedule of Capitalization, Long-term Debt [Line Items] | ' | ' |
Unamortized discount | -2,321 | -2,457 |
Long-term Debt | 468,597 | 468,563 |
Less current maturities | 107 | 1,246 |
Long-term debt, noncurrent | 468,490 | 467,317 |
NSP-Wisconsin | First Mortgage Bonds | Series Due Oct. 1, 2018 [Member] | ' | ' |
Schedule of Capitalization, Long-term Debt [Line Items] | ' | ' |
Long-term Debt, Gross | 150,000 | 150,000 |
NSP-Wisconsin | First Mortgage Bonds | Series Due Sept. 1, 2038 [Member] | ' | ' |
Schedule of Capitalization, Long-term Debt [Line Items] | ' | ' |
Long-term Debt, Gross | 200,000 | 200,000 |
NSP-Wisconsin | First Mortgage Bonds | Series Due Oct. 1, 2042 | ' | ' |
Schedule of Capitalization, Long-term Debt [Line Items] | ' | ' |
Long-term Debt, Gross | 100,000 | 100,000 |
NSP-Wisconsin | City of La Crosse Resource Recovery Bond [Member] | Series Due Nov. 1, 2021 [Member] | ' | ' |
Schedule of Capitalization, Long-term Debt [Line Items] | ' | ' |
Long-term Debt, Gross | 18,600 | 18,600 |
NSP-Wisconsin | Fort McCoy System Acquisition [Member] | Due Oct. 15, 2030 [Member] | ' | ' |
Schedule of Capitalization, Long-term Debt [Line Items] | ' | ' |
Long-term Debt, Gross | 558 | 591 |
NSP-Wisconsin | Other | ' | ' |
Schedule of Capitalization, Long-term Debt [Line Items] | ' | ' |
Long-term Debt, Gross | 1,760 | 1,829 |
Other Subsidiaries | ' | ' |
Schedule of Capitalization, Long-term Debt [Line Items] | ' | ' |
Long-term Debt | 37,490 | 39,984 |
Less current maturities | 1,128 | 2,881 |
Long-term debt, noncurrent | 36,362 | 37,103 |
Other Subsidiaries | Various Eloigne Co. Affordable Housing Project Notes [Member] | Due 2014-2050 [Member] | ' | ' |
Schedule of Capitalization, Long-term Debt [Line Items] | ' | ' |
Long-term Debt, Gross | 37,490 | 39,984 |
Xcel Energy Inc. | ' | ' |
Schedule of Capitalization, Long-term Debt [Line Items] | ' | ' |
Unamortized discount | -7,702 | -9,205 |
Total long-term debt | 1,724,190 | 1,670,416 |
Less current maturities | -2,617 | -2,271 |
Long-term debt, noncurrent | 1,796,276 | 1,744,774 |
Long-term debt, noncurrent | 1,726,807 | 1,672,687 |
Common Stockholders' Equity | ' | ' |
Total common stockholders’ equity | 9,565,950 | 8,874,077 |
Xcel Energy Inc. | Senior Unsecured Notes | Series Due May 9, 2016 | ' | ' |
Schedule of Capitalization, Long-term Debt [Line Items] | ' | ' |
Long-term Debt, Gross | 450,000 | 0 |
Xcel Energy Inc. | Senior Unsecured Notes | Series Due April 1, 2017 [Member] | ' | ' |
Schedule of Capitalization, Long-term Debt [Line Items] | ' | ' |
Long-term Debt, Gross | 253,979 | 253,979 |
Xcel Energy Inc. | Senior Unsecured Notes | Series Due May 15, 2020 [Member] | ' | ' |
Schedule of Capitalization, Long-term Debt [Line Items] | ' | ' |
Long-term Debt, Gross | 550,000 | 550,000 |
Xcel Energy Inc. | Senior Unsecured Notes | Series Due July 1, 2036 [Member] | ' | ' |
Schedule of Capitalization, Long-term Debt [Line Items] | ' | ' |
Long-term Debt, Gross | 300,000 | 300,000 |
Xcel Energy Inc. | Senior Unsecured Notes | Series Due Sept. 15, 2041 [Member] | ' | ' |
Schedule of Capitalization, Long-term Debt [Line Items] | ' | ' |
Long-term Debt, Gross | 250,000 | 250,000 |
Xcel Energy Inc. | Junior Subordinated Notes | Series Due Jan. 1, 2068 [Member] | ' | ' |
Schedule of Capitalization, Long-term Debt [Line Items] | ' | ' |
Long-term Debt, Gross | 0 | 400,000 |
Xcel Energy Inc. | Capital Lease Obligations [Member] | ' | ' |
Schedule of Capitalization, Long-term Debt [Line Items] | ' | ' |
Capital lease obligations | ($72,087) | ($74,358) |
CONSOLIDATED_STATEMENTS_OF_CAP1
CONSOLIDATED STATEMENTS OF CAPITALIZATION (Parenthetical) (USD $) | 12 Months Ended | ||||||||||||||||||||||||||||||||
Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | |||
NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | PSCo | PSCo | PSCo | PSCo | PSCo | PSCo | PSCo | PSCo | PSCo | SPS | SPS | SPS | SPS | NSP-Wisconsin | NSP-Wisconsin | NSP-Wisconsin | NSP-Wisconsin | Other Subsidiaries | Xcel Energy Inc. | Xcel Energy Inc. | Xcel Energy Inc. | Xcel Energy Inc. | |||
First Mortgage Bonds | First Mortgage Bonds | First Mortgage Bonds | First Mortgage Bonds | First Mortgage Bonds | First Mortgage Bonds | First Mortgage Bonds | First Mortgage Bonds | First Mortgage Bonds | First Mortgage Bonds | First Mortgage Bonds | First Mortgage Bonds | First Mortgage Bonds | First Mortgage Bonds | First Mortgage Bonds | First Mortgage Bonds | First Mortgage Bonds | Capital Lease Obligations [Member] | Senior Unsecured Notes | Senior Unsecured Notes | Senior Unsecured Notes | Senior Unsecured Notes | First Mortgage Bonds | First Mortgage Bonds | City of La Crosse Resource Recovery Bond [Member] | Fort McCoy System Acquisition [Member] | Various Eloigne Co. Affordable Housing Project Notes [Member] | Senior Unsecured Notes | Senior Unsecured Notes | Senior Unsecured Notes | Senior Unsecured Notes | |||
Series Due Aug. 15, 2015 [Member] | Series Due March 1, 2018 [Member] | Series Due July 1, 2025 [Member] | Series Due March 1, 2028 [Member] | Series Due July 15, 2035 [Member] | Series Due June 1, 2036 [Member] | Series Due July 1, 2037 [Member] | Series Due Nov. 1, 2039 [Member] | Series Due Aug. 15, 2040 [Member] | Series Due March 1, 2013 [Member] | Series Due April 1, 2014 [Member] | Series Due Sept. 1, 2017 [Member] | Series Due Aug. 1, 2018 [Member] | Series Due June 1, 2019 [Member] | Series Due Nov. 15, 2020 [Member] | Series Due Sept. 1, 2037 [Member] | Series Due Aug. 1, 2038 [Member] | Senior E Due Oct. 1, 2016 [Member] | Senior G Due Dec. 1, 2018 [Member] | Senior C and D Due Oct. 1, 2033 [Member] | Senior F Due Oct. 1, 2036 [Member] | Series Due Oct. 1, 2018 [Member] | Series Due Sept. 1, 2038 [Member] | Series Due Nov. 1, 2021 [Member] | Due Oct. 15, 2030 [Member] | Due 2014-2050 [Member] | Series Due April 1, 2017 [Member] | Series Due May 15, 2020 [Member] | Series Due July 1, 2036 [Member] | Series Due Sept. 15, 2041 [Member] | ||||
Schedule of Capitalization, Long-term Debt [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Debt instrument, interest rate, stated percentage (in hundredths) | 1.95% | 5.25% | 7.13% | 6.50% | 5.25% | 6.25% | 6.20% | 5.35% | 4.85% | 4.88% | 5.50% | 4.38% | [1] | 5.80% | 5.13% | 3.20% | 6.25% | 6.50% | ' | 5.60% | 8.75% | 6.00% | 6.00% | 5.25% | 6.38% | 6.00% | [2] | 7.00% | ' | 5.61% | 4.70% | 6.50% | 4.80% |
Debt instrument, maturity date | 15-Aug-15 | 1-Mar-18 | 1-Jul-25 | 1-Mar-28 | 15-Jul-35 | 1-Jun-36 | 1-Jul-37 | 1-Nov-39 | 15-Aug-40 | 1-Mar-13 | 1-Apr-14 | 1-Sep-17 | [1] | 1-Aug-18 | 1-Jun-19 | 15-Nov-20 | 1-Sep-37 | 1-Aug-38 | ' | 1-Oct-16 | 1-Dec-18 | 1-Oct-33 | 1-Oct-36 | 1-Oct-18 | 1-Sep-38 | 1-Nov-21 | [2] | 15-Oct-30 | ' | 1-Apr-17 | 15-May-20 | 1-Jul-36 | 15-Sep-41 |
Debt Instrument, Interest Rate, Stated Percentage Rate Range, Minimum (in hundredths) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 11.20% | ' | ' | ' | ' | ' | ' | ' | ' | 0.00% | ' | ' | ' | ' | ||
Debt Instrument, Interest Rate, Stated Percentage Rate Range, Maximum (in hundredths) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 14.30% | ' | ' | ' | ' | ' | ' | ' | ' | 8.36% | ' | ' | ' | ' | ||
Debt Instrument, Maturity Date Range, Start | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1-Jan-14 | ' | ' | ' | ' | ||
Debt Instrument, Maturity Date Range, End | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 31-Dec-60 | ' | ' | ' | ' | ' | ' | ' | ' | 31-Dec-50 | ' | ' | ' | ' | ||
[1] | Pollution control financing. | ||||||||||||||||||||||||||||||||
[2] | Resource recovery financing. |
Summary_of_Significant_Account
Summary of Significant Accounting Policies | 12 Months Ended | |
Dec. 31, 2013 | ||
Accounting Policies [Abstract] | ' | |
Summary of Significant Accounting Policies | ' | |
Summary of Significant Accounting Policies | ||
Business and System of Accounts — Xcel Energy Inc.’s utility subsidiaries are principally engaged in the regulated generation, purchase, transmission, distribution and sale of electricity and in the regulated purchase, transportation, distribution and sale of natural gas. Xcel Energy’s consolidated financial statements and disclosures are presented in accordance with GAAP. All of the utility subsidiaries’ underlying accounting records also conform to the FERC uniform system of accounts or to systems required by various state regulatory commissions, which are the same in all material respects. | ||
Principles of Consolidation — In 2013, Xcel Energy’s operations included the activity of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS. These utility subsidiaries serve electric and natural gas customers in portions of Colorado, Michigan, Minnesota, New Mexico, North Dakota, South Dakota, Texas and Wisconsin. Also included in Xcel Energy’s operations are WGI, an interstate natural gas pipeline company, and WYCO, a joint venture with CIG to develop and lease natural gas pipelines, storage and compression facilities. | ||
Xcel Energy Inc.’s nonregulated subsidiary is Eloigne, which invests in rental housing projects that qualify for low-income housing tax credits. Xcel Energy Inc. owns the following additional direct subsidiaries, some of which are intermediate holding companies with additional subsidiaries: Xcel Energy Wholesale Group Inc., Xcel Energy Markets Holdings Inc., Xcel Energy Ventures Inc., Xcel Energy Retail Holdings Inc., Xcel Energy Communications Group, Inc., Xcel Energy International Inc., and Xcel Energy Services Inc. Xcel Energy Inc. and its subsidiaries collectively are referred to as Xcel Energy. | ||
Xcel Energy’s consolidated financial statements include its wholly-owned subsidiaries and variable interest entities for which it is the primary beneficiary. In the consolidation process, all intercompany transactions and balances are eliminated. Xcel Energy uses the equity method of accounting for its investment in WYCO. Xcel Energy’s equity earnings in WYCO are included on the consolidated statements of income as equity earnings of unconsolidated subsidiaries. Xcel Energy has investments in several plants and transmission facilities jointly owned with nonaffiliated utilities. Xcel Energy’s proportionate share of jointly owned facilities is recorded as property, plant and equipment on the consolidated balance sheets, and Xcel Energy’s proportionate share of the operating costs associated with these facilities is included in its consolidated statements of income. See Note 5 for further discussion of jointly owned generation, transmission, and gas facilities and related ownership percentages. | ||
Xcel Energy evaluates its arrangements and contracts with other entities, including but not limited to, investments, PPAs and fuel contracts to determine if the other party is a variable interest entity, if Xcel Energy has a variable interest and if Xcel Energy is the primary beneficiary. Xcel Energy follows accounting guidance for variable interest entities which requires consideration of the activities that most significantly impact an entity’s financial performance and power to direct those activities, when determining whether Xcel Energy is a variable interest entity’s primary beneficiary. See Note 13 for further discussion of variable interest entities. | ||
Use of Estimates — In recording transactions and balances resulting from business operations, Xcel Energy uses estimates based on the best information available. Estimates are used for such items as plant depreciable lives, AROs, regulatory assets and liabilities, tax provisions, uncollectible amounts, environmental costs, unbilled revenues, jurisdictional fuel and energy cost allocations and actuarially determined benefit costs. The recorded estimates are revised when better information becomes available or when actual amounts can be determined. Those revisions can affect operating results. | ||
Regulatory Accounting — Our regulated utility subsidiaries account for certain income and expense items in accordance with accounting guidance for regulated operations. Under this guidance: | ||
• | Certain costs, which would otherwise be charged to expense or OCI, are deferred as regulatory assets based on the expected ability to recover the costs in future rates; and | |
• | Certain credits, which would otherwise be reflected as income, are deferred as regulatory liabilities based on the expectation the amounts will be returned to customers in future rates, or because the amounts were collected in rates prior to the costs being incurred. | |
Estimates of recovering deferred costs and returning deferred credits are based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are amortized consistent with the treatment in the rate setting process. | ||
If restructuring or other changes in the regulatory environment occur, regulated utility subsidiaries may no longer be eligible to apply this accounting treatment, and may be required to eliminate regulatory assets and liabilities from their balance sheets. Such changes could have a material effect on Xcel Energy’s financial condition, results of operations and cash flows. See Note 15 for further discussion of regulatory assets and liabilities. | ||
Revenue Recognition — Revenues related to the sale of energy are generally recorded when service is rendered or energy is delivered to customers. However, the determination of the energy sales to individual customers is based on the reading of their meter, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is recognized. Xcel Energy presents its revenues net of any excise or other fiduciary-type taxes or fees. | ||
NSP-Minnesota participates in MISO, and SPS participates in SPP. The revenues and charges from these RTOs related to serving retail and wholesale electric customers comprising the native load of NSP-Minnesota and SPS are recorded on a net basis within cost of sales. Revenues and charges for short term wholesale sales of excess energy transacted through RTOs are recorded on a gross basis in electric revenues and cost of sales. | ||
Xcel Energy Inc.’s utility subsidiaries have various rate-adjustment mechanisms in place that provide for the recovery of natural gas, electric fuel and purchased energy costs. These cost-adjustment tariffs may increase or decrease the level of revenue collected from customers and are revised periodically for differences between the total amount collected under the clauses and the costs incurred. When applicable, under governing regulatory commission rate orders, fuel cost over-recoveries (the excess of fuel revenue billed to customers over fuel costs incurred) are deferred as regulatory liabilities and under-recoveries (the excess of fuel costs incurred over fuel revenues billed to customers) are deferred as regulatory assets. | ||
Conservation Programs — Xcel Energy Inc.’s utility subsidiaries have implemented programs in many of their retail jurisdictions to assist customers in conserving energy and reducing peak demand on the electric and natural gas systems. These programs include efficiency and redesign programs, as well as rebates for the purchase of items such as compact fluorescent bulbs, saver switches and energy-efficient heating and cooling appliances. | ||
The costs incurred for DSM and CIP programs are deferred if it is probable future revenue will be provided to permit recovery of the incurred cost. For incentive programs designed to allow adjustments of future rates for recovery of lost margins and/or conservation performance incentives, recorded revenues are limited to those amounts expected to be collected within 24 months following the end of the annual period in which they are earned. | ||
For PSCo, SPS and NSP-Minnesota, DSM and CIP program costs are recovered through a combination of base rate revenue and rider mechanisms. The revenue billed to customers recovers incurred costs for conservation programs and also incentive amounts that are designed to encourage Xcel Energy’s achievement of energy conservation goals and compensate for related lost sales margin. For these utility subsidiaries, regulatory assets are recognized to reflect the amount of costs or earned incentives that have not yet been collected from customers. NSP-Wisconsin recovers approved conservation program costs in base rate revenue. | ||
Property, Plant and Equipment and Depreciation — Property, plant and equipment is stated at original cost. The cost of plant includes direct labor and materials, contracted work, overhead costs and AFUDC. The cost of plant retired is charged to accumulated depreciation and amortization. Amounts recovered in rates for future removal costs are recorded as regulatory liabilities. Significant additions or improvements extending asset lives are capitalized, while repairs and maintenance costs are charged to expense as incurred. Maintenance and replacement of items determined to be less than a unit of property are charged to operating expenses as incurred. Planned major maintenance activities are charged to operating expense unless the cost represents the acquisition of an additional unit of property or the replacement of an existing unit of property. Property, plant and equipment also includes costs associated with property held for future use. The depreciable lives of certain plant assets are reviewed annually and revised, if appropriate. Property, plant and equipment that is required to be decommissioned early by a regulator is reclassified as plant to be retired. | ||
Property, plant and equipment is tested for impairment when it is determined that the carrying value of the assets may not be recoverable. Recently completed property, plant and equipment that is disallowed for cost recovery is expensed in the current period. For investments in property, plant and equipment that are not expected to go into service, incurred costs and related deferred tax amounts are compared to the discounted estimated future rate recovery, and a loss on abandonment is recognized, if necessary. | ||
Xcel Energy records depreciation expense related to its plant using the straight-line method over the plant’s useful life. Actuarial and semi-actuarial life studies are performed on a periodic basis and submitted to the state and federal commissions for review. Upon acceptance by the various commissions, the resulting lives and net salvage rates are used to calculate depreciation. Depreciation expense, expressed as a percentage of average depreciable property, was approximately 2.9, 2.8, and 2.9 percent for the years ended Dec. 31, 2013, 2012 and 2011, respectively. | ||
Leases — Xcel Energy evaluates a variety of contracts for lease classification at inception, including PPAs and rental arrangements for office space, vehicles and equipment. Contracts determined to contain a lease because of per unit pricing that is other than fixed or market price, terms regarding the use of a particular asset, and other factors are evaluated further to determine if the arrangement is a capital lease. See Note 13 for further discussion of leases. | ||
AFUDC — AFUDC represents the cost of capital used to finance utility construction activity. AFUDC is computed by applying a composite financing rate to qualified CWIP. The amount of AFUDC capitalized as a utility construction cost is credited to other nonoperating income (for equity capital) and interest charges (for debt capital). AFUDC amounts capitalized are included in Xcel Energy’s rate base for establishing utility service rates. In addition to construction-related amounts, cost of capital also is recorded to reflect returns on capital used to finance conservation programs in Minnesota. | ||
Generally, AFUDC costs are recovered from customers as the related property is depreciated. However, in some cases commissions have approved a more current recovery of the cost of capital associated with large capital projects, resulting in a lower recognition of AFUDC. In other cases, some commissions have allowed an AFUDC calculation greater than the FERC-defined AFUDC rate, resulting in higher recognition of AFUDC. | ||
AROs — Xcel Energy Inc.’s utility subsidiaries account for AROs under accounting guidance that requires a liability for the fair value of an ARO to be recognized in the period in which it is incurred if it can be reasonably estimated, with the offsetting associated asset retirement costs capitalized as a long-lived asset. The liability is generally increased over time by applying the effective interest method of accretion, and the capitalized costs are depreciated over the useful life of the long-lived asset. Changes resulting from revisions to the timing or amount of expected asset retirement cash flows are recognized as an increase or a decrease in the ARO. Xcel Energy Inc.’s utility subsidiaries also recover through rates certain future plant removal costs in addition to AROs. The accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability. See Note 13 for further discussion of AROs. | ||
Nuclear Decommissioning — Nuclear decommissioning studies estimate NSP-Minnesota’s ultimate costs of decommissioning its nuclear power plants and are performed at least every three years and submitted to the MPUC and other state commissions for approval. The MPUC approved NSP-Minnesota’s most recent triennial nuclear decommissioning studies in December 2012. These studies reflect NSP-Minnesota’s plans for prompt dismantlement of the Monticello and Prairie Island facilities. These studies assume that NSP-Minnesota will be storing spent fuel on site pending removal to a U.S. government facility. | ||
For rate making purposes, NSP-Minnesota recovers the total decommissioning costs related to its nuclear power plants over each facility’s expected service life based on the triennial decommissioning studies filed with the MPUC and other state commissions. The studies consider estimated future costs of decommissioning and the market value of investments in trust funds, and recommend annual funding amounts. Amounts collected in rates are deposited in the trust funds. See Note 14 for further discussion of the approved nuclear decommissioning studies and funded amounts. For financial reporting purposes, NSP-Minnesota accounts for nuclear decommissioning as an ARO as described above. | ||
Restricted funds for the payment of future decommissioning expenditures for NSP-Minnesota’s nuclear facilities are included in the nuclear decommissioning fund on the consolidated balance sheets. See Note 11 for further discussion of the nuclear decommissioning fund. | ||
Nuclear Fuel Expense — Nuclear fuel expense, which is recorded as NSP-Minnesota’s nuclear generating plants use fuel, includes the cost of fuel used in the current period (including AFUDC), as well as future disposal costs of spent nuclear fuel and costs associated with the end-of-life fuel segments. | ||
Nuclear Refueling Outage Costs — Xcel Energy uses a deferral and amortization method for nuclear refueling O&M costs. This method amortizes refueling outage costs over the period between refueling outages consistent with how the costs are recovered ratably in electric rates. | ||
Income Taxes — Xcel Energy accounts for income taxes using the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements. Xcel Energy defers income taxes for all temporary differences between pretax financial and taxable income, and between the book and tax bases of assets and liabilities. Xcel Energy uses the tax rates that are scheduled to be in effect when the temporary differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date. | ||
Deferred tax assets are reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax asset will not be realized. In making such a determination, all available evidence is considered, including scheduled reversals of deferred tax liabilities, projected future taxable income, tax planning strategies and recent financial operations. | ||
Due to the effects of past regulatory practices, when deferred taxes were not required to be recorded due to the use of flow through accounting for ratemaking purposes, the reversal of some temporary differences are accounted for as current income tax expense. Investment tax credits are deferred and their benefits amortized over the book depreciable lives of the related property. Utility rate regulation also has resulted in the recognition of certain regulatory assets and liabilities related to income taxes, which are summarized in Note 15. | ||
Xcel Energy follows the applicable accounting guidance to measure and disclose uncertain tax positions that it has taken or expects to take in its income tax returns. Xcel Energy recognizes a tax position in its consolidated financial statements when it is more likely than not that the position will be sustained upon examination based on the technical merits of the position. Recognition of changes in uncertain tax positions are reflected as a component of income tax. | ||
Xcel Energy reports interest and penalties related to income taxes within the other income and interest charges sections in the consolidated statements of income. | ||
Xcel Energy Inc. and its subsidiaries file consolidated federal income tax returns as well as combined or separate state income tax returns. Federal income taxes paid by Xcel Energy Inc. are allocated to Xcel Energy Inc.’s subsidiaries based on separate company computations of tax. A similar allocation is made for state income taxes paid by Xcel Energy Inc. in connection with combined state filings. Xcel Energy Inc. also allocates its own income tax benefits to its direct subsidiaries based on the relative positive tax liabilities of the subsidiaries. | ||
See Note 6 for further discussion of income taxes. | ||
Types of and Accounting for Derivative Instruments — Xcel Energy uses derivative instruments in connection with its interest rate, utility commodity price, vehicle fuel price, short-term wholesale and commodity trading activities, including forward contracts, futures, swaps and options. All derivative instruments not designated and qualifying for the normal purchases and normal sales exception, as defined by the accounting guidance for derivatives and hedging, are recorded on the consolidated balance sheets at fair value as derivative instruments. This includes certain instruments used to mitigate market risk for the utility operations including transmission in organized markets and all instruments related to the commodity trading operations. The classification of changes in fair value for those derivative instruments is dependent on the designation of a qualifying hedging relationship. Changes in fair value of derivative instruments not designated in a qualifying hedging relationship are reflected in current earnings or as a regulatory asset or liability. The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. | ||
Gains or losses on commodity trading transactions are recorded as a component of electric operating revenues; hedging transactions for vehicle fuel costs are recorded as a component of capital projects or O&M costs; and interest rate hedging transactions are recorded as a component of interest expense. Certain utility subsidiaries are allowed to recover in electric or natural gas rates the costs of certain financial instruments purchased to reduce commodity cost volatility. For further information on derivatives entered to mitigate commodity price risk on behalf of electric and natural gas customers, see Note 11. | ||
Cash Flow Hedges — Certain qualifying hedging relationships are designated as a hedge of a forecasted transaction, or future cash flow (cash flow hedge). Changes in the fair value of a derivative designated as a cash flow hedge, to the extent effective, are included in OCI or deferred as a regulatory asset or liability based on recovery mechanisms until earnings are affected by the hedged transaction. | ||
Normal Purchases and Normal Sales — Xcel Energy enters into contracts for the purchase and sale of commodities for use in its business operations. Derivatives and hedging accounting guidance requires a company to evaluate these contracts to determine whether the contracts are derivatives. Certain contracts that meet the definition of a derivative may be exempted from derivative accounting if designated as normal purchases or normal sales. | ||
Xcel Energy evaluates all of its contracts at inception to determine if they are derivatives and if they meet the normal purchases and normal sales designation requirements. None of the contracts entered into within the commodity trading operations qualify for a normal purchases and normal sales designation. | ||
See Note 11 for further discussion of Xcel Energy’s risk management and derivative activities. | ||
Commodity Trading Operations — All applicable gains and losses related to commodity trading activities, whether or not settled physically, are shown on a net basis in electric operating revenues in the consolidated statements of income. | ||
Xcel Energy’s commodity trading operations are conducted by NSP-Minnesota, PSCo and SPS. Commodity trading activities are not associated with energy produced from Xcel Energy’s generation assets or energy and capacity purchased to serve native load. Commodity trading contracts are recorded at fair market value and commodity trading results include the impact of all margin-sharing mechanisms. See Note 11 for further discussion. | ||
Fair Value Measurements — Xcel Energy presents cash equivalents, interest rate derivatives, commodity derivatives and nuclear decommissioning fund assets at estimated fair values in its consolidated financial statements. Cash equivalents are recorded at cost plus accrued interest; money market funds are measured using quoted net asset values. For interest rate derivatives, quoted prices based primarily on observable market interest rate curves are used as a primary input to establish fair value. For commodity derivatives, the most observable inputs available are generally used to determine the fair value of each contract. In the absence of a quoted price for an identical contract in an active market, Xcel Energy may use quoted prices for similar contracts or internally prepared valuation models to determine fair value. For the nuclear decommissioning fund, published trading data and pricing models, generally using the most observable inputs available, are utilized to estimate fair value for each class of security. See Note 11 for further discussion. | ||
Cash and Cash Equivalents — Xcel Energy considers investments in certain instruments, including commercial paper and money market funds, with a remaining maturity of 3 months or less at the time of purchase, to be cash equivalents. | ||
Accounts Receivable and Allowance for Bad Debts — Accounts receivable are stated at the actual billed amount net of an allowance for bad debts. Xcel Energy establishes an allowance for uncollectible receivables based on a policy that reflects its expected exposure to the credit risk of customers. | ||
Inventory — All inventory is recorded at average cost. | ||
RECs — RECs are marketable environmental instruments that represent proof that energy was generated from eligible renewable energy sources. RECs are awarded upon delivery of the associated energy and can be bought and sold. RECs are typically used as a form of measurement of compliance to RPS enacted by those states that are encouraging construction and consumption from renewable energy sources, but can also be sold separately from the energy produced. Utility subsidiaries acquire RECs from the generation or purchase of renewable power. | ||
When RECs are purchased or acquired in the course of generation they are recorded as inventory at cost. The cost of RECs that are utilized for compliance purposes is recorded as electric fuel and purchased power expense. As a result of state regulatory orders, Xcel Energy reduces recoverable fuel costs for the cost of certain RECs and records that cost as a regulatory asset when the amount is recoverable in future rates. | ||
Sales of RECs that are purchased or acquired in the course of generation are recorded in electric utility operating revenues on a gross basis. The cost of these RECs, related transaction costs, and amounts credited to customers under margin-sharing mechanisms are recorded in electric fuel and purchased power expense. The sales of RECs for trading purposes are recorded in electric utility operating revenues, net of the cost of the RECs, transaction costs, and amounts credited to customers under margin-sharing mechanisms. | ||
Emission Allowances — Emission allowances, including the annual SO2 and NOx emission allowance entitlement received from the EPA, are recorded at cost plus associated broker commission fees. Xcel Energy follows the inventory accounting model for all emission allowances. Sales of emission allowances are included in electric utility operating revenues and the operating activities section of the consolidated statements of cash flows. | ||
Environmental Costs — Environmental costs are recorded when it is probable Xcel Energy is liable for remediation costs and the liability can be reasonably estimated. Costs are deferred as a regulatory asset if it is probable that the costs will be recovered from customers in future rates. Otherwise, the costs are expensed. If an environmental expense is related to facilities currently in use, such as emission-control equipment, the cost is capitalized and depreciated over the life of the plant. | ||
Estimated remediation costs, excluding inflationary increases, are recorded. The estimates are based on experience, an assessment of the current situation and the technology currently available for use in the remediation. The recorded costs are regularly adjusted as estimates are revised and remediation proceeds. If other participating PRPs exist and acknowledge their potential involvement with a site, costs are estimated and recorded only for Xcel Energy’s expected share of the cost. Any future costs of restoring sites where operation may extend indefinitely are treated as a capitalized cost of plant retirement. The depreciation expense levels recoverable in rates include a provision for removal expenses, which may include final remediation costs. Removal costs recovered in rates are classified as a regulatory liability. | ||
See Note 13 for further discussion of environmental costs. | ||
Benefit Plans and Other Postretirement Benefits — Xcel Energy maintains pension and postretirement benefit plans for eligible employees. Recognizing the cost of providing benefits and measuring the projected benefit obligation of these plans under applicable accounting guidance requires management to make various assumptions and estimates. | ||
Based on the regulatory recovery mechanisms of Xcel Energy Inc.’s utility subsidiaries, certain unrecognized actuarial gains and losses and unrecognized prior service costs or credits are recorded as regulatory assets and liabilities, rather than OCI. | ||
See Note 9 for further discussion of benefit plans and other postretirement benefits. | ||
Guarantees — Xcel Energy recognizes, upon issuance or modification of a guarantee, a liability for the fair market value of the obligation that has been assumed in issuing the guarantee. This liability includes consideration of specific triggering events and other conditions which may modify the ongoing obligation to perform under the guarantee. | ||
The obligation recognized is reduced over the term of the guarantee as Xcel Energy is released from risk under the guarantee. See Note 13 for specific details of issued guarantees. | ||
Reclassifications — Certain previously reported amounts have been reclassified to conform to the current year presentation. | ||
Subsequent Events — Management has evaluated the impact of events occurring after Dec. 31, 2013 up to the date of issuance of these consolidated financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation. |
Accounting_Pronouncements
Accounting Pronouncements | 12 Months Ended |
Dec. 31, 2013 | |
New Accounting Pronouncements and Changes in Accounting Principles [Abstract] | ' |
Accounting Pronouncements | ' |
Accounting Pronouncements | |
Recently Adopted | |
Balance Sheet Offsetting — In December 2011, the FASB issued Balance Sheet (Topic 210) — Disclosures about Offsetting Assets and Liabilities (ASU No. 2011-11), which requires disclosures regarding netting arrangements in agreements underlying derivatives, certain financial instruments and related collateral amounts, and the extent to which an entity’s financial statement presentation policies related to netting arrangements impact amounts recorded to the financial statements. In January 2013, the FASB issued Balance Sheet (Topic 210) – Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities (ASU No. 2013-01) to clarify the specific instruments that should be considered in these disclosures. These disclosure requirements do not affect the presentation of amounts in the consolidated balance sheets, and were effective for annual reporting periods beginning on or after Jan. 1, 2013, and interim periods within those annual reporting periods. Xcel Energy implemented the disclosure guidance effective Jan. 1, 2013, and the implementation did not have a material impact on its consolidated financial statements. See Note 11 for the required disclosures. | |
Comprehensive Income Disclosures — In February 2013, the FASB issued Comprehensive Income (Topic 220) — Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income (ASU No. 2013-02), which requires detailed disclosures regarding changes in components of accumulated OCI and amounts reclassified out of accumulated OCI. These disclosure requirements do not change how net income or comprehensive income are presented in the consolidated financial statements. These disclosure requirements were effective for annual reporting periods beginning on or after Dec. 15, 2012, and interim periods within those annual reporting periods. Xcel Energy implemented the disclosure guidance effective Jan. 1, 2013, and the implementation did not have a material impact on its consolidated financial statements. See Note 16 for the required disclosures. |
Selected_Balance_Sheet_Data
Selected Balance Sheet Data | 12 Months Ended | ||||||||
Dec. 31, 2013 | |||||||||
Balance Sheet Related Disclosures [Abstract] | ' | ||||||||
Selected Balance Sheet Data | ' | ||||||||
Selected Balance Sheet Data | |||||||||
(Thousands of Dollars) | Dec. 31, 2013 | Dec. 31, 2012 | |||||||
Accounts receivable, net | |||||||||
Accounts receivable | $ | 797,267 | $ | 769,440 | |||||
Less allowance for bad debts | (53,107 | ) | (51,394 | ) | |||||
$ | 744,160 | $ | 718,046 | ||||||
(Thousands of Dollars) | Dec. 31, 2013 | Dec. 31, 2012 | |||||||
Inventories | |||||||||
Materials and supplies | $ | 225,308 | $ | 213,739 | |||||
Fuel | 189,485 | 189,425 | |||||||
Natural gas | 161,745 | 132,410 | |||||||
$ | 576,538 | $ | 535,574 | ||||||
(Thousands of Dollars) | Dec. 31, 2013 | Dec. 31, 2012 | |||||||
Property, plant and equipment, net | |||||||||
Electric plant | $ | 30,341,310 | $ | 28,285,031 | |||||
Natural gas plant | 4,086,651 | 3,836,335 | |||||||
Common and other property | 1,485,547 | 1,480,558 | |||||||
Plant to be retired (a) | 101,279 | 152,730 | |||||||
CWIP | 2,371,566 | 1,757,189 | |||||||
Total property, plant and equipment | 38,386,353 | 35,511,843 | |||||||
Less accumulated depreciation | (12,608,305 | ) | (12,048,697 | ) | |||||
Nuclear fuel | 2,186,799 | 2,090,801 | |||||||
Less accumulated amortization | (1,842,688 | ) | (1,744,599 | ) | |||||
$ | 26,122,159 | $ | 23,809,348 | ||||||
(a) | As a result of the CPUC’s 2010 approval of PSCo’s CACJA compliance plan, subsequent CPCNs and the December 2013 approval of PSCo’s preferred plans for applicable generating resources, PSCo has received approval for early retirement of Cherokee Units 1, 2 and 3, Arapahoe Units 3 and 4 and Valmont Unit 5 between 2011 and 2017. In 2011, Cherokee Unit 2 was retired, in 2012, Cherokee Unit 1 was retired, and in 2013, Arapahoe Units 3 and 4 were retired. Amounts are presented net of accumulated depreciation. |
Borrowings_and_Other_Financing
Borrowings and Other Financing Instruments | 12 Months Ended | ||||||||||||
Dec. 31, 2013 | |||||||||||||
Debt Disclosure [Abstract] | ' | ||||||||||||
Borrowings and Other Financing Instruments | ' | ||||||||||||
Borrowings and Other Financing Instruments | |||||||||||||
Short-Term Borrowings | |||||||||||||
Money Pool — Xcel Energy Inc. and its utility subsidiaries have established a money pool arrangement that allows for short-term investments in and borrowings between the utility subsidiaries. NSP-Wisconsin does not participate in the money pool. Xcel Energy Inc. may make investments in the utility subsidiaries at market-based interest rates; however, the money pool arrangement does not allow the utility subsidiaries to make investments in Xcel Energy Inc. The money pool balances are eliminated in consolidation. | |||||||||||||
Commercial Paper — Xcel Energy Inc. and its utility subsidiaries meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under their credit facilities. Commercial paper outstanding for Xcel Energy was as follows: | |||||||||||||
(Amounts in Millions, Except Interest Rates) | Three Months Ended | ||||||||||||
Dec. 31, 2013 | |||||||||||||
Borrowing limit | $ | 2,450 | |||||||||||
Amount outstanding at period end | 759 | ||||||||||||
Average amount outstanding | 515 | ||||||||||||
Maximum amount outstanding | 759 | ||||||||||||
Weighted average interest rate, computed on a daily basis | 0.29 | % | |||||||||||
Weighted average interest rate at period end | 0.25 | ||||||||||||
(Amounts in Millions, Except Interest Rates) | Twelve Months Ended | Twelve Months Ended | Twelve Months Ended | ||||||||||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |||||||||||
Borrowing limit | $ | 2,450 | $ | 2,450 | $ | 2,450 | |||||||
Amount outstanding at period end | 759 | 602 | 219 | ||||||||||
Average amount outstanding | 481 | 403 | 430 | ||||||||||
Maximum amount outstanding | 1,160 | 634 | 824 | ||||||||||
Weighted average interest rate, computed on a daily basis | 0.31 | % | 0.35 | % | 0.36 | % | |||||||
Weighted average interest rate at end of period | 0.25 | 0.36 | 0.4 | ||||||||||
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 Dec. 31, 2013 and 2012, there were $47.8 million and $14.2 million of letters of credit outstanding, respectively, under the credit facilities. The contract amounts of these letters of credit approximate their fair value and are subject to fees. | |||||||||||||
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. | |||||||||||||
NSP-Minnesota, NSP-Wisconsin, PSCo, SPS and Xcel Energy Inc. each have five-year credit agreements with a syndicate of banks. The total size of the credit facilities is $2.45 billion and each credit facility terminates in July 2017. | |||||||||||||
NSP-Minnesota, PSCo, SPS, and Xcel Energy Inc. each have the right to request an extension of the revolving termination date for two additional one-year periods. NSP-Wisconsin has the right to request an extension of the revolving termination date for an additional one-year period. All extension requests are subject to majority bank group approval. | |||||||||||||
Features of the credit facilities include: | |||||||||||||
• | Xcel Energy Inc. may increase its credit facility by up to $200 million, NSP-Minnesota and PSCo may each increase their credit facilities by $100 million and SPS may increase its credit facility by $50 million. The NSP-Wisconsin credit facility cannot be increased. | ||||||||||||
• | Each credit facility has a financial covenant requiring that the debt-to-total capitalization ratio of each entity be less than or equal to 65 percent. Each entity was in compliance at Dec. 31, 2013 and 2012, respectively, as evidenced by the table below: | ||||||||||||
Debt-to-Total Capitalization Ratio | |||||||||||||
2013 | 2012 | ||||||||||||
Xcel Energy | 56 | % | 56 | % | |||||||||
NSP-Wisconsin | 47 | 50 | |||||||||||
NSP-Minnesota | 47 | 48 | |||||||||||
SPS | 49 | 49 | |||||||||||
PSCo | 45 | 45 | |||||||||||
• | If Xcel Energy Inc. or any of its utility subsidiaries do not comply with the covenant, an event of default may be declared, and if not remedied, any outstanding amounts due under the facility can be declared due by the lender. | ||||||||||||
• | The Xcel Energy Inc. credit facility has a cross-default provision that provides Xcel Energy Inc. will be in default on its borrowings under the facility if it or any of its subsidiaries, except NSP-Wisconsin as long as its total assets do not comprise more than 15 percent of Xcel Energy’s consolidated total assets, default on certain indebtedness in an aggregate principal amount exceeding $75 million. | ||||||||||||
• | The interest rates under these lines of credit are based on Eurodollar borrowing margins ranging from 87.5 to 175 basis points per year based on the applicable long-term credit ratings. | ||||||||||||
• | The commitment fees, also based on applicable long-term credit ratings, are calculated on the unused portion of the lines of credit at a range of 7.5 to 27.5 basis points per year. | ||||||||||||
At Dec. 31, 2013, Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available: | |||||||||||||
(Millions of Dollars) | Credit Facility (a) | Drawn (b) | Available | ||||||||||
Xcel Energy Inc. | $ | 800 | $ | 476 | $ | 324 | |||||||
PSCo | 700 | 6.4 | 693.6 | ||||||||||
NSP-Minnesota | 500 | 146.9 | 353.1 | ||||||||||
SPS | 300 | 109.5 | 190.5 | ||||||||||
NSP-Wisconsin | 150 | 68 | 82 | ||||||||||
Total | $ | 2,450.00 | $ | 806.8 | $ | 1,643.20 | |||||||
(a) | These credit facilities expire in July 2017. | ||||||||||||
(b) | Includes outstanding commercial paper and letters of credit. | ||||||||||||
All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the respective credit facilities. Xcel Energy Inc. and its subsidiaries had no direct advances on the credit facilities outstanding at Dec. 31, 2013 and 2012. | |||||||||||||
Long-Term Borrowings and Other Financing Instruments | |||||||||||||
Generally, all real and personal property of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS are subject to the liens of their first mortgage indentures. Debt premiums, discounts and expenses are amortized over the life of the related debt. The premiums, discounts and expenses associated with refinanced debt are deferred and amortized over the life of the related new issuance, in accordance with regulatory guidelines. | |||||||||||||
Maturities of long-term debt are as follows: | |||||||||||||
(Millions of Dollars) | |||||||||||||
2014 | $ | 281 | |||||||||||
2015 | 256 | ||||||||||||
2016 | 656 | ||||||||||||
2017 | 388 | ||||||||||||
2018 | 1,206 | ||||||||||||
During 2013, Xcel Energy Inc. and its utility subsidiaries completed the following financings: | |||||||||||||
• | In March 2013, PSCo issued $250 million of 2.50 percent first mortgage bonds due March 15, 2023 and $250 million of 3.95 percent first mortgage bonds due March 15, 2043. | ||||||||||||
• | In May 2013, Xcel Energy Inc. issued $450 million of 0.75 percent senior unsecured notes due May 9, 2016. | ||||||||||||
• | In May 2013, NSP-Minnesota issued $400 million of 2.60 percent first mortgage bonds due May 15, 2023. | ||||||||||||
• | In August 2013, SPS issued $100 million of 4.50 percent first mortgage bonds due Aug. 15, 2041. Including the $300 million of this series previously issued, total principal outstanding for this series is $400 million. | ||||||||||||
During 2012, Xcel Energy Inc. and its utility subsidiaries completed the following financings: | |||||||||||||
• | In June 2012, SPS issued an additional $100 million of its 4.50 percent first mortgage bonds due Aug. 15, 2041. | ||||||||||||
• | In August 2012, NSP-Minnesota issued $300 million of 2.15 percent first mortgage bonds due Aug. 15, 2022, and $500 million of 3.40 percent first mortgage bonds due Aug. 15, 2042. | ||||||||||||
• | In September 2012, PSCo issued $300 million of 2.25 percent first mortgage bonds due Sept. 15, 2022, and $500 million of 3.60 percent first mortgage bonds due Sept. 15, 2042. | ||||||||||||
• | In October 2012, NSP-Wisconsin issued $100 million of 3.70 percent first mortgage bonds due Oct. 1, 2042. | ||||||||||||
Issuances of Common Stock — In March 2013, Xcel Energy Inc. filed a prospectus supplement under which it may sell up to $400 million of its common stock through an at-the-market offering program. No shares of common stock have been issued through this program since April 2013. As of Dec. 31, 2013, Xcel Energy Inc. had issued 7.7 million shares of common stock through this program and received cash proceeds of $223 million, net of $3 million in fees and commissions. The proceeds from the issuances of common stock were used to repay short-term debt, infuse equity into the utility subsidiaries and for other general corporate purposes. | |||||||||||||
Debt Redemption — On May 31, 2013, Xcel Energy Inc. redeemed the entire $400 million principal amount of its 7.60 percent junior subordinated notes. Upon redemption, Xcel Energy Inc. recognized $6.3 million of related unamortized debt issuance costs as interest charges. | |||||||||||||
Deferred Financing Costs — Other assets included deferred financing costs of approximately $83 million and $85 million, net of amortization, at Dec. 31, 2013 and 2012, respectively. Xcel Energy is amortizing these financing costs over the remaining maturity periods of the related debt. | |||||||||||||
Capital Stock — Xcel Energy Inc. has 7,000,000 shares of preferred stock authorized to be issued with a $100 par value. At Dec. 31, 2013 and 2012, there were no shares of preferred stock outstanding. | |||||||||||||
In 2011, Xcel Energy Inc. redeemed all series of its preferred stock at an aggregate purchase price of $108 million, plus accrued dividends. The redemption premium of $3.3 million and accrued dividends are reflected as reductions of Xcel Energy’s earnings available to common shareholders in the consolidated statement of income for 2011. | |||||||||||||
The charters of PSCo and SPS authorize each subsidiary to issue 10,000,000 shares of preferred stock with par values of $0.01 and $1.00 per share, respectively. At Dec. 31, 2013 and 2012, there were no preferred shares of subsidiaries outstanding. | |||||||||||||
Xcel Energy Inc. has 1,000,000,000 shares of common stock authorized to be issued with a $2.50 par value. Outstanding shares at Dec. 31, 2013 and 2012 were 497,971,508 and 487,959,516, respectively. | |||||||||||||
Dividend and Other Capital-Related Restrictions — Xcel Energy Inc.’s Articles of Incorporation place restrictions on the amount of common stock dividends it can pay when preferred stock is outstanding. As there was no preferred stock outstanding at any time during the year ended Dec. 31, 2013, the restrictions did not place any effective limit on Xcel Energy Inc.’s ability to pay dividends. | |||||||||||||
Xcel Energy depends on its subsidiaries to pay dividends. All of Xcel Energy Inc.’s utility subsidiaries’ dividends are subject to the FERC’s jurisdiction under the Federal Power Act, which prohibits the payment of dividends out of capital accounts; payment of dividends is allowed out of retained earnings only. Due to certain restrictive covenants, Xcel Energy Inc. is required to be current on particular interest payments before dividends can be paid. | |||||||||||||
As discussed below, the most restrictive dividend limitations for NSP-Minnesota, NSP-Wisconsin and SPS are imposed by their respective state regulatory commission. PSCo’s dividends are subject to the FERC’s jurisdiction under the Federal Power Act, which prohibits the payment of dividends out of capital accounts; payment of dividends is allowed out of retained earnings only. | |||||||||||||
Only NSP-Minnesota has a first mortgage indenture which places certain restrictions on the amount of cash dividends it can pay to Xcel Energy Inc., the holder of its common stock. Even with this restriction, NSP-Minnesota could have paid more than $1.4 billion and $1.3 billion in additional cash dividends to Xcel Energy Inc. at Dec. 31, 2013 and 2012, respectively. | |||||||||||||
NSP-Minnesota’s state regulatory commissions indirectly limit the amount of dividends NSP-Minnesota can pay by requiring an equity-to-total capitalization ratio between 46.8 percent and 57.2 percent. NSP-Minnesota’s equity-to-total capitalization ratio was 52.5 percent at Dec. 31, 2013 and $912 million in retained earnings was not restricted. Total capitalization for NSP-Minnesota was $8.5 billion at Dec. 31, 2013, which did not exceed the limit of $9.0 billion. | |||||||||||||
NSP-Wisconsin cannot pay annual dividends in excess of approximately $31.2 million if its calendar year average equity-to-total capitalization ratio is or falls below the state commission authorized level of 52.5 percent, as calculated consistent with PSCW requirements. NSP-Wisconsin’s calendar year average equity-to-total capitalization ratio calculated on this basis was 52.8 percent at Dec. 31, 2013 and $17.1 million in retained earnings was not restricted. | |||||||||||||
SPS’ state regulatory commissions indirectly limit the amount of dividends that SPS can pay Xcel Energy Inc. by requiring an equity-to-total capitalization ratio (excluding short-term debt) between 45.0 percent and 55.0 percent. In addition, SPS may not pay a dividend that would cause it to lose its investment grade bond rating. SPS’ equity-to-total capitalization ratio (excluding short-term debt) was 53.2 percent at Dec. 31, 2013 and $359 million in retained earnings was not restricted. | |||||||||||||
The issuance of securities by Xcel Energy Inc. generally is not subject to regulatory approval. However, utility financings and certain intra-system financings are subject to the jurisdiction of the applicable state regulatory commissions and/or the FERC under the Federal Power Act. | |||||||||||||
• | PSCo currently has authorization to issue up to an additional $1 billion of long-term debt and up to $800 million of short-term debt. | ||||||||||||
• | SPS currently has no authorization to issue any long-term debt in 2014 and up to $400 million of short-term debt. | ||||||||||||
• | NSP-Wisconsin currently has authorization to issue up to an additional $150 million of long-term debt and up to $150 million of short-term debt. | ||||||||||||
• | NSP-Minnesota has authorization to issue long-term securities provided the equity-to-total capitalization ratio remains between 46.8 percent and 57.2 percent and to issue short-term debt provided it does not exceed 15 percent of total capitalization. Total capitalization for NSP-Minnesota cannot exceed $9 billion. | ||||||||||||
Xcel Energy believes these authorizations are adequate and will seek additional authorization when necessary; however, there can be no assurance that additional authorization will be granted on the timeframe or in the amounts requested. |
Joint_Ownership_of_Generation_
Joint Ownership of Generation, Transmission and Gas Facilities | 12 Months Ended | |||||||||||||||
Dec. 31, 2013 | ||||||||||||||||
Joint Ownership of Generation, Transmission and Gas Facilities [Abstract] | ' | |||||||||||||||
Joint Ownership of Generation, Transmission and Gas Facilities | ' | |||||||||||||||
Joint Ownership of Generation, Transmission and Gas Facilities | ||||||||||||||||
Following are the investments by Xcel Energy Inc.’s utility subsidiaries in jointly owned generation, transmission and gas facilities and the related ownership percentages as of Dec. 31, 2013: | ||||||||||||||||
(Thousands of Dollars) | Plant in | Accumulated | CWIP | Ownership % | ||||||||||||
Service | Depreciation | |||||||||||||||
NSP-Minnesota | ||||||||||||||||
Electric Generation: | ||||||||||||||||
Sherco Unit 3 | $ | 596,314 | $ | 371,925 | $ | 4,533 | 59 | % | ||||||||
Sherco Common Facilities Units 1, 2 and 3 | 145,579 | 87,289 | 61 | 80 | ||||||||||||
Sherco Substation | 4,790 | 2,884 | — | 59 | ||||||||||||
Electric Transmission: | ||||||||||||||||
Grand Meadow Line and Substation | 10,647 | 1,225 | — | 50 | ||||||||||||
CapX2020 Transmission | 340,333 | 77,803 | 503,714 | 53.3 | ||||||||||||
Total NSP-Minnesota | $ | 1,097,663 | $ | 541,126 | $ | 508,308 | ||||||||||
(Thousands of Dollars) | Plant in | Accumulated | CWIP | Ownership % | ||||||||||||
Service | Depreciation | |||||||||||||||
NSP-Wisconsin | ||||||||||||||||
Electric Transmission: | ||||||||||||||||
CapX2020 Transmission | $ | 13,337 | $ | 4,659 | $ | 30,199 | 77.9 | % | ||||||||
La Crosse, Wis. to Madison, Wis. | — | — | 5,431 | 50 | ||||||||||||
Total NSP-Wisconsin | $ | 13,337 | $ | 4,659 | $ | 35,630 | ||||||||||
(Thousands of Dollars) | Plant in | Accumulated | CWIP | Ownership % | ||||||||||||
Service | Depreciation | |||||||||||||||
PSCo | ||||||||||||||||
Electric Generation: | ||||||||||||||||
Hayden Unit 1 | $ | 97,879 | $ | 63,474 | $ | 53 | 75.5 | % | ||||||||
Hayden Unit 2 | 119,972 | 57,875 | 5,563 | 37.4 | ||||||||||||
Hayden Common Facilities | 36,916 | 16,055 | 2 | 53.1 | ||||||||||||
Craig Units 1 and 2 | 60,089 | 34,754 | 537 | 9.7 | ||||||||||||
Craig Common Facilities 1, 2 and 3 | 37,177 | 17,247 | — | 6.5 | ||||||||||||
Comanche Unit 3 | 877,489 | 63,963 | 581 | 66.7 | ||||||||||||
Comanche Common Facilities | 19,812 | 711 | 2,255 | 82 | ||||||||||||
Electric Transmission: | ||||||||||||||||
Transmission and other facilities, including substations | 150,502 | 59,118 | 827 | Various | ||||||||||||
Gas Transportation: | ||||||||||||||||
Rifle, Colo. to Avon, Colo. | 16,278 | 6,044 | — | 60 | ||||||||||||
Total PSCo | $ | 1,416,114 | $ | 319,241 | $ | 9,818 | ||||||||||
NSP-Minnesota and PSCo have approximately 500 MW and 820 MW of jointly owned generating capacity, respectively. Each Company's share of operating expenses and construction expenditures are included in the applicable utility accounts. Each of the respective owners is responsible for providing its own financing. |
Income_Taxes
Income Taxes | 12 Months Ended | ||||||||||||
Dec. 31, 2013 | |||||||||||||
Income Tax Disclosure [Abstract] | ' | ||||||||||||
Income Taxes | ' | ||||||||||||
Income Taxes | |||||||||||||
American Taxpayer Relief Act of 2012 — In January 2013, the American Taxpayer Relief Act of 2012 (the “Act”) was signed into law. The Act provides for the following: | |||||||||||||
• | The top tax rate for dividends increased from 15 percent to 20 percent. The 20 percent dividend rate is now consistent with the tax rates for capital gains; | ||||||||||||
• | The research and experimentation (R&E) credit was extended for 2012 and 2013; | ||||||||||||
• | PTCs were extended for projects that begin construction before the end of 2013; and | ||||||||||||
• | 50 percent bonus depreciation was extended one year through 2013. Additionally, some longer production period property placed in service in 2014 is also eligible for 50 percent bonus depreciation. | ||||||||||||
Because a change in tax law is accounted for in the period of enactment, the accounting related to the Act, including the provisions related to 2012, were recorded beginning in the first quarter of 2013. Accordingly, in 2013, Xcel Energy recorded an R&E benefit of $5 million related to 2012 and an estimated $6 million related to 2013. | |||||||||||||
Prescription drug tax benefit — In the third quarter of 2012, Xcel Energy implemented a tax strategy related to the allocation of funding of Xcel Energy’s retiree prescription drug plan. This strategy restored a portion of the tax benefit associated with federal subsidies for prescription drug plans that had been accrued since 2004 and was expensed in 2010. As a result, Xcel Energy recognized approximately $17 million of income tax benefit. | |||||||||||||
Medicare Part D — In March 2010, the Patient Protection and Affordable Care Act was signed into law. The law includes provisions to generate tax revenue to help offset the cost of the new legislation. One of these provisions reduces the deductibility of retiree health care costs to the extent of federal subsidies received by plan sponsors that provide retiree prescription drug benefits equivalent to Medicare Part D coverage, beginning in 2013. Xcel Energy expensed approximately $17 million of previously recognized tax benefits relating to the federal subsidies during the first quarter of 2010. | |||||||||||||
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 IRS commenced an examination of tax years 2010 and 2011, including the 2009 carryback claim. As of Dec. 31, 2013, 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 are 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 Dec. 31, 2013, Xcel Energy’s earliest open tax years that are subject to examination by state taxing authorities in its major operating jurisdictions were as follows: | |||||||||||||
State | Year | ||||||||||||
Colorado | 2009 | ||||||||||||
Minnesota | 2009 | ||||||||||||
Texas | 2008 | ||||||||||||
Wisconsin | 2009 | ||||||||||||
In the fourth quarter of 2013, the state of Colorado completed an examination of tax years 2006 through 2009. In the first quarter of 2013, the state of Wisconsin commenced an examination of tax years 2009 through 2011. As of Dec. 31, 2013, no material adjustments had been proposed for either of these audits. There are currently no other state income tax audits in progress. | |||||||||||||
Unrecognized Tax Benefits — The unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the annual 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) | Dec. 31, 2013 | Dec. 31, 2012 | |||||||||||
Unrecognized tax benefit — Permanent tax positions | $ | 12.9 | $ | 4.7 | |||||||||
Unrecognized tax benefit — Temporary tax positions | 28.3 | 29.8 | |||||||||||
Total unrecognized tax benefit | $ | 41.2 | $ | 34.5 | |||||||||
A reconciliation of the beginning and ending amount of unrecognized tax benefit is as follows: | |||||||||||||
(Millions of Dollars) | 2013 | 2012 | 2011 | ||||||||||
Balance at Jan. 1 | $ | 34.5 | $ | 34.7 | $ | 40.5 | |||||||
Additions based on tax positions related to the current year | 15.1 | 5.2 | 11.9 | ||||||||||
Reductions based on tax positions related to the current year | (0.4 | ) | (5.7 | ) | (1.9 | ) | |||||||
Additions for tax positions of prior years | 21.6 | 9.6 | 14 | ||||||||||
Reductions for tax positions of prior years | (4.8 | ) | (9.3 | ) | (2.4 | ) | |||||||
Settlements with taxing authorities | (24.8 | ) | — | (27.3 | ) | ||||||||
Lapse of applicable statutes of limitations | — | — | (0.1 | ) | |||||||||
Balance at Dec. 31 | $ | 41.2 | $ | 34.5 | $ | 34.7 | |||||||
The unrecognized tax benefit amounts were reduced by the tax benefits associated with NOL and tax credit carryforwards. The amounts of tax benefits associated with NOL and tax credit carryforwards are as follows: | |||||||||||||
(Millions of Dollars) | Dec. 31, 2013 | Dec. 31, 2012 | |||||||||||
NOL and tax credit carryforwards | $ | (27.1 | ) | $ | (33.5 | ) | |||||||
It is reasonably possible that Xcel Energy’s amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS and state audits progress. As the IRS examination moves closer to completion, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $20 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 Dec. 31, 2013, 2012 and 2011 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of Dec. 31, 2013, 2012 or 2011. | |||||||||||||
Tangible Property Regulations — In September 2013, the U.S. Treasury issued final regulations addressing the tax consequences associated with the acquisition, production and improvement of tangible property. As Xcel Energy had adopted certain utility-specific guidance previously issued by the IRS, the issuance is not expected to have a material impact on its consolidated financial statements. | |||||||||||||
Other Income Tax Matters — NOL amounts represent the amount of the tax loss that is carried forward and tax credits represent the deferred tax asset. NOL and tax credit carryforwards as of Dec. 31 were as follows: | |||||||||||||
(Millions of Dollars) | 2013 | 2012 | |||||||||||
Federal NOL carryforward | $ | 1,311 | $ | 969 | |||||||||
Federal tax credit carryforwards | 294 | 257 | |||||||||||
State NOL carryforwards | 1,706 | 1,465 | |||||||||||
Valuation allowances for state NOL carryforwards | (51 | ) | (52 | ) | |||||||||
State tax credit carryforwards, net of federal detriment (a) | 17 | 17 | |||||||||||
(a) | State tax credit carryforwards are net of federal detriment of $9 million as of Dec. 31, 2013 and 2012. | ||||||||||||
The federal carryforward periods expire between 2021 and 2033. The state carryforward periods expire between 2014 and 2033. | |||||||||||||
Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense. The following reconciles such differences for the years ending Dec. 31: | |||||||||||||
2013 | 2012 | 2011 | |||||||||||
Federal statutory rate | 35 | % | 35 | % | 35 | % | |||||||
Increases (decreases) in tax from: | |||||||||||||
Tax credits recognized, net of federal income tax expense | (2.6 | ) | (2.2 | ) | (2.6 | ) | |||||||
Regulatory differences — utility plant items | (1.6 | ) | (1.0 | ) | (0.8 | ) | |||||||
NOL carryback | (0.8 | ) | (1.1 | ) | — | ||||||||
State income taxes, net of federal income tax benefit | 4.1 | 4 | 4.3 | ||||||||||
Change in unrecognized tax benefits | 0.6 | — | (0.1 | ) | |||||||||
Prescription drug tax benefit and Medicare Part D | — | (1.2 | ) | — | |||||||||
Other, net | (0.9 | ) | (0.3 | ) | — | ||||||||
Effective income tax rate | 33.8 | % | 33.2 | % | 35.8 | % | |||||||
The components of Xcel Energy’s income tax expense for the years ending Dec. 31 were: | |||||||||||||
(Thousands of Dollars) | 2013 | 2012 | 2011 | ||||||||||
Current federal tax (benefit) expense | $ | (46,173 | ) | $ | 7,876 | $ | 3,399 | ||||||
Current state tax expense | 7,678 | 31,478 | 9,971 | ||||||||||
Current change in unrecognized tax expense (benefit) | 13,162 | (1,704 | ) | (8,266 | ) | ||||||||
Deferred federal tax expense | 439,085 | 366,409 | 383,931 | ||||||||||
Deferred state tax expense | 80,907 | 50,741 | 78,770 | ||||||||||
Deferred change in unrecognized tax (benefit) expense | (4,930 | ) | 2,013 | 6,705 | |||||||||
Deferred investment tax credits | (5,753 | ) | (6,610 | ) | (6,194 | ) | |||||||
Total income tax expense | $ | 483,976 | $ | 450,203 | $ | 468,316 | |||||||
The components of deferred income tax expense for the years ending Dec. 31 were: | |||||||||||||
(Thousands of Dollars) | 2013 | 2012 | 2011 | ||||||||||
Deferred tax expense excluding items below | $ | 588,053 | $ | 559,860 | $ | 446,893 | |||||||
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities | (64,420 | ) | (63,862 | ) | (7,108 | ) | |||||||
Tax (expense) benefit allocated to OCI | (8,572 | ) | 12,102 | 26,798 | |||||||||
Other | 1 | (6 | ) | (16 | ) | ||||||||
Deferred tax expense | $ | 515,062 | $ | 508,094 | $ | 466,567 | |||||||
The components of Xcel Energy’s net deferred tax liability (current and noncurrent) at Dec. 31 were as follows: | |||||||||||||
(Thousands of Dollars) | 2013 | 2012 | |||||||||||
Deferred tax liabilities: | |||||||||||||
Differences between book and tax bases of property | $ | 5,562,446 | $ | 4,867,142 | |||||||||
Regulatory assets | 321,636 | 293,367 | |||||||||||
Other | 254,639 | 220,781 | |||||||||||
Total deferred tax liabilities | $ | 6,138,721 | $ | 5,381,290 | |||||||||
Deferred tax assets: | |||||||||||||
NOL carryforward | $ | 532,774 | $ | 430,765 | |||||||||
Tax credit carryforward | 311,388 | 273,776 | |||||||||||
Unbilled revenue - fuel costs | 58,908 | 60,068 | |||||||||||
Rate refund | 49,804 | 8,109 | |||||||||||
Environmental remediation | 42,886 | 44,549 | |||||||||||
Regulatory liabilities | 40,947 | 34,471 | |||||||||||
Deferred investment tax credits | 34,231 | 35,767 | |||||||||||
Other | 81,202 | 95,308 | |||||||||||
NOL and tax credit valuation allowances | (3,263 | ) | (3,314 | ) | |||||||||
Total deferred tax assets | $ | 1,148,877 | $ | 979,499 | |||||||||
Net deferred tax liability | $ | 4,989,844 | $ | 4,401,791 | |||||||||
Earnings_Per_Share
Earnings Per Share | 12 Months Ended | |||||||||||||||||||||||||||||||||
Dec. 31, 2013 | ||||||||||||||||||||||||||||||||||
Earnings Per Share [Abstract] | ' | |||||||||||||||||||||||||||||||||
Earnings Per Share | ' | |||||||||||||||||||||||||||||||||
Earnings Per Share | ||||||||||||||||||||||||||||||||||
Basic EPS was computed by dividing the earnings available to common shareholders by the weighted average number of common shares outstanding during the period. Diluted EPS was computed by dividing the earnings available to common shareholders by the diluted weighted average number of common shares outstanding during the period. Diluted EPS reflects the potential dilution that could occur if securities or other agreements to issue common stock (i.e., common stock equivalents), were settled. The weighted average number of potentially dilutive shares outstanding used to calculate Xcel Energy Inc.’s diluted EPS is calculated based on the treasury stock method. | ||||||||||||||||||||||||||||||||||
Common Stock Equivalents — Xcel Energy Inc. currently has common stock equivalents related to certain equity awards in share-based compensation arrangements. | ||||||||||||||||||||||||||||||||||
Common stock equivalents related to share-based compensation causing dilutive impact to EPS relates to commitments to issue common stock as an employer match to 401(k) plan participants. In October 2013, Xcel Energy determined that it would settle the 2013 401(k) employer match in cash instead of common stock for all employee groups except PSCo bargaining 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: | ||||||||||||||||||||||||||||||||||
• | RSU 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. | |||||||||||||||||||||||||||||||||
• | PSP 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: | ||||||||||||||||||||||||||||||||||
2013 | 2012 | 2011 | ||||||||||||||||||||||||||||||||
(Amounts in thousands, except per share data) | Income | Shares | Per | Income | Shares | Per | Income | Shares | Per | |||||||||||||||||||||||||
Share | Share | Share | ||||||||||||||||||||||||||||||||
Amount | Amount | Amount | ||||||||||||||||||||||||||||||||
Net income | $ | 948,234 | $ | 905,229 | $ | 841,172 | ||||||||||||||||||||||||||||
Less: Dividend requirements on preferred stock | — | — | (3,534 | ) | ||||||||||||||||||||||||||||||
Less: Premium on redemption of preferred stock | — | — | (3,260 | ) | ||||||||||||||||||||||||||||||
Basic earnings per share: | ||||||||||||||||||||||||||||||||||
Earnings available to common shareholders | 948,234 | 496,073 | $ | 1.91 | 905,229 | 487,899 | $ | 1.86 | 834,378 | 485,039 | $ | 1.72 | ||||||||||||||||||||||
Effect of dilutive securities: | ||||||||||||||||||||||||||||||||||
401(k) equity awards | — | 459 | — | 535 | — | 576 | ||||||||||||||||||||||||||||
Diluted earnings per share: | ||||||||||||||||||||||||||||||||||
Earnings available to common shareholders | $ | 948,234 | 496,532 | $ | 1.91 | $ | 905,229 | 488,434 | $ | 1.85 | $ | 834,378 | 485,615 | $ | 1.72 | |||||||||||||||||||
No stock options were outstanding during 2013 and 2012. In 2011, Xcel Energy Inc. had approximately 2.1 million weighted average options outstanding that were antidilutive, and therefore, excluded from the EPS calculation. | ||||||||||||||||||||||||||||||||||
Share Repurchase — In February 2012, Xcel Energy Inc.’s Board of Directors approved the repurchase of up to 0.7 million shares of common stock for the issuance of shares in connection with the vesting of awards under the Xcel Energy Inc. 2005 Long-Term Incentive Plan. In March 2012, Xcel Energy Inc. repurchased the approved 0.7 million shares in the open market at an average price of $26.42 per share. In addition, approximately 0.9 million shares of common stock were purchased in February 2012 through an agent independent of Xcel Energy to fulfill requirements for the employer match pursuant to the Xcel Energy 401(k) Savings Plan; the NCE Employees’ Savings and Stock Ownership Plan for Bargaining Unit Employees and Former Non-Bargaining Unit Employees; and the NCE Employee Investment Plan for Bargaining Unit Employees and Non-Bargaining Employees. |
ShareBased_Compensation
Share-Based Compensation | 12 Months Ended | ||||||||||||
Dec. 31, 2013 | |||||||||||||
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | ' | ||||||||||||
Share-Based Compensation | ' | ||||||||||||
Share-Based Compensation | |||||||||||||
Stock Options — Xcel Energy Inc. has incentive compensation plans under which stock options and other incentives are awarded to key employees. Xcel Energy Inc. has not granted stock options since 2001. There were no stock options outstanding and no stock option activity during 2013 and 2012. | |||||||||||||
Activity in stock options for the year ended Dec. 31 was as follows: | |||||||||||||
2011 | |||||||||||||
(Awards in Thousands) | Awards | Average | |||||||||||
Exercise | |||||||||||||
Price | |||||||||||||
Outstanding and exercisable at Jan. 1 | 2,498 | $ | 30.42 | ||||||||||
Exercised | (1,173 | ) | 25.9 | ||||||||||
Expired | (1,325 | ) | 34.42 | ||||||||||
Outstanding and exercisable at Dec. 31 | — | — | |||||||||||
The total market value and the total intrinsic value of stock options exercised were as follows for the year ended Dec. 31: | |||||||||||||
(Thousands of Dollars) | 2011 | ||||||||||||
Market value of exercises | $ | 30,761 | |||||||||||
Intrinsic value of options exercised (a) | 380 | ||||||||||||
(a) | Intrinsic value is calculated as market price at exercise date less the option exercise price. | ||||||||||||
Cash received from stock options exercised and the actual tax benefit realized for the tax deductions from stock options exercised during the year ended Dec. 31 were as follows: | |||||||||||||
(Thousands of Dollars) | 2011 | ||||||||||||
Cash received from stock options exercised | $ | 30,381 | |||||||||||
Tax benefit realized for the tax deductions from stock options exercised | 157 | ||||||||||||
Restricted Stock — Certain employees may elect to receive shares of common or restricted stock under the Xcel Energy Inc. Executive Annual Incentive Award Plan. Restricted stock vests and settles in equal annual installments over a three-year period. Xcel Energy Inc. reinvests dividends on the restricted stock while restrictions are in place. Restrictions also apply to the additional shares of restricted stock acquired through dividend reinvestment. If the restricted shares are forfeited, the employee is not entitled to the dividends on those shares. Restricted stock has a fair value equal to the market trading price of Xcel Energy Inc.’s stock at the grant date. | |||||||||||||
Xcel Energy Inc. granted shares of restricted stock for the years ended Dec. 31 as follows: | |||||||||||||
(Shares in Thousands) | 2013 | 2012 | 2011 | ||||||||||
Granted shares | 33 | 33 | 15 | ||||||||||
Grant date fair value | $ | 28.3 | $ | 26.43 | $ | 23.62 | |||||||
A summary of the changes of nonvested restricted stock for the year ended 2013 were as follows: | |||||||||||||
(Shares in Thousands) | Shares | Weighted Average | |||||||||||
Grant Date Fair Value | |||||||||||||
Nonvested restricted stock at Jan. 1, 2013 | 54 | $ | 24.85 | ||||||||||
Granted | 33 | 28.3 | |||||||||||
Vested | (27 | ) | 23.65 | ||||||||||
Dividend equivalents | 2 | 28.88 | |||||||||||
Nonvested restricted stock at Dec. 31, 2013 | 62 | 27.33 | |||||||||||
RSUs — Xcel Energy Inc.’s Board of Directors has granted RSUs under the Xcel Energy Inc. 2005 Long-term Incentive Plan (as amended and restated in 2010). The plan allows the attachment of various performance goals to the RSUs granted. The performance goals may vary by plan year. At the end of the restricted performance period, such grants will be awarded if the performance goals are met. If the goals are not achieved by the end of the restricted performance period, all associated RSUs and dividend equivalents are forfeited. | |||||||||||||
For RSUs issued in 2010, if the performance criteria have not been met within four years of the grant date, all RSUs, plus associated dividend equivalents, shall be forfeited. The performance conditions for RSUs granted in 2011 and 2012, and most granted in 2013 will be measured three years after the grant date, at which time the RSUs, plus associated dividend equivalents, will either be settled or forfeited. In 2013, approximately 0.2 million RSUs were granted subject to service conditions, but no performance conditions. Payout of all other RSUs and the lapsing of restrictions on the transfer of units are based on one of two separate performance criteria. | |||||||||||||
The performance conditions for a portion of the awarded units are based on EPS growth, with an additional condition that Xcel Energy Inc.’s annual dividend paid on its common stock remains at a specified amount per share or greater. These RSUs issued in 2011, 2012 and 2013, plus associated dividend equivalents, will be settled or forfeited and the restricted period will lapse after three years, with potential payouts ranging from zero to 150 percent, depending on the level of EPS growth. | |||||||||||||
The performance conditions for the remaining performance-based units are based on environmental goals. These RSUs issued in 2011, 2012 and 2013, plus associated dividend equivalents, will be settled or forfeited and the restricted period will lapse after three years with potential payouts ranging from zero to 150 percent, depending on the level of environmental performance, based on established indicators. | |||||||||||||
The 2010 RSUs measured on EPS growth and all 2009 RSUs met their targets as of Dec. 31, 2011, and were settled in shares in February 2012. The 2010 environmental RSUs met their targets as of Dec. 31, 2012 and were settled in shares in February 2013. The 2011 RSUs measured on EPS growth and the 2011 environmental RSUs met their targets as of Dec. 31, 2013 and will be settled in shares in February 2014. | |||||||||||||
The RSUs granted for the years ended Dec. 31 were as follows: | |||||||||||||
(Units in Thousands) | 2013 | 2012 | 2011 | ||||||||||
Granted units | 774 | 591 | 828 | ||||||||||
Weighted average grant date fair value | $ | 27.65 | $ | 27.35 | $ | 23.63 | |||||||
A summary of the changes of nonvested RSUs for the year ended 2013, were as follows: | |||||||||||||
(Units in Thousands) | Units | Weighted | |||||||||||
Average | |||||||||||||
Grant Date | |||||||||||||
Fair Value | |||||||||||||
Nonvested RSUs at Jan. 1, 2013 | 1,155 | $ | 25.41 | ||||||||||
Granted | 774 | 27.65 | |||||||||||
Forfeited | (81 | ) | 26.32 | ||||||||||
Vested | (600 | ) | 23.62 | ||||||||||
Dividend equivalents | 64 | 26.11 | |||||||||||
Nonvested RSUs at Dec. 31, 2013 | 1,312 | 27.53 | |||||||||||
The total fair value of nonvested RSUs as of Dec. 31, 2013 was $36.7 million and the weighted average remaining contractual life was 1.7 years. | |||||||||||||
Approximately 0.6 million RSUs vested during 2013 at a total fair value of $16.8 million. Approximately 0.1 million RSUs vested during 2012 at a total fair value of $1.2 million. Approximately 1.1 million RSUs vested during 2011 at a total fair value of $30.1 million. | |||||||||||||
Stock Equivalent Unit Plan — Non-employee members of the Xcel Energy Inc. Board of Directors receive annual awards of stock equivalent units, with each unit having a value equal to one share of Xcel Energy Inc. common stock. The annual grants are vested as of the date of each member’s election to the board of directors; there is no further service or other condition attached to the annual grants after the member has been elected to the board. Additionally, directors may elect to receive their fees in stock equivalent units in lieu of cash, and similarly have no further service or other conditions attached. Dividends on Xcel Energy Inc.’s common stock are converted to stock equivalent units and granted based on the number of stock equivalent units held by each participant as of the dividend date. The stock equivalent units are payable as a distribution of Xcel Energy Inc.’s common stock upon a director’s termination of service. | |||||||||||||
The stock equivalent units granted for the years ended Dec. 31 were as follows: | |||||||||||||
(Units in Thousands) | 2013 | 2012 | 2011 | ||||||||||
Granted units | 69 | 65 | 60 | ||||||||||
Grant date fair value | $ | 29.52 | $ | 27.41 | $ | 25.12 | |||||||
A summary of the stock equivalent unit changes for the year ended 2013 are as follows: | |||||||||||||
(Units in Thousands) | Units | Weighted | |||||||||||
Average | |||||||||||||
Grant Date | |||||||||||||
Fair Value | |||||||||||||
Stock equivalent units at Jan. 1, 2013 | 577 | $ | 21.71 | ||||||||||
Granted | 69 | 29.52 | |||||||||||
Units distributed | (32 | ) | 18.23 | ||||||||||
Dividend equivalents | 22 | 29.06 | |||||||||||
Stock equivalent units at Dec. 31, 2013 | 636 | 22.98 | |||||||||||
PSP Awards — Xcel Energy Inc.’s Board of Directors has granted PSP awards under the Xcel Energy Inc. 2005 Long-term Incentive Plan (as amended and restated effective in 2010). The plan allows Xcel Energy to attach various performance goals to the PSP awards granted. The PSP awards have been historically dependent on a single measure of performance, Xcel Energy Inc.’s TSR measured over a three-year period. Xcel Energy Inc.’s TSR is compared to the TSR of other companies in the EEI Investor-Owned Electrics index. At the end of the three-year period, potential payouts of the PSP awards range from zero to 200 percent, depending on Xcel Energy Inc.’s TSR compared to the peer group. | |||||||||||||
The PSP awards granted for the years ended Dec. 31 were as follows: | |||||||||||||
(In Thousands) | 2013 | 2012 | 2011 | ||||||||||
Awards granted | 215 | 161 | 311 | ||||||||||
The total amounts of performance awards settled during the years ended Dec. 31 were as follows: | |||||||||||||
(In Thousands) | 2013 | 2012 | 2011 | ||||||||||
Awards settled | 108 | 286 | 305 | ||||||||||
Settlement amount (cash and common stock) | $ | 3,057 | $ | 7,554 | $ | 7,200 | |||||||
The amount of cash used to settle Xcel Energy’s PSP awards was $1.5 million, $3.8 million and $3.6 million in 2013, 2012 and 2011, respectively. | |||||||||||||
Share-Based Compensation Expense — The vesting of the RSUs is generally predicated on the achievement of a performance condition, which is the achievement of an EPS or environmental measures target. Additionally, approximately 0.2 million of RSUs were granted in 2013 with vesting subject only to service conditions for periods up to five years. RSU awards and restricted stock are considered to be equity awards, since the plan settlement determination (shares or cash) resides with Xcel Energy and not the participants. In addition, these awards have not been previously settled in cash and Xcel Energy plans to continue electing share settlement. The grant date fair value of RSUs and restricted stock is expensed over the service period as employees vest in their rights to those awards. | |||||||||||||
The PSP awards have been historically settled partially in cash, and therefore, do not qualify as equity awards, but rather are accounted for as liability awards. As liability awards, the fair value on which ratable expense is based, as employees vest in their rights to those awards, is remeasured each period based on the current stock price and performance conditions, and final expense is based on the market value of the shares on the date the award is settled. | |||||||||||||
The compensation costs related to share-based awards for the years ended Dec. 31 were as follows: | |||||||||||||
(Thousands of Dollars) | 2013 | 2012 | 2011 | ||||||||||
Compensation cost for share-based awards (a) (b) (c) | $ | 24,613 | $ | 26,970 | $ | 45,006 | |||||||
Tax benefit recognized in income | 9,571 | 10,513 | 17,559 | ||||||||||
Capitalized compensation cost for share-based awards | 1,698 | 4,270 | 3,857 | ||||||||||
(a) | Compensation costs for share-based payment arrangements is included in O&M expense in the consolidated statements of income. | ||||||||||||
(b) | Included in compensation cost for share-based awards are matching contributions related to the Xcel Energy 401(k) plan, which totaled $7.0 million, $22.2 million and $21.6 million for the years ended 2013, 2012 and 2011, respectively. | ||||||||||||
(c) | In October 2013, Xcel Energy determined that it would settle the 2013 401(k) employer match in cash instead of common stock for all employee groups except PSCo bargaining 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. | ||||||||||||
The maximum aggregate number of shares of common stock available for issuance under the Xcel Energy Inc. 2005 Long-term Incentive Plan (as amended and restated effective Feb. 17, 2010) is 8.3 million shares. Under the Xcel Energy Inc. Executive Annual Incentive Award Plan (as amended and restated effective Feb. 17, 2010), the total number of shares approved for issuance is 1.2 million shares. | |||||||||||||
As of Dec. 31, 2013 and 2012, there was approximately $22.1 million and $15.3 million, respectively, of total unrecognized compensation cost related to nonvested share-based compensation awards. Xcel Energy expects to recognize the amount unrecognized at Dec. 31, 2013 over a weighted average period of 1.8 years. |
Benefit_Plans_and_Other_Postre
Benefit Plans and Other Postretirement Benefits | 12 Months Ended | ||||||||||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||||||||||
Compensation and Retirement Disclosure [Abstract] | ' | ||||||||||||||||||||||||
Benefit Plans and Other Postretirement Benefits | ' | ||||||||||||||||||||||||
Benefit Plans and Other Postretirement Benefits | |||||||||||||||||||||||||
Xcel Energy offers various benefit plans to its employees. Approximately 48 percent of employees that receive benefits are represented by several local labor unions under several collective-bargaining agreements. At Dec. 31, 2013: | |||||||||||||||||||||||||
• | NSP-Minnesota had 2,022 and NSP-Wisconsin had 399 bargaining employees covered under a collective-bargaining agreement, which expires at the end of 2016. NSP-Minnesota also had an additional 248 nuclear operation bargaining employees covered under several collective-bargaining agreements, which expire at various dates in 2015 and 2016. | ||||||||||||||||||||||||
• | PSCo had 2,086 bargaining employees covered under a collective-bargaining agreement, which expires in May 2014. | ||||||||||||||||||||||||
• | SPS had 832 bargaining employees covered under a collective-bargaining agreement, which expires in October 2014. | ||||||||||||||||||||||||
The plans invest in various instruments which are disclosed under the accounting guidance for fair value measurements which establishes a hierarchical framework for disclosing the observability of the inputs utilized in measuring fair value. The three levels in the hierarchy and examples of each level are as follows: | |||||||||||||||||||||||||
Level 1 — Quoted prices are available in active markets for identical assets as of the reporting date. The types of assets 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 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 included in Level 3 are those with inputs 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. | |||||||||||||||||||||||||
Insurance contracts — Insurance contract fair values take into consideration the value of the investments in separate accounts of the insurer, which are priced based on observable inputs. | |||||||||||||||||||||||||
Investments in equity securities and other funds — Equity securities are valued using quoted prices in active markets. Preferred stock is valued using recent trades and quoted prices of similar securities. The fair values for commingled 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 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 the plan’s evaluation of its ability to redeem private equity and real estate investments, fair value measurements for private equity and real estate investments have been assigned a Level 3. | |||||||||||||||||||||||||
Investments in debt securities — Fair values for debt securities are determined by a third party pricing service using recent trades and observable spreads from benchmark interest rates for similar securities. | |||||||||||||||||||||||||
Derivative Instruments — Fair values for foreign currency derivatives are determined using pricing models based on the prevailing forward exchange rate of the underlying currencies. The fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts. | |||||||||||||||||||||||||
Pension Benefits | |||||||||||||||||||||||||
Xcel Energy has several noncontributory, defined benefit pension plans that cover almost all employees. Benefits are based on a combination of years of service, the employee’s average pay and social security benefits. Xcel Energy’s policy is to fully fund into an external trust the actuarially determined pension costs recognized for ratemaking and financial reporting purposes, subject to the limitations of applicable employee benefit and tax laws. | |||||||||||||||||||||||||
In addition to the qualified pension plans, Xcel Energy maintains a supplemental executive retirement plan (SERP) and a nonqualified pension plan. The SERP is maintained for certain executives that were participants in the plan in 2008, when the SERP was closed to new participants. The nonqualified pension plan provides unfunded, nonqualified benefits for compensation that is in excess of the limits applicable to the qualified pension plans. The total obligations of the SERP and nonqualified plan as of Dec. 31, 2013 and 2012 were $36.5 million and $39.4 million, respectively. In 2013 and 2012, Xcel Energy recognized net benefit cost for financial reporting for the SERP and nonqualified plans of $6.6 million and $15.6 million, respectively. Benefits for these unfunded plans are paid out of Xcel Energy’s consolidated operating cash flows. | |||||||||||||||||||||||||
Xcel Energy bases the investment-return assumption on expected long-term performance for each of the investment types included in its pension asset portfolio. Xcel Energy considers the historical returns achieved by its asset portfolio over the past 20-year or longer period, as well as the long-term return levels projected and recommended by investment experts. The pension cost determination assumes a forecasted mix of investment types over the long-term. Investment returns were below the assumed level of 6.88 percent in 2013 and above the assumed levels of 7.10 and 7.50 percent in 2012 and 2011, respectively. Xcel Energy continually reviews its pension assumptions. In 2014, Xcel Energy’s expected investment return assumption is 7.05 percent. | |||||||||||||||||||||||||
The assets are invested in a portfolio according to Xcel Energy’s return, liquidity and diversification objectives to provide a source of funding for plan obligations and minimize the necessity of contributions to the plan, within appropriate levels of risk. The principal mechanism for achieving these objectives is the projected allocation of assets to selected asset classes, given the long-term risk, return, and liquidity characteristics of each particular asset class. There were no significant concentrations of risk in any particular industry, index, or entity. Market volatility can impact even well-diversified portfolios and significantly affect the return levels achieved by pension assets in any year. | |||||||||||||||||||||||||
The following table presents the target pension asset allocations for Xcel Energy: | |||||||||||||||||||||||||
2013 | 2012 | ||||||||||||||||||||||||
Domestic and international equity securities | 30 | % | 25 | % | |||||||||||||||||||||
Long-duration fixed income and interest rate swap securities | 33 | 40 | |||||||||||||||||||||||
Short-to-intermediate fixed income securities | 15 | 10 | |||||||||||||||||||||||
Alternative investments | 20 | 23 | |||||||||||||||||||||||
Cash | 2 | 2 | |||||||||||||||||||||||
Total | 100 | % | 100 | % | |||||||||||||||||||||
Xcel Energy’s ongoing investment strategy is based on plan-specific investment recommendations that seek to minimize potential investment and interest rate risk as a plan’s funded status increases over time. The investment recommendations result in a greater percentage of long-duration fixed income securities being allocated to specific plans having relatively higher funded status ratios, and a greater percentage of growth assets being allocated to plans having relatively lower funded status ratios. The aggregate projected asset allocation presented in the table above for the master pension trust results from the plan-specific strategies. | |||||||||||||||||||||||||
Pension Plan Assets | |||||||||||||||||||||||||
The following tables present, for each of the fair value hierarchy levels, Xcel Energy’s pension plan assets that are measured at fair value as of Dec. 31, 2013 and 2012: | |||||||||||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||||||||||
(Thousands of Dollars) | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||||||
Cash equivalents | $ | 109,700 | $ | — | $ | — | $ | 109,700 | |||||||||||||||||
Derivatives | — | 29,759 | — | 29,759 | |||||||||||||||||||||
Government securities | — | 230,212 | — | 230,212 | |||||||||||||||||||||
Corporate bonds | — | 547,715 | — | 547,715 | |||||||||||||||||||||
Asset-backed securities | — | 6,754 | — | 6,754 | |||||||||||||||||||||
Mortgage-backed securities | — | 15,025 | — | 15,025 | |||||||||||||||||||||
Common stock | 99,346 | — | — | 99,346 | |||||||||||||||||||||
Private equity investments | — | — | 152,849 | 152,849 | |||||||||||||||||||||
Commingled funds | — | 1,769,076 | — | 1,769,076 | |||||||||||||||||||||
Real estate | — | — | 47,553 | 47,553 | |||||||||||||||||||||
Securities lending collateral obligation and other | — | 2,151 | — | 2,151 | |||||||||||||||||||||
Total | $ | 209,046 | $ | 2,600,692 | $ | 200,402 | $ | 3,010,140 | |||||||||||||||||
Dec. 31, 2012 | |||||||||||||||||||||||||
(Thousands of Dollars) | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||||||
Cash equivalents | $ | 164,096 | $ | — | $ | — | $ | 164,096 | |||||||||||||||||
Derivatives | — | 12,955 | — | 12,955 | |||||||||||||||||||||
Government securities | — | 298,141 | — | 298,141 | |||||||||||||||||||||
Corporate bonds | — | 622,597 | — | 622,597 | |||||||||||||||||||||
Asset-backed securities | — | — | 14,639 | 14,639 | |||||||||||||||||||||
Mortgage-backed securities | — | — | 39,904 | 39,904 | |||||||||||||||||||||
Common stock | 73,247 | — | — | 73,247 | |||||||||||||||||||||
Private equity investments | — | — | 158,498 | 158,498 | |||||||||||||||||||||
Commingled funds | — | 1,524,563 | — | 1,524,563 | |||||||||||||||||||||
Real estate | — | — | 64,597 | 64,597 | |||||||||||||||||||||
Securities lending collateral obligation and other | — | (29,454 | ) | — | (29,454 | ) | |||||||||||||||||||
Total | $ | 237,343 | $ | 2,428,802 | $ | 277,638 | $ | 2,943,783 | |||||||||||||||||
The following tables present the changes in Xcel Energy’s Level 3 pension plan assets for the years ended Dec. 31, 2013, 2012 and 2011: | |||||||||||||||||||||||||
(Thousands of Dollars) | Jan. 1, 2013 | Net Realized | Net Unrealized | Purchases, | Transfers Out of Level 3 (a) | Dec. 31, 2013 | |||||||||||||||||||
Gains (Losses) | Gains (Losses) | Issuances and | |||||||||||||||||||||||
Settlements, Net | |||||||||||||||||||||||||
Asset-backed securities | $ | 14,639 | $ | — | $ | — | $ | — | $ | (14,639 | ) | $ | — | ||||||||||||
Mortgage-backed securities | 39,904 | — | — | — | (39,904 | ) | — | ||||||||||||||||||
Private equity investments | 158,498 | 22,058 | (24,335 | ) | (3,372 | ) | — | 152,849 | |||||||||||||||||
Real estate | 64,597 | (2,659 | ) | 8,690 | 9,317 | (32,392 | ) | 47,553 | |||||||||||||||||
Total | $ | 277,638 | $ | 19,399 | $ | (15,645 | ) | $ | 5,945 | $ | (86,935 | ) | $ | 200,402 | |||||||||||
(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 and were subsequently sold during 2013. | ||||||||||||||||||||||||
(Thousands of Dollars) | Jan. 1, 2012 | Net Realized | Net Unrealized | Purchases, | Transfers Out of Level 3 | Dec. 31, 2012 | |||||||||||||||||||
Gains (Losses) | Gains (Losses) | Issuances and | |||||||||||||||||||||||
Settlements, Net | |||||||||||||||||||||||||
Asset-backed securities | $ | 31,368 | $ | 3,886 | $ | (5,363 | ) | $ | (15,252 | ) | $ | — | $ | 14,639 | |||||||||||
Mortgage-backed securities | 73,522 | 1,822 | (2,127 | ) | (33,313 | ) | — | 39,904 | |||||||||||||||||
Private equity investments | 159,363 | 17,537 | (22,587 | ) | 4,185 | — | 158,498 | ||||||||||||||||||
Real estate | 37,106 | 19 | 6,048 | 21,424 | — | 64,597 | |||||||||||||||||||
Total | $ | 301,359 | $ | 23,264 | $ | (24,029 | ) | $ | (22,956 | ) | $ | — | $ | 277,638 | |||||||||||
(Thousands of Dollars) | Jan. 1, 2011 | Net Realized | Net Unrealized | Purchases, | Transfers Out of Level 3 | Dec. 31, 2011 | |||||||||||||||||||
Gains (Losses) | Gains (Losses) | Issuances and | |||||||||||||||||||||||
Settlements, Net | |||||||||||||||||||||||||
Asset-backed securities | $ | 26,986 | $ | 2,391 | $ | (2,504 | ) | $ | 4,495 | $ | — | $ | 31,368 | ||||||||||||
Mortgage-backed securities | 113,418 | 1,103 | (5,926 | ) | (35,073 | ) | — | 73,522 | |||||||||||||||||
Private equity investments | 122,223 | 3,971 | 12,412 | 20,757 | — | 159,363 | |||||||||||||||||||
Real estate | 73,701 | (629 | ) | 20,271 | (56,237 | ) | — | 37,106 | |||||||||||||||||
Total | $ | 336,328 | $ | 6,836 | $ | 24,253 | $ | (66,058 | ) | $ | — | $ | 301,359 | ||||||||||||
Benefit Obligations — A comparison of the actuarially computed pension benefit obligation and plan assets for Xcel Energy is presented in the following table: | |||||||||||||||||||||||||
(Thousands of Dollars) | 2013 | 2012 | |||||||||||||||||||||||
Accumulated Benefit Obligation at Dec. 31 | $ | 3,282,651 | $ | 3,475,154 | |||||||||||||||||||||
Change in Projected Benefit Obligation: | |||||||||||||||||||||||||
Obligation at Jan. 1 | $ | 3,639,530 | $ | 3,226,219 | |||||||||||||||||||||
Service cost | 96,282 | 86,364 | |||||||||||||||||||||||
Interest cost | 140,690 | 157,035 | |||||||||||||||||||||||
Plan amendments | (4,120 | ) | 6,240 | ||||||||||||||||||||||
Actuarial (gain) loss | (153,338 | ) | 400,429 | ||||||||||||||||||||||
Benefit payments | (278,340 | ) | (236,757 | ) | |||||||||||||||||||||
Obligation at Dec. 31 | $ | 3,440,704 | $ | 3,639,530 | |||||||||||||||||||||
(Thousands of Dollars) | 2013 | 2012 | |||||||||||||||||||||||
Change in Fair Value of Plan Assets: | |||||||||||||||||||||||||
Fair value of plan assets at Jan. 1 | $ | 2,943,783 | $ | 2,670,280 | |||||||||||||||||||||
Actual return on plan assets | 152,259 | 312,167 | |||||||||||||||||||||||
Employer contributions | 192,438 | 198,093 | |||||||||||||||||||||||
Benefit payments | (278,340 | ) | (236,757 | ) | |||||||||||||||||||||
Fair value of plan assets at Dec. 31 | $ | 3,010,140 | $ | 2,943,783 | |||||||||||||||||||||
(Thousands of Dollars) | 2013 | 2012 | |||||||||||||||||||||||
Funded Status of Plans at Dec. 31: | |||||||||||||||||||||||||
Funded status (a) | $ | (430,564 | ) | $ | (695,747 | ) | |||||||||||||||||||
(a) | Amounts are recognized in noncurrent liabilities on Xcel Energy’s consolidated balance sheets. | ||||||||||||||||||||||||
(Thousands of Dollars) | 2013 | 2012 | |||||||||||||||||||||||
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost: | |||||||||||||||||||||||||
Net loss | $ | 1,549,474 | $ | 1,800,770 | |||||||||||||||||||||
Prior service credit | (12,624 | ) | (2,633 | ) | |||||||||||||||||||||
Total | $ | 1,536,850 | $ | 1,798,137 | |||||||||||||||||||||
(Thousands of Dollars) | 2013 | 2012 | |||||||||||||||||||||||
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates: | |||||||||||||||||||||||||
Current regulatory assets | $ | 125,702 | $ | 115,811 | |||||||||||||||||||||
Noncurrent regulatory assets | 1,343,432 | 1,606,524 | |||||||||||||||||||||||
Deferred income taxes | 26,403 | 31,075 | |||||||||||||||||||||||
Net-of-tax accumulated OCI | 41,313 | 44,727 | |||||||||||||||||||||||
Total | $ | 1,536,850 | $ | 1,798,137 | |||||||||||||||||||||
Measurement date | Dec. 31, 2013 | Dec. 31, 2012 | |||||||||||||||||||||||
2013 | 2012 | ||||||||||||||||||||||||
Significant Assumptions Used to Measure Benefit Obligations: | |||||||||||||||||||||||||
Discount rate for year-end valuation | 4.75 | % | 4 | % | |||||||||||||||||||||
Expected average long-term increase in compensation level | 3.75 | 3.75 | |||||||||||||||||||||||
Mortality table | RP 2000 | RP 2000 | |||||||||||||||||||||||
Cash Flows — Cash funding requirements can be impacted by changes to actuarial assumptions, actual asset levels and other calculations prescribed by the funding requirements of income tax and other pension-related regulations. These regulations did not require cash funding for 2008 through 2010 for Xcel Energy’s pension plans. Required contributions were made in 2011, 2012 and 2013 to meet minimum funding requirements. | |||||||||||||||||||||||||
The following are the pension funding contributions, both voluntary and required, made by Xcel Energy for 2011 through January 2014: | |||||||||||||||||||||||||
• | In January 2014, contributions of $130.0 million were made across three of Xcel Energy’s pension plans; | ||||||||||||||||||||||||
• | In 2013, contributions of $192.4 million were made across four of Xcel Energy’s pension plans; | ||||||||||||||||||||||||
• | In 2012, contributions of $198.1 million were made across four of Xcel Energy’s pension plans; | ||||||||||||||||||||||||
• | In 2011, contributions of $137.3 million were made across three of Xcel Energy’s pension plans; | ||||||||||||||||||||||||
• | For future years, Xcel Energy anticipates contributions will be made as necessary. | ||||||||||||||||||||||||
Plan Amendments —The 2013 decrease of the projected benefit obligation for plan amendments is due to fully insuring the long-term disability benefit for NSP bargaining participants. This decrease was partially offset by an increase to the projected benefit obligation resulting from a change in the discount rate basis for lump sum conversion of annuities for participants in the Xcel Energy Pension Plan. In 2012, the plan was amended to allow a one time transfer of a portion of qualifying obligations from the nonqualified pension plan into the qualified pension plans. Xcel Energy also modified the benefit formula for nonbargaining new hires beginning in 2012 to a reduced benefit level. | |||||||||||||||||||||||||
Benefit Costs — The components of Xcel Energy’s net periodic pension cost were: | |||||||||||||||||||||||||
(Thousands of Dollars) | 2013 | 2012 | 2011 | ||||||||||||||||||||||
Service cost | $ | 96,282 | $ | 86,364 | $ | 77,319 | |||||||||||||||||||
Interest cost | 140,690 | 157,035 | 161,412 | ||||||||||||||||||||||
Expected return on plan assets | (198,452 | ) | (207,095 | ) | (221,600 | ) | |||||||||||||||||||
Amortization of prior service cost | 5,871 | 21,065 | 22,533 | ||||||||||||||||||||||
Amortization of net loss | 144,151 | 108,982 | 78,510 | ||||||||||||||||||||||
Net periodic pension cost | 188,542 | 166,351 | 118,174 | ||||||||||||||||||||||
Costs not recognized due to effects of regulation | (36,724 | ) | (39,217 | ) | (37,198 | ) | |||||||||||||||||||
Net benefit cost recognized for financial reporting | $ | 151,818 | $ | 127,134 | $ | 80,976 | |||||||||||||||||||
2013 | 2012 | 2011 | |||||||||||||||||||||||
Significant Assumptions Used to Measure Costs: | |||||||||||||||||||||||||
Discount rate | 4 | % | 5 | % | 5.5 | % | |||||||||||||||||||
Expected average long-term increase in compensation level | 3.75 | 4 | 4 | ||||||||||||||||||||||
Expected average long-term rate of return on assets | 6.88 | 7.1 | 7.5 | ||||||||||||||||||||||
Pension costs include an expected return impact for the current year that may differ from actual investment performance in the plan. The return assumption used for 2014 pension cost calculations is 7.05 percent. | |||||||||||||||||||||||||
Defined Contribution Plans | |||||||||||||||||||||||||
Xcel Energy maintains 401(k) and other defined contribution plans that cover substantially all employees. Total expense to these plans was approximately $30.3 million in 2013, $28.0 million in 2012 and $27.1 million in 2011. | |||||||||||||||||||||||||
Postretirement Health Care Benefits | |||||||||||||||||||||||||
Xcel Energy has a contributory health and welfare benefit plan that provides health care and death benefits to certain Xcel Energy retirees. | |||||||||||||||||||||||||
• | The former NSP, which includes NSP-Minnesota and NSP-Wisconsin, discontinued contributing toward health care benefits for nonbargaining employees retiring after 1998 and for bargaining employees who retired after 1999. | ||||||||||||||||||||||||
• | Xcel Energy discontinued contributing toward health care benefits for former NCE, which includes PSCo and SPS, nonbargaining employees retiring after June 30, 2003. | ||||||||||||||||||||||||
• | Employees of NCE who retired in 2002 continue to receive employer-subsidized health care benefits. | ||||||||||||||||||||||||
• | Nonbargaining employees of the former NCE who retired after 1998, bargaining employees of the former NCE who retired after 1999 and nonbargaining employees of NCE who retired after June 30, 2003, are eligible to participate in the Xcel Energy health care program with no employer subsidy. | ||||||||||||||||||||||||
In 1993, Xcel Energy adopted accounting guidance regarding other non-pension postretirement benefits and elected to amortize the unrecognized APBO on a straight-line basis over 20 years. | |||||||||||||||||||||||||
Regulatory agencies for nearly all of Xcel Energy’s retail and wholesale utility customers have allowed rate recovery of accrued postretirement benefit costs. The Colorado jurisdictional postretirement benefit costs deferred during the transition period were amortized to expense on a straight-line basis over the 15-year period from 1998 to 2012. PSCo transitioned to full accrual accounting for postretirement benefit costs between 1993 and 1997. | |||||||||||||||||||||||||
Plan Assets — Certain state agencies that regulate Xcel Energy Inc.’s utility subsidiaries also have issued guidelines related to the funding of postretirement benefit costs. SPS is required to fund postretirement benefit costs for Texas and New Mexico jurisdictional amounts collected in rates. PSCo is required to fund postretirement benefit costs in irrevocable external trusts that are dedicated to the payment of these postretirement benefits. Also, a portion of the assets contributed on behalf of nonbargaining retirees has been funded into a sub-account of the Xcel Energy pension plans. These assets are invested in a manner consistent with the investment strategy for the pension plan. | |||||||||||||||||||||||||
Xcel Energy bases its investment-return assumption for the postretirement health care fund assets on expected long-term performance for each of the investment types included in its asset portfolio. The assets are invested in a portfolio according to Xcel Energy’s return, liquidity and diversification objectives to provide a source of funding for plan obligations and minimize the necessity of contributions to the plan, within appropriate levels of risk. The principal mechanism for achieving these objectives is the projected allocation of assets to selected asset classes, given the long-term risk, return, correlation, and liquidity characteristics of each particular asset class. There were no significant concentrations of risk in any particular industry, index, or entity. Market volatility can impact even well-diversified portfolios and significantly affect the return levels achieved by postretirement health care assets in any year. | |||||||||||||||||||||||||
The following tables present, for each of the fair value hierarchy levels, Xcel Energy’s postretirement benefit plan assets that are measured at fair value as of Dec. 31, 2013 and 2012: | |||||||||||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||||||||||
(Thousands of Dollars) | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||||||
Cash equivalents | $ | 20,438 | $ | — | $ | — | $ | 20,438 | |||||||||||||||||
Derivatives | — | (414 | ) | — | (414 | ) | |||||||||||||||||||
Government securities | — | 58,421 | — | 58,421 | |||||||||||||||||||||
Insurance contracts | — | 52,808 | — | 52,808 | |||||||||||||||||||||
Corporate bonds | — | 51,861 | — | 51,861 | |||||||||||||||||||||
Asset-backed securities | — | 3,358 | — | 3,358 | |||||||||||||||||||||
Mortgage-backed securities | — | 24,246 | — | 24,246 | |||||||||||||||||||||
Commingled funds | — | 298,258 | — | 298,258 | |||||||||||||||||||||
Other | — | (16,940 | ) | — | (16,940 | ) | |||||||||||||||||||
Total | $ | 20,438 | $ | 471,598 | $ | — | $ | 492,036 | |||||||||||||||||
Dec. 31, 2012 | |||||||||||||||||||||||||
(Thousands of Dollars) | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||||||
Cash equivalents | $ | 91,278 | $ | — | $ | — | $ | 91,278 | |||||||||||||||||
Derivatives | — | 4 | — | 4 | |||||||||||||||||||||
Government securities | — | 73,449 | — | 73,449 | |||||||||||||||||||||
Insurance contracts | — | 50,008 | — | 50,008 | |||||||||||||||||||||
Corporate bonds | — | 43,810 | — | 43,810 | |||||||||||||||||||||
Asset-backed securities | — | — | 757 | 757 | |||||||||||||||||||||
Mortgage-backed securities | — | — | 39,958 | 39,958 | |||||||||||||||||||||
Commingled funds | — | 228,423 | — | 228,423 | |||||||||||||||||||||
Other | — | (46,845 | ) | — | (46,845 | ) | |||||||||||||||||||
Total | $ | 91,278 | $ | 348,849 | $ | 40,715 | $ | 480,842 | |||||||||||||||||
The following tables present the changes in Xcel Energy’s Level 3 postretirement benefit plan assets for the years ended Dec. 31, 2013, 2012 and 2011: | |||||||||||||||||||||||||
(Thousands of Dollars) | Jan. 1, 2013 | Net Realized | Net Unrealized | Purchases, | Transfers Out of Level 3 (a) | Dec. 31, 2013 | |||||||||||||||||||
Gains (Losses) | Gains (Losses) | Issuances and | |||||||||||||||||||||||
Settlements, Net | |||||||||||||||||||||||||
Asset-backed securities | $ | 757 | $ | — | $ | — | $ | — | $ | (757 | ) | $ | — | ||||||||||||
Mortgage-backed securities | 39,958 | — | — | — | (39,958 | ) | — | ||||||||||||||||||
Total | $ | 40,715 | $ | — | $ | — | $ | — | $ | (40,715 | ) | $ | — | ||||||||||||
(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 and were subsequently sold during 2013. | ||||||||||||||||||||||||
(Thousands of Dollars) | Jan. 1, 2012 | Net Realized | Net Unrealized | Purchases, | Transfers Out of Level 3 | Dec. 31, 2012 | |||||||||||||||||||
Gains (Losses) | Gains (Losses) | Issuances and | |||||||||||||||||||||||
Settlements, Net | |||||||||||||||||||||||||
Asset-backed securities | $ | 7,867 | $ | (331 | ) | $ | 1,481 | $ | (8,260 | ) | $ | — | $ | 757 | |||||||||||
Mortgage-backed securities | 27,253 | (724 | ) | 3,301 | 10,128 | — | 39,958 | ||||||||||||||||||
Private equity investments | 479 | — | (65 | ) | (414 | ) | — | — | |||||||||||||||||
Real estate | 144 | — | 35 | (179 | ) | — | — | ||||||||||||||||||
Total | $ | 35,743 | $ | (1,055 | ) | $ | 4,752 | $ | 1,275 | $ | — | $ | 40,715 | ||||||||||||
(Thousands of Dollars) | Jan. 1, 2011 | Net Realized | Net Unrealized | Purchases, | Transfers Out of Level 3 | Dec. 31, 2011 | |||||||||||||||||||
Gains (Losses) | Gains (Losses) | Issuances and | |||||||||||||||||||||||
Settlements, Net | |||||||||||||||||||||||||
Asset-backed securities | $ | 2,585 | $ | (10 | ) | $ | (664 | ) | $ | 5,956 | $ | — | $ | 7,867 | |||||||||||
Mortgage-backed securities | 19,212 | (1,669 | ) | 2,623 | 7,087 | — | 27,253 | ||||||||||||||||||
Private equity investments | — | 12 | 53 | 414 | — | 479 | |||||||||||||||||||
Real estate | — | (2 | ) | (34 | ) | 180 | — | 144 | |||||||||||||||||
Total | $ | 21,797 | $ | (1,669 | ) | $ | 1,978 | $ | 13,637 | $ | — | $ | 35,743 | ||||||||||||
Benefit Obligations — A comparison of the actuarially computed benefit obligation and plan assets for Xcel Energy is presented in the following table: | |||||||||||||||||||||||||
(Thousands of Dollars) | 2013 | 2012 | |||||||||||||||||||||||
Change in Projected Benefit Obligation: | |||||||||||||||||||||||||
Obligation at Jan. 1 | $ | 851,952 | $ | 776,847 | |||||||||||||||||||||
Service cost | 4,079 | 4,203 | |||||||||||||||||||||||
Interest cost | 32,141 | 37,861 | |||||||||||||||||||||||
Medicare subsidy reimbursements | 1,197 | 3,741 | |||||||||||||||||||||||
Plan amendments | (14,571 | ) | (41,128 | ) | |||||||||||||||||||||
Plan participants’ contributions | 9,580 | 14,241 | |||||||||||||||||||||||
Actuarial (gain) loss | (103,359 | ) | 119,949 | ||||||||||||||||||||||
Benefit payments | (49,591 | ) | (63,762 | ) | |||||||||||||||||||||
Obligation at Dec. 31 | $ | 731,428 | $ | 851,952 | |||||||||||||||||||||
(Thousands of Dollars) | 2013 | 2012 | |||||||||||||||||||||||
Change in Fair Value of Plan Assets: | |||||||||||||||||||||||||
Fair value of plan assets at Jan. 1 | $ | 480,842 | $ | 426,835 | |||||||||||||||||||||
Actual return on plan assets | 33,644 | 56,385 | |||||||||||||||||||||||
Plan participants’ contributions | 9,580 | 14,241 | |||||||||||||||||||||||
Employer contributions | 17,561 | 47,143 | |||||||||||||||||||||||
Benefit payments | (49,591 | ) | (63,762 | ) | |||||||||||||||||||||
Fair value of plan assets at Dec. 31 | $ | 492,036 | $ | 480,842 | |||||||||||||||||||||
(Thousands of Dollars) | 2013 | 2012 | |||||||||||||||||||||||
Funded Status of Plans at Dec. 31: | |||||||||||||||||||||||||
Funded status | $ | (239,392 | ) | $ | (371,110 | ) | |||||||||||||||||||
Current liabilities | (6,807 | ) | (6,070 | ) | |||||||||||||||||||||
Noncurrent liabilities | (232,585 | ) | (365,040 | ) | |||||||||||||||||||||
Net postretirement amounts recognized on consolidated balance sheets | $ | (239,392 | ) | $ | (371,110 | ) | |||||||||||||||||||
(Thousands of Dollars) | 2013 | 2012 | |||||||||||||||||||||||
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost: | |||||||||||||||||||||||||
Net loss | $ | 195,630 | $ | 321,946 | |||||||||||||||||||||
Prior service credit | (86,298 | ) | (84,228 | ) | |||||||||||||||||||||
Transition obligation | 2 | 827 | |||||||||||||||||||||||
Total | $ | 109,334 | $ | 238,545 | |||||||||||||||||||||
(Thousands of Dollars) | 2013 | 2012 | |||||||||||||||||||||||
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates: | |||||||||||||||||||||||||
Current regulatory assets | $ | 12,102 | $ | 6,930 | |||||||||||||||||||||
Noncurrent regulatory assets | 99,071 | 226,052 | |||||||||||||||||||||||
Current regulatory liabilities | (319 | ) | (954 | ) | |||||||||||||||||||||
Noncurrent regulatory liabilities | (8,858 | ) | (3,453 | ) | |||||||||||||||||||||
Deferred income taxes | 2,965 | 4,050 | |||||||||||||||||||||||
Net-of-tax accumulated OCI | 4,373 | 5,920 | |||||||||||||||||||||||
Total | $ | 109,334 | $ | 238,545 | |||||||||||||||||||||
Measurement date | Dec. 31, 2013 | Dec. 31, 2012 | |||||||||||||||||||||||
2013 | 2012 | ||||||||||||||||||||||||
Significant Assumptions Used to Measure Benefit Obligations: | |||||||||||||||||||||||||
Discount rate for year-end valuation | 4.82 | % | 4.1 | % | |||||||||||||||||||||
Mortality table | RP 2000 | RP 2000 | |||||||||||||||||||||||
Health care costs trend rate — initial | 7 | 7.5 | |||||||||||||||||||||||
Effective Jan. 1, 2014, the initial medical trend rate was decreased from 7.5 percent to 7.0 percent. The ultimate trend assumption remained at 4.5 percent. The period until the ultimate rate is reached is five years. Xcel Energy bases its medical trend assumption on the long-term cost inflation expected in the health care market, considering the levels projected and recommended by industry experts, as well as recent actual medical cost experienced by Xcel Energy’s retiree medical plan. | |||||||||||||||||||||||||
A one-percent change in the assumed health care cost trend rate would have the following effects on Xcel Energy: | |||||||||||||||||||||||||
One-Percentage Point | |||||||||||||||||||||||||
(Thousands of Dollars) | Increase | Decrease | |||||||||||||||||||||||
APBO | $ | 75,617 | $ | (63,360 | ) | ||||||||||||||||||||
Service and interest components | 3,580 | (2,826 | ) | ||||||||||||||||||||||
Cash Flows — The postretirement health care plans have no funding requirements under income tax and other retirement-related regulations other than fulfilling benefit payment obligations, when claims are presented and approved under the plans. Additional cash funding requirements are prescribed by certain state and federal rate regulatory authorities, as discussed previously. Xcel Energy contributed $17.6 million during 2013, $47.1 million during 2012, $49.0 million during 2011 and expects to contribute approximately $13.3 million during 2014. | |||||||||||||||||||||||||
Plan Amendments — The 2013 decrease of the projected Xcel Energy and PSCo postretirement health and welfare benefit obligation for plan amendments is due to changes in the participant co-pay structure for certain retiree groups. The 2012 decrease of the projected Xcel Energy and PSCo postretirement health and welfare benefit obligation for plan amendments is due to the expected transition of certain participant groups to an external plan administrator. | |||||||||||||||||||||||||
Benefit Costs — The components of Xcel Energy’s net periodic postretirement benefit costs were: | |||||||||||||||||||||||||
(Thousands of Dollars) | 2013 | 2012 | 2011 | ||||||||||||||||||||||
Service cost | $ | 4,079 | $ | 4,203 | $ | 4,824 | |||||||||||||||||||
Interest cost | 32,141 | 37,861 | 42,086 | ||||||||||||||||||||||
Expected return on plan assets | (33,011 | ) | (28,409 | ) | (31,962 | ) | |||||||||||||||||||
Amortization of transition obligation | 825 | 14,320 | 14,444 | ||||||||||||||||||||||
Amortization of prior service credit | (12,501 | ) | (7,552 | ) | (4,932 | ) | |||||||||||||||||||
Amortization of net loss | 22,325 | 16,906 | 13,294 | ||||||||||||||||||||||
Net periodic postretirement benefit cost | 13,858 | 37,329 | 37,754 | ||||||||||||||||||||||
Additional cost recognized due to effects of regulation | — | 3,891 | 3,891 | ||||||||||||||||||||||
Net benefit cost recognized for financial reporting | $ | 13,858 | $ | 41,220 | $ | 41,645 | |||||||||||||||||||
2013 | 2012 | 2011 | |||||||||||||||||||||||
Significant Assumptions Used to Measure Costs: | |||||||||||||||||||||||||
Discount rate | 4.1 | % | 5 | % | 5.5 | % | |||||||||||||||||||
Expected average long-term rate of return on assets | 7.11 | 6.75 | 7.5 | ||||||||||||||||||||||
Projected Benefit Payments | |||||||||||||||||||||||||
The following table lists Xcel Energy’s projected benefit payments for the pension and postretirement benefit plans: | |||||||||||||||||||||||||
(Thousands of Dollars) | Projected | Gross Projected | Expected | Net Projected | |||||||||||||||||||||
Pension Benefit | Postretirement | Medicare Part D | Postretirement | ||||||||||||||||||||||
Payments | Health Care | Subsidies | Health Care | ||||||||||||||||||||||
Benefit Payments | Benefit Payments | ||||||||||||||||||||||||
2014 | $ | 313,226 | $ | 53,516 | $ | 2,627 | $ | 50,889 | |||||||||||||||||
2015 | 266,802 | 54,576 | 2,806 | 51,770 | |||||||||||||||||||||
2016 | 267,186 | 55,965 | 2,969 | 52,996 | |||||||||||||||||||||
2017 | 269,526 | 56,513 | 3,135 | 53,378 | |||||||||||||||||||||
2018 | 272,908 | 58,181 | 3,291 | 54,890 | |||||||||||||||||||||
2019-2023 | 1,339,764 | 282,860 | 18,274 | 264,586 | |||||||||||||||||||||
Multiemployer Plans | |||||||||||||||||||||||||
NSP-Minnesota and NSP-Wisconsin each contribute to several union multiemployer pension and other postretirement benefit plans, none of which are individually significant. These plans provide pension and postretirement health care benefits to certain union employees, including electrical workers, boilermakers, and other construction and facilities workers who may perform services for more than one employer during a given period and do not participate in the NSP-Minnesota and NSP-Wisconsin sponsored pension and postretirement health care plans. Contributing to these types of plans creates risk that differs from providing benefits under NSP-Minnesota and NSP-Wisconsin sponsored plans, in that if another participating employer ceases to contribute to a multiemployer plan, additional unfunded obligations may need to be funded over time by remaining participating employers. | |||||||||||||||||||||||||
Contributions to multiemployer plans were as follows for the years ended Dec. 31, 2013, 2012 and 2011. The average number of NSP-Minnesota union employees covered by the multiemployer pension plans increased to approximately 1,100 in 2013 from approximately 800 in 2012. There were no other significant changes to the nature or magnitude of the participation of NSP-Minnesota and NSP-Wisconsin in multiemployer plans for the years presented: | |||||||||||||||||||||||||
(Thousands of Dollars) | 2013 | 2012 | 2011 | ||||||||||||||||||||||
Multiemployer pension contributions: | |||||||||||||||||||||||||
NSP-Minnesota | $ | 23,515 | $ | 14,984 | $ | 17,811 | |||||||||||||||||||
NSP-Wisconsin | 130 | 163 | 169 | ||||||||||||||||||||||
Total | $ | 23,645 | $ | 15,147 | $ | 17,980 | |||||||||||||||||||
Multiemployer other postretirement benefit contributions: | |||||||||||||||||||||||||
NSP-Minnesota | $ | 390 | $ | 197 | $ | 336 | |||||||||||||||||||
Total | $ | 390 | $ | 197 | $ | 336 | |||||||||||||||||||
Other_Income_Net
Other Income, Net | 12 Months Ended | ||||||||||||
Dec. 31, 2013 | |||||||||||||
Other Income and Expenses [Abstract] | ' | ||||||||||||
Other Income, Net | ' | ||||||||||||
Other Income, Net | |||||||||||||
Other income, net for the years ended Dec. 31 consisted of the following: | |||||||||||||
(Thousands of Dollars) | 2013 | 2012 | 2011 | ||||||||||
Interest income | $ | 8,343 | $ | 10,327 | $ | 10,639 | |||||||
Other nonoperating income | 3,025 | 3,483 | 3,722 | ||||||||||
Insurance policy expense | (8,292 | ) | (7,365 | ) | (4,785 | ) | |||||||
Other nonoperating expense | (104 | ) | (270 | ) | (321 | ) | |||||||
Other income, net | $ | 2,972 | $ | 6,175 | $ | 9,255 | |||||||
Fair_Value_of_Financial_Assets
Fair Value of Financial Assets and Liabilities | 12 Months Ended | ||||||||||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||||||||||
Fair Value Disclosures [Abstract] | ' | ||||||||||||||||||||||||
Fair Value of Financial Assets and Liabilities | ' | ||||||||||||||||||||||||
Fair Value of Financial Assets and Liabilities | |||||||||||||||||||||||||
Fair Value Measurements | |||||||||||||||||||||||||
The accounting guidance for fair value measurements and disclosures provides a single definition of fair value and requires certain disclosures about assets and liabilities measured at fair value. A hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value is established by this guidance. The three levels in the hierarchy are as follows: | |||||||||||||||||||||||||
Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices. | |||||||||||||||||||||||||
Level 2 — Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reporting date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, or priced with models using highly observable inputs. | |||||||||||||||||||||||||
Level 3 — Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 are those valued with models requiring significant management judgment or estimation. | |||||||||||||||||||||||||
Specific valuation methods include the following: | |||||||||||||||||||||||||
Cash equivalents — The fair values of cash equivalents are generally based on cost plus accrued interest; money market funds are measured using quoted net asset values. | |||||||||||||||||||||||||
Investments in equity securities and other funds — Equity securities are valued using quoted prices in active markets. The fair values for commingled funds, international equity funds, private equity investments and real estate investments are measured using net asset values, which take into consideration the value of underlying fund investments, as well as the other accrued assets and liabilities of a fund, in order to determine a per-share market value. The investments in commingled funds and international equity funds may be redeemed for net asset value with proper notice. Proper notice varies by fund and can range from daily with one or two days notice to annually with 90 days notice. Private equity investments require approval of the fund for any unscheduled redemption, and such redemptions may be approved or denied by the fund at its sole discretion. Unscheduled distributions from real estate investments may be redeemed with proper notice, which is typically quarterly with 45-90 days notice; however, withdrawals from real estate investments may be delayed or discounted as a result of fund illiquidity. Based on Xcel Energy’s evaluation of its ability to redeem private equity and real estate investments, fair value measurements for private equity and real estate investments have been assigned a Level 3. | |||||||||||||||||||||||||
Investments in debt securities — Fair values for debt securities are determined by a third party pricing service using recent trades and observable spreads from benchmark interest rates for similar securities. | |||||||||||||||||||||||||
Interest rate derivatives — The fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts. | |||||||||||||||||||||||||
Commodity derivatives — The methods used to measure the fair value of commodity derivative forwards and options utilize forward prices and volatilities, as well as pricing adjustments for specific delivery locations, and are generally assigned a Level 2. When contractual settlements extend to periods beyond those readily observable on active exchanges or quoted by brokers, the significance of the use of less observable forecasts of long-term forward prices and volatilities on a valuation is evaluated, and may result in Level 3 classification. | |||||||||||||||||||||||||
Electric commodity derivatives held by NSP-Minnesota include transmission congestion instruments purchased from MISO, PJM, ERCOT and NYISO, generally referred to as FTRs. Electric commodity derivatives held by SPS include FTRs purchased from SPP. FTRs purchased from an 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 FCA as applicable in each jurisdiction, and therefore changes in the fair value of the yet to be settled portions of most FTRs are deferred as a regulatory asset or liability. Given this regulatory treatment and the limited magnitude of FTRs relative to the electric utility operations of NSP-Minnesota and SPS, the numerous unobservable quantitative inputs to the complex model used for valuation of FTRs are insignificant to the consolidated financial statements of Xcel Energy. | |||||||||||||||||||||||||
Non-Derivative Instruments Fair Value Measurements | |||||||||||||||||||||||||
The NRC requires NSP-Minnesota to maintain a portfolio of investments to fund the costs of decommissioning its nuclear generating plants. Together with all accumulated earnings or losses, the assets of the nuclear decommissioning fund are legally restricted for the purpose of decommissioning the Monticello and Prairie Island nuclear generating plants. The fund contains cash equivalents, debt securities, equity securities and other investments – all classified as available-for-sale. NSP-Minnesota plans to reinvest matured securities until decommissioning begins. NSP-Minnesota uses the MPUC approved asset allocation for the escrow and investment targets by asset class for both the escrow and qualified trust. | |||||||||||||||||||||||||
NSP-Minnesota recognizes the costs of funding the decommissioning of its nuclear generating plants over the lives of the plants, assuming rate recovery of all costs. Given the purpose and legal restrictions on the use of nuclear decommissioning fund assets, realized and unrealized gains on fund investments over the life of the fund are deferred as an offset of NSP-Minnesota’s regulatory asset for nuclear decommissioning costs. Consequently, any realized and unrealized gains and losses on securities in the nuclear decommissioning fund, including any other-than-temporary impairments, are deferred as a component of the regulatory asset for nuclear decommissioning. | |||||||||||||||||||||||||
Unrealized gains for the nuclear decommissioning fund were $240.3 million and $135.8 million at Dec. 31, 2013 and 2012, respectively, and unrealized losses and amounts recorded as other-than-temporary impairments were $58.5 million and $46.4 million at Dec. 31, 2013 and 2012, respectively. | |||||||||||||||||||||||||
The following tables present the cost and fair value of Xcel Energy’s non-derivative instruments with recurring fair value measurements in the nuclear decommissioning fund at Dec. 31, 2013 and 2012: | |||||||||||||||||||||||||
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. | ||||||||||||||||||||||||
Dec. 31, 2012 | |||||||||||||||||||||||||
Fair Value | |||||||||||||||||||||||||
(Thousands of Dollars) | Cost | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||
Nuclear decommissioning fund (a) | |||||||||||||||||||||||||
Cash equivalents | $ | 246,904 | $ | 237,938 | $ | 8,966 | $ | — | $ | 246,904 | |||||||||||||||
Commingled funds | 396,681 | — | 417,583 | — | 417,583 | ||||||||||||||||||||
International equity funds | 66,452 | — | 69,481 | — | 69,481 | ||||||||||||||||||||
Private equity investments | 27,943 | — | — | 33,250 | 33,250 | ||||||||||||||||||||
Real estate | 32,561 | — | — | 39,074 | 39,074 | ||||||||||||||||||||
Debt securities: | |||||||||||||||||||||||||
Government securities | 21,092 | — | 21,521 | — | 21,521 | ||||||||||||||||||||
U.S. corporate bonds | 162,053 | — | 169,488 | — | 169,488 | ||||||||||||||||||||
International corporate bonds | 15,165 | — | 16,052 | — | 16,052 | ||||||||||||||||||||
Municipal bonds | 21,392 | — | 23,650 | — | 23,650 | ||||||||||||||||||||
Asset-backed securities | 2,066 | — | — | 2,067 | 2,067 | ||||||||||||||||||||
Mortgage-backed securities | 28,743 | — | — | 30,209 | 30,209 | ||||||||||||||||||||
Equity securities: | |||||||||||||||||||||||||
Common stock | 379,093 | 420,263 | — | — | 420,263 | ||||||||||||||||||||
Total | $ | 1,400,145 | $ | 658,201 | $ | 726,741 | $ | 104,600 | $ | 1,489,542 | |||||||||||||||
(a) | Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $91.2 million of equity investments in unconsolidated subsidiaries and $37.1 million of miscellaneous investments. | ||||||||||||||||||||||||
The following tables present the changes in Level 3 nuclear decommissioning fund investments: | |||||||||||||||||||||||||
(Thousands of Dollars) | Jan. 1, 2013 | Purchases | Settlements | Gains | Transfers Out of Level 3 (a) | Dec. 31, 2013 | |||||||||||||||||||
Recognized as | |||||||||||||||||||||||||
Regulatory Assets and Liabilities | |||||||||||||||||||||||||
Private equity investments | $ | 33,250 | $ | 24,201 | $ | — | $ | 5,245 | $ | — | $ | 62,696 | |||||||||||||
Real estate | 39,074 | 31,626 | (18,622 | ) | 5,290 | — | 57,368 | ||||||||||||||||||
Asset-backed securities | 2,067 | — | — | — | (2,067 | ) | — | ||||||||||||||||||
Mortgage-backed securities | 30,209 | — | — | — | (30,209 | ) | — | ||||||||||||||||||
Total | $ | 104,600 | $ | 55,827 | $ | (18,622 | ) | $ | 10,535 | $ | (32,276 | ) | $ | 120,064 | |||||||||||
(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 and were subsequently sold during 2013. | ||||||||||||||||||||||||
(Thousands of Dollars) | Jan. 1, 2012 | Purchases | Settlements | Gains (Losses) | Transfers Out of Level 3 | Dec. 31, 2012 | |||||||||||||||||||
Recognized as | |||||||||||||||||||||||||
Regulatory Assets and Liabilities | |||||||||||||||||||||||||
Private equity investments | $ | 9,203 | $ | 20,671 | $ | (1,931 | ) | $ | 5,307 | $ | — | $ | 33,250 | ||||||||||||
Real estate | 26,395 | 9,777 | (3,611 | ) | 6,513 | — | 39,074 | ||||||||||||||||||
Asset-backed securities | 16,501 | — | (14,450 | ) | 16 | — | 2,067 | ||||||||||||||||||
Mortgage-backed securities | 78,664 | 33,016 | (79,899 | ) | (1,572 | ) | — | 30,209 | |||||||||||||||||
Total | $ | 130,763 | $ | 63,464 | $ | (99,891 | ) | $ | 10,264 | $ | — | $ | 104,600 | ||||||||||||
(Thousands of Dollars) | Jan. 1, 2011 | Purchases | Settlements | Gains (Losses) | Transfers Out of Level 3 | Dec. 31, 2011 | |||||||||||||||||||
Recognized as | |||||||||||||||||||||||||
Regulatory Assets and Liabilities | |||||||||||||||||||||||||
Private equity investments | $ | — | $ | 9,203 | $ | — | $ | — | $ | — | $ | 9,203 | |||||||||||||
Real estate | — | 24,768 | — | 1,627 | — | 26,395 | |||||||||||||||||||
Asset-backed securities | 33,174 | 16,518 | (32,560 | ) | (631 | ) | — | 16,501 | |||||||||||||||||
Mortgage-backed securities | 72,589 | 168,688 | (161,134 | ) | (1,479 | ) | — | 78,664 | |||||||||||||||||
Total | $ | 105,763 | $ | 219,177 | $ | (193,694 | ) | $ | (483 | ) | $ | — | $ | 130,763 | |||||||||||
The following table summarizes the final contractual maturity dates of the debt securities in the nuclear decommissioning fund, by asset class, at Dec. 31, 2013: | |||||||||||||||||||||||||
Final Contractual Maturity | |||||||||||||||||||||||||
(Thousands of Dollars) | Due in 1 Year | Due in 1 to 5 | Due in 5 to 10 | Due after 10 | Total | ||||||||||||||||||||
or Less | Years | Years | Years | ||||||||||||||||||||||
Government securities | $ | — | $ | — | $ | — | $ | 27,628 | $ | 27,628 | |||||||||||||||
U.S. corporate bonds | 780 | 17,850 | 63,089 | 1,819 | 83,538 | ||||||||||||||||||||
International corporate bonds | — | 2,222 | 13,136 | — | 15,358 | ||||||||||||||||||||
Municipal bonds | 3,554 | 25,663 | 33,109 | 169,690 | 232,016 | ||||||||||||||||||||
Debt securities | $ | 4,334 | $ | 45,735 | $ | 109,334 | $ | 199,137 | $ | 358,540 | |||||||||||||||
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 Dec. 31, 2013, accumulated other comprehensive losses related to interest rate derivatives included $2.3 million of net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings, including forecasted amounts for unsettled hedges, as applicable. | |||||||||||||||||||||||||
In conjunction with the NSP-Minnesota debt issuance in August 2012, NSP-Minnesota settled interest rate hedging instruments with a notional amount of $225 million with cash payments of $45.0 million. In conjunction with the PSCo debt issuance in September 2012, PSCo settled interest rate hedging instruments with a notional amount of $250 million with cash payments of $44.7 million. These losses are classified as a component of accumulated other comprehensive loss on the consolidated balance sheet, net of tax, and are being reclassified to earnings over the term of the hedged interest payments. See Note 4 for further discussion of long-term borrowings. | |||||||||||||||||||||||||
Wholesale and Commodity Trading Risk — Xcel Energy Inc.’s utility subsidiaries conduct various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy and energy-related instruments. Xcel Energy’s risk management policy allows management to conduct these activities within guidelines and limitations as approved by its risk management committee, which is made up of management personnel not directly involved in the activities governed by this policy. | |||||||||||||||||||||||||
Commodity Derivatives — Xcel Energy enters into derivative instruments to manage variability of future cash flows from changes in commodity prices in its electric and natural gas operations, as well as for trading purposes. This could include the purchase or sale of energy or energy-related products, natural gas to generate electric energy, natural gas for resale and vehicle fuel. | |||||||||||||||||||||||||
At Dec. 31, 2013, Xcel Energy had various vehicle fuel contracts designated as cash flow hedges extending through December 2016. Xcel Energy also enters into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers but are not designated as qualifying hedging transactions. Changes in the fair value of non-trading commodity derivative instruments are recorded in OCI 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 years ended Dec. 31, 2013 and 2012. | |||||||||||||||||||||||||
At Dec. 31, 2013, net gains related to commodity derivative cash flow hedges recorded as a component of accumulated other comprehensive losses included $0.1 million of net gains expected to be reclassified into earnings during the next 12 months as the hedged transactions occur. | |||||||||||||||||||||||||
Additionally, Xcel Energy enters into commodity derivative instruments for trading purposes not directly related to commodity price risks associated with serving its electric and natural gas customers. Changes in the fair value of these commodity derivatives are recorded in electric operating revenues, net of amounts credited to customers under margin-sharing mechanisms. | |||||||||||||||||||||||||
The following table details the gross notional amounts of commodity forwards, options and FTRs at Dec. 31, 2013 and 2012: | |||||||||||||||||||||||||
(Amounts in Thousands) (a)(b) | Dec. 31, 2013 | Dec. 31, 2012 | |||||||||||||||||||||||
MWh of electricity | 58,423 | 55,976 | |||||||||||||||||||||||
MMBtu of natural gas | 9,854 | 725 | |||||||||||||||||||||||
Gallons of vehicle fuel | 482 | 682 | |||||||||||||||||||||||
(a) | Amounts are not reflective of net positions in the underlying commodities. | ||||||||||||||||||||||||
(b) | Notional amounts for options are included on a gross basis, but are weighted for the probability of exercise. | ||||||||||||||||||||||||
Consideration of Credit Risk and Concentrations — Xcel Energy continuously monitors the creditworthiness of the counterparties to its interest rate derivatives and commodity derivative contracts prior to settlement, and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. Given this assessment, as well as an assessment of the impact of Xcel Energy’s own credit risk when determining the fair value of derivative liabilities, the impact of considering credit risk was immaterial to the fair value of unsettled commodity derivatives presented in the consolidated balance sheets. | |||||||||||||||||||||||||
Xcel Energy Inc. and its subsidiaries employ additional credit risk control mechanisms when appropriate, such as letters of credit, parental guarantees, standardized master netting agreements and termination provisions that allow for offsetting of positive and negative exposures. Credit exposure is monitored and, when necessary, the activity with a specific counterparty is limited until credit enhancement is provided. | |||||||||||||||||||||||||
Xcel Energy’s utility subsidiaries’ most significant concentrations of credit risk with particular entities or industries are contracts with counterparties to their wholesale, trading and non-trading commodity activities. At Dec. 31, 2013, four of Xcel Energy’s 10 most significant counterparties for these activities, comprising $49.3 million or 18 percent of this credit exposure, had investment grade credit ratings from Standard & Poor’s, Moody’s or Fitch Ratings. The remaining six significant counterparties, comprising $68.1 million or 25 percent of this credit exposure at Dec. 31, 2013, 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 municipal or cooperative electric entities or other utilities. | |||||||||||||||||||||||||
Financial Impact of Qualifying Cash Flow Hedges — The impact of qualifying interest rate and vehicle fuel cash flow hedges on Xcel Energy’s accumulated other comprehensive loss, included in the consolidated statements of common stockholders’ equity and in the consolidated statements of comprehensive income, is detailed in the following table: | |||||||||||||||||||||||||
(Thousands of Dollars) | 2013 | 2012 | 2011 | ||||||||||||||||||||||
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1 | $ | (61,241 | ) | $ | (45,738 | ) | $ | (8,094 | ) | ||||||||||||||||
After-tax net unrealized gains (losses) related to derivatives accounted for as hedges | 12 | (19,200 | ) | (38,292 | ) | ||||||||||||||||||||
After-tax net realized losses on derivative transactions reclassified into earnings | 1,476 | 3,697 | 648 | ||||||||||||||||||||||
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31 | $ | (59,753 | ) | $ | (61,241 | ) | $ | (45,738 | ) | ||||||||||||||||
The following tables detail the impact of derivative activity during the years ended Dec. 31, 2013, 2012 and 2011, on accumulated other comprehensive loss, regulatory assets and liabilities, and income: | |||||||||||||||||||||||||
Year Ended Dec. 31, 2013 | |||||||||||||||||||||||||
Pre-Tax Fair Value | Pre-Tax (Gains) Losses | Pre-Tax Gains (Losses) | |||||||||||||||||||||||
Gains (Losses) Recognized | Reclassified into Income | Recognized | |||||||||||||||||||||||
During the Period in: | During the Period from: | During the Period in Income | |||||||||||||||||||||||
(Thousands of Dollars) | Accumulated | Regulatory | Accumulated | Regulatory | |||||||||||||||||||||
Other | (Assets) and Liabilities | Other | Assets and(Liabilities) | ||||||||||||||||||||||
Comprehensive Loss | Comprehensive Loss | ||||||||||||||||||||||||
Derivatives designated as cash flow hedges | |||||||||||||||||||||||||
Interest rate | $ | — | $ | — | $ | 4,107 | (a) | $ | — | $ | — | ||||||||||||||
Vehicle fuel and other commodity | 29 | — | (90 | ) | (b) | — | — | ||||||||||||||||||
Total | $ | 29 | $ | — | $ | 4,017 | $ | — | $ | — | |||||||||||||||
Other derivative instruments | |||||||||||||||||||||||||
Commodity trading | $ | — | $ | — | $ | — | $ | — | $ | 11,221 | (c) | ||||||||||||||
Electric commodity | — | 75,817 | — | (52,796 | ) | (d) | — | ||||||||||||||||||
Natural gas commodity | — | (3,088 | ) | — | 5,019 | (e) | (6,589 | ) | (d) | ||||||||||||||||
Total | $ | — | $ | 72,729 | $ | — | $ | (47,777 | ) | $ | 4,632 | ||||||||||||||
Year Ended Dec. 31, 2012 | |||||||||||||||||||||||||
Pre-Tax Fair Value | Pre-Tax (Gains) Losses | Pre-Tax Gains | |||||||||||||||||||||||
Gains (Losses) Recognized | Reclassified into Income | (Losses) Recognized | |||||||||||||||||||||||
During the Period in: | During the Period from: | During the Period in Income | |||||||||||||||||||||||
(Thousands of Dollars) | Accumulated | Regulatory | Accumulated | Regulatory | |||||||||||||||||||||
Other | (Assets) and Liabilities | Other | Assets and (Liabilities) | ||||||||||||||||||||||
Comprehensive Loss | Comprehensive Loss | ||||||||||||||||||||||||
Derivatives designated as cash flow hedges | |||||||||||||||||||||||||
Interest rate | $ | (31,913 | ) | $ | — | $ | 6,582 | (a) | $ | — | $ | — | |||||||||||||
Vehicle fuel and other commodity | 120 | — | (198 | ) | (b) | — | — | ||||||||||||||||||
Total | $ | (31,793 | ) | $ | — | $ | 6,384 | $ | — | $ | — | ||||||||||||||
Other derivative instruments | |||||||||||||||||||||||||
Commodity trading | $ | — | $ | — | $ | — | $ | — | $ | 12,226 | (c) | ||||||||||||||
Electric commodity | — | 44,162 | — | (39,999 | ) | (d) | — | ||||||||||||||||||
Natural gas commodity | — | (10,809 | ) | — | 80,902 | (e) | (137 | ) | (d) | ||||||||||||||||
Total | $ | — | $ | 33,353 | $ | — | $ | 40,903 | $ | 12,089 | |||||||||||||||
Year Ended Dec. 31, 2011 | |||||||||||||||||||||||||
Pre-Tax Fair Value | Pre-Tax (Gains) Losses | Pre-Tax Gains | |||||||||||||||||||||||
Gains (Losses) Recognized | Reclassified into Income | (Losses) Recognized | |||||||||||||||||||||||
During the Period in: | During the Period from: | During the Period in Income | |||||||||||||||||||||||
(Thousands of Dollars) | Accumulated | Regulatory | Accumulated | Regulatory | |||||||||||||||||||||
Other | (Assets) and Liabilities | Other | Assets and(Liabilities) | ||||||||||||||||||||||
Comprehensive Loss | Comprehensive Loss | ||||||||||||||||||||||||
Derivatives designated as cash flow hedges | |||||||||||||||||||||||||
Interest rate | $ | (63,573 | ) | $ | — | $ | 1,424 | (a) | $ | — | $ | — | |||||||||||||
Vehicle fuel and other commodity | 195 | — | (178 | ) | (b) | — | — | ||||||||||||||||||
Total | $ | (63,378 | ) | $ | — | $ | 1,246 | $ | — | $ | — | ||||||||||||||
Other derivative instruments | |||||||||||||||||||||||||
Commodity trading | $ | — | $ | — | $ | — | $ | — | $ | 6,418 | (c) | ||||||||||||||
Electric commodity | — | 49,818 | — | (40,492 | ) | (d) | — | ||||||||||||||||||
Natural gas commodity | — | (111,574 | ) | — | 91,743 | (e) | (382 | ) | (d) | ||||||||||||||||
Total | $ | — | $ | (61,756 | ) | $ | — | $ | 51,251 | $ | 6,036 | ||||||||||||||
(a) | Amounts are recorded to interest charges. | ||||||||||||||||||||||||
(b) | Amounts are recorded to O&M expenses. | ||||||||||||||||||||||||
(c) | Amounts are recorded to electric operating revenues. Portions of these gains and losses are subject to sharing with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate. | ||||||||||||||||||||||||
(d) | Amounts are recorded to electric fuel and purchased power. These derivative settlement gains and losses are shared with electric customers through fuel and purchased energy cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate. | ||||||||||||||||||||||||
(e) | Amounts for the years ended Dec. 31, 2012 and 2011 included $5.0 million and $12.7 million, respectively, of settlement losses on derivatives entered to mitigate natural gas price risk for electric generation, recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate. Such losses for the year ended Dec. 31, 2013 were immaterial. The remaining settlement losses for the years ended Dec. 31, 2013, 2012 and 2011 relate to natural gas operations and are recorded to cost of natural gas sold and transported. These losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset, as appropriate. | ||||||||||||||||||||||||
Xcel Energy had no derivative instruments designated as fair value hedges during the years ended Dec. 31, 2013, 2012 and 2011. Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for these periods. | |||||||||||||||||||||||||
Credit Related Contingent Features — Contract provisions for derivative instruments that the utility subsidiaries enter, including those recorded to the consolidated balance sheet at fair value, as well as those accounted for as normal purchase-normal sale contracts and therefore not reflected on the balance sheet, may require the posting of collateral or settlement of the contracts for various reasons, including if the applicable utility subsidiary is unable to maintain its credit ratings. If the credit ratings of Xcel Energy Inc.’s utility subsidiaries were downgraded below investment grade, derivative instruments reflected in a $1.4 million and $4.6 million gross liability position on the consolidated balance sheets at Dec. 31, 2013 and 2012, respectively, would have required Xcel Energy Inc.’s utility subsidiaries to post collateral or settle outstanding contracts, including other contracts subject to master netting agreements, which would have resulted in payments of $1.4 million and $4.6 million at Dec. 31, 2013 and 2012, respectively. At Dec. 31, 2013 and 2012, there was no collateral posted on these specific contracts. | |||||||||||||||||||||||||
Certain derivative instruments are also subject to contract provisions that contain adequate assurance clauses. These provisions allow counterparties to seek performance assurance, including cash collateral, in the event that a given utility subsidiary’s ability to fulfill its contractual obligations is reasonably expected to be impaired. Xcel Energy had no collateral posted related to adequate assurance clauses in derivative contracts as of Dec. 31, 2013 and 2012. | |||||||||||||||||||||||||
Recurring Fair Value Measurements — The following table presents for each of the fair value hierarchy levels, Xcel Energy’s derivative assets and liabilities measured at fair value on a recurring basis at Dec. 31, 2013: | |||||||||||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||||||||||
Fair Value | Fair Value Total | Counterparty | |||||||||||||||||||||||
(Thousands of Dollars) | Level 1 | Level 2 | Level 3 | Netting (b) | Total | ||||||||||||||||||||
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 | |||||||||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||||||||||
Fair Value | Fair Value Total | Counterparty | |||||||||||||||||||||||
(Thousands of Dollars) | Level 1 | Level 2 | Level 3 | Netting (b) | Total | ||||||||||||||||||||
Current derivative liabilities | |||||||||||||||||||||||||
Other derivative instruments: | |||||||||||||||||||||||||
Commodity trading | $ | — | $ | 10,546 | $ | 1,804 | $ | 12,350 | $ | (12,002 | ) | $ | 348 | ||||||||||||
Electric commodity | — | — | 8,210 | 8,210 | (8,210 | ) | — | ||||||||||||||||||
Total current derivative liabilities | $ | — | $ | 10,546 | $ | 10,014 | $ | 20,560 | $ | (20,212 | ) | 348 | |||||||||||||
PPAs (a) | 23,034 | ||||||||||||||||||||||||
Current derivative instruments | $ | 23,382 | |||||||||||||||||||||||
Noncurrent derivative liabilities | |||||||||||||||||||||||||
Other derivative instruments: | |||||||||||||||||||||||||
Commodity trading | $ | — | $ | 14,382 | $ | — | $ | 14,382 | $ | (9,087 | ) | $ | 5,295 | ||||||||||||
Total noncurrent derivative liabilities | $ | — | $ | 14,382 | $ | — | $ | 14,382 | $ | (9,087 | ) | 5,295 | |||||||||||||
PPAs (a) | 203,929 | ||||||||||||||||||||||||
Noncurrent derivative instruments | $ | 209,224 | |||||||||||||||||||||||
(a) | In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, Xcel Energy began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, Xcel Energy qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities. | ||||||||||||||||||||||||
(b) | Xcel Energy nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2013. At Dec. 31, 2013, derivative assets and liabilities include obligations to return cash collateral of $0.2 million and rights to reclaim cash collateral of $4.2 million. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements. | ||||||||||||||||||||||||
The following table presents for each of the fair value hierarchy levels, Xcel Energy’s derivative assets and liabilities measured at fair value on a recurring basis at Dec. 31, 2012: | |||||||||||||||||||||||||
Dec. 31, 2012 | |||||||||||||||||||||||||
Fair Value | Fair Value Total | Counterparty | |||||||||||||||||||||||
(Thousands of Dollars) | Level 1 | Level 2 | Level 3 | Netting (b) | Total | ||||||||||||||||||||
Current derivative assets | |||||||||||||||||||||||||
Derivatives designated as cash flow hedges: | |||||||||||||||||||||||||
Vehicle fuel and other commodity | $ | — | $ | 95 | $ | — | $ | 95 | $ | — | $ | 95 | |||||||||||||
Other derivative instruments: | |||||||||||||||||||||||||
Commodity trading | — | 26,303 | 692 | 26,995 | (6,675 | ) | 20,320 | ||||||||||||||||||
Electric commodity | — | — | 16,724 | 16,724 | (843 | ) | 15,881 | ||||||||||||||||||
Natural gas commodity | — | 7 | — | 7 | (7 | ) | — | ||||||||||||||||||
Total current derivative assets | $ | — | $ | 26,405 | $ | 17,416 | $ | 43,821 | $ | (7,525 | ) | 36,296 | |||||||||||||
PPAs (a) | 32,717 | ||||||||||||||||||||||||
Current derivative instruments | $ | 69,013 | |||||||||||||||||||||||
Noncurrent derivative assets | |||||||||||||||||||||||||
Derivatives designated as cash flow hedges: | |||||||||||||||||||||||||
Vehicle fuel and other commodity | $ | — | $ | 86 | $ | — | $ | 86 | $ | (47 | ) | $ | 39 | ||||||||||||
Other derivative instruments: | |||||||||||||||||||||||||
Commodity trading | — | 41,282 | 77 | 41,359 | (4,162 | ) | 37,197 | ||||||||||||||||||
Total noncurrent derivative assets | $ | — | $ | 41,368 | $ | 77 | $ | 41,445 | $ | (4,209 | ) | 37,236 | |||||||||||||
PPAs (a) | 89,061 | ||||||||||||||||||||||||
Noncurrent derivative instruments | $ | 126,297 | |||||||||||||||||||||||
Dec. 31, 2012 | |||||||||||||||||||||||||
Fair Value | Fair Value Total | Counterparty | |||||||||||||||||||||||
(Thousands of Dollars) | Level 1 | Level 2 | Level 3 | Netting (b) | Total | ||||||||||||||||||||
Current derivative liabilities | |||||||||||||||||||||||||
Other derivative instruments: | |||||||||||||||||||||||||
Commodity trading | $ | — | $ | 18,622 | $ | 1 | $ | 18,623 | $ | (9,112 | ) | $ | 9,511 | ||||||||||||
Electric commodity | — | — | 843 | 843 | (843 | ) | — | ||||||||||||||||||
Natural gas commodity | — | 98 | — | 98 | (7 | ) | 91 | ||||||||||||||||||
Total current derivative liabilities | $ | — | $ | 18,720 | $ | 844 | $ | 19,564 | $ | (9,962 | ) | 9,602 | |||||||||||||
PPAs (a) | 22,880 | ||||||||||||||||||||||||
Current derivative instruments | $ | 32,482 | |||||||||||||||||||||||
Noncurrent derivative liabilities | |||||||||||||||||||||||||
Other derivative instruments: | |||||||||||||||||||||||||
Commodity trading | $ | — | $ | 21,417 | $ | — | $ | 21,417 | $ | (4,210 | ) | $ | 17,207 | ||||||||||||
Total noncurrent derivative liabilities | $ | — | $ | 21,417 | $ | — | $ | 21,417 | $ | (4,210 | ) | 17,207 | |||||||||||||
PPAs (a) | 225,659 | ||||||||||||||||||||||||
Noncurrent derivative instruments | $ | 242,866 | |||||||||||||||||||||||
(a) | In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, Xcel Energy began recording several long-term 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, 2012. At Dec. 31, 2012, derivative assets and liabilities include obligations to return cash collateral of $0.6 million and rights to reclaim cash collateral of $3.0 million. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements. | ||||||||||||||||||||||||
The following table presents the changes in Level 3 commodity derivatives for the years ended Dec. 31, 2013, 2012 and 2011: | |||||||||||||||||||||||||
Year Ended Dec. 31 | |||||||||||||||||||||||||
(Thousands of Dollars) | 2013 | 2012 | 2011 | ||||||||||||||||||||||
Balance at Jan. 1 | $ | 16,649 | $ | 12,417 | $ | 2,392 | |||||||||||||||||||
Purchases | 61,474 | 37,595 | 33,609 | ||||||||||||||||||||||
Settlements | (45,199 | ) | (44,950 | ) | (36,555 | ) | |||||||||||||||||||
Net transactions recorded during the period: | |||||||||||||||||||||||||
Gains recognized in earnings (a) | 3,947 | 463 | 69 | ||||||||||||||||||||||
Gains recognized as regulatory assets and liabilities | 4,789 | 11,124 | 12,902 | ||||||||||||||||||||||
Balance at Dec. 31 | $ | 41,660 | $ | 16,649 | $ | 12,417 | |||||||||||||||||||
(a) | These amounts relate to commodity derivatives held at the end of the period. | ||||||||||||||||||||||||
Xcel Energy recognizes transfers between levels as of the beginning of each period. There were no transfers of amounts between levels for derivative instruments for the years ended Dec. 31, 2013, 2012 and 2011. | |||||||||||||||||||||||||
Fair Value of Long-Term Debt | |||||||||||||||||||||||||
As of Dec. 31, 2013 and 2012, other financial instruments for which the carrying amount did not equal fair value were as follows: | |||||||||||||||||||||||||
2013 | 2012 | ||||||||||||||||||||||||
(Thousands of Dollars) | Carrying Amount | Fair Value | Carrying Amount | Fair Value | |||||||||||||||||||||
Long-term debt, including current portion | $ | 11,191,517 | $ | 11,878,643 | $ | 10,402,060 | $ | 12,207,866 | |||||||||||||||||
The fair value of Xcel Energy’s long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities. The fair value estimates are based on information available to management as of Dec. 31, 2013 and 2012, and given the observability of the inputs to these estimates, the fair values presented for long-term debt have been assigned a Level 2. |
Rate_Matters
Rate Matters | 12 Months Ended | ||||||||||||
Dec. 31, 2013 | |||||||||||||
Public Utilities, General Disclosures [Abstract] | ' | ||||||||||||
Rate Matters | ' | ||||||||||||
Rate Matters | |||||||||||||
NSP-Minnesota | |||||||||||||
Pending and Recently Concluded Regulatory Proceedings — MPUC | |||||||||||||
NSP-Minnesota – Minnesota 2014 Multi-Year Electric Rate Case — On Nov. 4, 2013, NSP-Minnesota filed a two-year, electric rate case with the MPUC. The rate case is based on a requested ROE of 10.25 percent, a 52.5 percent equity ratio, a 2014 average electric rate base of $6.67 billion and an additional average rate base of $412 million in 2015. | |||||||||||||
The NSP-Minnesota electric rate case reflects an overall increase in revenues of approximately $193 million or 6.9 percent in 2014 and an additional $98 million or 3.5 percent in 2015. The request includes a proposed rate moderation plan for 2014 and 2015. After reflecting interim rate adjustments, the impact of NSP-Minnesota’s request on customer bills would result in a 4.6 percent increase in 2014 and an additional 5.6 percent in 2015. | |||||||||||||
NSP-Minnesota’s moderation plan includes the acceleration of the eight-year amortization of the excess theoretical depreciation reserve which the MPUC approved in NSP-Minnesota’s last electric rate case and the use of expected funds from the DOE for settlement of certain claims. These DOE refunds would be in excess of amounts needed to fund its decommissioning expense. The interim rate adjustments are primarily associated with ROE, Monticello LCM/EPU project costs and NSP-Minnesota’s request to amortize amounts associated with the canceled Prairie Island EPU project. NSP-Minnesota plans to file a petition for deferred accounting regarding these Monticello costs in the first quarter of 2014. | |||||||||||||
The rate request, moderation plan, interim rate adjustments, customer bill impacts and certain impacts on expenses are detailed in the table below: | |||||||||||||
(Millions of Dollars) | 2014 | Percentage | 2015 | Percentage | |||||||||
Increase | Increase | ||||||||||||
Pre-moderation deficiency | $ | 274 | $ | 81 | |||||||||
Moderation change compared to prior year: | |||||||||||||
Excess theoretical depreciation reserve | (81 | ) | 53 | ||||||||||
DOE settlement proceeds | — | (36 | ) | ||||||||||
Filed rate request | 193 | 6.90% | 98 | 3.50% | |||||||||
Interim rate adjustments | (66 | ) | 66 | ||||||||||
Impact on customer bill | 127 | 4.60% | 164 | 5.60% | |||||||||
Potential expense deferral (Monticello/Prairie Island EPU projects) | 16 | — | |||||||||||
Depreciation expense - reduction/(increase) | 81 | (46 | ) | ||||||||||
Recognition of DOE settlement proceeds | — | 36 | |||||||||||
Pre-tax impact on operating income | $ | 224 | $ | 154 | |||||||||
On Dec. 12, 2013, the MPUC approved interim rates of $127 million as requested, 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 theoretical depreciation reserve amortization was a permissible adjustment to its interim rate request even though it differed from the MPUC’s 2013 Minnesota rate case order. | |||||||||||||
The next steps in the procedural schedule are expected to be as follows: | |||||||||||||
• | Direct Testimony — June 5, 2014; | ||||||||||||
• | Rebuttal Testimony — July 7, 2014; | ||||||||||||
• | Surrebuttal Testimony — Aug. 4, 2014; | ||||||||||||
• | Evidentiary Hearing — Aug. 11-18, 2014; | ||||||||||||
• | Reply Brief — Oct. 14, 2014; and | ||||||||||||
• | ALJ Report — Dec. 22, 2014. | ||||||||||||
A final MPUC decision is anticipated in March 2015. | |||||||||||||
NSP-Minnesota – Minnesota 2013 Electric Rate Case — In November 2012, NSP-Minnesota filed a request with the MPUC for an increase in annual revenues of approximately $285 million, or 10.7 percent. The rate filing was based on a 2013 FTY, a requested ROE of 10.6 percent, an average electric rate base of approximately $6.3 billion and an equity ratio of 52.56 percent. In January 2013, interim rates of approximately $251 million became effective, subject to refund. | |||||||||||||
In May 2013, NSP-Minnesota subsequently revised the requested annual revenue increase to approximately $209 million, or 7.8 percent, based on an ROE of 10.6 percent, a rate base of approximately $6.3 billion an equity ratio of 52.56 percent. The revenue requirement reflected a requested deficiency of $259 million combined with $50 million of rate mitigation through deferral mechanisms. | |||||||||||||
In September 2013, the MPUC issued an order approving a rate increase of approximately $103 million, or 3.8 percent, based on a 9.83 percent ROE and 52.56 percent equity ratio. In addition, the MPUC authorized approximately $20 million in deferrals, as well as a $24 million reduction in revenue and depreciation expense. | |||||||||||||
The table below reconciles NSP-Minnesota’s original request to the final MPUC order: | |||||||||||||
(Millions of Dollars) | MPUC Order | ||||||||||||
NSP-Minnesota original request | $ | 285 | |||||||||||
ROE | (43 | ) | |||||||||||
Sherco Unit 3 | (34 | ) | |||||||||||
Reduced recovery for nuclear plants | (15 | ) | |||||||||||
Incentive compensation | (4 | ) | |||||||||||
Sales forecast | (26 | ) | |||||||||||
Pension | (13 | ) | |||||||||||
Employee benefits | (6 | ) | |||||||||||
Black Dog remediation | (5 | ) | |||||||||||
Estimated impact of the theoretical depreciation reserve | (24 | ) | |||||||||||
NSP-Wisconsin wholesale allocation | (7 | ) | |||||||||||
Other, net | (5 | ) | |||||||||||
Recommended rate increase | 103 | ||||||||||||
Estimated impact of cost deferrals | 20 | ||||||||||||
Estimated impact of the theoretical depreciation reserve | 24 | ||||||||||||
Impact on pre-tax income | $ | 147 | |||||||||||
NSP-Minnesota filed its final rate implementation and interim rate refund compliance filing on Sept. 19, 2013, requesting final rates be implemented Dec. 1, 2013, with interim rate refunds of approximately $132.2 million, including interest, to begin by January 2014. On Nov. 19, 2013, the MPUC approved the final rate implementation plan, new rates began Dec. 1, 2013 and interim rate refunds were applied to customer accounts starting Dec. 16, 2013. | |||||||||||||
NSP-Minnesota Nuclear Project Prudence Investigation — The MPUC has initiated an investigation to determine whether the costs in excess of those included in the CON for NSP-Minnesota’s Monticello LCM/EPU project were prudent. In October 2013, NSP-Minnesota filed a summary report to further support the change and prudence of the incurred costs. The filing indicated the increase in costs was primarily attributable to three factors: (1) the original estimate was based on a high level conceptual design and the project scope increased as the actual conditions of the plant were incorporated into the design; (2) implementation difficulties, including the amount of work that occurred in confined and radioactive or electrically sensitive spaces and NSP-Minnesota’s and its vendors’ ability to attract and retain experienced workers; and (3) additional NRC licensing related requests over the five-plus year application process. NSP-Minnesota has provided information that the cost deviation is in line with similar upgrade projects undertaken by other utilities and the project remains economically beneficial to customers. The results and any recommendations from the conclusion of this prudence proceeding are expected to be considered by the MPUC in NSP-Minnesota’s 2014 Minnesota electric rate case. | |||||||||||||
The next steps in the procedural schedule are expected to be as follows: | |||||||||||||
• | Direct Testimony — July 2, 2014; | ||||||||||||
• | Rebuttal Testimony — Aug. 26, 2014; | ||||||||||||
• | Surrebuttal Testimony — Sept. 19, 2014; | ||||||||||||
• | Hearing — Sept. 29-Oct. 3, 2014; | ||||||||||||
• | Reply Brief — Nov. 21, 2014; and | ||||||||||||
• | ALJ report — Dec. 31, 2014. | ||||||||||||
A final MPUC decision is anticipated in the first quarter of 2015. | |||||||||||||
NSP-Minnesota - 2012 Transmission Cost Recovery Rate Filing — In January 2012, the 2012 NSP-Minnesota TCR filing was submitted to the MPUC, requesting recovery of $29.6 million of transmission investment costs. As project costs have decreased and certain transmission project costs have been removed and included in base rates, the anticipated revenue requirement for 2012 was modified to approximately $22.9 million. In December 2013, the MPUC approved the 2012 TCR filing, with a few adjustments, for approximately $22.7 million. | |||||||||||||
NSP-Minnesota - 2013/14 Transmission Cost Recovery Rate Filing — In December 2013, the 2013/14 NSP-Minnesota TCR filing was filed with the MPUC, requesting recovery of $20.7 million of 2013 transmission investment costs and $37.3 million of 2014 transmission investment costs not previously included in electric base rates. An MPUC decision is anticipated in late 2014, with implementation of new rates soon after approval. | |||||||||||||
Prairie Island Nuclear Plant EPU — In 2009, the MPUC granted NSP-Minnesota a CON for an EPU project at the Prairie Island nuclear generating plant. The total estimated cost of the EPU was $294 million, of which approximately $78.9 million had been incurred, including AFUDC of approximately $12.8 million. Subsequently, NSP-Minnesota made a change of circumstances filing notifying the MPUC that there were changes in the size, timing and cost estimates for this project, revisions to economic and project design analysis and changes due to the estimated impact of revised scheduled outages. The information indicated reductions to the estimated benefit of the uprate project. As a result, NSP-Minnesota concluded that further investment in this project would not benefit customers. In February 2013, the MPUC issued an order terminating the CON for the Prairie Island EPU project. | |||||||||||||
NSP-Minnesota plans to address recovery of incurred costs in rate cases for each of the NSP-Minnesota jurisdictions and to file a request with the FERC for approval to recover a portion of the costs from NSP-Wisconsin through the Interchange Agreement. NSP-Wisconsin plans to seek cost recovery in a future rate case. Based on the outcome of the December 2012 MPUC decision, EPU costs incurred to date were compared to the discounted value of the estimated future rate recovery based on past jurisdictional precedent, resulting in a $10.1 million pretax charge in December 2012 which is included in O&M expense for that year. | |||||||||||||
Pending and Recently Concluded Regulatory Proceedings — NDPSC | |||||||||||||
NSP-Minnesota – North Dakota 2013 Electric Rate Case — In December 2012, NSP-Minnesota filed a request with the NDPSC to increase annual retail electric rates approximately $16.9 million, or 9.25 percent. The rate filing was based on a 2013 FTY, a requested ROE of 10.6 percent, an electric rate base of approximately $377.6 million and an equity ratio of 52.56 percent. In January 2013, the NDPSC approved an interim electric increase of $14.7 million, effective Feb. 16, 2013, subject to refund. | |||||||||||||
In August 2013, NSP-Minnesota filed rebuttal testimony revising the requested increase in retail electric rates to approximately $14.9 million, based on a revised ROE of 10.25 percent and incorporating updated information. | |||||||||||||
In December 2013, a comprehensive settlement agreement between NSP-Minnesota and the NDPSC Staff was filed for approval, proposing resolution to the rate case and resolution of various regulatory proceedings for wind and natural gas generating resources pending before the NDPSC. The settlement agreement provided for a four-year rate plan including a 5.0 percent annual increase in retail revenues in North Dakota, effective Feb. 16, 2013 through Dec. 31, 2015, with no increase in 2016. As filed, the estimated 2013 settlement impact was $11.6 million. On Feb. 18, 2014, NSP-Minnesota filed an amended settlement agreement revising the annual increase to 4.9 percent, effective Feb. 16, 2013 through Dec. 31, 2015, with no increase in 2016. | |||||||||||||
The table below reflects the amended settlement’s 2013 impact. | |||||||||||||
(Millions of Dollars) | Amended Settlement Impact | ||||||||||||
Proposed 12 month settlement base rate increase | $ | 9 | |||||||||||
Pre-effective period impact (Jan. 1, 2013 - Feb. 15, 2013) | (1.6 | ) | |||||||||||
Proposed settlement base rate increase | 7.4 | ||||||||||||
Retention of DOE settlement proceeds | 3.9 | ||||||||||||
Other, net | (0.3 | ) | |||||||||||
Amended settlement’s 2013 impact | $ | 11 | |||||||||||
Additional settlement terms include: | |||||||||||||
• | An approval of two new rate rider tariff mechanisms to recover transmission and North Dakota renewable costs; | ||||||||||||
• | An authorized ROE of 9.75, 10.0, 10.0 and 10.25 percent in 2013 through 2016, respectively; | ||||||||||||
• | A 50 percent earnings sharing mechanism for amounts earned in excess of the authorized ROEs during the term of the settlement; | ||||||||||||
• | The continued use of a 12 month CP demand allocator for certain rate base and operating expenses; | ||||||||||||
• | A commitment to develop a generation cost allocation mechanism over the next 16 months that reflects North Dakota energy policy; providing for the exclusion of resources deemed inconsistent with North Dakota energy policy beginning in 2016 (such as certain Minnesota wind and biomass purchase power agreements) and reflecting replacement of those costs based on either system average costs or like resource costs (base load for base load generation, etc.) and recognizing the time needed to address complexity among multiple jurisdictions by providing that a plan for this mechanism be filed by June 2015; | ||||||||||||
• | The commitment to construct up to 400 MW of thermal generation in North Dakota by 2036 subject to least-cost resource planning principles; and | ||||||||||||
• | The retention of DOE settlement proceeds received in 2012, 2013 and expected in 2014. | ||||||||||||
A final NDPSC decision on the case is anticipated in the first quarter of 2014. | |||||||||||||
Recently Concluded Regulatory Proceedings — SDPUC | |||||||||||||
NSP-Minnesota – South Dakota 2012 Electric Rate Case — In March 2013, NSP-Minnesota and the SDPUC Staff reached a settlement agreement that provides for a base rate increase of approximately $11.6 million and the implementation of a new rider. On Oct. 1, 2013, NSP-Minnesota filed its compliance report consistent with the settlement to recover the revenue requirement on the specific major capital additions and incremental property tax resulting in recovery of $8.7 million for 2014. In December 2013, the SDPUC approved recovery of $8.5 million, reflecting updates made during review of the compliance filing. | |||||||||||||
Electric, Purchased Gas and Resource Adjustment Clauses | |||||||||||||
CIP and CIP Rider — In December 2012, the MPUC approved reductions to the CIP financial incentive mechanisms effective for the 2013 through 2015 program years. Based on the approved savings goals, the estimated average annual electric and natural gas incentives are $30.6 million and $3.6 million, respectively. | |||||||||||||
CIP expenses are recovered through base rates and a rider that is adjusted annually. In November 2013, the MPUC approved NSP-Minnesota’s 2012 CIP electric financial incentives totaling $54.0 million, as well as NSP-Minnesota’s proposed 2013 to 2014 electric CIP rider. In October 2013, the MPUC approved NSP-Minnesota’s 2012 CIP natural gas financial incentive of $2.7 million, as well as NSP-Minnesota’s proposed 2013 to 2014 natural gas CIP rider. NSP-Minnesota estimates 2014 recovery of $83.9 million of electric CIP expenses and $11.7 million of natural gas CIP expenses. This proposed recovery through the riders is in addition to an estimated $87.2 million and $3.1 million through electric and gas base rates, respectively. | |||||||||||||
NSP-Wisconsin | |||||||||||||
Recently Concluded Regulatory Proceedings — PSCW | |||||||||||||
NSP-Wisconsin – Wisconsin 2014 Electric and Gas Rate Case — In May 2013, NSP-Wisconsin filed a request with the PSCW to increase rates for electric and natural gas service effective Jan. 1, 2014. NSP-Wisconsin requested an overall increase in annual electric rates of $40.0 million, or 6.5 percent, and an increase in natural gas rates of $4.7 million, or 3.8 percent. The electric rate increase included a $4.5 million adjustment related to proceeds from a nuclear settlement agreement with the DOE. | |||||||||||||
The rate filing was based on a 2014 FTY, an ROE of 10.4 percent, an equity ratio of 52.5 percent, and a forecasted average rate base of approximately $895.3 million for the electric utility and $89.8 million for the natural gas utility. | |||||||||||||
In October 2013, NSP-Wisconsin filed rebuttal testimony revising the requested electric rate increase to $34.3 million and natural gas rate increase to zero, based on a 10.4 percent ROE and other adjustments. | |||||||||||||
In December 2013, the PSCW approved an electric rate increase of approximately $19.5 million or 3.1 percent based on a 10.2 percent ROE and an equity ratio of 52.5 percent. The PSCW also approved cost deferrals of $4.1 million for interchange agreement amounts from NSP-Minnesota related to the Monticello EPU project until the MPUC completes its prudence review. The PSCW did not change rates for NSP-Wisconsin’s natural gas utility. New electric rates went into effect on Jan. 1, 2014. | |||||||||||||
PSCo | |||||||||||||
Pending and Recently Concluded Regulatory Proceedings — CPUC | |||||||||||||
PSCo – Colorado 2013 Gas Rate Case — In December 2012, PSCo filed a multi-year request with the CPUC to increase Colorado retail natural gas rates by $48.5 million in 2013 with subsequent step increases of $9.9 million in 2014 and $12.1 million in 2015. The request was based on a 2013 FTY, a 10.5 percent ROE, a rate base of $1.3 billion and an equity ratio of 56 percent. PSCo requested an extension of its PSIA rider mechanism to collect the costs associated with its pipeline integrity efforts, including accelerated system renewal projects. PSCo estimated that the PSIA would increase by $26.8 million in 2014 with a subsequent step increase of $24.7 million in 2015 in addition to the proposed changes in base rate revenue. Interim rates, subject to refund, went into effect in August 2013. | |||||||||||||
In April 2013, several parties filed testimony. PSCo filed rebuttal testimony and revised its requested annual rate increase to $44.8 million for 2013, with subsequent step increases of $9.0 million for 2014 and $10.9 million for 2015, based on an ROE of 10.3 percent. This requested increase includes amounts to be transferred from the PSIA rider mechanism. The deficiency, based on an FTY, was $30.6 million. | |||||||||||||
In December 2013, the CPUC approved a natural gas base rate increase of approximately $15.8 million based on an ROE of 9.72 percent, a HTY with an end of year rate base and an equity ratio of 56 percent. As of Dec. 31, 2013, PSCo accrued revenue subject to refund of approximately $20.9 million. | |||||||||||||
While the CPUC rejected PSCo’s request of an FTY and multi-year rate plan, they made clear they supported the benefits that rate certainty brings to customers and PSCo. The CPUC did not reverse the ALJ’s failure to approve expansion and acceleration of PSCo’s pipeline integrity projects. However, the CPUC discussed the importance of pipeline integrity and safety matters and extended the PSIA recovery mechanism for one year to allow for PSCo to file an application for full consideration of all new projects and acceleration. | |||||||||||||
The following table summarizes the CPUC decision: | |||||||||||||
(Millions of Dollars) | CPUC Decision | ||||||||||||
PSCo deficiency based on a FTY | $ | 44.8 | |||||||||||
HTY adjustment | (5.4 | ) | |||||||||||
ROE and capital structure adjustments | (8.3 | ) | |||||||||||
Revenue adjustments | (1.4 | ) | |||||||||||
Other | (0.1 | ) | |||||||||||
Recommendation | 29.6 | ||||||||||||
Neutralize PSIA - base rate transfer | (13.8 | ) | |||||||||||
Incremental base revenue | $ | 15.8 | |||||||||||
Rates and conforming changes made to the PSIA were effective Jan. 1, 2014. | |||||||||||||
PSCo – Colorado 2013 Steam Rate Case — In December 2012, PSCo filed a request to increase Colorado retail steam rates by $1.6 million in 2013 with subsequent step increases of $0.9 million in 2014 and $2.3 million in 2015. The request was based on a 2013 FTY, a 10.5 percent ROE, a rate base of $21 million for steam and an equity ratio of 56 percent. | |||||||||||||
In October 2013, PSCo, the CPUC Staff, the OCC and Colorado Energy Consumers filed a comprehensive settlement, which tied the outcome of the steam rate case to key issues to be decided in the natural gas rate case, including ROE and capital structure. The settlement allowed the filed rates to be effective on Jan. 1, 2014, subject to refund, resulting in a minimum 2014 annual rate increase of $1.2 million. The settlement also withdrew the rate relief request for 2015 without prejudice to PSCo seeking prospective rate relief at any time through the filing of a future steam case. In November 2013, the settlement became final. Final rates were implemented on Feb. 1, 2014. | |||||||||||||
PSCo – Annual Electric Earnings Test — An earnings sharing mechanism is used to apply prospective electric rate adjustments for earnings in the prior year over PSCo’s authorized ROE threshold of 10 percent. In June 2013, PSCo entered into a comprehensive settlement of issues with all parties associated with the 2012 earnings test, resulting in a refund obligation of approximately $8.2 million to be refunded through June 2014. As of Dec. 31, 2013, PSCo has also recognized management’s best estimate of an accrual for the 2013 test year. | |||||||||||||
SmartGridCity (SGC) Cost Recovery — PSCo requested recovery of the revenue requirements associated with $45 million of capital and $4 million of annual O&M costs incurred to develop and operate SGC as part of its 2010 electric rate case. In February 2011, the CPUC allowed recovery of approximately $28 million of the capital cost and all of the O&M costs. In December 2011, PSCo requested CPUC approval for the recovery of the remaining capital investment in SGC. In April 2013, the CPUC denied the application with prejudice. Based on the ALJ’s previous recommended decision to deny recovery, PSCo recognized a $10.7 million pre-tax charge in 2012, representing the net book value of the disallowed investment, which is included in O&M expense. | |||||||||||||
ECA Prudence Review — In September 2013, the CPUC Staff requested that the 2012 annual ECA prudence review be set for hearing. The prudence review, as determined by the ALJ, will primarily consider if replacement power costs during the outage of jointly owned facilities were properly allocated between wholesale and retail customers. | |||||||||||||
2012 PSIA Report — In April 2013, PSCo filed its 2012 PSIA report. The OCC and CPUC Staff requested the CPUC set the matter for hearing to review in detail the information provided, including a review of the prudence of expenditures in 2012, and to develop standards for future filings. In July 2013, the CPUC approved the request and assigned the matter to an ALJ. | |||||||||||||
In January 2014, the CPUC Staff recommended a disallowance of $3.7 million of capital expenditures related to a pipeline replacement project and a disallowance related to an inspection program. Collectively, these represent approximately $0.6 million of disallowances related to 2012 revenue requirements. On Feb. 6, 2014, PSCo filed rebuttal testimony addressing the CPUC Staff’s recommended disallowances. | |||||||||||||
Next steps in the procedural schedule are as follows: | |||||||||||||
• | Evidentiary hearing — March 3 - March 7, 2014; | ||||||||||||
• | Initial brief — March 28, 2014; and | ||||||||||||
• | Reply brief — April 11, 2014. | ||||||||||||
Electric, Purchased Gas and Resource Adjustment Clauses | |||||||||||||
DSM and the DSMCA — The CPUC approved higher savings goals and a slightly higher financial incentive mechanism for PSCo’s electric DSM energy efficiency programs starting in 2012. Savings goals are 356 GWh in 2013 and 384 GWh in 2014 with incentives awarded in the year following plan achievements. PSCo is able to earn an incentive on 11 percent of net economic benefits and a maximum annual incentive of $30 million. | |||||||||||||
The CPUC approved the PSCo electric and gas DSM budget of $115.5 million and $13.3 million, respectively, effective Jan. 1, 2013. Energy efficiency and DSM costs are recovered through a combination of the DSMCA riders and base rates. Electric DSMCA rates are designed to collect $26.8 million in 2013 with the remainder of the electric DSM expenditures collected through base rates. PSCo filed its 2014 DSM plan in July 2013 and reached a settlement with all but one party. Hearings were held in December 2013 seeking approval of a 2014 DSM electric budget of $87.8 million and a gas budget of $12.3 million. A decision by the ALJ is anticipated by the end of the first quarter of 2014. DSMCA riders are adjusted biannually to capture program costs, performance incentives, and any over- or under-recoveries are trued-up in the following year. | |||||||||||||
REC Sharing — In May 2011, the CPUC determined that margin sharing on stand-alone REC transactions would be shared 20 percent to PSCo and 80 percent to customers and ultimately becoming 10 percent to PSCo and 90 percent to customers by 2014. The CPUC also approved a change to the treatment of hybrid REC trading margins (RECs that are bundled with energy) that allows the customers’ share of the margins to be netted against the RESA regulatory asset balance. | |||||||||||||
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 RESA regulatory asset balance. PSCo credited the RESA regulatory asset balance $22 million and $46 million in 2013 and 2012, respectively. The cumulative credit to the RESA regulatory asset balance was $104.5 million and $82.8 million at Dec. 31, 2013 and Dec. 31, 2012, respectively. The credits include the customers’ share of REC trading margins and the customers’ share of carbon offset funds. | |||||||||||||
This sharing mechanism will be effective through 2014. The CPUC is then expecting to review the framework and evidence regarding actual deliveries before determining to continue the sharing mechanism. | |||||||||||||
ECA / RESA Adjustment — In July 2013, PSCo advised the CPUC that it had inadvertently allocated purchased power expense between the deferred accounts for the ECA and the RESA from 2010 to 2012. PSCo proposed to transfer from the RESA deferred account to the ECA deferred account approximately $26.2 million and to amortize the recovery of this amount over 12 months. In addition, interest of $4.4 million was accrued on the amount related to the RESA. In January 2014, the ALJ determined that the $26.2 million was prudently incurred and recommended full recovery through the ECA over a 12 month period with interest accrued at the ECA interest rate. The difference between the RESA interest rate and the ECA interest rate is a decrease of approximately 7.4 percent, or $4.3 million. | |||||||||||||
Pending and Recently Concluded Regulatory Proceedings — FERC | |||||||||||||
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 power sales formula rates effective Sept. 1, 2013, which could reduce revenues approximately $2 million per year prospectively. The matter is currently pending the FERC’s action. | |||||||||||||
PSCo Transmission Formula Rate Cases — In April 2012, PSCo filed with the FERC to revise the wholesale transmission formula rates from a HTY formula rate to a forecast transmission formula rate and to establish formula ancillary services rates. PSCo proposed that the formula rates be updated annually to reflect changes in costs, subject to a true-up. The request would increase PSCo’s wholesale transmission and ancillary services revenue by approximately $2.0 million annually. Various transmission customers taking service under the tariff protested the filing. In June 2012, the FERC issued an order accepting the proposed transmission and ancillary services formula rates, suspending the increase to November 2012, subject to refund, and setting the case for settlement judge or hearing procedures. | |||||||||||||
In June 2012, several wholesale customers filed a complaint with the FERC seeking to have the transmission formula rate ROE reduced from 10.25 to 9.15 percent effective July 1, 2012. If implemented, the ROE reduction would reduce PSCo transmission and ancillary rate revenues by approximately $1.8 million annually. In October 2012, the FERC issued an order accepting the complaint, consolidating the complaint with the April 2012 formula rate change filing, establishing a refund effective date of July 1, 2012, and setting the complaint for settlement judge and hearing procedures. | |||||||||||||
In October 2013, PSCo and the wholesale customers filed a partial settlement that would resolve all issues related to the April 2012 transmission rate filing and June 2012 complaint other than ROE. The settlement is not expected to materially increase 2013 transmission revenues. In December 2013, the FERC approved the partial settlement. The ROE issue is now in an evidentiary hearing process. Initial testimony was filed in December 2013. PSCo filed testimony supporting the current ROE of 10.25 percent, while customers filed testimony recommending an ROE of 9.07 percent for the period July 2012 to November 2012, and an ROE of 8.92 percent thereafter. The case is scheduled for a hearing before an ALJ in May 2014, with the ALJ recommended decision by September 2014. | |||||||||||||
SPS | |||||||||||||
Pending and Recently Concluded Regulatory Proceedings — PUCT | |||||||||||||
SPS – Texas 2014 Electric Rate Case — On Jan. 7, 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 reflects a base rate increase, revenue credits transferred from base rates to rate riders or the fuel clause, and resetting the TCRF to zero when the final base rates become effective, as shown in the following table: | |||||||||||||
(Millions of Dollars) | SPS Request | ||||||||||||
Base rate increase | $ | 81.5 | |||||||||||
Resetting TCRF | (12.9 | ) | |||||||||||
Credit to customers for gain on sale to Lubbock moved to a rider | (4.9 | ) | |||||||||||
Net increase in base revenue | 63.7 | ||||||||||||
Fuel clause offsets | (11.0 | ) | |||||||||||
Retail customer net bill impact | $ | 52.7 | |||||||||||
The rate filing is 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 reflects an increase in depreciation expense of approximately $16 million. | |||||||||||||
The PUCT has suspended SPS' proposed rates through Oct. 31, 2014. If the PUCT has not issued a final order by July 11, 2014, then SPS' current rates will not change, but the final rates will be made effective retroactive to July 12, 2014. | |||||||||||||
Next steps in the procedural schedule are as follows: | |||||||||||||
• | Intervenor testimony — May 22, 2014; | ||||||||||||
• | PUCT Staff testimony — May 29, 2014; | ||||||||||||
• | Cross-rebuttal testimony — June 12, 2014; | ||||||||||||
• | Rebuttal testimony — June 16, 2014; | ||||||||||||
• | Evidentiary hearing — June 25, 2014; and | ||||||||||||
• | A PUCT decision and implementation of final rates are anticipated in the third quarter of 2014. | ||||||||||||
SPS – Texas 2012 Electric Rate Case — In November 2012, SPS filed an electric rate case in Texas with the PUCT for an increase in annual revenue of approximately $90.2 million. The rate filing is based on a historic 12 month test year ended June 30, 2012 (adjusted for known and measurable changes), a requested ROE of 10.65 percent, an electric rate base of $1.15 billion and an equity ratio of 52 percent. In June 2013, the PUCT approved a settlement agreement in which SPS’ base rate increased by $37 million, effective May 1, 2013 and by an additional $13.8 million on Sept. 1, 2013. | |||||||||||||
Electric, Purchased Gas and Resource Adjustment Clauses | |||||||||||||
TCRF Rider — In November 2013, SPS filed with the PUCT to implement the TCRF for Texas retail customers. The requested increase in revenues is $13 million. The PUCT issued an order allowing the TCRF to go into effect on an interim basis effective Jan. 1, 2014. | |||||||||||||
Next steps in the procedural schedule are as follows: | |||||||||||||
• | Intervenor testimony — April 17, 2014; | ||||||||||||
• | Rebuttal testimony — May 6, 2014; and | ||||||||||||
• | Evidentiary hearings — May 15 - May 16, 2014. | ||||||||||||
Pending Regulatory Proceedings — NMPRC | |||||||||||||
SPS – New Mexico 2014 Electric Rate Case — In December 2012, SPS filed an electric rate case in New Mexico with the NMPRC for an increase in annual revenue of approximately $45.9 million effective in 2014. The rate filing is based on a 2014 FTY, a requested ROE of 10.65 percent, an electric rate base of $479.8 million and an equity ratio of 53.89 percent. In June 2013, SPS revised its requested rate increase to $43.3 million. | |||||||||||||
In August 2013, the NMPRC Staff (Staff), the NMAG, the Federal Executive Agencies, the Coalition of Clean Affordable Energy, Occidental Permian, Ltd. and New Mexico Gas Company filed testimony. | |||||||||||||
The following table summarizes certain parties’ recommendations from SPS’ revised request: | |||||||||||||
(Millions of Dollars) | Staff | NMAG | |||||||||||
Testimony | Testimony | ||||||||||||
Aug-13 | Aug-13 | ||||||||||||
SPS revised request | $ | 43.3 | $ | 43.3 | |||||||||
Rate rider for renewable energy costs (a) | (14.5 | ) | (8.5 | ) | |||||||||
Present revenues (sales growth and weather) | (4.4 | ) | (6.4 | ) | |||||||||
ROE (9.8 percent and 8.63 percent, respectively) | (3.2 | ) | (8.1 | ) | |||||||||
Capital structure | (1.5 | ) | (1.1 | ) | |||||||||
Employee benefits | (2.8 | ) | (1.8 | ) | |||||||||
Reduced recovery for payroll expense | (0.1 | ) | (0.1 | ) | |||||||||
Gain on sale of transmission assets | — | (1.7 | ) | ||||||||||
Fuel clause revenue | 6 | — | |||||||||||
Other, net | (5.0 | ) | (6.6 | ) | |||||||||
Recommended rate increase | $ | 17.8 | $ | 9 | |||||||||
Means of recovery: | |||||||||||||
Base revenue | $ | 8.8 | $ | (6.0 | ) | ||||||||
Rider revenue | 7.3 | 13.3 | |||||||||||
Fuel cost adjustment revenue | 1.7 | 1.7 | |||||||||||
$ | 17.8 | $ | 9 | ||||||||||
(a) | Adjustments represent recommended deferrals, extended amortizations and moving costs from rider to fuel in base rates. | ||||||||||||
In September 2013, SPS filed rebuttal testimony, revising its requested rate increase to $32.5 million, based on updated information and an ROE of 10.25 percent. This reflects a base and fuel increase of $20.9 million, an increase of rider revenue of $12.1 million and a decrease to other of $0.5 million. | |||||||||||||
In January 2014, the hearing examiner released her recommended decision. SPS estimates the recommendation reduces the requested rate increase by approximately $6.2 million, resulting in a base revenue increase of $14.7 million. The recommendation proposes an ROE of 9.73 percent, an equity ratio of 53.89 percent, an FTY with certain adjustments and excludes certain employee benefits and other costs. In February 2014, the hearing examiner released a supplemental recommended decision proposing the approval of the requested $12.1 million renewable energy rider revenue recovery. Parties have filed exceptions to the hearing examiner’s recommendations. An NMPRC decision and final rates are expected to be effective in the second quarter of 2014. | |||||||||||||
Pending and Recently Concluded Regulatory Proceedings — FERC | |||||||||||||
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 Electric Cooperative, Inc. (Golden Spread), a wholesale cooperative customer, and PNM and an Order on Initial Decision in a subsequent 2006 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 3CP rather than a 12CP system. | |||||||||||||
The pre-tax impact to 2013 earnings from these orders is approximately $36 million. Pending the timing and resolution of this matter, the annual impact to revenues through 2014 could be up to $6 million and decreasing to $4 million on June 1, 2015. | |||||||||||||
In September 2013, SPS filed a request for rehearing of the FERC ruling on the CP allocation and refund decisions. SPS asserted that the FERC applied an improper burden of proof 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. | |||||||||||||
SPS Wholesale Rate Complaint — In April 2012, Golden Spread 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. Golden Spread alleged that the appropriate base ROE is 9.15 percent, or an annual difference of approximately $3.3 million. An additional 50 basis point incentive is added to the base ROE for the transmission formula rate for SPS’ participation in the SPP RTO. Golden Spread is not contesting this transmission incentive. The FERC has taken no action on this complaint. If granted, the complaint could reduce SPS revenues approximately $3.1 million per year prospectively from the effective date established by the FERC. | |||||||||||||
Sale of Texas Transmission Assets — In March 2013, SPS reached an agreement to sell certain segments of SPS’ transmission lines and two related substations to Sharyland. In 2013, SPS received all necessary regulatory approvals for the transaction. On Dec. 30, 2013, SPS received $37.1 million and recognized a pre-tax gain of $13.6 million. The gain is reflected in the consolidated statement of income as a reduction to O&M expenses. Regulatory liabilities were recorded for jurisdictional gain sharing of $7.2 million. |
Commitments_and_Contingencies
Commitments and Contingencies | 12 Months Ended | ||||||||||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||||||||||
Commitments and Contingencies Disclosure [Abstract] | ' | ||||||||||||||||||||||||
Commitments and Contingencies | ' | ||||||||||||||||||||||||
Commitments and Contingencies | |||||||||||||||||||||||||
Commitments | |||||||||||||||||||||||||
Capital Commitments — Xcel Energy has made commitments in connection with a portion of its projected capital expenditures. Xcel Energy’s capital commitments primarily relate to the following major projects: | |||||||||||||||||||||||||
Southeast New Mexico Transmission Development — SPS is developing a transmission expansion plan for southeastern New Mexico. The SPP, with input from SPS, is conducting a High Priority Incremental Load Study to review oil and natural gas load additions in several areas, including southeastern New Mexico. A final report is expected by SPP in April 2014. SPS has started right-of-way work on four projects for which NTCs are anticipated from SPP in early 2014. | |||||||||||||||||||||||||
CapX2020 — CapX2020 is an alliance of electric cooperatives, municipals and investor-owned utilities in the upper Midwest, including the NSP System that has proposed several groups of transmission projects to be completed by 2020. Group 1 project investments consist of four transmission lines. Major construction began in 2010 on the Group 1 transmission lines with an expected completion date in 2015. NSP System’s investment depends on the routes and configurations approved by affected state commissions and on the allocation of costs borne by other participating utilities in the upper Midwest. | |||||||||||||||||||||||||
CACJA — The CACJA required PSCo to file a plan to reduce annual emissions of NOx by at least 70 to 80 percent or greater from 2008 levels by 2017 from its coal fired generation resources. In September 2012, the EPA formally approved the Colorado SIP for regional haze, including resource planning changes that include early coal-fueled plant retirements, fuel switching and SCR installation. | |||||||||||||||||||||||||
PSCo Gas Transmission Integrity Management Programs – PSCo is proactively identifying and addressing the safety and reliability of natural gas transmission pipelines. The pipeline integrity efforts include system renewal projects and increased maintenance. | |||||||||||||||||||||||||
NSP-Minnesota Wind Projects — In October 2013, the MPUC approved two projects totaling 350 MW that will be owned by NSP-Minnesota. A NDSPC decision is anticipated in early 2014. The Pleasant Valley wind farm in Minnesota and the Border Winds wind farm projects in North Dakota are anticipated to be operational by 2015. | |||||||||||||||||||||||||
SPS Transmission NTC — SPS has accepted NTCs for several hundred miles of transmission line and related substation projects based on needs identified through SPP’s various planning processes, including those associated with economics, reliability, generator interconnection or the load addition processes. A major project committed to is the TUCO to Woodward District Extra High Voltage Interchange, a 345 KV transmission line. This line connects the TUCO substation near Lubbock, Texas with the OGE substation in Woodward, Okla. The PUCT approved SPS’ CCN to build the line in 2012. It is anticipated to be complete in 2014. | |||||||||||||||||||||||||
Fuel Contracts — Xcel Energy has entered into various long-term commitments for the purchase and delivery of a significant portion of its current coal, nuclear fuel and natural gas requirements. These contracts expire in various years between 2014 and 2060. Xcel Energy is required to pay additional amounts depending on actual quantities shipped under these agreements. | |||||||||||||||||||||||||
The estimated minimum purchases for Xcel Energy under these contracts as of Dec. 31, 2013 are as follows: | |||||||||||||||||||||||||
(Millions of Dollars) | Coal | Nuclear fuel | Natural gas supply | Natural gas | |||||||||||||||||||||
storage and | |||||||||||||||||||||||||
transportation | |||||||||||||||||||||||||
2014 | $ | 947.6 | $ | 128.8 | $ | 492.8 | $ | 272.3 | |||||||||||||||||
2015 | 770.7 | 79.9 | 234.4 | 266.4 | |||||||||||||||||||||
2016 | 500.2 | 121.5 | 232 | 207.5 | |||||||||||||||||||||
2017 | 221.3 | 127.5 | 225.4 | 164.2 | |||||||||||||||||||||
2018 | 73.2 | 69.4 | 278.4 | 106.6 | |||||||||||||||||||||
Thereafter | 428.6 | 697.6 | 1,211.30 | 1,214.20 | |||||||||||||||||||||
Total | $ | 2,941.60 | $ | 1,224.70 | $ | 2,674.30 | $ | 2,231.20 | |||||||||||||||||
Additional expenditures for fuel and natural gas storage and transportation will be required to meet expected future electric generation and natural gas needs. Xcel Energy’s risk of loss, in the form of increased costs from market price changes in fuel, is mitigated through the use of natural gas and energy cost-rate adjustment mechanisms, which provide for pass-through of most fuel, storage and transportation costs to customers. | |||||||||||||||||||||||||
PPAs — NSP Minnesota, PSCo and SPS have entered into PPAs with other utilities and energy suppliers with expiration dates through 2033 for purchased power to meet system load and energy requirements and meet operating reserve obligations. In general, these agreements provide for energy payments, based on actual energy delivered and capacity payments. Certain PPAs accounted for as executory contracts also contain minimum energy purchase commitments. Capacity and energy payments are typically contingent on the independent power producing entity meeting certain contract obligations, including plant availability requirements. Certain contractual payments are adjusted based on market indices. The effects of price adjustments on our financial results are mitigated through purchased energy cost recovery mechanisms. | |||||||||||||||||||||||||
Included in electric fuel and purchased power expenses for PPAs accounted for as executory contracts were payments for capacity of $217.0 million, $261.9 million and $325.3 million in 2013, 2012 and 2011, respectively. At Dec. 31, 2013, the estimated future payments for capacity and energy that the utility subsidiaries of Xcel Energy are obligated to purchase pursuant to these executory contracts, subject to availability, are as follows: | |||||||||||||||||||||||||
(Millions of Dollars) | Capacity | Energy (a) | |||||||||||||||||||||||
2014 | $ | 254.2 | $ | 121.9 | |||||||||||||||||||||
2015 | 254.5 | 120.5 | |||||||||||||||||||||||
2016 | 215.5 | 100.2 | |||||||||||||||||||||||
2017 | 186.1 | 90.4 | |||||||||||||||||||||||
2018 | 141.1 | 93.2 | |||||||||||||||||||||||
Thereafter | 571.3 | 866.7 | |||||||||||||||||||||||
Total | $ | 1,622.70 | $ | 1,392.90 | |||||||||||||||||||||
(a) | Excludes contingent energy payments for renewable PPAs. | ||||||||||||||||||||||||
Additional energy payments under these PPAs and PPAs accounted for as operating leases will be required to meet expected future electric demand. | |||||||||||||||||||||||||
Leases — Xcel Energy leases a variety of equipment and facilities used in the normal course of business. Three of these leases qualify as capital leases and are accounted for accordingly. The assets and liabilities at the inception of a capital lease are recorded at the lower of fair market value or the present value of future lease payments and are amortized over the term of the contract. | |||||||||||||||||||||||||
WYCO was formed as a joint venture with CIG to develop and lease natural gas pipeline, storage, and compression facilities. Xcel Energy Inc. has a 50 percent ownership interest in WYCO. WYCO leases the facilities to CIG, and CIG operates the facilities, providing natural gas storage services to PSCo under a service arrangement. | |||||||||||||||||||||||||
PSCo accounts for its Totem natural gas storage service arrangement with CIG as a capital lease. As a result, PSCo had $144.2 million and $148.7 million of capital lease obligations recorded for the arrangement as of Dec. 31, 2013 and 2012, respectively. Xcel Energy Inc. eliminates 50 percent of the capital lease obligation related to WYCO in the consolidated balance sheet along with an equal amount of Xcel Energy Inc.’s equity investment in WYCO. | |||||||||||||||||||||||||
PSCo records amortization for its capital leases as cost of natural gas sold and transported on the consolidated statements of income. Total amortization expenses under capital lease assets were approximately $6.3 million, $5.7 million and $3.2 million for 2013, 2012 and 2011, respectively. Following is a summary of property held under capital leases: | |||||||||||||||||||||||||
(Millions of Dollars) | 2013 | 2012 | |||||||||||||||||||||||
Storage, leaseholds and rights | $ | 200.5 | $ | 200.5 | |||||||||||||||||||||
Gas pipeline | 20.7 | 20.7 | |||||||||||||||||||||||
Property held under capital lease | 221.2 | 221.2 | |||||||||||||||||||||||
Accumulated depreciation | (41.8 | ) | (35.5 | ) | |||||||||||||||||||||
Total property held under capital leases, net | $ | 179.4 | $ | 185.7 | |||||||||||||||||||||
The remainder of the leases, primarily for office space, railcars, generating facilities, trucks, aircraft, cars and power-operated equipment, are accounted for as operating leases. Total expenses under operating lease obligations for Xcel Energy were approximately $242.1 million, $217.8 million and $204.8 million for 2013, 2012 and 2011, respectively. These expenses include capacity payments for PPAs accounted for as operating leases of $197.7 million, $174.4 million and $160.5 million in 2013, 2012 and 2011, respectively, recorded to electric fuel and purchased power expenses. | |||||||||||||||||||||||||
Included in the future commitments under operating leases are estimated future capacity payments under PPAs that have been accounted for as operating leases in accordance with the applicable accounting guidance. | |||||||||||||||||||||||||
Future commitments under operating and capital leases are: | |||||||||||||||||||||||||
(Millions of Dollars) | Operating | PPA | Total | Capital Leases | |||||||||||||||||||||
Leases | Operating | Operating | |||||||||||||||||||||||
Leases (a) (b) | Leases | ||||||||||||||||||||||||
2014 | $ | 26.5 | $ | 214.2 | $ | 240.7 | $ | 18 | |||||||||||||||||
2015 | 25.4 | 207.4 | 232.8 | 17.8 | |||||||||||||||||||||
2016 | 22.4 | 197 | 219.4 | 17.1 | |||||||||||||||||||||
2017 | 17.2 | 192.7 | 209.9 | 15 | |||||||||||||||||||||
2018 | 16.1 | 194.4 | 210.5 | 14.7 | |||||||||||||||||||||
Thereafter | 143.6 | 1,771.90 | 1,915.50 | 289.1 | |||||||||||||||||||||
Total minimum obligation | 371.7 | ||||||||||||||||||||||||
Interest component of obligation | (264.3 | ) | |||||||||||||||||||||||
Present value of minimum obligation | $ | 107.4 | (c) | ||||||||||||||||||||||
(a) | Amounts do not include PPAs accounted for as executory contracts. | ||||||||||||||||||||||||
(b) | PPA operating leases contractually expire through 2033. | ||||||||||||||||||||||||
(c) | Future commitments exclude certain amounts related to Xcel Energy’s 50 percent ownership interest in WYCO. | ||||||||||||||||||||||||
Variable Interest Entities — The accounting guidance for consolidation of variable interest entities requires enterprises to consider the activities that most significantly impact an entity’s financial performance, and power to direct those activities, when determining whether an enterprise is a variable interest entity’s primary beneficiary. | |||||||||||||||||||||||||
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. | |||||||||||||||||||||||||
Xcel Energy has determined that certain independent power producing entities are variable interest entities. Xcel Energy is not subject to risk of loss from the operations of these entities, and no significant financial support has been, or is in the future, required to be provided other than contractual payments for energy and capacity set forth in the PPAs. | |||||||||||||||||||||||||
Xcel Energy has evaluated each of these variable interest entities for possible consolidation, including review of qualitative factors such as the length and terms of the contract, control over O&M, control over dispatch of electricity, historical and estimated future fuel and electricity prices, and financing activities. 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. The Xcel Energy utility subsidiaries had approximately 3,338 MW and 3,324 MW of capacity under long-term PPAs as of Dec. 31, 2013, and 2012, respectively, with entities that have been determined to be variable interest entities. These agreements have expiration dates through the year 2033. | |||||||||||||||||||||||||
Fuel Contracts — SPS purchases all of its coal requirements for its Harrington and Tolk electric generating stations from TUCO under contracts for those facilities that expire in 2016 and 2017, respectively. TUCO arranges for the purchase, receiving, transporting, unloading, handling, crushing, weighing, and delivery of coal to meet SPS’ requirements. TUCO is responsible for negotiating and administering contracts with coal suppliers, transporters and handlers. | |||||||||||||||||||||||||
No significant financial support has been, or is in the future, required to be provided to TUCO by SPS, other than contractual payments for delivered coal. However, the fuel contracts create a variable interest in TUCO due to SPS’ reimbursement of certain fuel procurement costs. SPS has determined that TUCO is a variable interest entity. SPS has concluded that it is not the primary beneficiary of TUCO because SPS does not have the power to direct the activities that most significantly impact TUCO’s economic performance. | |||||||||||||||||||||||||
Low-Income Housing Limited Partnerships — Eloigne and NSP-Wisconsin have entered into limited partnerships for the construction and operation of affordable rental housing developments which qualify for low-income housing tax credits. Xcel Energy Inc. has determined Eloigne and NSP-Wisconsin’s low-income housing limited partnerships to be variable interest entities primarily due to contractual arrangements within each limited partnership that establish sharing of ongoing voting control and profits and losses that does not consistently align with the partners’ proportional equity ownership. These limited partnerships are designed to qualify for low-income housing tax credits, and Eloigne and NSP-Wisconsin generally receive a larger allocation of the tax credits than the general partners at inception of the arrangements. Xcel Energy Inc. has determined that Eloigne and NSP-Wisconsin have the power to direct the activities that most significantly impact these entities’ economic performance, and therefore Xcel Energy Inc. consolidates these limited partnerships in its consolidated financial statements. | |||||||||||||||||||||||||
Equity financing for these entities has been provided by Eloigne, NSP-Wisconsin and the general partner of each limited partnership, and Xcel Energy’s risk of loss is limited to its capital contributions, adjusted for any distributions and its share of undistributed profits and losses; no significant additional financial support has been, or is in the future, required to be provided to the limited partnerships by Eloigne or NSP-Wisconsin. Mortgage-backed debt typically comprises the majority of the financing at inception of each limited partnership and is paid over the life of the limited partnership arrangement. Obligations of the limited partnerships are generally secured by the housing properties of each limited partnership, and the creditors of each limited partnership have no significant recourse to Xcel Energy Inc. or its subsidiaries. Likewise, the assets of the limited partnerships may only be used to settle obligations of the limited partnerships, and not those of Xcel Energy Inc. or its subsidiaries. | |||||||||||||||||||||||||
Amounts reflected in Xcel Energy’s consolidated balance sheets for the Eloigne and NSP-Wisconsin low-income housing limited partnerships include the following: | |||||||||||||||||||||||||
(Thousands of Dollars) | Dec. 31, 2013 | Dec. 31, 2012 | |||||||||||||||||||||||
Current assets | $ | 7,982 | $ | 3,380 | |||||||||||||||||||||
Property, plant and equipment, net | 65,451 | 72,489 | |||||||||||||||||||||||
Other noncurrent assets | 1,654 | 6,044 | |||||||||||||||||||||||
Total assets | $ | 75,087 | $ | 81,913 | |||||||||||||||||||||
Current liabilities | $ | 11,388 | $ | 8,458 | |||||||||||||||||||||
Mortgages and other long-term debt payable | 38,049 | 37,720 | |||||||||||||||||||||||
Other noncurrent liabilities | 707 | 7,678 | |||||||||||||||||||||||
Total liabilities | $ | 50,144 | $ | 53,856 | |||||||||||||||||||||
Technology Agreements — Xcel Energy has a contract that extends through June 2019 with International Business Machines Corp. (IBM) for information technology services. The contract is cancelable at Xcel Energy’s option, although Xcel Energy would be obligated to pay 50 percent of the contract value for early termination. Xcel Energy capitalized or expensed $90.3 million, $86.5 million and $93.6 million associated with the IBM contract in 2013, 2012, and 2011, respectively. | |||||||||||||||||||||||||
Xcel Energy’s contract with Accenture for information technology services extends through Jan. 2017. The contract is cancelable at Xcel Energy’s option, although there are financial penalties for early termination. Xcel Energy capitalized or expensed $23.7 million, $18.3 million and $15.2 million associated with the Accenture contract in 2013, 2012 and 2011, respectively. | |||||||||||||||||||||||||
Committed minimum payments under these obligations are as follows: | |||||||||||||||||||||||||
(Millions of Dollars) | IBM | Accenture | |||||||||||||||||||||||
Agreement | Agreement | ||||||||||||||||||||||||
2014 | $ | 35.5 | $ | 8.9 | |||||||||||||||||||||
2015 | 32.2 | 8.8 | |||||||||||||||||||||||
2016 | 31.5 | 8.8 | |||||||||||||||||||||||
2017 | 31.6 | — | |||||||||||||||||||||||
2018 | 31.1 | — | |||||||||||||||||||||||
Thereafter | 15.5 | — | |||||||||||||||||||||||
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 Dec. 31, 2013 and 2012, Xcel Energy Inc. and its subsidiaries had no assets held as collateral related to their guarantees, bond indemnities and indemnification agreements. | |||||||||||||||||||||||||
Guarantees and Surety Bonds | |||||||||||||||||||||||||
The following table presents guarantees and bond indemnities issued and outstanding as of Dec. 31, 2013: | |||||||||||||||||||||||||
(Millions of Dollars) | Guarantor | Guarantee | Current | Triggering | |||||||||||||||||||||
Amount | Exposure | Event | |||||||||||||||||||||||
Guarantee of customer loans for the Farm Rewiring Program (a) | NSP-Wisconsin | $ | 1 | $ | 0.3 | (e) | |||||||||||||||||||
Guarantee of the indemnification obligations of Xcel Energy Services Inc. under the aircraft leases (b) | Xcel Energy Inc. | 9.2 | — | (f) | |||||||||||||||||||||
Guarantee of residual value of assets under the BTM Capital Corporation Equipment Leasing Agreement (c) | NSP-Minnesota | 9.2 | — | (g) | |||||||||||||||||||||
Total guarantees issued | $ | 19.4 | $ | 0.3 | |||||||||||||||||||||
Guarantee performance and payment of surety bonds for Xcel Energy Inc. and its subsidiaries (d) | Xcel Energy Inc. | $ | 32.1 | (i) | (h) | ||||||||||||||||||||
(a) | The term of this guarantee expires in 2017, which is the final scheduled repayment date for the loans. As of Dec. 31, 2013, no claims had been made by the lender. | ||||||||||||||||||||||||
(b) | The term of this guarantee expires in 2017 when the associated leases expire. | ||||||||||||||||||||||||
(c) | The terms of these guarantees expire in 2014 and 2015 when the associated leases expire. | ||||||||||||||||||||||||
(d) | The surety bonds primarily relate to workers compensation benefits and utility projects. The workers compensation bonds are renewed annually and the project based bonds expire in conjunction with the completion of the related projects. | ||||||||||||||||||||||||
(e) | The debtor becomes the subject of bankruptcy or other insolvency proceedings. | ||||||||||||||||||||||||
(f) | Nonperformance and/or nonpayment. | ||||||||||||||||||||||||
(g) | Actual fair value of leased assets is less than the guaranteed residual value amount at the end of the lease term. | ||||||||||||||||||||||||
(h) | Failure of Xcel Energy Inc. or one of its subsidiaries to perform under the agreement that is the subject of the relevant bond. In addition, per the indemnity agreement between Xcel Energy Inc. and the various surety companies, the surety companies have the discretion to demand that collateral be posted. | ||||||||||||||||||||||||
(i) | Due to the magnitude of projects associated with the surety bonds, the total current exposure of this indemnification cannot be determined. Xcel Energy Inc. believes the exposure to be significantly less than the total amount of the outstanding bonds. | ||||||||||||||||||||||||
Indemnification Agreements | |||||||||||||||||||||||||
In connection with the sale of certain Texas electric transmission assets to Sharyland, 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. 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 | |||||||||||||||||||||||||
Xcel Energy has been or is currently involved with the cleanup of contamination from certain hazardous substances at several sites. In many situations, the subsidiary involved believes it will recover some portion of these costs through insurance claims. Additionally, where applicable, the subsidiary involved is pursuing, or intends to pursue, recovery from other PRPs and through the regulated rate process. New and changing federal and state environmental mandates can also create added financial liabilities for Xcel Energy, which are normally recovered through the regulated rate process. To the extent any costs are not recovered through the options listed above, Xcel Energy would be required to recognize an expense. | |||||||||||||||||||||||||
Site Remediation — Various federal and state environmental laws impose liability, without regard to the legality of the original conduct, where hazardous substances or other regulated materials have been released to the environment. Xcel Energy Inc.’s subsidiaries may sometimes pay all or a portion of the cost to remediate sites where past activities of their predecessors or other parties have caused environmental contamination. Environmental contingencies could arise from various situations, including sites of former MGPs operated by Xcel Energy Inc.’s subsidiaries or their predecessors, or other entities; and third-party sites, such as landfills, for which one or more of Xcel Energy Inc.’s subsidiaries are alleged to be a PRP that sent hazardous materials and wastes to that site. | |||||||||||||||||||||||||
MGP Sites | |||||||||||||||||||||||||
Ashland MGP Site — NSP-Wisconsin has been named a 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 EPA issued its Record of Decision (ROD) in 2010, which describes the preferred remedy the EPA has selected for the cleanup of the Ashland site. For the Sediments at the Ashland Site, the ROD preferred remedy is a hybrid remedy involving both dry excavation and wet conventional dredging methodologies (the Hybrid Remedy). The ROD also identifies the possibility of a wet conventional dredging only remedy for the Sediments (the Wet Dredge), contingent upon the completion of a successful Wet Dredge pilot study. | |||||||||||||||||||||||||
In 2011, the EPA issued special notice letters identifying several entities, including NSP-Wisconsin, as PRPs, for future remediation at the site. The special notice letters requested that those PRPs participate in negotiations with the EPA regarding how the PRPs intended to conduct or pay for the remediation at the Ashland site. As a result of settlement negotiations with NSP-Wisconsin, the EPA agreed to segment the Ashland site into separate areas. The first area (Phase I Project Area) includes soil and groundwater in Kreher Park and the Upper Bluff. The second area includes the Sediments. | |||||||||||||||||||||||||
In October 2012, a settlement among the EPA, the WDNR, the Bad River and Red Cliff Bands of the Lake Superior Tribe of Chippewa Indians and NSP-Wisconsin was approved by the U.S. District Court for the Western District of Wisconsin. This settlement resolves claims against NSP-Wisconsin for its alleged responsibility for the remediation of the Phase I Project Area. Under the terms of the settlement, NSP-Wisconsin agreed to perform the remediation of the Phase I Project Area, but does not admit any liability with respect to the Ashland site. The settlement reflects a cost estimate for the clean up of the Phase I Project Area of $40 million. The settlement also resolves claims by the federal, state and tribal trustees against NSP-Wisconsin for alleged natural resource damages at the Ashland site, including both the Phase I Project Area and the Sediments. As part of the settlement, NSP-Wisconsin has conveyed approximately 1,390 acres of land to the State of Wisconsin and tribal trustees. Fieldwork to address the Phase I Project Area at the Ashland site began at the end of 2012 and continues. | |||||||||||||||||||||||||
Negotiations are ongoing between the EPA and NSP-Wisconsin regarding who will pay or perform the cleanup of the Sediments and what remedy will be implemented at the site to address the Sediments. In August and September 2013, NSP-Wisconsin performed field studies in the Sediments to gather more data about site conditions. The data from that investigation was received and reported to the EPA at the end of 2013. It is NSP-Wisconsin’s view that this data demonstrates the Hybrid Remedy is not safe or feasible to implement. The EPA’s ROD for the Ashland site includes estimates that the cost of the Hybrid Remedy is between $63 million and $77 million, with a potential deviation in such estimated costs of up to 50 percent higher to 30 percent lower. Also, in September 2013, the EPA requested NSP-Wisconsin consider re-submitting another proposal to perform a Wet Dredge pilot study for a portion of the Sediments. NSP-Wisconsin previously submitted a proposal for a Wet Dredge pilot study in 2011. In November 2013, NSP-Wisconsin submitted a revised Wet Dredge pilot study work plan proposal to the EPA. NSP-Wisconsin is in the process of negotiating a final pilot study work plan for possible implementation in late summer or early fall of 2014. | |||||||||||||||||||||||||
In August 2012, NSP-Wisconsin also filed litigation against other PRPs for their share of the cleanup costs for the Ashland site. Trial for this matter is scheduled for April 2015. Negotiations between the EPA, NSP-Wisconsin and several of the other PRPs regarding the PRPs’ fair share of the cleanup costs for the Ashland site are also ongoing. | |||||||||||||||||||||||||
At Dec. 31, 2013 and 2012, NSP-Wisconsin had recorded a liability of $104.6 million and $103.7 million, respectively, for the Ashland site based upon potential remediation and design costs together with estimated outside legal and consultant costs; of which $25.2 million and $20.1 million, respectively, was considered a current liability. NSP-Wisconsin’s potential liability, the actual cost of remediation and the time frame over which the amounts may be paid are subject to change. NSP-Wisconsin also continues to work to identify and access state and federal funds to apply to the ultimate remediation cost of the entire site. Unresolved issues or factors that could result in higher or lower NSP-Wisconsin remediation costs for the Ashland site include the cleanup approach implemented for the Sediments, which party implements the cleanup, the timing of when the cleanup is implemented, potential contributions by other PRPs and whether federal or state funding may be directed to help offset remediation costs at the Ashland site. | |||||||||||||||||||||||||
NSP-Wisconsin has deferred the estimated site remediation costs, as a regulatory asset, based on an expectation that the PSCW will continue to allow NSP-Wisconsin to recover payments for environmental remediation from its customers. The PSCW has consistently authorized in NSP-Wisconsin rates recovery of all remediation costs incurred at the Ashland site, and has authorized recovery of MGP remediation costs by other Wisconsin utilities. External MGP remediation costs are subject to deferral in the Wisconsin retail jurisdiction and are reviewed for prudence as part of the Wisconsin retail rate case process. Under an existing PSCW policy, utilities have recovered remediation costs for MGPs in natural gas rates, amortized over a four- to six-year period. The PSCW historically has not allowed utilities to recover their carrying costs on unamortized regulatory assets for MGP remediation. | |||||||||||||||||||||||||
In the 2013 rate case decision, the PSCW recognized the potential magnitude of the future liability for the cleanup at the Ashland site and granted an exception to its existing policy at the request of NSP-Wisconsin. The elements of this exception include: 1) approval to begin recovery of estimated Phase 1 Project costs beginning on Jan. 1, 2013; 2) approval to amortize these estimated costs over a ten-year period; and 3) approval to apply a three percent carrying cost to the unamortized regulatory asset. In the 2014 rate case decision, the PSCW continued the cost recovery treatment established in the 2013 rate case, with respect to the 2013 and 2014 clean-up costs for the Phase I Project Area. The PSCW determined the timing of the clean-up of the Sediments was uncertain and declined NSP-Wisconsin’s request to begin cost recovery for this portion of the clean-up in 2014 rates. However, the PSCW allowed NSP-Wisconsin to increase its 2014 amortization expense related to the clean-up by an additional $1.1 million to offset the need for a rate decrease for the natural gas utility. The cost recovery treatment granted by the PSCW in the 2013 and 2014 rate cases will help mitigate the rate impact to natural gas customers and the risk to NSP-Wisconsin from a longer amortization period. | |||||||||||||||||||||||||
Other MGP Sites — Xcel Energy is currently involved in investigating and/or remediating several other MGP sites where hazardous or other regulated materials may have been deposited. Xcel Energy has identified seven sites across all of its service territories, where former MGP activities have or may have resulted in site contamination and are under current investigation and/or remediation. At some or all of these MGP sites, there are other parties that may have responsibility for some portion of any remediation. Xcel Energy anticipates that the majority of the remediation at these sites will continue through at least 2014. Xcel Energy had accrued a total of $5.1 million and $3.0 million for all of these sites at Dec. 31, 2013 and 2012, respectively. There may be insurance recovery and/or recovery from other PRPs that will offset any costs incurred. Xcel Energy anticipates that any amounts spent will be fully recovered from customers. | |||||||||||||||||||||||||
Environmental Requirements | |||||||||||||||||||||||||
Water and waste | |||||||||||||||||||||||||
Asbestos Removal — Some of Xcel Energy’s facilities contain asbestos. Most asbestos will remain undisturbed until the facilities that contain it are demolished or removed. Xcel Energy has recorded an estimate for final removal of the asbestos as an ARO. It may be necessary to remove some asbestos to perform maintenance or make improvements to other equipment. The cost of removing asbestos as part of other work is not expected to be material and is recorded as incurred as operating expenses for maintenance projects, capital expenditures for construction projects or removal costs for demolition projects. | |||||||||||||||||||||||||
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. Refuse derived fuel, biomass and other alternatively fueled power plants are not addressed by the proposed revisions. The proposed rule identifies four potential regulatory options and invites comments on those regulatory approaches. The options differ in the number of waste streams covered, size of the units controlled and stringency of controls. It is not yet known when the EPA will issue a finalized rule. Under the current proposed rule, facilities would need to comply as soon as possible after July 2017 but no later than July 2022. The impact of this rule on Xcel Energy is uncertain at this time. | |||||||||||||||||||||||||
Federal CWA Section 316 (b) — The federal CWA requires the EPA to regulate cooling water intake structures to assure that these structures reflect the best technology available for minimizing adverse environmental impacts to aquatic species. In 2011, the EPA published the proposed rule that sets standards for minimization of aquatic species impingement, but leaves entrainment reduction requirements at the discretion of the permit writer and the regional EPA office. A final rule is anticipated in April 2014. It is not possible to provide an accurate estimate of the overall cost of this rulemaking at this time due to the uncertainty of the final regulatory requirements. | |||||||||||||||||||||||||
NSP-Minnesota submitted its Black Dog CWA compliance plan for the MPCA’s review and approval in 2010. The MPCA is currently reviewing the proposal in consultation with the EPA. | |||||||||||||||||||||||||
Proposed Coal Ash Regulation — Xcel Energy’s operations are subject to federal and state laws that impose requirements for handling, storage, treatment and disposal of hazardous waste. In 2010, the EPA published a proposed rule on whether to regulate coal combustion byproducts (coal ash) as hazardous or nonhazardous waste. Coal ash is currently exempt from hazardous waste regulation. Xcel Energy’s costs for the management and disposal of coal ash would significantly increase and the beneficial reuse of coal ash would be negatively impacted if the EPA ultimately issues a rule under which coal ash is regulated as hazardous waste. The EPA has entered into a consent decree to act on final regulations by December 2014. The timing, scope and potential cost of any final rule that might be implemented are not determinable at this time. | |||||||||||||||||||||||||
Air | |||||||||||||||||||||||||
EPA GHG Regulation — In 2009, the EPA issued its “endangerment” finding that GHG emissions pose a threat to public health and welfare. This finding required the EPA to adopt GHG emission standards for mobile sources. In 2011, new EPA permitting requirements became effective for GHG emissions of new and modified large stationary sources, which are applicable to the construction of new power plants or power plant modifications that increase emissions above a certain threshold. These rules were upheld on appeal to the D.C. Circuit. The U.S. Supreme Court has granted review on one issue related to these rules, specifically whether the EPA’s regulation of GHG emissions from mobile sources triggered, by operation of law, new source review permitting requirements for stationary sources, which was the EPA’s basis for adopting the 2011 permitting rules. The Court is scheduled to hear arguments in February 2014. A ruling is anticipated by June 2014. 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 and NSPS Proposal — In June 2013, President Obama issued a memorandum directing the EPA to develop GHG emission standards for existing power plants. The memorandum anticipates the EPA will issue a proposed GHG emission standard for existing power plants in June 2014. It is not possible to evaluate the impact of existing source standards until the upcoming proposal and final requirements are known. | |||||||||||||||||||||||||
In January 2014, the EPA re-proposed a GHG NSPS for newly constructed power plants which seeks to establish CO2 emission rates for coal-fired power plants that reflect emission reductions using partial carbon capture and storage technology (CCS). The EPA’s proposed CO2 emission limits for gas-fired power plants reflect emissions levels from combined cycle technology with no CCS. The EPA continues to propose that the NSPS not apply to modified or reconstructed existing power plants. In addition, installation of control equipment on existing plants would not constitute a “modification” to those plants under the NSPS program. It is not possible to evaluate the impact of the re-proposed NSPS until its final requirements are known. | |||||||||||||||||||||||||
CSAPR — In 2011, the EPA issued the CSAPR to address long range transport of PM and ozone by requiring reductions in SO2 and NOx from utilities in the eastern half of the United States. For Xcel Energy, the rule would have applied in Minnesota, Wisconsin and Texas. The CSAPR would have set more stringent requirements than the proposed Clean Air Transport Rule and would have required plants in Texas to reduce their SO2 and annual NOx emissions. The rule also would have created an emissions trading program. | |||||||||||||||||||||||||
In August 2012, the D.C. Circuit vacated the CSAPR and remanded it back to the EPA. The D.C. Circuit stated that the EPA must continue administering the CAIR pending adoption of a valid replacement. In December 2013, the U.S. Supreme Court heard oral arguments on the D.C. Circuit’s 2012 decision to vacate the CSAPR. A decision is anticipated by June 2014. It is not yet known whether the D.C. Circuit’s decision will be upheld, or how the EPA might approach a replacement rule. Therefore, it is not known what requirements may be imposed in the future. | |||||||||||||||||||||||||
As the EPA continues administering the CAIR while the CSAPR or a replacement rule is pending, Xcel Energy expects to comply with the CAIR as described below. | |||||||||||||||||||||||||
CAIR — In 2005, the EPA issued the CAIR to further regulate SO2 and NOx emissions. The CAIR applies to Texas and Wisconsin. The CAIR does not currently apply to Minnesota. | |||||||||||||||||||||||||
Under the CAIR’s cap and trade structure, companies can comply through capital investments in emission controls or purchase of emission allowances from other utilities making reductions on their systems. NSP-Wisconsin purchased allowances in 2012 and 2013 and plans to continue to purchase allowances in 2014 to comply with the CAIR. In the SPS region, installation of low-NOx combustion control technology was completed in 2012 on Tolk Unit 1. SPS plans to install the same combustion control technology on Tolk Unit 2 in the second quarter of 2014. These installations will reduce or eliminate SPS’ need to purchase NOx emission allowances. SPS had sufficient SO2 allowances to comply with the CAIR in 2013 and has sufficient allowances for 2014. At Dec. 31, 2013, the estimated annual CAIR NOx allowance cost for Xcel Energy did not have a material impact on the results of operations, financial position or cash flows. | |||||||||||||||||||||||||
EGU Mercury and Air Toxics Standards (MATS) Rule — The final EGU MATS rule became effective in April 2012. The EGU MATS rule sets emission limits for acid gases, mercury and other hazardous air pollutants and requires coal-fired utility facilities greater than 25 MW to demonstrate compliance within three to four years of the effective date. Xcel Energy expects to comply with the EGU MATS rule through a combination of mercury and other emission control projects. Xcel Energy believes EGU MATS costs will be recoverable through regulatory mechanisms and does not expect a material impact on results of operations, financial position or cash flows. | |||||||||||||||||||||||||
Minnesota Mercury Legislation — NSP-Minnesota installed sorbent control systems at the Sherco Unit 3 and A.S. King generating plants and has obtained MPUC approval to install mercury controls on Sherco Units 1 and 2 by the end of 2014. NSP-Minnesota projects installation costs of $12.0 million for the mercury controls on the units and believes these costs will be recoverable through regulatory mechanisms. | |||||||||||||||||||||||||
Industrial Boiler (IB) MACT Rules — In 2011, the EPA finalized IB MACT rules to regulate boilers and process heaters fueled with coal, biomass and liquid fuels, which would apply to NSP-Wisconsin’s Bay Front Units 1 and 2. The capital cost to install controls to meet the requirements in the final reconsidered rule is anticipated to be $17.2 million in total and is targeted for completion in 2014. | |||||||||||||||||||||||||
Regional Haze Rules — In 2005, the EPA amended the 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 SIPs, Colorado, Minnesota and Texas identified the Xcel Energy facilities that will have to reduce SO2, NOx and PM emissions under BART and set emissions limits for those facilities. | |||||||||||||||||||||||||
PSCo | |||||||||||||||||||||||||
In 2011, the Colorado Air Quality Control Commission approved a SIP (the Colorado SIP) that included the CACJA emission reduction plan as satisfying regional haze requirements for the facilities included in the CACJA plan. In addition, the Colorado SIP included a BART determination for Comanche Units 1 and 2. The EPA approved the Colorado SIP in 2012. Emission controls at the Hayden and Pawnee plants are projected to cost $359.5 million and are expected to be installed between 2014 and 2017. PSCo anticipates these costs will be fully recoverable in rates. | |||||||||||||||||||||||||
The Colorado Mining Association (CMA) challenged the Colorado SIP in Colorado District Court. The District Court dismissed the CMA’s challenge in 2012, and the Colorado Court of Appeals upheld the District Court’s decision in November 2013. The CMA did not petition for review by the Colorado Supreme Court, thus ending the case. | |||||||||||||||||||||||||
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 SCR be added to the units. PSCo intervened in the case. The 10th Circuit is scheduled to hear argument in November 2014, following completion of the briefs in August 2014. | |||||||||||||||||||||||||
In 2010, two environmental groups petitioned the DOI to certify that 12 coal-fired boilers and one coal-fired cement kiln in Colorado are contributing to visibility problems in Rocky Mountain National Park. The following PSCo plants are named in the petition: Cherokee, Hayden, Pawnee and Valmont. The groups allege the Colorado BART rule is inadequate to satisfy the CAA mandate of ensuring reasonable further progress towards restoring natural visibility conditions in the park. It is not known when the DOI will rule on the petition. | |||||||||||||||||||||||||
NSP-Minnesota | |||||||||||||||||||||||||
In 2009, the MPCA approved a SIP (the Minnesota SIP) and submitted it to the EPA for approval. The MPCA’s source-specific BART limits for Sherco Units 1 and 2 require combustion controls for NOx and scrubber upgrades for SO2. The MPCA concluded SCRs should not be required because the minor visibility benefits derived from SCRs do not outweigh the substantial costs. The combustion controls have been installed and the scrubber upgrades, to be completed by January 2015, are underway. These emission controls are projected to cost approximately $50 million, of which $40.3 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 EGUs and also approved the source-specific emission limits for Sherco Units 1 and 2 as strengthening the Minnesota SIP, but avoided characterizing them as BART limits. | |||||||||||||||||||||||||
In August 2012, the National Parks Conservation Association, Sierra Club, Voyageurs National Park Association, Friends of the Boundary Waters Wilderness, Minnesota Center for Environmental Advocacy and Fresh Energy appealed the EPA’s approval of the Minnesota SIP to the U.S. Court of Appeals for the Eighth Circuit. NSP-Minnesota and other regulated parties were denied intervention. In June 2013, the Court ordered this case to be held in abeyance until the U.S. Supreme Court decides on the CSAPR. If this litigation results in further EPA proceedings concerning the Minnesota SIP, such proceedings may consider whether SCRs should be required for Sherco Units 1 and 2. | |||||||||||||||||||||||||
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 review of the CSAPR may impact the EPA’s approval of the Texas SIP. | |||||||||||||||||||||||||
Reasonably Attributable Visibility Impairment (RAVI) — Additional visibility rules relate to a program called the RAVI program. In 2009, the DOI certified that a portion of the visibility impairment in Voyageurs and Isle Royale National Parks is reasonably attributable to emissions from NSP-Minnesota’s Sherco Units 1 and 2. The EPA is required to make its own determination as to whether Sherco Units 1 and 2 cause or contribute to RAVI and, if so, whether the level of controls required by the MPCA is appropriate. The EPA has stated it plans to issue a separate notice on the issue of BART for Sherco Units 1 and 2 under the RAVI program. It is not yet known when the EPA will publish a proposal under RAVI or what that proposal will entail. | |||||||||||||||||||||||||
In December 2012, a lawsuit against the EPA was filed in the U.S. District Court for the District of Minnesota by the following organizations: National Parks Conservation Association, Minnesota Center for Environmental Advocacy, Friends of the Boundary Waters Wilderness, Voyageurs National Park Association, Fresh Energy and Sierra Club. The lawsuit alleges the EPA has failed to perform a nondiscretionary duty to determine BART for Sherco Units 1 and 2 under the RAVI program. The EPA filed an answer denying the allegations. The Court denied NSP-Minnesota’s motion to intervene in July 2013. NSP-Minnesota appealed this decision to the U.S. Court of Appeals for the Eighth Circuit. Oral arguments have been scheduled for March 2014. | |||||||||||||||||||||||||
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. The EPA is expected to designate 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. | |||||||||||||||||||||||||
PSCo NOV — In 2002, PSCo received an NOV from the EPA alleging violations of the New Source Review (NSR) requirements of the CAA at the Comanche Station and Pawnee Generating Station in Colorado. The NOV alleges that various maintenance, repair and replacement projects at the plants in the mid to late 1990s should have required a permit under the NSR process. PSCo believes it has acted in full compliance with the CAA and NSR process. PSCo also believes that the projects identified in the NOV fit within the routine maintenance, repair and replacement exemption contained within the NSR regulations or are otherwise not subject to the NSR requirements. PSCo disagrees with the assertions contained in the NOV and intends to vigorously defend its position. It is not known whether any costs would be incurred as a result of this NOV. | |||||||||||||||||||||||||
NSP-Minnesota NOV — In 2011, NSP-Minnesota received an NOV from the EPA alleging violations of the NSR requirements of the CAA at the Sherco plant and Black Dog plant in Minnesota. The NOV alleges that various maintenance, repair and replacement projects at the plants in the mid 2000s should have required a permit under the NSR process. NSP-Minnesota believes it has acted in full compliance with the CAA and NSR process. NSP-Minnesota also believes that the projects identified in the NOV fit within the routine maintenance, repair and replacement exemption contained within the NSR regulations or are otherwise not subject to the NSR requirements. NSP-Minnesota disagrees with the assertions contained in the NOV and intends to vigorously defend its position. It is not known whether any costs would be incurred as a result of this NOV. | |||||||||||||||||||||||||
Asset Retirement Obligations | |||||||||||||||||||||||||
Recorded AROs — AROs have been recorded for property related to the following: electric production (nuclear, steam, wind, other and hydro), electric distribution and transmission, natural gas production, natural gas transmission and distribution, and general property. The electric production obligations include asbestos, ash-containment facilities, radiation sources, storage tanks, control panels and decommissioning. The asbestos recognition associated with the steam production includes certain plants at NSP-Minnesota, NSP-Wisconsin, PSCo and SPS. NSP-Minnesota also recorded asbestos recognition for its general office building. This asbestos abatement removal obligation originated in 1973 with the CAA, which applied to the demolition of buildings or removal of equipment containing asbestos that can become airborne on removal. AROs also have been recorded for NSP-Minnesota, PSCo and SPS steam production related to ash-containment facilities such as bottom ash ponds, evaporation ponds and solid waste landfills. The origination dates on the ARO recognition for ash-containment facilities at steam plants was the in-service dates of the various facilities. NSP-Minnesota and PSCo have also recorded AROs for the retirement and removal of assets at certain wind production facilities for which the land is leased and removal is required by contract, with the origination dates being the in-service date of the various facilities. | |||||||||||||||||||||||||
Xcel Energy has recognized an ARO for the retirement costs of natural gas mains at NSP-Minnesota, NSP-Wisconsin and PSCo and an ARO for the retirement of above ground gas storage facilities at PSCo. In addition, an ARO was recognized for the removal of electric transmission and distribution equipment at NSP-Minnesota, NSP-Wisconsin, PSCo and SPS, which consists of many small potential obligations associated with PCBs, mineral oil, storage tanks, treated poles, lithium batteries, mercury and street lighting lamps. The electric and common general AROs include small obligations related to storage tanks, radiation sources and office buildings. These assets have numerous in-service dates for which it is difficult to assign the obligation to a particular year. Therefore, the obligation was measured using an average service life. | |||||||||||||||||||||||||
For the nuclear assets, the ARO associated with the decommissioning of the NSP-Minnesota nuclear generating plants, Monticello and Prairie Island, originated with the in-service date of the facility. See Note 14 for further discussion of nuclear obligations. | |||||||||||||||||||||||||
A reconciliation of Xcel Energy’s AROs is shown in the tables below for the years ended Dec. 31, 2013 and 2012: | |||||||||||||||||||||||||
(Thousands of Dollars) | Beginning | Liabilities | Liabilities | Accretion | Revisions | Ending | |||||||||||||||||||
Balance | Recognized | Settled | to Prior | Balance | |||||||||||||||||||||
Jan. 1, 2013 | Estimates | Dec. 31, 2013 | |||||||||||||||||||||||
Electric plant | |||||||||||||||||||||||||
Nuclear production decommissioning | $ | 1,546,358 | $ | — | $ | — | $ | 81,940 | $ | — | $ | 1,628,298 | |||||||||||||
Steam and other production ash containment | 61,735 | — | — | 2,105 | 15,513 | 79,353 | |||||||||||||||||||
Steam and other production asbestos | 45,461 | — | (1,059 | ) | 2,551 | 3,874 | 50,827 | ||||||||||||||||||
Wind production | 35,864 | — | — | 1,600 | — | 37,464 | |||||||||||||||||||
Electric distribution | 24,150 | — | — | 708 | (12,672 | ) | 12,186 | ||||||||||||||||||
Other | 3,152 | — | — | 240 | 159 | 3,551 | |||||||||||||||||||
Natural gas plant | |||||||||||||||||||||||||
Gas transmission and distribution | 1,258 | — | — | 81 | (141 | ) | 1,198 | ||||||||||||||||||
Gas gathering | — | 575 | — | — | — | 575 | |||||||||||||||||||
Common and other property | |||||||||||||||||||||||||
Common general plant asbestos | 1,197 | — | — | 66 | (783 | ) | 480 | ||||||||||||||||||
Common miscellaneous | 621 | — | — | 59 | 778 | 1,458 | |||||||||||||||||||
Total liability | $ | 1,719,796 | $ | 575 | $ | (1,059 | ) | $ | 89,350 | $ | 6,728 | $ | 1,815,390 | ||||||||||||
The aggregate fair value of NSP-Minnesota’s legally restricted assets, for purposes of funding future nuclear decommissioning, was $1.6 billion as of Dec. 31, 2013, consisting of external investment funds. | |||||||||||||||||||||||||
In 2013, Xcel Energy revised asbestos, ash containment facilities, radiation sources, miscellaneous electric production, electric transmission and distribution, natural gas transmission and distribution and general AROs due to revised estimated cash flows. Additionally, in 2013, an ARO was recorded to reflect the expected costs with the retirement of certain gas gathering facilities at PSCo and AROs were settled for the asbestos abatement at the Cameo and Riverview generating facilities at PSCo and SPS, respectively. | |||||||||||||||||||||||||
(Thousands of Dollars) | Beginning | Liabilities | Liabilities | Accretion | Revisions | Ending | |||||||||||||||||||
Balance | Recognized | Settled | to Prior | Balance | |||||||||||||||||||||
Jan. 1, 2012 | Estimates | Dec. 31, 2012 | |||||||||||||||||||||||
Electric plant | |||||||||||||||||||||||||
Nuclear production decommissioning | $ | 1,482,741 | $ | — | $ | — | $ | 75,301 | $ | (11,684 | ) | $ | 1,546,358 | ||||||||||||
Steam and other production ash containment | 41,278 | — | — | 1,614 | 18,843 | 61,735 | |||||||||||||||||||
Steam and other production asbestos | 54,342 | 1,962 | (9,372 | ) | 3,417 | (4,888 | ) | 45,461 | |||||||||||||||||
Wind production | 40,515 | 2,928 | — | 2,068 | (9,647 | ) | 35,864 | ||||||||||||||||||
Electric distribution | 27,592 | — | — | 1,000 | (4,442 | ) | 24,150 | ||||||||||||||||||
Other | 2,390 | — | — | 92 | 670 | 3,152 | |||||||||||||||||||
Natural gas plant | |||||||||||||||||||||||||
Gas transmission and distribution | 1,201 | — | — | 73 | (16 | ) | 1,258 | ||||||||||||||||||
Common and other property | |||||||||||||||||||||||||
Common general plant asbestos | 1,135 | — | — | 62 | — | 1,197 | |||||||||||||||||||
Common miscellaneous | 599 | — | — | 22 | — | 621 | |||||||||||||||||||
Total liability | $ | 1,651,793 | $ | 4,890 | $ | (9,372 | ) | $ | 83,649 | $ | (11,164 | ) | $ | 1,719,796 | |||||||||||
The aggregate fair value of NSP-Minnesota’s legally restricted assets, for purposes of funding future nuclear decommissioning, was $1.5 billion as of Dec. 31, 2012, consisting of external investment funds. | |||||||||||||||||||||||||
In 2012, revisions were made for nuclear decommissioning, asbestos, ash-containment facilities, wind facilities and electric transmission and distribution AROs due to revised estimated cash flows. | |||||||||||||||||||||||||
Indeterminate AROs — PSCo has underground natural gas storage facilities that have special closure requirements for which the final removal date cannot be determined; therefore, an ARO has not been recorded. | |||||||||||||||||||||||||
Removal Costs — Xcel Energy records a regulatory liability for the plant removal costs of steam and other generation, transmission and distribution facilities of its utility subsidiaries. Generally, the accrual of future non-ARO removal obligations is not required. However, long-standing ratemaking practices approved by applicable state and federal regulatory commissions have allowed provisions for such costs in historical depreciation rates. These removal costs have accumulated over a number of years based on varying rates as authorized by the appropriate regulatory entities. Given the long time periods over which the amounts were accrued and the changing of rates over time, the utility subsidiaries have estimated the amount of removal costs accumulated through historic depreciation expense based on current factors used in the existing depreciation rates. | |||||||||||||||||||||||||
The accumulated balances by entity were as follows at Dec. 31: | |||||||||||||||||||||||||
(Millions of Dollars) | 2013 | 2012 | |||||||||||||||||||||||
NSP-Minnesota | $ | 378 | $ | 377 | |||||||||||||||||||||
NSP-Wisconsin | 116 | 114 | |||||||||||||||||||||||
PSCo | 359 | 365 | |||||||||||||||||||||||
SPS | 53 | 67 | |||||||||||||||||||||||
Total Xcel Energy | $ | 906 | $ | 923 | |||||||||||||||||||||
Nuclear Insurance | |||||||||||||||||||||||||
NSP-Minnesota’s public liability for claims resulting from any nuclear incident is limited to $13.6 billion under the Price-Anderson amendment to the Atomic Energy Act. NSP-Minnesota has secured $375 million of coverage for its public liability exposure with a pool of insurance companies. The remaining $13.2 billion of exposure is funded by the Secondary Financial Protection Program, available from assessments by the federal government in case of a nuclear accident. NSP-Minnesota is subject to assessments of up to $127.3 million per reactor per accident for each of its three licensed reactors, to be applied for public liability arising from a nuclear incident at any licensed nuclear facility in the United States. The maximum funding requirement is $19.0 million per reactor during any one year. These maximum assessment amounts are both subject to inflation adjustment by the NRC and state premium taxes. The NRC’s last adjustment was effective September 2013. | |||||||||||||||||||||||||
NSP-Minnesota purchases insurance for property damage and site decontamination cleanup costs from Nuclear Electric Insurance Ltd. (NEIL). The coverage limits are $2.3 billion for each of NSP-Minnesota’s two nuclear plant sites. NEIL also provides business interruption insurance coverage, including the cost of replacement power obtained during certain prolonged accidental outages of nuclear generating units. Premiums are expensed over the policy term. All companies insured with NEIL are subject to retroactive premium adjustments if losses exceed accumulated reserve funds. Capital has been accumulated in the reserve funds of NEIL to the extent that NSP-Minnesota would have no exposure for retroactive premium assessments in case of a single incident under the business interruption and the property damage insurance coverage. However, in each calendar year, NSP-Minnesota could be subject to maximum assessments of approximately $16.1 million for business interruption insurance and $40.2 million for property damage insurance if losses exceed accumulated reserve funds. | |||||||||||||||||||||||||
Legal Contingencies | |||||||||||||||||||||||||
Xcel Energy is involved in various litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or is a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Management maintains accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss. For current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Xcel Energy’s financial statements. Unless otherwise required by GAAP, legal fees are expensed as incurred. | |||||||||||||||||||||||||
Employment, Tort and Commercial Litigation | |||||||||||||||||||||||||
Merricourt Wind Project Litigation — In April 2011, NSP-Minnesota terminated its agreements with enXco Development Corporation (enXco) for the development of a 150 MW wind project in southeastern North Dakota. NSP-Minnesota’s decision to terminate the agreements was based in large part on the adverse impact this project could have on endangered or threatened species protected by federal law and the uncertainty in cost and timing in mitigating this impact. NSP-Minnesota also terminated the agreements due to enXco’s nonperformance of certain other conditions, including failure to obtain a Certificate of Site Compatibility and the failure to close on the contracts by an agreed upon date of March 31, 2011. NSP-Minnesota recorded a $101 million deposit in the first quarter of 2011, which was collected in April 2011. In May 2011, NSP-Minnesota filed a declaratory judgment action in the U.S. District Court in Minnesota to obtain a determination that it acted properly in terminating the agreements. enXco also filed a separate lawsuit in the same court seeking approximately $240 million for an alleged breach of contract. NSP-Minnesota believes enXco’s lawsuit is without merit. In October 2012, NSP-Minnesota filed a motion for summary judgment. In April 2013, the U.S. District Court granted NSP-Minnesota’s motion and entered judgment in its favor. In April 2013, enXco filed a notice of appeal to the Eighth Circuit. It is uncertain when the Eighth Circuit will decide this appeal. Although Xcel Energy believes the likelihood of loss is remote based on existing case law and the U.S. District Court’s April 2013 decision, it is not possible to estimate the amount or range of reasonably possible loss in the event of an adverse outcome of this matter. No accrual has been recorded for this matter. | |||||||||||||||||||||||||
Exelon Wind (formerly John Deere Wind) Complaint — Several lawsuits in Texas state and federal courts and regulatory proceedings have arisen out of a dispute concerning SPS’ payments for energy and capacity produced from the Exelon Wind subsidiaries’ projects. There are two main areas of dispute. First, Exelon Wind claims that it established legally enforceable obligations (LEOs) for each of its 12 wind facilities in 2005 through 2008 that require SPS to buy power based on SPS’ forecasted avoided cost as determined in 2005 through 2008. Although SPS has refused to accept Exelon Wind’s LEOs, SPS accepts that it must take energy from Exelon Wind under SPS’ PUCT-approved QF Tariff. Second, Exelon Wind has raised various challenges to SPS’ PUCT-approved QF Tariff, which became effective in August 2010. The state and federal lawsuits and regulatory proceedings are in various stages of litigation, including a pending appeal by SPS in the Fifth Circuit Court of Appeals. SPS believes the likelihood of loss in these lawsuits and proceedings is remote based primarily on existing case law and while it is not possible to estimate the amount or range of reasonably possible loss in the event of an adverse outcome, SPS believes such loss would not be material based upon its belief that it would be permitted to recover such costs, if needed, through its various fuel clause mechanisms. No accrual has been recorded for this matter. | |||||||||||||||||||||||||
Pacific Northwest FERC Refund Proceeding — In July 2001, the FERC ordered a preliminary hearing to determine whether there were unjust and unreasonable charges for spot market bilateral sales in the Pacific Northwest for December 2000 through June 2001. PSCo supplied energy to the Pacific Northwest markets during this period and has been a participant in the hearings. In September 2001, the presiding ALJ concluded that prices in the Pacific Northwest during the referenced period were the result of a number of factors, including the shortage of supply, excess demand, drought and increased natural gas prices. Under these circumstances, the ALJ concluded that the prices in the Pacific Northwest markets were not unreasonable or unjust and no refunds should be ordered. Subsequent to the ruling, the FERC has allowed the parties to request additional evidence. Parties have claimed that the total amount of transactions with PSCo subject to refund is $34 million. In June 2003, the FERC issued an order terminating the proceeding without ordering further proceedings. Certain purchasers filed appeals of the FERC’s orders in this proceeding with the Ninth Circuit. | |||||||||||||||||||||||||
In an order issued in August 2007, the Ninth Circuit remanded the proceeding back to the FERC and indicated that the FERC should consider other rulings addressing overcharges in the California organized markets. The Ninth Circuit denied a petition for rehearing in April 2009, and the mandate was issued. | |||||||||||||||||||||||||
The FERC issued an order on remand establishing principles for the review proceeding in October 2011. In September 2012, the City of Seattle filed its direct case against PSCo and other Pacific Northwest sellers claiming refunds for the period January 2000 through June 2001. The City of Seattle indicated that for the period June 2000 through June 2001 PSCo had sales to the City of Seattle of approximately $50 million. The City of Seattle did not identify specific instances of unlawful market activity by PSCo, but rather based its claim for refunds on market dysfunction in the Western markets. PSCo submitted its answering case in December 2012. | |||||||||||||||||||||||||
In April 2013, the FERC issued an order on rehearing. The FERC confirmed that the City of Seattle would be able to attempt to obtain refunds back from January 2000, but reaffirmed the transaction-specific standard that the City of Seattle and other complainants would have to comply with to obtain refunds. In addition, the FERC rejected the imposition of any market-wide remedies. Although the FERC order on rehearing established the period for which the City of Seattle could seek refunds as January 2000 through June 2001, it is unclear what claim the City of Seattle has against PSCo prior to June 2000. In the proceeding, the City of Seattle does not allege specific misconduct or tariff violations by PSCo but instead asserts generally that the rates charged by PSCo and other sellers were excessive. | |||||||||||||||||||||||||
A hearing in this case was held before a FERC ALJ and concluded in October 2013. The matter is presently being briefed, and the ALJ is expected to issue an initial decision on or before March 18, 2014. | |||||||||||||||||||||||||
Preliminary calculations of the City of Seattle’s claim for refunds from PSCo are approximately $28 million excluding interest. PSCo has concluded that a loss is reasonably possible with respect to this matter; however, given the surrounding uncertainties, PSCo is currently unable to estimate the amount or range of reasonably possible loss in the event of an adverse outcome of this matter. In making this assessment, PSCo considered two factors. First, not withstanding PSCo’s view that the City of Seattle has failed to apply the standard that the FERC has established in this proceeding, and the recognition that this case raises a novel issue and the FERC’s standard has been challenged on appeal to the Ninth Circuit, the outcome of such an appeal cannot be predicted with any certainty. Second, PSCo would expect to make equitable arguments against refunds even if the City of Seattle were to establish that it was overcharged for transactions. If a loss were sustained, PSCo would attempt to recover those losses from other PRPs. No accrual has been recorded for this matter. | |||||||||||||||||||||||||
Fru-Con Construction Corporation (Fru-Con) vs. Utility Engineering Corporation (UE) et al. — In December 2001, a former wholly owned subsidiary of SPS and power plant design services company, UE, was engaged by the Sacramento Municipal Utility District (SMUD) to furnish design services for a natural gas-fired, combined-cycle power plant to be constructed by Fru-Con. In March 2005, Fru-Con commenced a lawsuit against UE and SMUD for damages allegedly suffered during the construction of the plant. In April 2005, Zachry Group (Zachry) purchased UE from Xcel Energy. As this lawsuit commenced prior to the sale of UE to Zachry, Xcel Energy agreed to indemnify Zachry for damages related to this case up to $17.5 million. In October 2013, the lawsuit was dismissed. Xcel Energy’s obligation to indemnify Zachry for damages related to the sale expired upon final resolution of this case, which brings this litigation to a close. | |||||||||||||||||||||||||
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 received the initial $100 million payment in August 2011, the second installment of $18.6 million in March 2012, the third installment of $20.7 million in October 2012, and the fourth installment of $42.6 million in November 2013. Amounts received from the installments were subsequently credited to customers, except for approved reductions such as legal costs, customer credits still in process at Dec. 31, 2013, and amounts set aside to be credited through another regulatory mechanism. | |||||||||||||||||||||||||
Other Contingencies | |||||||||||||||||||||||||
See Note 12 for further discussion. |
Nuclear_Obligations
Nuclear Obligations | 12 Months Ended | ||||||||||||
Dec. 31, 2013 | |||||||||||||
Nuclear Obligations [Abstract] | ' | ||||||||||||
Nuclear Obligations [Text Block] | ' | ||||||||||||
Nuclear Obligations | |||||||||||||
Fuel Disposal — NSP-Minnesota is responsible for temporarily storing used or spent nuclear fuel from its nuclear plants. The DOE is responsible for permanently storing spent fuel from NSP-Minnesota’s nuclear plants as well as from other U.S. nuclear plants. NSP-Minnesota has funded its portion of the DOE’s permanent disposal program since 1981. The fuel disposal fees are based on a charge of 0.1 cent per KWh sold to customers from nuclear generation. In January 2014, the DOE sent its court mandated proposal to adjust the current fee to zero. The Nuclear Waste Policy Act provides that a proposal by the Secretary of Energy to adjust the fee shall be effective after a period of 90 days of continuous session unless either House of Congress adopts a resolution disapproving the Secretary’s proposed adjustment. | |||||||||||||
Fuel expense includes the DOE fuel disposal assessments of approximately $10 million in 2013, $12 million in 2012 and $11 million in 2011. In total, NSP-Minnesota had paid approximately $444.8 million to the DOE through Dec. 31, 2013. See Note 13 — Nuclear Waste Disposal Litigation for further discussion. | |||||||||||||
NSP-Minnesota has its own temporary on-site storage facilities for spent fuel at its Monticello and Prairie Island nuclear plants, which consist of storage pools and dry cask facilities at both sites. The amount of spent fuel storage capacity currently authorized by the NRC and the MPUC will allow NSP-Minnesota to continue operation of its Prairie Island nuclear plant until the end of its renewed licenses terms in 2033 for Unit 1 and 2034 for Unit 2 and its Monticello nuclear plant until the end of its renewed operating license in 2030. Other alternatives for spent fuel storage are being investigated until a DOE facility is available, including pursuing the establishment of a private facility for interim storage of spent nuclear fuel as part of a consortium of electric utilities. | |||||||||||||
Regulatory Plant Decommissioning Recovery — Decommissioning of NSP-Minnesota’s nuclear facilities is planned for the period from cessation of operations through at least 2091, assuming the prompt dismantlement method. NSP-Minnesota is currently recording the costs for decommissioning over the MPUC-approved cost-recovery period. | |||||||||||||
Monticello received its initial operating license in 1970 and began commercial operation in 1971. With its renewed operating license and CON for spent fuel capacity to support 20 years of extended operation, Monticello can operate until 2030. The Monticello 20-year depreciation life extension until September 2030 was granted by the MPUC in 2007. The Monticello dry-cask storage facility currently stores 15 of the 30 canisters authorized by the MPUC. | |||||||||||||
Prairie Island Units 1 and 2 received their initial operating license and began commercial operations in 1973 and 1974. With its renewed operating license from the NRC, Prairie Island Units 1 and 2 can operate until 2033 and 2034, respectively. The MPUC approved depreciation life for Prairie Island is consistent with the remaining life of the NRC approved operating license. The Prairie Island dry-cask storage facility currently stores 35 of the 64 casks authorized by the MPUC. | |||||||||||||
NSP-Minnesota previously recorded annual decommissioning accruals based on periodic site-specific cost studies and a presumed level of dedicated funding consistent with cost-recovery in utility customer rates. Cost studies quantify decommissioning costs in current dollars. This study presumed that costs will escalate in the future at a rate of 3.63 percent per year during operations and radiological portion of decommissioning and 2.63 percent during the independent spent fuel storage installation and site restoration portion of decommissioning. The total estimated decommissioning costs that will ultimately be paid, net of income earned by the external decommissioning trust fund, is currently being accrued using an annuity approach over the approved plant-recovery period. This annuity approach uses an assumed rate of return on funding, which is an after-tax return between 4.57 percent and 5.53 percent, depending on production unit and time frame for external funding. The net unrealized gain or loss on nuclear decommissioning investments is deferred as a regulatory asset or liability. | |||||||||||||
The total obligation for decommissioning currently is expected to be funded 100 percent by the external decommissioning trust fund, as approved by the MPUC, when decommissioning commences. The external funds are held in trust and in escrow. The portion in escrow is subject to refund if approved by the various commissions. In November 2012, the MPUC approved NSP-Minnesota’s most recent nuclear decommissioning study which used 2011 cost data. The MPUC approved the use of a 60-year decommissioning scenario. This resulted in an approved annual accrual of $14.2 million for Minnesota retail customers, to be held in our external escrow fund. | |||||||||||||
As of Dec. 31, 2013, NSP-Minnesota has accumulated $1.6 billion of assets held in external decommissioning trusts. The following table summarizes the funded status of NSP-Minnesota’s decommissioning obligation based on approved regulatory recovery parameters from the most recently approved decommissioning study. Xcel Energy believes future decommissioning cost expense, if necessary, will continue to be recovered in customer rates. These amounts are not those recorded in the financial statements for the ARO. | |||||||||||||
Regulatory Basis | |||||||||||||
(Thousands of Dollars) | 2013 | 2012 | |||||||||||
Estimated decommissioning cost obligation from most recently approved study (2011 dollars) | $ | 2,694,079 | $ | 2,694,079 | |||||||||
Effect of escalating costs (to 2013 and 2012 dollars, respectively, at 3.63/2.63 percent) | 189,924 | 93,327 | |||||||||||
Estimated decommissioning cost obligation (in current dollars) | 2,884,003 | 2,787,406 | |||||||||||
Effect of escalating costs to payment date (3.63/2.63 percent) | 5,697,285 | 5,793,882 | |||||||||||
Estimated future decommissioning costs (undiscounted) | 8,581,288 | 8,581,288 | |||||||||||
Effect of discounting obligation (using risk-free interest rate) | (6,215,050 | ) | (6,243,332 | ) | |||||||||
Discounted decommissioning cost obligation | $ | 2,366,238 | $ | 2,337,956 | |||||||||
Assets held in external decommissioning trust | $ | 1,627,026 | $ | 1,489,542 | |||||||||
Underfunding of external decommissioning fund compared to the discounted decommissioning obligation | 739,212 | 848,414 | |||||||||||
Decommissioning expenses recognized as a result of regulation include the following components: | |||||||||||||
(Thousands of Dollars) | 2013 | 2012 | 2011 | ||||||||||
Annual decommissioning recorded as depreciation expense: (a) | |||||||||||||
Externally funded | $ | 6,402 | $ | — | $ | — | |||||||
Internally funded (including interest costs) | — | (1,251 | ) | (456 | ) | ||||||||
Net decommissioning expense recorded | $ | 6,402 | $ | (1,251 | ) | $ | (456 | ) | |||||
(a) | Decommissioning expense does not include depreciation of the capitalized nuclear asset retirement costs. | ||||||||||||
Reductions to expense for internally-funded portions in 2012 and 2011 are a direct result of the 2008 decommissioning study jurisdictional allocation and 100 percent external funding approval, effectively unwinding the remaining internal fund over the previously licensed operating life of the unit (2010 for Monticello, 2013 for Prairie Island Unit 1 and 2014 for Prairie Island Unit 2). Due to the immaterial amount remaining in the internal fund, the entire remaining amount was unwound for Prairie Island 1 and 2 in 2012. As of December 2013, there is no balance remaining in the internally funded decommissioning account. The 2011 nuclear decommissioning filing approved in 2012 has been used for the regulatory presentation. |
Regulatory_Assets_and_Liabilit
Regulatory Assets and Liabilities | 12 Months Ended | |||||||||||||||||||||
Dec. 31, 2013 | ||||||||||||||||||||||
Regulatory Assets and Liabilities Disclosure [Abstract] | ' | |||||||||||||||||||||
Regulatory Assets and Liabilities | ' | |||||||||||||||||||||
Regulatory Assets and Liabilities | ||||||||||||||||||||||
Xcel Energy Inc. and subsidiaries prepare their consolidated financial statements in accordance with the applicable accounting guidance, as discussed in Note 1. Under this guidance, regulatory assets and liabilities are created for amounts that regulators may allow to be collected, or may require to be paid back to customers in future electric and natural gas rates. Any portion of Xcel Energy’s business that is not regulated cannot establish regulatory assets and liabilities. If changes in the utility industry or the business of Xcel Energy no longer allow for the application of regulatory accounting guidance under GAAP, Xcel Energy would be required to recognize the write-off of regulatory assets and liabilities in net income or OCI. | ||||||||||||||||||||||
The components of regulatory assets shown on the consolidated balance sheets at Dec. 31, 2013 and 2012 are: | ||||||||||||||||||||||
(Thousands of Dollars) | See Note(s) | Remaining | Dec. 31, 2013 | Dec. 31, 2012 | ||||||||||||||||||
Amortization Period | ||||||||||||||||||||||
Regulatory Assets | Current | Noncurrent | Current | Noncurrent | ||||||||||||||||||
Pension and retiree medical obligations (a) | 9 | Various | $ | 118,179 | $ | 1,192,808 | $ | 100,713 | $ | 1,552,375 | ||||||||||||
Recoverable deferred taxes on AFUDC recorded in plant | 1 | Plant lives | — | 359,215 | — | 321,680 | ||||||||||||||||
Contract valuation adjustments (b) | 1, 11 | Term of related contract | 3,620 | 153,393 | 3,775 | 147,755 | ||||||||||||||||
Net AROs (c) | 1, 13, 14 | Plant lives | — | 160,544 | — | 178,146 | ||||||||||||||||
Conservation programs (d) | 1 | One to six years | 55,088 | 63,275 | 60,956 | 84,146 | ||||||||||||||||
Environmental remediation costs | 1, 13 | Various | 4,735 | 119,175 | 3,986 | 109,377 | ||||||||||||||||
Renewable resources and environmental initiatives | 13 | One to four years | 46,076 | 37,858 | 59,518 | 38,138 | ||||||||||||||||
Depreciation differences | 1 | One to seventeen years | 10,918 | 95,844 | 5,274 | 50,057 | ||||||||||||||||
Purchased power contract costs | 13 | Term of related contract | — | 68,182 | — | 63,134 | ||||||||||||||||
Losses on reacquired debt | 4 | Term of related debt | 5,525 | 36,534 | 5,917 | 42,060 | ||||||||||||||||
Nuclear refueling outage costs | 1 | One to two years | 86,333 | 36,477 | 56,035 | 22,647 | ||||||||||||||||
Gas pipeline inspection and remediation costs | 12 | Various | 5,416 | 33,884 | 5,416 | 27,560 | ||||||||||||||||
Recoverable purchased natural gas and electric energy costs | 1 | One to two years | 42,288 | 15,495 | 32,098 | 8,340 | ||||||||||||||||
Sherco Unit 3 deferral | Twenty-one years | 503 | 10,063 | — | — | |||||||||||||||||
State commission adjustments | 1 | Plant lives | 444 | 14,204 | 374 | 12,181 | ||||||||||||||||
Prairie Island EPU (e) | 12 | Pending rate cases | — | 69,668 | — | 67,590 | ||||||||||||||||
Property tax | Three years | 18,427 | 30,626 | 6,005 | 12,010 | |||||||||||||||||
Other | Various | 20,249 | 11,973 | 12,910 | 24,833 | |||||||||||||||||
Total regulatory assets | $ | 417,801 | $ | 2,509,218 | $ | 352,977 | $ | 2,762,029 | ||||||||||||||
(a) | Includes $303.3 million and $330.3 million for the regulatory recognition of the NSP-Minnesota pension expense of which $23.2 million and $24.3 million is included in the current asset at Dec. 31, 2013 and 2012, respectively. Also included are $17.7 million and $21.5 million of regulatory assets related to the nonqualified pension plan of which $2.2 million is included in the current asset at Dec. 31, 2013 and 2012, respectively. | |||||||||||||||||||||
(b) | Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases. | |||||||||||||||||||||
(c) | Includes amounts recorded for future recovery of AROs, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments. | |||||||||||||||||||||
(d) | Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions. | |||||||||||||||||||||
(e) | For the canceled Prairie Island EPU project, NSP-Minnesota plans to address recovery of incurred costs in the pending multi-year rate case. | |||||||||||||||||||||
The components of regulatory liabilities shown on the consolidated balance sheets at Dec. 31, 2013 and 2012 are: | ||||||||||||||||||||||
(Thousands of Dollars) | See Note(s) | Remaining | Dec. 31, 2013 | Dec. 31, 2012 | ||||||||||||||||||
Amortization Period | ||||||||||||||||||||||
Regulatory Liabilities | Current | Noncurrent | Current | Noncurrent | ||||||||||||||||||
Plant removal costs | 1, 13 | Plant lives | $ | — | $ | 906,403 | $ | — | $ | 922,963 | ||||||||||||
Deferred electric and steam production and natural gas costs | 1 | Less than one year | 96,574 | — | 90,454 | — | ||||||||||||||||
DOE settlement | 12 | One to two years | 44,208 | 1,131 | 22,700 | 1,131 | ||||||||||||||||
Investment tax credit deferrals | 1, 6 | Various | — | 56,535 | — | 59,052 | ||||||||||||||||
Deferred income tax adjustment | 1, 6 | Various | — | 43,581 | — | 44,667 | ||||||||||||||||
Conservation programs (b) | 1, 12 | Less than one year | 19,531 | — | 6,292 | — | ||||||||||||||||
Contract valuation adjustments (a) | 1, 11 | Term of related contract | 54,455 | 6,849 | 29,431 | 11,159 | ||||||||||||||||
Gain from asset sales | 12 | One to three years | 12,859 | 4,568 | 7,318 | 10,311 | ||||||||||||||||
Renewable resources and environmental initiatives | 12, 13 | Various | 2,499 | 1,412 | 256 | 1,412 | ||||||||||||||||
Low income discount program | Less than one year | 6,229 | — | 6,164 | — | |||||||||||||||||
PSCo earnings test | 12 | One to two years | 22,891 | 19,203 | 1,732 | 1,732 | ||||||||||||||||
Other | Various | 15,523 | 19,713 | 4,511 | 7,512 | |||||||||||||||||
Total regulatory liabilities | $ | 274,769 | $ | 1,059,395 | $ | 168,858 | $ | 1,059,939 | ||||||||||||||
(a) | Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases. | |||||||||||||||||||||
(b) | Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions. | |||||||||||||||||||||
At Dec. 31, 2013 and 2012, approximately $306 million and $275 million of Xcel Energy’s regulatory assets represented past expenditures not currently earning a return, respectively. This amount primarily includes Prairie Island EPU costs, recoverable purchased natural gas and electric energy costs and certain expenditures associated with renewable resources and environmental initiatives. |
Other_Comprehensive_Income
Other Comprehensive Income | 12 Months Ended | ||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||
Stockholders' Equity Note [Abstract] | ' | ||||||||||||||||
Other Comprehensive Income | ' | ||||||||||||||||
Other Comprehensive Income | |||||||||||||||||
Changes in accumulated other comprehensive loss, net of tax, for the year ended Dec. 31, 2013 were as follows: | |||||||||||||||||
(Thousands of Dollars) | Gains and | Unrealized | Defined Benefit | Total | |||||||||||||
Losses on Cash Flow Hedges | Gains and Losses | Pension and | |||||||||||||||
on Marketable | Postretirement | ||||||||||||||||
Securities | Items | ||||||||||||||||
Accumulated other comprehensive loss at Jan. 1 | $ | (61,241 | ) | $ | (99 | ) | $ | (51,313 | ) | $ | (112,653 | ) | |||||
Other comprehensive gain before reclassifications | 12 | 176 | 1,408 | 1,596 | |||||||||||||
Losses reclassified from net accumulated other comprehensive loss | 1,476 | — | 3,306 | 4,782 | |||||||||||||
Net current period OCI | 1,488 | 176 | 4,714 | 6,378 | |||||||||||||
Accumulated other comprehensive gain (loss) at Dec. 31 | $ | (59,753 | ) | $ | 77 | $ | (46,599 | ) | $ | (106,275 | ) | ||||||
Reclassifications from accumulated other comprehensive loss for the year ended Dec. 31, 2013 were as follows: | |||||||||||||||||
(Thousands of Dollars) | Amounts Reclassified from Accumulated Other Comprehensive Loss | ||||||||||||||||
(Gains) losses on cash flow hedges: | |||||||||||||||||
Interest rate derivatives | $ | 4,107 | (a) | ||||||||||||||
Vehicle fuel derivatives | (90 | ) | (b) | ||||||||||||||
Total, pre-tax | 4,017 | ||||||||||||||||
Tax benefit | (2,541 | ) | |||||||||||||||
Total, net of tax | 1,476 | ||||||||||||||||
Defined benefit pension and postretirement losses: | |||||||||||||||||
Amortization of net loss | 7,077 | (c) | |||||||||||||||
Prior service cost | 372 | (c) | |||||||||||||||
Transition obligation | 8 | (c) | |||||||||||||||
Total, pre-tax | 7,457 | ||||||||||||||||
Tax benefit | (4,151 | ) | |||||||||||||||
Total, net of tax | 3,306 | ||||||||||||||||
Total amounts reclassified, net of tax | $ | 4,782 | |||||||||||||||
(a) | Included in interest charges. | ||||||||||||||||
(b) | Included in O&M expenses. | ||||||||||||||||
(c) | Included in the computation of net periodic pension and post retirement benefit costs. See Note 9 for details regarding these benefit plans. |
Segments_and_Related_Informati
Segments and Related Information | 12 Months Ended | ||||||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||||||
Segment Reporting [Abstract] | ' | ||||||||||||||||||||
Segment Information | ' | ||||||||||||||||||||
Segments and Related Information | |||||||||||||||||||||
The regulated electric utility operating results of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS, as well as the regulated natural gas utility operating results of NSP-Minnesota, NSP-Wisconsin and PSCo are each separately and regularly reviewed by Xcel Energy’s chief operating decision maker. Xcel Energy evaluates performance by each utility subsidiary based on profit or loss generated from the product or service provided. These segments are managed separately because the revenue streams are dependent upon regulated rate recovery, which is separately determined for each segment. | |||||||||||||||||||||
Xcel Energy has the following reportable segments: regulated electric utility, regulated natural gas utility and all other. | |||||||||||||||||||||
• | Xcel Energy’s regulated electric utility segment generates, transmits and distributes electricity in Minnesota, Wisconsin, Michigan, North Dakota, South Dakota, Colorado, Texas and New Mexico. In addition, this segment includes sales for resale and provides wholesale transmission service to various entities in the United States. Regulated electric utility also includes commodity trading operations. | ||||||||||||||||||||
• | Xcel Energy’s regulated natural gas utility segment transports, stores and distributes natural gas primarily in portions of Minnesota, Wisconsin, North Dakota, Michigan and Colorado. | ||||||||||||||||||||
• | Revenues from operating segments not included above are below the necessary quantitative thresholds and are therefore included in the all other category. Those primarily include steam revenue, appliance repair services, nonutility real estate activities, revenues associated with processing solid waste into refuse-derived fuel and investments in rental housing projects that qualify for low-income housing tax credits. | ||||||||||||||||||||
Xcel Energy had equity investments in unconsolidated subsidiaries of $87.1 million and $91.2 million as of Dec. 31, 2013 and 2012, respectively, included in the regulated natural gas utility segment. | |||||||||||||||||||||
Asset and capital expenditure information is not provided for Xcel Energy’s reportable segments because as an integrated electric and natural gas utility, Xcel Energy operates significant assets that are not dedicated to a specific business segment, and reporting assets and capital expenditures by business segment would require arbitrary and potentially misleading allocations which may not necessarily reflect the assets that would be required for the operation of the business segments on a stand-alone basis. | |||||||||||||||||||||
To report income from 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. | |||||||||||||||||||||
The accounting policies of the segments are the same as those described in Note 1. | |||||||||||||||||||||
(Thousands of Dollars) | Regulated | Regulated | All Other | Reconciling | Consolidated | ||||||||||||||||
Electric | Natural Gas | Eliminations | Total | ||||||||||||||||||
2013 | |||||||||||||||||||||
Operating revenues from external customers | $ | 9,034,045 | $ | 1,804,679 | $ | 76,198 | $ | — | $ | 10,914,922 | |||||||||||
Intersegment revenues | 1,332 | 2,717 | — | (4,049 | ) | — | |||||||||||||||
Total revenues | $ | 9,035,377 | $ | 1,807,396 | $ | 76,198 | $ | (4,049 | ) | $ | 10,914,922 | ||||||||||
Depreciation and amortization | $ | 840,833 | $ | 128,186 | $ | 8,844 | $ | — | $ | 977,863 | |||||||||||
Interest charges and financing costs | 386,198 | 44,927 | 104,895 | — | 536,020 | ||||||||||||||||
Income tax expense (benefit) | 495,044 | 25,543 | (36,611 | ) | — | 483,976 | |||||||||||||||
Net income (loss) | 850,572 | 123,702 | (26,040 | ) | — | 948,234 | |||||||||||||||
(Thousands of Dollars) | Regulated | Regulated | All Other | Reconciling | Consolidated | ||||||||||||||||
Electric | Natural Gas | Eliminations | Total | ||||||||||||||||||
2012 | |||||||||||||||||||||
Operating revenues from external customers | $ | 8,517,296 | $ | 1,537,374 | $ | 73,553 | $ | — | $ | 10,128,223 | |||||||||||
Intersegment revenues | 1,169 | 1,425 | — | (2,594 | ) | — | |||||||||||||||
Total revenues | $ | 8,518,465 | $ | 1,538,799 | $ | 73,553 | $ | (2,594 | ) | $ | 10,128,223 | ||||||||||
Depreciation and amortization | $ | 801,649 | $ | 115,038 | $ | 9,366 | $ | — | $ | 926,053 | |||||||||||
Interest charges and financing costs | 397,457 | 49,456 | 119,324 | — | 566,237 | ||||||||||||||||
Income tax expense (benefit) | 465,626 | 50,322 | (65,745 | ) | — | 450,203 | |||||||||||||||
Net income (loss) | 851,929 | 98,061 | (44,761 | ) | — | 905,229 | |||||||||||||||
(Thousands of Dollars) | Regulated | Regulated | All Other | Reconciling | Consolidated | ||||||||||||||||
Electric | Natural Gas | Eliminations | Total | ||||||||||||||||||
2011 | |||||||||||||||||||||
Operating revenues from external customers | $ | 8,766,593 | $ | 1,811,926 | $ | 76,251 | $ | — | $ | 10,654,770 | |||||||||||
Intersegment revenues | 1,269 | 2,358 | — | (3,627 | ) | — | |||||||||||||||
Total revenues | $ | 8,767,862 | $ | 1,814,284 | $ | 76,251 | $ | (3,627 | ) | $ | 10,654,770 | ||||||||||
Depreciation and amortization | $ | 773,392 | $ | 106,870 | $ | 10,357 | $ | — | $ | 890,619 | |||||||||||
Interest charges and financing costs | 402,668 | 52,115 | 108,336 | — | 563,119 | ||||||||||||||||
Income tax expense (benefit) | 473,848 | 57,408 | (62,940 | ) | — | 468,316 | |||||||||||||||
Net income (loss) | 788,967 | 101,842 | (49,637 | ) | — | 841,172 | |||||||||||||||
Summarized_Quarterly_Financial
Summarized Quarterly Financial Data (Unaudited) | 12 Months Ended | ||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||
Quarterly Financial Information Disclosure [Abstract] | ' | ||||||||||||||||
Summarized Quarterly Financial Data (Unaudited) | ' | ||||||||||||||||
Summarized Quarterly Financial Data (Unaudited) | |||||||||||||||||
Quarter Ended | |||||||||||||||||
(Amounts in thousands, except per share data) | 31-Mar-13 | 30-Jun-13 | Sept. 30, 2013 | Dec. 31, 2013 | |||||||||||||
Operating revenues | $ | 2,782,849 | $ | 2,578,913 | $ | 2,822,338 | $ | 2,730,822 | |||||||||
Operating income | 454,624 | 402,236 | 665,113 | 325,582 | |||||||||||||
Net income | 236,570 | 196,857 | 364,752 | 150,055 | |||||||||||||
Earnings per share total — basic | $ | 0.48 | $ | 0.4 | $ | 0.73 | $ | 0.3 | |||||||||
Earnings per share total — diluted | 0.48 | 0.4 | 0.73 | 0.3 | |||||||||||||
Cash dividends declared per common share | 0.27 | 0.28 | 0.28 | 0.28 | |||||||||||||
Quarter Ended | |||||||||||||||||
(Amounts in thousands, except per share data) | 31-Mar-12 | 30-Jun-12 | Sept. 30, 2012 | Dec. 31, 2012 | |||||||||||||
Operating revenues | $ | 2,578,079 | $ | 2,274,668 | $ | 2,724,341 | $ | 2,551,135 | |||||||||
Operating income | 380,162 | 405,690 | 720,434 | 316,397 | |||||||||||||
Net income | 183,893 | 183,060 | 398,106 | 140,170 | |||||||||||||
Earnings per share total — basic | $ | 0.38 | $ | 0.38 | $ | 0.82 | $ | 0.29 | |||||||||
Earnings per share total — diluted | 0.38 | 0.38 | 0.81 | 0.29 | |||||||||||||
Cash dividends declared per common share | 0.26 | 0.27 | 0.27 | 0.27 | |||||||||||||
Schedule_I_Condensed_Financial
Schedule I, Condensed Financial Statements of Xcel Energy Inc | 12 Months Ended | ||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||
Condensed Financial Information of Parent Company Only Disclosure [Abstract] | ' | ||||||||||||||||
Schedule I, Condensed Financial Statements of Xcel Energy Inc. | ' | ||||||||||||||||
XCEL ENERGY INC. | |||||||||||||||||
CONDENSED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | |||||||||||||||||
(amounts in thousands, except per share data) | |||||||||||||||||
Year Ended Dec. 31 | |||||||||||||||||
2013 | 2012 | 2011 | |||||||||||||||
Income | |||||||||||||||||
Equity earnings of subsidiaries | $ | 1,018,783 | $ | 976,395 | $ | 904,315 | |||||||||||
Total income | 1,018,783 | 976,395 | 904,315 | ||||||||||||||
Expenses and other deductions | |||||||||||||||||
Operating expenses | 18,513 | 15,948 | 14,513 | ||||||||||||||
Other income | (206 | ) | (652 | ) | (760 | ) | |||||||||||
Interest charges and financing costs | 102,914 | 116,731 | 104,499 | ||||||||||||||
Total expenses and other deductions | 121,221 | 132,027 | 118,252 | ||||||||||||||
Income before income taxes | 897,562 | 844,368 | 786,063 | ||||||||||||||
Income tax benefit | (50,672 | ) | (60,861 | ) | (55,109 | ) | |||||||||||
Net income | 948,234 | 905,229 | 841,172 | ||||||||||||||
Dividend requirements on preferred stock | — | — | 3,534 | ||||||||||||||
Premium on redemption of preferred stock | — | — | 3,260 | ||||||||||||||
Earnings available to common shareholders | $ | 948,234 | $ | 905,229 | $ | 834,378 | |||||||||||
Other Comprehensive Income | |||||||||||||||||
Pension and retiree medical benefits, net of tax of $5,897, $(2,331) and $(2,247), respectively | 4,714 | (3,311 | ) | (3,205 | ) | ||||||||||||
Derivative instruments, net of tax of $2,558, $(9,906) and $(24,488), respectively | 1,488 | (15,503 | ) | (37,644 | ) | ||||||||||||
Other, net of tax of $117, $135 and $(63), respectively | 176 | 196 | (93 | ) | |||||||||||||
Other comprehensive income (loss) | 6,378 | (18,618 | ) | (40,942 | ) | ||||||||||||
Comprehensive income | $ | 954,612 | $ | 886,611 | $ | 793,436 | |||||||||||
Weighted average common shares outstanding: | |||||||||||||||||
Basic | 496,073 | 487,899 | 485,039 | ||||||||||||||
Diluted | 496,532 | 488,434 | 485,615 | ||||||||||||||
Earnings per average common share: | |||||||||||||||||
Basic | $ | 1.91 | $ | 1.86 | $ | 1.72 | |||||||||||
Diluted | 1.91 | 1.85 | 1.72 | ||||||||||||||
Cash dividends declared per common share | 1.11 | 1.07 | 1.03 | ||||||||||||||
See Notes to Condensed Financial Statements | |||||||||||||||||
XCEL ENERGY INC. | |||||||||||||||||
CONDENSED STATEMENTS OF CASH FLOWS | |||||||||||||||||
(amounts in thousands) | |||||||||||||||||
Year Ended Dec. 31 | |||||||||||||||||
2013 | 2012 | 2011 | |||||||||||||||
Operating activities | |||||||||||||||||
Net cash provided by operating activities | $ | 545,177 | $ | 815,209 | $ | 595,732 | |||||||||||
Investing activities | |||||||||||||||||
Capital contributions to subsidiaries | (535,653 | ) | (366,783 | ) | (287,495 | ) | |||||||||||
Investments in the utility money pool | (1,778,000 | ) | (640,000 | ) | — | ||||||||||||
Return of investments in the utility money pool | 1,706,000 | 658,000 | — | ||||||||||||||
Net cash used in investing activities | (607,653 | ) | (348,783 | ) | (287,495 | ) | |||||||||||
Financing activities | |||||||||||||||||
Proceeds from (repayment of) short-term borrowings, net | 297,000 | 52,000 | (21,000 | ) | |||||||||||||
Proceeds from issuance of long-term debt | 447,595 | — | 246,877 | ||||||||||||||
Repayment of long-term debt | (400,000 | ) | — | — | |||||||||||||
Proceeds from issuance of common stock | 231,767 | 8,050 | 38,691 | ||||||||||||||
Repurchase of common stock | — | (18,529 | ) | — | |||||||||||||
Purchase of common stock for settlement of equity awards | — | (23,307 | ) | — | |||||||||||||
Redemption of preferred stock | — | — | (104,980 | ) | |||||||||||||
Dividends paid | (514,042 | ) | (486,757 | ) | (474,760 | ) | |||||||||||
Net cash provided by (used in) financing activities | 62,320 | (468,543 | ) | (315,172 | ) | ||||||||||||
Net change in cash and cash equivalents | (156 | ) | (2,117 | ) | (6,935 | ) | |||||||||||
Cash and cash equivalents at beginning of period | 602 | 2,719 | 9,654 | ||||||||||||||
Cash and cash equivalents at end of period | $ | 446 | $ | 602 | $ | 2,719 | |||||||||||
See Notes to Condensed Financial Statements | |||||||||||||||||
XCEL ENERGY INC. | |||||||||||||||||
CONDENSED BALANCE SHEETS | |||||||||||||||||
(amounts in thousands) | |||||||||||||||||
Dec. 31 | |||||||||||||||||
2013 | 2012 | ||||||||||||||||
Assets | |||||||||||||||||
Cash and cash equivalents | $ | 446 | $ | 602 | |||||||||||||
Accounts receivable from subsidiaries | 240,450 | 195,438 | |||||||||||||||
Other current assets | 51,086 | 11,497 | |||||||||||||||
Total current assets | 291,982 | 207,537 | |||||||||||||||
Investment in subsidiaries | 11,613,032 | 10,643,694 | |||||||||||||||
Other assets | 105,073 | 143,760 | |||||||||||||||
Total other assets | 11,718,105 | 10,787,454 | |||||||||||||||
Total assets | $ | 12,010,087 | $ | 10,994,991 | |||||||||||||
Liabilities and Equity | |||||||||||||||||
Dividends payable | $ | 139,432 | $ | 131,748 | |||||||||||||
Short-term debt | 476,000 | 179,000 | |||||||||||||||
Other current liabilities | 6,954 | 31,032 | |||||||||||||||
Total current liabilities | 622,386 | 341,780 | |||||||||||||||
Other liabilities | 25,475 | 34,360 | |||||||||||||||
Total other liabilities | 25,475 | 34,360 | |||||||||||||||
Commitments and contingencies | |||||||||||||||||
Capitalization | |||||||||||||||||
Long-term debt | 1,796,276 | 1,744,774 | |||||||||||||||
Common stockholders’ equity | 9,565,950 | 8,874,077 | |||||||||||||||
Total capitalization | 11,362,226 | 10,618,851 | |||||||||||||||
Total liabilities and equity | $ | 12,010,087 | $ | 10,994,991 | |||||||||||||
See Notes to Condensed Financial Statements | |||||||||||||||||
NOTES TO CONDENSED FINANCIAL STATEMENTS | |||||||||||||||||
Incorporated by reference are Xcel Energy’s consolidated statements of common stockholders’ equity and OCI in Part II, Item 8. | |||||||||||||||||
Basis of Presentation — The condensed financial information of Xcel Energy Inc. is presented to comply with Rule 12-04 of Regulation S-X. Xcel Energy Inc.’s investments in subsidiaries are presented under the equity method of accounting. Under this method, the assets and liabilities of subsidiaries are not consolidated. The investments in net assets of the subsidiaries are recorded in the balance sheets. The income from operations of the subsidiaries is reported on a net basis as equity in income of subsidiaries. | |||||||||||||||||
As a holding company with no business operations, Xcel Energy Inc.’s assets consist primarily of investments in its utility subsidiaries. Xcel Energy Inc.’s material cash inflows are only from dividends and other payments received from its utility subsidiaries and the proceeds raised from the sale of debt and equity securities. The ability of its utility subsidiaries to make dividend and other payments is subject to the availability of funds after taking into account their respective funding requirements, the terms of their respective indebtedness, the regulations of the FERC under the Federal Power Act, and applicable state laws. Management does not expect maintaining these requirements to have an impact on Xcel Energy Inc.’s ability to pay dividends at the current level in the foreseeable future. Each of its utility subsidiaries, however, is legally distinct and has no obligation, contingent or otherwise, to make funds available to Xcel Energy Inc. | |||||||||||||||||
Related Party Transactions — Xcel Energy Inc. presents its related party receivables net of payables. Accounts receivable and payable with affiliates at Dec. 31 were: | |||||||||||||||||
2013 | 2012 | ||||||||||||||||
(Thousands of Dollars) | Accounts Receivable | Accounts Payable | Accounts Receivable | Accounts Payable | |||||||||||||
NSP-Minnesota | $ | 57,596 | $ | — | $ | 63,682 | $ | — | |||||||||
NSP-Wisconsin | 6,933 | — | 7,631 | — | |||||||||||||
PSCo | 74,739 | — | — | (3,362 | ) | ||||||||||||
SPS | 5,705 | — | 15,806 | — | |||||||||||||
Xcel Energy Services Inc. | 60,138 | — | 61,217 | — | |||||||||||||
Xcel Energy Ventures Inc. | 20,194 | — | 20,427 | — | |||||||||||||
Other subsidiaries of Xcel Energy Inc. | 15,145 | — | 30,037 | — | |||||||||||||
$ | 240,450 | $ | — | $ | 198,800 | $ | (3,362 | ) | |||||||||
Dividends — Cash dividends paid to Xcel Energy Inc. by its subsidiaries were $606 million, $757 million and $626 million for the years ended Dec. 31, 2013, 2012 and 2011, respectively. | |||||||||||||||||
Money Pool — Xcel Energy received FERC approval to establish a utility money pool arrangement with the utility subsidiaries, subject to receipt of required state regulatory approvals. The utility money pool allows for short-term investments in and borrowings between the utility subsidiaries. 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 following tables present money pool lending for Xcel Energy Inc.: | |||||||||||||||||
(Amounts in Millions, Except Interest Rates) | Three Months Ended Dec. 31, 2013 | ||||||||||||||||
Lending limit | $ | 250 | |||||||||||||||
Loan outstanding at period end | 72 | ||||||||||||||||
Average loan outstanding | 109.8 | ||||||||||||||||
Maximum loan outstanding | 182 | ||||||||||||||||
Weighted average interest rate, computed on a daily basis | 0.31 | % | |||||||||||||||
Weighted average interest rate at end of period | 0.25 | ||||||||||||||||
Money pool interest income | $ | 0.1 | |||||||||||||||
(Amounts in Millions, Except Interest Rates) | Twelve Months Ended Dec. 31, 2013 | Twelve Months Ended Dec. 31, 2012 | Twelve Months Ended Dec. 31, 2011 | ||||||||||||||
Lending limit | $ | 250 | $ | 250 | $ | 250 | |||||||||||
Loan outstanding at period end | 72 | — | 18 | ||||||||||||||
Average loan outstanding | 88.2 | 26.1 | 0.4 | ||||||||||||||
Maximum loan outstanding | 243 | 226 | 43 | ||||||||||||||
Weighted average interest rate, computed on a daily basis | 0.3 | % | 0.33 | % | 0.35 | % | |||||||||||
Weighted average interest rate at end of period | 0.25 | N/A | 0.35 | ||||||||||||||
Money pool interest income | $ | 0.3 | $ | 0.1 | $ | — | |||||||||||
See Xcel Energy’s notes to the consolidated financial statements in Part II, Item 8 for other disclosures. |
Schedule_II_Valuation_and_Qual
Schedule II, Valuation and Qualifying Accounts | 12 Months Ended | |||||||||||||||||||
Dec. 31, 2013 | ||||||||||||||||||||
Valuation and Qualifying Accounts [Abstract] | ' | |||||||||||||||||||
Schedule II, Valuation and Qualifying Accounts | ' | |||||||||||||||||||
XCEL ENERGY INC. AND SUBSIDIARIES | ||||||||||||||||||||
VALUATION AND QUALIFYING ACCOUNTS | ||||||||||||||||||||
YEARS ENDED DEC. 31, 2013, 2012 AND 2011 | ||||||||||||||||||||
(amounts in thousands) | ||||||||||||||||||||
Additions | ||||||||||||||||||||
Balance at | Charged to | Charged to | Deductions from | Balance at | ||||||||||||||||
Jan. 1 | Costs and | Other | Reserves(b)(c) | Dec. 31 | ||||||||||||||||
Expenses | Accounts(a) | |||||||||||||||||||
Allowance for bad debts: | ||||||||||||||||||||
2013 | $ | 51,394 | $ | 37,627 | $ | 14,469 | $ | 50,383 | $ | 53,107 | ||||||||||
2012 | 58,565 | 33,808 | 16,033 | 57,012 | 51,394 | |||||||||||||||
2011 | 54,563 | 44,521 | 15,636 | 56,155 | 58,565 | |||||||||||||||
NOL and tax credit valuation allowances: | ||||||||||||||||||||
2013 | $ | 3,314 | $ | — | $ | — | $ | 51 | $ | 3,263 | ||||||||||
2012 | 5,683 | 32 | — | 2,401 | 3,314 | |||||||||||||||
2011 | 1,927 | 4,379 | — | 623 | 5,683 | |||||||||||||||
(a) | Recovery of amounts previously written off as related to allowance for bad debts. | |||||||||||||||||||
(b) | Principally bad debts written off as related to allowance for bad debts. | |||||||||||||||||||
(c) | Reductions to valuation allowances for NOL and tax credit carryforwards primarily due to changes in tax laws, expirations of certain carryforwards and identification of various tax planning strategies. |
Summary_of_Significant_Account1
Summary of Significant Accounting Policies Summary of Significant Accounting Policies (Policies) | 12 Months Ended | |
Dec. 31, 2013 | ||
Accounting Policies [Abstract] | ' | |
Business and System of Accounts | ' | |
Business and System of Accounts — Xcel Energy Inc.’s utility subsidiaries are principally engaged in the regulated generation, purchase, transmission, distribution and sale of electricity and in the regulated purchase, transportation, distribution and sale of natural gas. Xcel Energy’s consolidated financial statements and disclosures are presented in accordance with GAAP. All of the utility subsidiaries’ underlying accounting records also conform to the FERC uniform system of accounts or to systems required by various state regulatory commissions, which are the same in all material respects. | ||
Principles of Consolidation | ' | |
Principles of Consolidation — In 2013, Xcel Energy’s operations included the activity of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS. These utility subsidiaries serve electric and natural gas customers in portions of Colorado, Michigan, Minnesota, New Mexico, North Dakota, South Dakota, Texas and Wisconsin. Also included in Xcel Energy’s operations are WGI, an interstate natural gas pipeline company, and WYCO, a joint venture with CIG to develop and lease natural gas pipelines, storage and compression facilities. | ||
Xcel Energy Inc.’s nonregulated subsidiary is Eloigne, which invests in rental housing projects that qualify for low-income housing tax credits. Xcel Energy Inc. owns the following additional direct subsidiaries, some of which are intermediate holding companies with additional subsidiaries: Xcel Energy Wholesale Group Inc., Xcel Energy Markets Holdings Inc., Xcel Energy Ventures Inc., Xcel Energy Retail Holdings Inc., Xcel Energy Communications Group, Inc., Xcel Energy International Inc., and Xcel Energy Services Inc. Xcel Energy Inc. and its subsidiaries collectively are referred to as Xcel Energy. | ||
Xcel Energy’s consolidated financial statements include its wholly-owned subsidiaries and variable interest entities for which it is the primary beneficiary. In the consolidation process, all intercompany transactions and balances are eliminated. Xcel Energy uses the equity method of accounting for its investment in WYCO. Xcel Energy’s equity earnings in WYCO are included on the consolidated statements of income as equity earnings of unconsolidated subsidiaries. Xcel Energy has investments in several plants and transmission facilities jointly owned with nonaffiliated utilities. Xcel Energy’s proportionate share of jointly owned facilities is recorded as property, plant and equipment on the consolidated balance sheets, and Xcel Energy’s proportionate share of the operating costs associated with these facilities is included in its consolidated statements of income. See Note 5 for further discussion of jointly owned generation, transmission, and gas facilities and related ownership percentages. | ||
Xcel Energy evaluates its arrangements and contracts with other entities, including but not limited to, investments, PPAs and fuel contracts to determine if the other party is a variable interest entity, if Xcel Energy has a variable interest and if Xcel Energy is the primary beneficiary. Xcel Energy follows accounting guidance for variable interest entities which requires consideration of the activities that most significantly impact an entity’s financial performance and power to direct those activities, when determining whether Xcel Energy is a variable interest entity’s primary beneficiary. See Note 13 for further discussion of variable interest entities. | ||
Use of Estimates | ' | |
Use of Estimates — In recording transactions and balances resulting from business operations, Xcel Energy uses estimates based on the best information available. Estimates are used for such items as plant depreciable lives, AROs, regulatory assets and liabilities, tax provisions, uncollectible amounts, environmental costs, unbilled revenues, jurisdictional fuel and energy cost allocations and actuarially determined benefit costs. The recorded estimates are revised when better information becomes available or when actual amounts can be determined. Those revisions can affect operating results. | ||
Regulatory Accounting | ' | |
Regulatory Accounting — Our regulated utility subsidiaries account for certain income and expense items in accordance with accounting guidance for regulated operations. Under this guidance: | ||
• | Certain costs, which would otherwise be charged to expense or OCI, are deferred as regulatory assets based on the expected ability to recover the costs in future rates; and | |
• | Certain credits, which would otherwise be reflected as income, are deferred as regulatory liabilities based on the expectation the amounts will be returned to customers in future rates, or because the amounts were collected in rates prior to the costs being incurred. | |
Estimates of recovering deferred costs and returning deferred credits are based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are amortized consistent with the treatment in the rate setting process. | ||
If restructuring or other changes in the regulatory environment occur, regulated utility subsidiaries may no longer be eligible to apply this accounting treatment, and may be required to eliminate regulatory assets and liabilities from their balance sheets. Such changes could have a material effect on Xcel Energy’s financial condition, results of operations and cash flows. See Note 15 for further discussion of regulatory assets and liabilities. | ||
Revenue Recognition | ' | |
Revenue Recognition — Revenues related to the sale of energy are generally recorded when service is rendered or energy is delivered to customers. However, the determination of the energy sales to individual customers is based on the reading of their meter, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is recognized. Xcel Energy presents its revenues net of any excise or other fiduciary-type taxes or fees. | ||
NSP-Minnesota participates in MISO, and SPS participates in SPP. The revenues and charges from these RTOs related to serving retail and wholesale electric customers comprising the native load of NSP-Minnesota and SPS are recorded on a net basis within cost of sales. Revenues and charges for short term wholesale sales of excess energy transacted through RTOs are recorded on a gross basis in electric revenues and cost of sales. | ||
Xcel Energy Inc.’s utility subsidiaries have various rate-adjustment mechanisms in place that provide for the recovery of natural gas, electric fuel and purchased energy costs. These cost-adjustment tariffs may increase or decrease the level of revenue collected from customers and are revised periodically for differences between the total amount collected under the clauses and the costs incurred. When applicable, under governing regulatory commission rate orders, fuel cost over-recoveries (the excess of fuel revenue billed to customers over fuel costs incurred) are deferred as regulatory liabilities and under-recoveries (the excess of fuel costs incurred over fuel revenues billed to customers) are deferred as regulatory assets. | ||
Conservation Programs | ' | |
Conservation Programs — Xcel Energy Inc.’s utility subsidiaries have implemented programs in many of their retail jurisdictions to assist customers in conserving energy and reducing peak demand on the electric and natural gas systems. These programs include efficiency and redesign programs, as well as rebates for the purchase of items such as compact fluorescent bulbs, saver switches and energy-efficient heating and cooling appliances. | ||
The costs incurred for DSM and CIP programs are deferred if it is probable future revenue will be provided to permit recovery of the incurred cost. For incentive programs designed to allow adjustments of future rates for recovery of lost margins and/or conservation performance incentives, recorded revenues are limited to those amounts expected to be collected within 24 months following the end of the annual period in which they are earned. | ||
For PSCo, SPS and NSP-Minnesota, DSM and CIP program costs are recovered through a combination of base rate revenue and rider mechanisms. The revenue billed to customers recovers incurred costs for conservation programs and also incentive amounts that are designed to encourage Xcel Energy’s achievement of energy conservation goals and compensate for related lost sales margin. For these utility subsidiaries, regulatory assets are recognized to reflect the amount of costs or earned incentives that have not yet been collected from customers. NSP-Wisconsin recovers approved conservation program costs in base rate revenue. | ||
Property, Plant and Equipment and Depreciation | ' | |
Property, Plant and Equipment and Depreciation — Property, plant and equipment is stated at original cost. The cost of plant includes direct labor and materials, contracted work, overhead costs and AFUDC. The cost of plant retired is charged to accumulated depreciation and amortization. Amounts recovered in rates for future removal costs are recorded as regulatory liabilities. Significant additions or improvements extending asset lives are capitalized, while repairs and maintenance costs are charged to expense as incurred. Maintenance and replacement of items determined to be less than a unit of property are charged to operating expenses as incurred. Planned major maintenance activities are charged to operating expense unless the cost represents the acquisition of an additional unit of property or the replacement of an existing unit of property. Property, plant and equipment also includes costs associated with property held for future use. The depreciable lives of certain plant assets are reviewed annually and revised, if appropriate. Property, plant and equipment that is required to be decommissioned early by a regulator is reclassified as plant to be retired. | ||
Property, plant and equipment is tested for impairment when it is determined that the carrying value of the assets may not be recoverable. Recently completed property, plant and equipment that is disallowed for cost recovery is expensed in the current period. For investments in property, plant and equipment that are not expected to go into service, incurred costs and related deferred tax amounts are compared to the discounted estimated future rate recovery, and a loss on abandonment is recognized, if necessary. | ||
Xcel Energy records depreciation expense related to its plant using the straight-line method over the plant’s useful life. Actuarial and semi-actuarial life studies are performed on a periodic basis and submitted to the state and federal commissions for review. Upon acceptance by the various commissions, the resulting lives and net salvage rates are used to calculate depreciation. Depreciation expense, expressed as a percentage of average depreciable property, was approximately 2.9, 2.8, and 2.9 percent for the years ended Dec. 31, 2013, 2012 and 2011, respectively. | ||
Leases | ' | |
Leases — Xcel Energy evaluates a variety of contracts for lease classification at inception, including PPAs and rental arrangements for office space, vehicles and equipment. Contracts determined to contain a lease because of per unit pricing that is other than fixed or market price, terms regarding the use of a particular asset, and other factors are evaluated further to determine if the arrangement is a capital lease. See Note 13 for further discussion of leases. | ||
AFUDC | ' | |
AFUDC — AFUDC represents the cost of capital used to finance utility construction activity. AFUDC is computed by applying a composite financing rate to qualified CWIP. The amount of AFUDC capitalized as a utility construction cost is credited to other nonoperating income (for equity capital) and interest charges (for debt capital). AFUDC amounts capitalized are included in Xcel Energy’s rate base for establishing utility service rates. In addition to construction-related amounts, cost of capital also is recorded to reflect returns on capital used to finance conservation programs in Minnesota. | ||
Generally, AFUDC costs are recovered from customers as the related property is depreciated. However, in some cases commissions have approved a more current recovery of the cost of capital associated with large capital projects, resulting in a lower recognition of AFUDC. In other cases, some commissions have allowed an AFUDC calculation greater than the FERC-defined AFUDC rate, resulting in higher recognition of AFUDC. | ||
Asset Retirement Obligations | ' | |
AROs — Xcel Energy Inc.’s utility subsidiaries account for AROs under accounting guidance that requires a liability for the fair value of an ARO to be recognized in the period in which it is incurred if it can be reasonably estimated, with the offsetting associated asset retirement costs capitalized as a long-lived asset. The liability is generally increased over time by applying the effective interest method of accretion, and the capitalized costs are depreciated over the useful life of the long-lived asset. Changes resulting from revisions to the timing or amount of expected asset retirement cash flows are recognized as an increase or a decrease in the ARO. Xcel Energy Inc.’s utility subsidiaries also recover through rates certain future plant removal costs in addition to AROs. The accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability. See Note 13 for further discussion of AROs. | ||
Nuclear Decommissioning | ' | |
Nuclear Decommissioning — Nuclear decommissioning studies estimate NSP-Minnesota’s ultimate costs of decommissioning its nuclear power plants and are performed at least every three years and submitted to the MPUC and other state commissions for approval. The MPUC approved NSP-Minnesota’s most recent triennial nuclear decommissioning studies in December 2012. These studies reflect NSP-Minnesota’s plans for prompt dismantlement of the Monticello and Prairie Island facilities. These studies assume that NSP-Minnesota will be storing spent fuel on site pending removal to a U.S. government facility. | ||
For rate making purposes, NSP-Minnesota recovers the total decommissioning costs related to its nuclear power plants over each facility’s expected service life based on the triennial decommissioning studies filed with the MPUC and other state commissions. The studies consider estimated future costs of decommissioning and the market value of investments in trust funds, and recommend annual funding amounts. Amounts collected in rates are deposited in the trust funds. See Note 14 for further discussion of the approved nuclear decommissioning studies and funded amounts. For financial reporting purposes, NSP-Minnesota accounts for nuclear decommissioning as an ARO as described above. | ||
Restricted funds for the payment of future decommissioning expenditures for NSP-Minnesota’s nuclear facilities are included in the nuclear decommissioning fund on the consolidated balance sheets. See Note 11 for further discussion of the nuclear decommissioning fund. | ||
Nuclear Fuel Expense | ' | |
Nuclear Fuel Expense — Nuclear fuel expense, which is recorded as NSP-Minnesota’s nuclear generating plants use fuel, includes the cost of fuel used in the current period (including AFUDC), as well as future disposal costs of spent nuclear fuel and costs associated with the end-of-life fuel segments. | ||
Nuclear Refueling Outage Costs | ' | |
Nuclear Refueling Outage Costs — Xcel Energy uses a deferral and amortization method for nuclear refueling O&M costs. This method amortizes refueling outage costs over the period between refueling outages consistent with how the costs are recovered ratably in electric rates. | ||
Income Taxes | ' | |
Income Taxes — Xcel Energy accounts for income taxes using the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements. Xcel Energy defers income taxes for all temporary differences between pretax financial and taxable income, and between the book and tax bases of assets and liabilities. Xcel Energy uses the tax rates that are scheduled to be in effect when the temporary differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date. | ||
Deferred tax assets are reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax asset will not be realized. In making such a determination, all available evidence is considered, including scheduled reversals of deferred tax liabilities, projected future taxable income, tax planning strategies and recent financial operations. | ||
Due to the effects of past regulatory practices, when deferred taxes were not required to be recorded due to the use of flow through accounting for ratemaking purposes, the reversal of some temporary differences are accounted for as current income tax expense. Investment tax credits are deferred and their benefits amortized over the book depreciable lives of the related property. Utility rate regulation also has resulted in the recognition of certain regulatory assets and liabilities related to income taxes, which are summarized in Note 15. | ||
Xcel Energy follows the applicable accounting guidance to measure and disclose uncertain tax positions that it has taken or expects to take in its income tax returns. Xcel Energy recognizes a tax position in its consolidated financial statements when it is more likely than not that the position will be sustained upon examination based on the technical merits of the position. Recognition of changes in uncertain tax positions are reflected as a component of income tax. | ||
Xcel Energy reports interest and penalties related to income taxes within the other income and interest charges sections in the consolidated statements of income. | ||
Xcel Energy Inc. and its subsidiaries file consolidated federal income tax returns as well as combined or separate state income tax returns. Federal income taxes paid by Xcel Energy Inc. are allocated to Xcel Energy Inc.’s subsidiaries based on separate company computations of tax. A similar allocation is made for state income taxes paid by Xcel Energy Inc. in connection with combined state filings. Xcel Energy Inc. also allocates its own income tax benefits to its direct subsidiaries based on the relative positive tax liabilities of the subsidiaries. | ||
See Note 6 for further discussion of income taxes. | ||
Types of and Accounting for Derivative Instruments | ' | |
Types of and Accounting for Derivative Instruments — Xcel Energy uses derivative instruments in connection with its interest rate, utility commodity price, vehicle fuel price, short-term wholesale and commodity trading activities, including forward contracts, futures, swaps and options. All derivative instruments not designated and qualifying for the normal purchases and normal sales exception, as defined by the accounting guidance for derivatives and hedging, are recorded on the consolidated balance sheets at fair value as derivative instruments. This includes certain instruments used to mitigate market risk for the utility operations including transmission in organized markets and all instruments related to the commodity trading operations. The classification of changes in fair value for those derivative instruments is dependent on the designation of a qualifying hedging relationship. Changes in fair value of derivative instruments not designated in a qualifying hedging relationship are reflected in current earnings or as a regulatory asset or liability. The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. | ||
Gains or losses on commodity trading transactions are recorded as a component of electric operating revenues; hedging transactions for vehicle fuel costs are recorded as a component of capital projects or O&M costs; and interest rate hedging transactions are recorded as a component of interest expense. Certain utility subsidiaries are allowed to recover in electric or natural gas rates the costs of certain financial instruments purchased to reduce commodity cost volatility. For further information on derivatives entered to mitigate commodity price risk on behalf of electric and natural gas customers, see Note 11. | ||
Cash Flow Hedges — Certain qualifying hedging relationships are designated as a hedge of a forecasted transaction, or future cash flow (cash flow hedge). Changes in the fair value of a derivative designated as a cash flow hedge, to the extent effective, are included in OCI or deferred as a regulatory asset or liability based on recovery mechanisms until earnings are affected by the hedged transaction. | ||
Normal Purchases and Normal Sales — Xcel Energy enters into contracts for the purchase and sale of commodities for use in its business operations. Derivatives and hedging accounting guidance requires a company to evaluate these contracts to determine whether the contracts are derivatives. Certain contracts that meet the definition of a derivative may be exempted from derivative accounting if designated as normal purchases or normal sales. | ||
Xcel Energy evaluates all of its contracts at inception to determine if they are derivatives and if they meet the normal purchases and normal sales designation requirements. None of the contracts entered into within the commodity trading operations qualify for a normal purchases and normal sales designation. | ||
See Note 11 for further discussion of Xcel Energy’s risk management and derivative activities. | ||
Commodity Trading Operations | ' | |
Commodity Trading Operations — All applicable gains and losses related to commodity trading activities, whether or not settled physically, are shown on a net basis in electric operating revenues in the consolidated statements of income. | ||
Xcel Energy’s commodity trading operations are conducted by NSP-Minnesota, PSCo and SPS. Commodity trading activities are not associated with energy produced from Xcel Energy’s generation assets or energy and capacity purchased to serve native load. Commodity trading contracts are recorded at fair market value and commodity trading results include the impact of all margin-sharing mechanisms. See Note 11 for further discussion. | ||
Fair Value Measurements | ' | |
Fair Value Measurements — Xcel Energy presents cash equivalents, interest rate derivatives, commodity derivatives and nuclear decommissioning fund assets at estimated fair values in its consolidated financial statements. Cash equivalents are recorded at cost plus accrued interest; money market funds are measured using quoted net asset values. For interest rate derivatives, quoted prices based primarily on observable market interest rate curves are used as a primary input to establish fair value. For commodity derivatives, the most observable inputs available are generally used to determine the fair value of each contract. In the absence of a quoted price for an identical contract in an active market, Xcel Energy may use quoted prices for similar contracts or internally prepared valuation models to determine fair value. For the nuclear decommissioning fund, published trading data and pricing models, generally using the most observable inputs available, are utilized to estimate fair value for each class of security. See Note 11 for further discussion. | ||
Cash and Cash Equivalents | ' | |
Cash and Cash Equivalents — Xcel Energy considers investments in certain instruments, including commercial paper and money market funds, with a remaining maturity of 3 months or less at the time of purchase, to be cash equivalents. | ||
Accounts Receivable and Allowance for Bad Debts | ' | |
Accounts Receivable and Allowance for Bad Debts — Accounts receivable are stated at the actual billed amount net of an allowance for bad debts. Xcel Energy establishes an allowance for uncollectible receivables based on a policy that reflects its expected exposure to the credit risk of customers. | ||
Inventory | ' | |
Inventory — All inventory is recorded at average cost. | ||
Renewable Energy Credits | ' | |
RECs — RECs are marketable environmental instruments that represent proof that energy was generated from eligible renewable energy sources. RECs are awarded upon delivery of the associated energy and can be bought and sold. RECs are typically used as a form of measurement of compliance to RPS enacted by those states that are encouraging construction and consumption from renewable energy sources, but can also be sold separately from the energy produced. Utility subsidiaries acquire RECs from the generation or purchase of renewable power. | ||
When RECs are purchased or acquired in the course of generation they are recorded as inventory at cost. The cost of RECs that are utilized for compliance purposes is recorded as electric fuel and purchased power expense. As a result of state regulatory orders, Xcel Energy reduces recoverable fuel costs for the cost of certain RECs and records that cost as a regulatory asset when the amount is recoverable in future rates. | ||
Sales of RECs that are purchased or acquired in the course of generation are recorded in electric utility operating revenues on a gross basis. The cost of these RECs, related transaction costs, and amounts credited to customers under margin-sharing mechanisms are recorded in electric fuel and purchased power expense. The sales of RECs for trading purposes are recorded in electric utility operating revenues, net of the cost of the RECs, transaction costs, and amounts credited to customers under margin-sharing mechanisms. | ||
Emission Allowances | ' | |
Emission Allowances — Emission allowances, including the annual SO2 and NOx emission allowance entitlement received from the EPA, are recorded at cost plus associated broker commission fees. Xcel Energy follows the inventory accounting model for all emission allowances. Sales of emission allowances are included in electric utility operating revenues and the operating activities section of the consolidated statements of cash flows. | ||
Environmental Costs | ' | |
Environmental Costs — Environmental costs are recorded when it is probable Xcel Energy is liable for remediation costs and the liability can be reasonably estimated. Costs are deferred as a regulatory asset if it is probable that the costs will be recovered from customers in future rates. Otherwise, the costs are expensed. If an environmental expense is related to facilities currently in use, such as emission-control equipment, the cost is capitalized and depreciated over the life of the plant. | ||
Estimated remediation costs, excluding inflationary increases, are recorded. The estimates are based on experience, an assessment of the current situation and the technology currently available for use in the remediation. The recorded costs are regularly adjusted as estimates are revised and remediation proceeds. If other participating PRPs exist and acknowledge their potential involvement with a site, costs are estimated and recorded only for Xcel Energy’s expected share of the cost. Any future costs of restoring sites where operation may extend indefinitely are treated as a capitalized cost of plant retirement. The depreciation expense levels recoverable in rates include a provision for removal expenses, which may include final remediation costs. Removal costs recovered in rates are classified as a regulatory liability. | ||
See Note 13 for further discussion of environmental costs. | ||
Benefit Plans and Other Postretirement Benefits | ' | |
Benefit Plans and Other Postretirement Benefits — Xcel Energy maintains pension and postretirement benefit plans for eligible employees. Recognizing the cost of providing benefits and measuring the projected benefit obligation of these plans under applicable accounting guidance requires management to make various assumptions and estimates. | ||
Based on the regulatory recovery mechanisms of Xcel Energy Inc.’s utility subsidiaries, certain unrecognized actuarial gains and losses and unrecognized prior service costs or credits are recorded as regulatory assets and liabilities, rather than OCI. | ||
See Note 9 for further discussion of benefit plans and other postretirement benefits. | ||
Guarantees | ' | |
Guarantees — Xcel Energy recognizes, upon issuance or modification of a guarantee, a liability for the fair market value of the obligation that has been assumed in issuing the guarantee. This liability includes consideration of specific triggering events and other conditions which may modify the ongoing obligation to perform under the guarantee. | ||
The obligation recognized is reduced over the term of the guarantee as Xcel Energy is released from risk under the guarantee. See Note 13 for specific details of issued guarantees. | ||
Reclassifications | ' | |
Reclassifications — Certain previously reported amounts have been reclassified to conform to the current year presentation. | ||
Subsequent Events | ' | |
Subsequent Events — Management has evaluated the impact of events occurring after Dec. 31, 2013 up to the date of issuance of these consolidated financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation. |
Selected_Balance_Sheet_Data_Ta
Selected Balance Sheet Data (Tables) | 12 Months Ended | ||||||||
Dec. 31, 2013 | |||||||||
Balance Sheet Related Disclosures [Abstract] | ' | ||||||||
Accounts Receivable, Net | ' | ||||||||
(Thousands of Dollars) | Dec. 31, 2013 | Dec. 31, 2012 | |||||||
Accounts receivable, net | |||||||||
Accounts receivable | $ | 797,267 | $ | 769,440 | |||||
Less allowance for bad debts | (53,107 | ) | (51,394 | ) | |||||
$ | 744,160 | $ | 718,046 | ||||||
Inventories | ' | ||||||||
(Thousands of Dollars) | Dec. 31, 2013 | Dec. 31, 2012 | |||||||
Inventories | |||||||||
Materials and supplies | $ | 225,308 | $ | 213,739 | |||||
Fuel | 189,485 | 189,425 | |||||||
Natural gas | 161,745 | 132,410 | |||||||
$ | 576,538 | $ | 535,574 | ||||||
Property, Plant and Equipment, Net | ' | ||||||||
(Thousands of Dollars) | Dec. 31, 2013 | Dec. 31, 2012 | |||||||
Property, plant and equipment, net | |||||||||
Electric plant | $ | 30,341,310 | $ | 28,285,031 | |||||
Natural gas plant | 4,086,651 | 3,836,335 | |||||||
Common and other property | 1,485,547 | 1,480,558 | |||||||
Plant to be retired (a) | 101,279 | 152,730 | |||||||
CWIP | 2,371,566 | 1,757,189 | |||||||
Total property, plant and equipment | 38,386,353 | 35,511,843 | |||||||
Less accumulated depreciation | (12,608,305 | ) | (12,048,697 | ) | |||||
Nuclear fuel | 2,186,799 | 2,090,801 | |||||||
Less accumulated amortization | (1,842,688 | ) | (1,744,599 | ) | |||||
$ | 26,122,159 | $ | 23,809,348 | ||||||
(a) | As a result of the CPUC’s 2010 approval of PSCo’s CACJA compliance plan, subsequent CPCNs and the December 2013 approval of PSCo’s preferred plans for applicable generating resources, PSCo has received approval for early retirement of Cherokee Units 1, 2 and 3, Arapahoe Units 3 and 4 and Valmont Unit 5 between 2011 and 2017. In 2011, Cherokee Unit 2 was retired, in 2012, Cherokee Unit 1 was retired, and in 2013, Arapahoe Units 3 and 4 were retired. Amounts are presented net of accumulated depreciation. |
Borrowings_and_Other_Financing1
Borrowings and Other Financing Instruments (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2013 | |||||||||||||
Debt Disclosure [Abstract] | ' | ||||||||||||
Commercial Paper | ' | ||||||||||||
Commercial Paper — Xcel Energy Inc. and its utility subsidiaries meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under their credit facilities. Commercial paper outstanding for Xcel Energy was as follows: | |||||||||||||
(Amounts in Millions, Except Interest Rates) | Three Months Ended | ||||||||||||
Dec. 31, 2013 | |||||||||||||
Borrowing limit | $ | 2,450 | |||||||||||
Amount outstanding at period end | 759 | ||||||||||||
Average amount outstanding | 515 | ||||||||||||
Maximum amount outstanding | 759 | ||||||||||||
Weighted average interest rate, computed on a daily basis | 0.29 | % | |||||||||||
Weighted average interest rate at period end | 0.25 | ||||||||||||
(Amounts in Millions, Except Interest Rates) | Twelve Months Ended | Twelve Months Ended | Twelve Months Ended | ||||||||||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |||||||||||
Borrowing limit | $ | 2,450 | $ | 2,450 | $ | 2,450 | |||||||
Amount outstanding at period end | 759 | 602 | 219 | ||||||||||
Average amount outstanding | 481 | 403 | 430 | ||||||||||
Maximum amount outstanding | 1,160 | 634 | 824 | ||||||||||
Weighted average interest rate, computed on a daily basis | 0.31 | % | 0.35 | % | 0.36 | % | |||||||
Weighted average interest rate at end of period | 0.25 | 0.36 | 0.4 | ||||||||||
The following tables present money pool lending for Xcel Energy Inc.: | |||||||||||||
(Amounts in Millions, Except Interest Rates) | Three Months Ended Dec. 31, 2013 | ||||||||||||
Lending limit | $ | 250 | |||||||||||
Loan outstanding at period end | 72 | ||||||||||||
Average loan outstanding | 109.8 | ||||||||||||
Maximum loan outstanding | 182 | ||||||||||||
Weighted average interest rate, computed on a daily basis | 0.31 | % | |||||||||||
Weighted average interest rate at end of period | 0.25 | ||||||||||||
Money pool interest income | $ | 0.1 | |||||||||||
(Amounts in Millions, Except Interest Rates) | Twelve Months Ended Dec. 31, 2013 | Twelve Months Ended Dec. 31, 2012 | Twelve Months Ended Dec. 31, 2011 | ||||||||||
Lending limit | $ | 250 | $ | 250 | $ | 250 | |||||||
Loan outstanding at period end | 72 | — | 18 | ||||||||||
Average loan outstanding | 88.2 | 26.1 | 0.4 | ||||||||||
Maximum loan outstanding | 243 | 226 | 43 | ||||||||||
Weighted average interest rate, computed on a daily basis | 0.3 | % | 0.33 | % | 0.35 | % | |||||||
Weighted average interest rate at end of period | 0.25 | N/A | 0.35 | ||||||||||
Money pool interest income | $ | 0.3 | $ | 0.1 | $ | — | |||||||
Schedule Of Debt To Total Capitalization Ratio | ' | ||||||||||||
ach entity was in compliance at Dec. 31, 2013 and 2012, respectively, as evidenced by the table below: | |||||||||||||
Debt-to-Total Capitalization Ratio | |||||||||||||
2013 | 2012 | ||||||||||||
Xcel Energy | 56 | % | 56 | % | |||||||||
NSP-Wisconsin | 47 | 50 | |||||||||||
NSP-Minnesota | 47 | 48 | |||||||||||
SPS | 49 | 49 | |||||||||||
PSCo | 45 | 45 | |||||||||||
Committed Credit Facilities Available | ' | ||||||||||||
At Dec. 31, 2013, Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available: | |||||||||||||
(Millions of Dollars) | Credit Facility (a) | Drawn (b) | Available | ||||||||||
Xcel Energy Inc. | $ | 800 | $ | 476 | $ | 324 | |||||||
PSCo | 700 | 6.4 | 693.6 | ||||||||||
NSP-Minnesota | 500 | 146.9 | 353.1 | ||||||||||
SPS | 300 | 109.5 | 190.5 | ||||||||||
NSP-Wisconsin | 150 | 68 | 82 | ||||||||||
Total | $ | 2,450.00 | $ | 806.8 | $ | 1,643.20 | |||||||
(a) | These credit facilities expire in July 2017. | ||||||||||||
(b) | Includes outstanding commercial paper and letters of credit. | ||||||||||||
Schedule of Maturities of Long-term Debt | ' | ||||||||||||
Maturities of long-term debt are as follows: | |||||||||||||
(Millions of Dollars) | |||||||||||||
2014 | $ | 281 | |||||||||||
2015 | 256 | ||||||||||||
2016 | 656 | ||||||||||||
2017 | 388 | ||||||||||||
2018 | 1,206 | ||||||||||||
Joint_Ownership_of_Generation_1
Joint Ownership of Generation, Transmission and Gas Facilities (Tables) | 12 Months Ended | |||||||||||||||
Dec. 31, 2013 | ||||||||||||||||
Joint Ownership of Generation, Transmission and Gas Facilities [Abstract] | ' | |||||||||||||||
Investments in Jointly Owned Generation, Transmission and Gas Facilities | ' | |||||||||||||||
Following are the investments by Xcel Energy Inc.’s utility subsidiaries in jointly owned generation, transmission and gas facilities and the related ownership percentages as of Dec. 31, 2013: | ||||||||||||||||
(Thousands of Dollars) | Plant in | Accumulated | CWIP | Ownership % | ||||||||||||
Service | Depreciation | |||||||||||||||
NSP-Minnesota | ||||||||||||||||
Electric Generation: | ||||||||||||||||
Sherco Unit 3 | $ | 596,314 | $ | 371,925 | $ | 4,533 | 59 | % | ||||||||
Sherco Common Facilities Units 1, 2 and 3 | 145,579 | 87,289 | 61 | 80 | ||||||||||||
Sherco Substation | 4,790 | 2,884 | — | 59 | ||||||||||||
Electric Transmission: | ||||||||||||||||
Grand Meadow Line and Substation | 10,647 | 1,225 | — | 50 | ||||||||||||
CapX2020 Transmission | 340,333 | 77,803 | 503,714 | 53.3 | ||||||||||||
Total NSP-Minnesota | $ | 1,097,663 | $ | 541,126 | $ | 508,308 | ||||||||||
(Thousands of Dollars) | Plant in | Accumulated | CWIP | Ownership % | ||||||||||||
Service | Depreciation | |||||||||||||||
NSP-Wisconsin | ||||||||||||||||
Electric Transmission: | ||||||||||||||||
CapX2020 Transmission | $ | 13,337 | $ | 4,659 | $ | 30,199 | 77.9 | % | ||||||||
La Crosse, Wis. to Madison, Wis. | — | — | 5,431 | 50 | ||||||||||||
Total NSP-Wisconsin | $ | 13,337 | $ | 4,659 | $ | 35,630 | ||||||||||
(Thousands of Dollars) | Plant in | Accumulated | CWIP | Ownership % | ||||||||||||
Service | Depreciation | |||||||||||||||
PSCo | ||||||||||||||||
Electric Generation: | ||||||||||||||||
Hayden Unit 1 | $ | 97,879 | $ | 63,474 | $ | 53 | 75.5 | % | ||||||||
Hayden Unit 2 | 119,972 | 57,875 | 5,563 | 37.4 | ||||||||||||
Hayden Common Facilities | 36,916 | 16,055 | 2 | 53.1 | ||||||||||||
Craig Units 1 and 2 | 60,089 | 34,754 | 537 | 9.7 | ||||||||||||
Craig Common Facilities 1, 2 and 3 | 37,177 | 17,247 | — | 6.5 | ||||||||||||
Comanche Unit 3 | 877,489 | 63,963 | 581 | 66.7 | ||||||||||||
Comanche Common Facilities | 19,812 | 711 | 2,255 | 82 | ||||||||||||
Electric Transmission: | ||||||||||||||||
Transmission and other facilities, including substations | 150,502 | 59,118 | 827 | Various | ||||||||||||
Gas Transportation: | ||||||||||||||||
Rifle, Colo. to Avon, Colo. | 16,278 | 6,044 | — | 60 | ||||||||||||
Total PSCo | $ | 1,416,114 | $ | 319,241 | $ | 9,818 | ||||||||||
Income_Taxes_Tables
Income Taxes (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2013 | |||||||||||||
Income Tax Disclosure [Abstract] | ' | ||||||||||||
Earliest Open Tax Years Subject to Examination by State Taxing Authorities in the Major Operating Jurisdictions | ' | ||||||||||||
State Audits — Xcel Energy files consolidated state tax returns based on income in its major operating jurisdictions of Colorado, Minnesota, Texas, and Wisconsin, and various other state income-based tax returns. As of Dec. 31, 2013, Xcel Energy’s earliest open tax years that are subject to examination by state taxing authorities in its major operating jurisdictions were as follows: | |||||||||||||
State | Year | ||||||||||||
Colorado | 2009 | ||||||||||||
Minnesota | 2009 | ||||||||||||
Texas | 2008 | ||||||||||||
Wisconsin | 2009 | ||||||||||||
Reconciliation of Unrecognized Tax Benefits | ' | ||||||||||||
A reconciliation of the amount of unrecognized tax benefit is as follows: | |||||||||||||
(Millions of Dollars) | Dec. 31, 2013 | Dec. 31, 2012 | |||||||||||
Unrecognized tax benefit — Permanent tax positions | $ | 12.9 | $ | 4.7 | |||||||||
Unrecognized tax benefit — Temporary tax positions | 28.3 | 29.8 | |||||||||||
Total unrecognized tax benefit | $ | 41.2 | $ | 34.5 | |||||||||
A reconciliation of the beginning and ending amount of unrecognized tax benefit is as follows: | |||||||||||||
(Millions of Dollars) | 2013 | 2012 | 2011 | ||||||||||
Balance at Jan. 1 | $ | 34.5 | $ | 34.7 | $ | 40.5 | |||||||
Additions based on tax positions related to the current year | 15.1 | 5.2 | 11.9 | ||||||||||
Reductions based on tax positions related to the current year | (0.4 | ) | (5.7 | ) | (1.9 | ) | |||||||
Additions for tax positions of prior years | 21.6 | 9.6 | 14 | ||||||||||
Reductions for tax positions of prior years | (4.8 | ) | (9.3 | ) | (2.4 | ) | |||||||
Settlements with taxing authorities | (24.8 | ) | — | (27.3 | ) | ||||||||
Lapse of applicable statutes of limitations | — | — | (0.1 | ) | |||||||||
Balance at Dec. 31 | $ | 41.2 | $ | 34.5 | $ | 34.7 | |||||||
Tax Benefits Associated with NOL and Tax Credit Carryforwards | ' | ||||||||||||
The unrecognized tax benefit amounts were reduced by the tax benefits associated with NOL and tax credit carryforwards. The amounts of tax benefits associated with NOL and tax credit carryforwards are as follows: | |||||||||||||
(Millions of Dollars) | Dec. 31, 2013 | Dec. 31, 2012 | |||||||||||
NOL and tax credit carryforwards | $ | (27.1 | ) | $ | (33.5 | ) | |||||||
NOL and Tax Credit Carryforwards | ' | ||||||||||||
Other Income Tax Matters — NOL amounts represent the amount of the tax loss that is carried forward and tax credits represent the deferred tax asset. NOL and tax credit carryforwards as of Dec. 31 were as follows: | |||||||||||||
(Millions of Dollars) | 2013 | 2012 | |||||||||||
Federal NOL carryforward | $ | 1,311 | $ | 969 | |||||||||
Federal tax credit carryforwards | 294 | 257 | |||||||||||
State NOL carryforwards | 1,706 | 1,465 | |||||||||||
Valuation allowances for state NOL carryforwards | (51 | ) | (52 | ) | |||||||||
State tax credit carryforwards, net of federal detriment (a) | 17 | 17 | |||||||||||
(a) | State tax credit carryforwards are net of federal detriment of $9 million as of Dec. 31, 2013 and 2012. | ||||||||||||
Schedule of Effective Income Tax Rate Reconciliation | ' | ||||||||||||
Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense. The following reconciles such differences for the years ending Dec. 31: | |||||||||||||
2013 | 2012 | 2011 | |||||||||||
Federal statutory rate | 35 | % | 35 | % | 35 | % | |||||||
Increases (decreases) in tax from: | |||||||||||||
Tax credits recognized, net of federal income tax expense | (2.6 | ) | (2.2 | ) | (2.6 | ) | |||||||
Regulatory differences — utility plant items | (1.6 | ) | (1.0 | ) | (0.8 | ) | |||||||
NOL carryback | (0.8 | ) | (1.1 | ) | — | ||||||||
State income taxes, net of federal income tax benefit | 4.1 | 4 | 4.3 | ||||||||||
Change in unrecognized tax benefits | 0.6 | — | (0.1 | ) | |||||||||
Prescription drug tax benefit and Medicare Part D | — | (1.2 | ) | — | |||||||||
Other, net | (0.9 | ) | (0.3 | ) | — | ||||||||
Effective income tax rate | 33.8 | % | 33.2 | % | 35.8 | % | |||||||
Schedule of Components of Income Tax Expense (Benefit) | ' | ||||||||||||
The components of Xcel Energy’s income tax expense for the years ending Dec. 31 were: | |||||||||||||
(Thousands of Dollars) | 2013 | 2012 | 2011 | ||||||||||
Current federal tax (benefit) expense | $ | (46,173 | ) | $ | 7,876 | $ | 3,399 | ||||||
Current state tax expense | 7,678 | 31,478 | 9,971 | ||||||||||
Current change in unrecognized tax expense (benefit) | 13,162 | (1,704 | ) | (8,266 | ) | ||||||||
Deferred federal tax expense | 439,085 | 366,409 | 383,931 | ||||||||||
Deferred state tax expense | 80,907 | 50,741 | 78,770 | ||||||||||
Deferred change in unrecognized tax (benefit) expense | (4,930 | ) | 2,013 | 6,705 | |||||||||
Deferred investment tax credits | (5,753 | ) | (6,610 | ) | (6,194 | ) | |||||||
Total income tax expense | $ | 483,976 | $ | 450,203 | $ | 468,316 | |||||||
The components of deferred income tax expense for the years ending Dec. 31 were: | |||||||||||||
(Thousands of Dollars) | 2013 | 2012 | 2011 | ||||||||||
Deferred tax expense excluding items below | $ | 588,053 | $ | 559,860 | $ | 446,893 | |||||||
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities | (64,420 | ) | (63,862 | ) | (7,108 | ) | |||||||
Tax (expense) benefit allocated to OCI | (8,572 | ) | 12,102 | 26,798 | |||||||||
Other | 1 | (6 | ) | (16 | ) | ||||||||
Deferred tax expense | $ | 515,062 | $ | 508,094 | $ | 466,567 | |||||||
Schedule of Deferred Tax Assets and Liabilities | ' | ||||||||||||
The components of Xcel Energy’s net deferred tax liability (current and noncurrent) at Dec. 31 were as follows: | |||||||||||||
(Thousands of Dollars) | 2013 | 2012 | |||||||||||
Deferred tax liabilities: | |||||||||||||
Differences between book and tax bases of property | $ | 5,562,446 | $ | 4,867,142 | |||||||||
Regulatory assets | 321,636 | 293,367 | |||||||||||
Other | 254,639 | 220,781 | |||||||||||
Total deferred tax liabilities | $ | 6,138,721 | $ | 5,381,290 | |||||||||
Deferred tax assets: | |||||||||||||
NOL carryforward | $ | 532,774 | $ | 430,765 | |||||||||
Tax credit carryforward | 311,388 | 273,776 | |||||||||||
Unbilled revenue - fuel costs | 58,908 | 60,068 | |||||||||||
Rate refund | 49,804 | 8,109 | |||||||||||
Environmental remediation | 42,886 | 44,549 | |||||||||||
Regulatory liabilities | 40,947 | 34,471 | |||||||||||
Deferred investment tax credits | 34,231 | 35,767 | |||||||||||
Other | 81,202 | 95,308 | |||||||||||
NOL and tax credit valuation allowances | (3,263 | ) | (3,314 | ) | |||||||||
Total deferred tax assets | $ | 1,148,877 | $ | 979,499 | |||||||||
Net deferred tax liability | $ | 4,989,844 | $ | 4,401,791 | |||||||||
Earnings_Per_Share_Tables
Earnings Per Share (Tables) | 12 Months Ended | |||||||||||||||||||||||||||||||||
Dec. 31, 2013 | ||||||||||||||||||||||||||||||||||
Earnings Per Share [Abstract] | ' | |||||||||||||||||||||||||||||||||
Dilutive Impact of Common Stock Equivalents | ' | |||||||||||||||||||||||||||||||||
The dilutive impact of common stock equivalents affecting EPS was as follows: | ||||||||||||||||||||||||||||||||||
2013 | 2012 | 2011 | ||||||||||||||||||||||||||||||||
(Amounts in thousands, except per share data) | Income | Shares | Per | Income | Shares | Per | Income | Shares | Per | |||||||||||||||||||||||||
Share | Share | Share | ||||||||||||||||||||||||||||||||
Amount | Amount | Amount | ||||||||||||||||||||||||||||||||
Net income | $ | 948,234 | $ | 905,229 | $ | 841,172 | ||||||||||||||||||||||||||||
Less: Dividend requirements on preferred stock | — | — | (3,534 | ) | ||||||||||||||||||||||||||||||
Less: Premium on redemption of preferred stock | — | — | (3,260 | ) | ||||||||||||||||||||||||||||||
Basic earnings per share: | ||||||||||||||||||||||||||||||||||
Earnings available to common shareholders | 948,234 | 496,073 | $ | 1.91 | 905,229 | 487,899 | $ | 1.86 | 834,378 | 485,039 | $ | 1.72 | ||||||||||||||||||||||
Effect of dilutive securities: | ||||||||||||||||||||||||||||||||||
401(k) equity awards | — | 459 | — | 535 | — | 576 | ||||||||||||||||||||||||||||
Diluted earnings per share: | ||||||||||||||||||||||||||||||||||
Earnings available to common shareholders | $ | 948,234 | 496,532 | $ | 1.91 | $ | 905,229 | 488,434 | $ | 1.85 | $ | 834,378 | 485,615 | $ | 1.72 | |||||||||||||||||||
ShareBased_Compensation_Tables
Share-Based Compensation (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2013 | |||||||||||||
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | ' | ||||||||||||
Activity in Stock Options | ' | ||||||||||||
Activity in stock options for the year ended Dec. 31 was as follows: | |||||||||||||
2011 | |||||||||||||
(Awards in Thousands) | Awards | Average | |||||||||||
Exercise | |||||||||||||
Price | |||||||||||||
Outstanding and exercisable at Jan. 1 | 2,498 | $ | 30.42 | ||||||||||
Exercised | (1,173 | ) | 25.9 | ||||||||||
Expired | (1,325 | ) | 34.42 | ||||||||||
Outstanding and exercisable at Dec. 31 | — | — | |||||||||||
Total Market Value and Total Intrinsic Value of Stock Options Exercised | ' | ||||||||||||
The total market value and the total intrinsic value of stock options exercised were as follows for the year ended Dec. 31: | |||||||||||||
(Thousands of Dollars) | 2011 | ||||||||||||
Market value of exercises | $ | 30,761 | |||||||||||
Intrinsic value of options exercised (a) | 380 | ||||||||||||
(a) | Intrinsic value is calculated as market price at exercise date less the option exercise price. | ||||||||||||
Cash Received and Actual Tax Benefit from Stock Options Exercised | ' | ||||||||||||
Cash received from stock options exercised and the actual tax benefit realized for the tax deductions from stock options exercised during the year ended Dec. 31 were as follows: | |||||||||||||
(Thousands of Dollars) | 2011 | ||||||||||||
Cash received from stock options exercised | $ | 30,381 | |||||||||||
Tax benefit realized for the tax deductions from stock options exercised | 157 | ||||||||||||
Restricted Stock | ' | ||||||||||||
Xcel Energy Inc. granted shares of restricted stock for the years ended Dec. 31 as follows: | |||||||||||||
(Shares in Thousands) | 2013 | 2012 | 2011 | ||||||||||
Granted shares | 33 | 33 | 15 | ||||||||||
Grant date fair value | $ | 28.3 | $ | 26.43 | $ | 23.62 | |||||||
A summary of the changes of nonvested restricted stock for the year ended 2013 were as follows: | |||||||||||||
(Shares in Thousands) | Shares | Weighted Average | |||||||||||
Grant Date Fair Value | |||||||||||||
Nonvested restricted stock at Jan. 1, 2013 | 54 | $ | 24.85 | ||||||||||
Granted | 33 | 28.3 | |||||||||||
Vested | (27 | ) | 23.65 | ||||||||||
Dividend equivalents | 2 | 28.88 | |||||||||||
Nonvested restricted stock at Dec. 31, 2013 | 62 | 27.33 | |||||||||||
Restricted Stock Units | ' | ||||||||||||
The RSUs granted for the years ended Dec. 31 were as follows: | |||||||||||||
(Units in Thousands) | 2013 | 2012 | 2011 | ||||||||||
Granted units | 774 | 591 | 828 | ||||||||||
Weighted average grant date fair value | $ | 27.65 | $ | 27.35 | $ | 23.63 | |||||||
A summary of the changes of nonvested RSUs for the year ended 2013, were as follows: | |||||||||||||
(Units in Thousands) | Units | Weighted | |||||||||||
Average | |||||||||||||
Grant Date | |||||||||||||
Fair Value | |||||||||||||
Nonvested RSUs at Jan. 1, 2013 | 1,155 | $ | 25.41 | ||||||||||
Granted | 774 | 27.65 | |||||||||||
Forfeited | (81 | ) | 26.32 | ||||||||||
Vested | (600 | ) | 23.62 | ||||||||||
Dividend equivalents | 64 | 26.11 | |||||||||||
Nonvested RSUs at Dec. 31, 2013 | 1,312 | 27.53 | |||||||||||
Stock Equivalent Unit Plan | ' | ||||||||||||
The stock equivalent units granted for the years ended Dec. 31 were as follows: | |||||||||||||
(Units in Thousands) | 2013 | 2012 | 2011 | ||||||||||
Granted units | 69 | 65 | 60 | ||||||||||
Grant date fair value | $ | 29.52 | $ | 27.41 | $ | 25.12 | |||||||
A summary of the stock equivalent unit changes for the year ended 2013 are as follows: | |||||||||||||
(Units in Thousands) | Units | Weighted | |||||||||||
Average | |||||||||||||
Grant Date | |||||||||||||
Fair Value | |||||||||||||
Stock equivalent units at Jan. 1, 2013 | 577 | $ | 21.71 | ||||||||||
Granted | 69 | 29.52 | |||||||||||
Units distributed | (32 | ) | 18.23 | ||||||||||
Dividend equivalents | 22 | 29.06 | |||||||||||
Stock equivalent units at Dec. 31, 2013 | 636 | 22.98 | |||||||||||
PSP Awards | ' | ||||||||||||
The PSP awards granted for the years ended Dec. 31 were as follows: | |||||||||||||
(In Thousands) | 2013 | 2012 | 2011 | ||||||||||
Awards granted | 215 | 161 | 311 | ||||||||||
The total amounts of performance awards settled during the years ended Dec. 31 were as follows: | |||||||||||||
(In Thousands) | 2013 | 2012 | 2011 | ||||||||||
Awards settled | 108 | 286 | 305 | ||||||||||
Settlement amount (cash and common stock) | $ | 3,057 | $ | 7,554 | $ | 7,200 | |||||||
Compensation costs related to share-based awards | ' | ||||||||||||
The compensation costs related to share-based awards for the years ended Dec. 31 were as follows: | |||||||||||||
(Thousands of Dollars) | 2013 | 2012 | 2011 | ||||||||||
Compensation cost for share-based awards (a) (b) (c) | $ | 24,613 | $ | 26,970 | $ | 45,006 | |||||||
Tax benefit recognized in income | 9,571 | 10,513 | 17,559 | ||||||||||
Capitalized compensation cost for share-based awards | 1,698 | 4,270 | 3,857 | ||||||||||
(a) | Compensation costs for share-based payment arrangements is included in O&M expense in the consolidated statements of income. | ||||||||||||
(b) | Included in compensation cost for share-based awards are matching contributions related to the Xcel Energy 401(k) plan, which totaled $7.0 million, $22.2 million and $21.6 million for the years ended 2013, 2012 and 2011, respectively. | ||||||||||||
(c) | In October 2013, Xcel Energy determined that it would settle the 2013 401(k) employer match in cash instead of common stock for all employee groups except PSCo bargaining 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. |
Benefit_Plans_and_Other_Postre1
Benefit Plans and Other Postretirement Benefits (Tables) | 12 Months Ended | ||||||||||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||||||||||
Benefit Plans and Other Postretirement Benefits [Abstract] | ' | ||||||||||||||||||||||||
Projected Benefit Payments for the Pension and Postretirement Benefit Plans | ' | ||||||||||||||||||||||||
The following table lists Xcel Energy’s projected benefit payments for the pension and postretirement benefit plans: | |||||||||||||||||||||||||
(Thousands of Dollars) | Projected | Gross Projected | Expected | Net Projected | |||||||||||||||||||||
Pension Benefit | Postretirement | Medicare Part D | Postretirement | ||||||||||||||||||||||
Payments | Health Care | Subsidies | Health Care | ||||||||||||||||||||||
Benefit Payments | Benefit Payments | ||||||||||||||||||||||||
2014 | $ | 313,226 | $ | 53,516 | $ | 2,627 | $ | 50,889 | |||||||||||||||||
2015 | 266,802 | 54,576 | 2,806 | 51,770 | |||||||||||||||||||||
2016 | 267,186 | 55,965 | 2,969 | 52,996 | |||||||||||||||||||||
2017 | 269,526 | 56,513 | 3,135 | 53,378 | |||||||||||||||||||||
2018 | 272,908 | 58,181 | 3,291 | 54,890 | |||||||||||||||||||||
2019-2023 | 1,339,764 | 282,860 | 18,274 | 264,586 | |||||||||||||||||||||
Contributions to Multiemployer Plans | ' | ||||||||||||||||||||||||
Contributions to multiemployer plans were as follows for the years ended Dec. 31, 2013, 2012 and 2011. The average number of NSP-Minnesota union employees covered by the multiemployer pension plans increased to approximately 1,100 in 2013 from approximately 800 in 2012. There were no other significant changes to the nature or magnitude of the participation of NSP-Minnesota and NSP-Wisconsin in multiemployer plans for the years presented: | |||||||||||||||||||||||||
(Thousands of Dollars) | 2013 | 2012 | 2011 | ||||||||||||||||||||||
Multiemployer pension contributions: | |||||||||||||||||||||||||
NSP-Minnesota | $ | 23,515 | $ | 14,984 | $ | 17,811 | |||||||||||||||||||
NSP-Wisconsin | 130 | 163 | 169 | ||||||||||||||||||||||
Total | $ | 23,645 | $ | 15,147 | $ | 17,980 | |||||||||||||||||||
Multiemployer other postretirement benefit contributions: | |||||||||||||||||||||||||
NSP-Minnesota | $ | 390 | $ | 197 | $ | 336 | |||||||||||||||||||
Total | $ | 390 | $ | 197 | $ | 336 | |||||||||||||||||||
Pension Plans | ' | ||||||||||||||||||||||||
Benefit Plans and Other Postretirement Benefits [Abstract] | ' | ||||||||||||||||||||||||
Target Asset Allocations and Plan Assets Measured at Fair Value | ' | ||||||||||||||||||||||||
The following table presents the target pension asset allocations for Xcel Energy: | |||||||||||||||||||||||||
2013 | 2012 | ||||||||||||||||||||||||
Domestic and international equity securities | 30 | % | 25 | % | |||||||||||||||||||||
Long-duration fixed income and interest rate swap securities | 33 | 40 | |||||||||||||||||||||||
Short-to-intermediate fixed income securities | 15 | 10 | |||||||||||||||||||||||
Alternative investments | 20 | 23 | |||||||||||||||||||||||
Cash | 2 | 2 | |||||||||||||||||||||||
Total | 100 | % | 100 | % | |||||||||||||||||||||
The following tables present, for each of the fair value hierarchy levels, Xcel Energy’s pension plan assets that are measured at fair value as of Dec. 31, 2013 and 2012: | |||||||||||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||||||||||
(Thousands of Dollars) | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||||||
Cash equivalents | $ | 109,700 | $ | — | $ | — | $ | 109,700 | |||||||||||||||||
Derivatives | — | 29,759 | — | 29,759 | |||||||||||||||||||||
Government securities | — | 230,212 | — | 230,212 | |||||||||||||||||||||
Corporate bonds | — | 547,715 | — | 547,715 | |||||||||||||||||||||
Asset-backed securities | — | 6,754 | — | 6,754 | |||||||||||||||||||||
Mortgage-backed securities | — | 15,025 | — | 15,025 | |||||||||||||||||||||
Common stock | 99,346 | — | — | 99,346 | |||||||||||||||||||||
Private equity investments | — | — | 152,849 | 152,849 | |||||||||||||||||||||
Commingled funds | — | 1,769,076 | — | 1,769,076 | |||||||||||||||||||||
Real estate | — | — | 47,553 | 47,553 | |||||||||||||||||||||
Securities lending collateral obligation and other | — | 2,151 | — | 2,151 | |||||||||||||||||||||
Total | $ | 209,046 | $ | 2,600,692 | $ | 200,402 | $ | 3,010,140 | |||||||||||||||||
Dec. 31, 2012 | |||||||||||||||||||||||||
(Thousands of Dollars) | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||||||
Cash equivalents | $ | 164,096 | $ | — | $ | — | $ | 164,096 | |||||||||||||||||
Derivatives | — | 12,955 | — | 12,955 | |||||||||||||||||||||
Government securities | — | 298,141 | — | 298,141 | |||||||||||||||||||||
Corporate bonds | — | 622,597 | — | 622,597 | |||||||||||||||||||||
Asset-backed securities | — | — | 14,639 | 14,639 | |||||||||||||||||||||
Mortgage-backed securities | — | — | 39,904 | 39,904 | |||||||||||||||||||||
Common stock | 73,247 | — | — | 73,247 | |||||||||||||||||||||
Private equity investments | — | — | 158,498 | 158,498 | |||||||||||||||||||||
Commingled funds | — | 1,524,563 | — | 1,524,563 | |||||||||||||||||||||
Real estate | — | — | 64,597 | 64,597 | |||||||||||||||||||||
Securities lending collateral obligation and other | — | (29,454 | ) | — | (29,454 | ) | |||||||||||||||||||
Total | $ | 237,343 | $ | 2,428,802 | $ | 277,638 | $ | 2,943,783 | |||||||||||||||||
Changes in Level 3 Plan Assets | ' | ||||||||||||||||||||||||
The following tables present the changes in Xcel Energy’s Level 3 pension plan assets for the years ended Dec. 31, 2013, 2012 and 2011: | |||||||||||||||||||||||||
(Thousands of Dollars) | Jan. 1, 2013 | Net Realized | Net Unrealized | Purchases, | Transfers Out of Level 3 (a) | Dec. 31, 2013 | |||||||||||||||||||
Gains (Losses) | Gains (Losses) | Issuances and | |||||||||||||||||||||||
Settlements, Net | |||||||||||||||||||||||||
Asset-backed securities | $ | 14,639 | $ | — | $ | — | $ | — | $ | (14,639 | ) | $ | — | ||||||||||||
Mortgage-backed securities | 39,904 | — | — | — | (39,904 | ) | — | ||||||||||||||||||
Private equity investments | 158,498 | 22,058 | (24,335 | ) | (3,372 | ) | — | 152,849 | |||||||||||||||||
Real estate | 64,597 | (2,659 | ) | 8,690 | 9,317 | (32,392 | ) | 47,553 | |||||||||||||||||
Total | $ | 277,638 | $ | 19,399 | $ | (15,645 | ) | $ | 5,945 | $ | (86,935 | ) | $ | 200,402 | |||||||||||
(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 and were subsequently sold during 2013. | ||||||||||||||||||||||||
(Thousands of Dollars) | Jan. 1, 2012 | Net Realized | Net Unrealized | Purchases, | Transfers Out of Level 3 | Dec. 31, 2012 | |||||||||||||||||||
Gains (Losses) | Gains (Losses) | Issuances and | |||||||||||||||||||||||
Settlements, Net | |||||||||||||||||||||||||
Asset-backed securities | $ | 31,368 | $ | 3,886 | $ | (5,363 | ) | $ | (15,252 | ) | $ | — | $ | 14,639 | |||||||||||
Mortgage-backed securities | 73,522 | 1,822 | (2,127 | ) | (33,313 | ) | — | 39,904 | |||||||||||||||||
Private equity investments | 159,363 | 17,537 | (22,587 | ) | 4,185 | — | 158,498 | ||||||||||||||||||
Real estate | 37,106 | 19 | 6,048 | 21,424 | — | 64,597 | |||||||||||||||||||
Total | $ | 301,359 | $ | 23,264 | $ | (24,029 | ) | $ | (22,956 | ) | $ | — | $ | 277,638 | |||||||||||
(Thousands of Dollars) | Jan. 1, 2011 | Net Realized | Net Unrealized | Purchases, | Transfers Out of Level 3 | Dec. 31, 2011 | |||||||||||||||||||
Gains (Losses) | Gains (Losses) | Issuances and | |||||||||||||||||||||||
Settlements, Net | |||||||||||||||||||||||||
Asset-backed securities | $ | 26,986 | $ | 2,391 | $ | (2,504 | ) | $ | 4,495 | $ | — | $ | 31,368 | ||||||||||||
Mortgage-backed securities | 113,418 | 1,103 | (5,926 | ) | (35,073 | ) | — | 73,522 | |||||||||||||||||
Private equity investments | 122,223 | 3,971 | 12,412 | 20,757 | — | 159,363 | |||||||||||||||||||
Real estate | 73,701 | (629 | ) | 20,271 | (56,237 | ) | — | 37,106 | |||||||||||||||||
Total | $ | 336,328 | $ | 6,836 | $ | 24,253 | $ | (66,058 | ) | $ | — | $ | 301,359 | ||||||||||||
Change in Projected Benefit Obligation | ' | ||||||||||||||||||||||||
Benefit Obligations — A comparison of the actuarially computed pension benefit obligation and plan assets for Xcel Energy is presented in the following table: | |||||||||||||||||||||||||
(Thousands of Dollars) | 2013 | 2012 | |||||||||||||||||||||||
Accumulated Benefit Obligation at Dec. 31 | $ | 3,282,651 | $ | 3,475,154 | |||||||||||||||||||||
Change in Projected Benefit Obligation: | |||||||||||||||||||||||||
Obligation at Jan. 1 | $ | 3,639,530 | $ | 3,226,219 | |||||||||||||||||||||
Service cost | 96,282 | 86,364 | |||||||||||||||||||||||
Interest cost | 140,690 | 157,035 | |||||||||||||||||||||||
Plan amendments | (4,120 | ) | 6,240 | ||||||||||||||||||||||
Actuarial (gain) loss | (153,338 | ) | 400,429 | ||||||||||||||||||||||
Benefit payments | (278,340 | ) | (236,757 | ) | |||||||||||||||||||||
Obligation at Dec. 31 | $ | 3,440,704 | $ | 3,639,530 | |||||||||||||||||||||
Change in Fair Value of Plan Assets | ' | ||||||||||||||||||||||||
(Thousands of Dollars) | 2013 | 2012 | |||||||||||||||||||||||
Change in Fair Value of Plan Assets: | |||||||||||||||||||||||||
Fair value of plan assets at Jan. 1 | $ | 2,943,783 | $ | 2,670,280 | |||||||||||||||||||||
Actual return on plan assets | 152,259 | 312,167 | |||||||||||||||||||||||
Employer contributions | 192,438 | 198,093 | |||||||||||||||||||||||
Benefit payments | (278,340 | ) | (236,757 | ) | |||||||||||||||||||||
Fair value of plan assets at Dec. 31 | $ | 3,010,140 | $ | 2,943,783 | |||||||||||||||||||||
Funded Status of Plans | ' | ||||||||||||||||||||||||
(Thousands of Dollars) | 2013 | 2012 | |||||||||||||||||||||||
Funded Status of Plans at Dec. 31: | |||||||||||||||||||||||||
Funded status (a) | $ | (430,564 | ) | $ | (695,747 | ) | |||||||||||||||||||
(a) | Amounts are recognized in noncurrent liabilities on Xcel Energy’s consolidated balance sheets. | ||||||||||||||||||||||||
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost | ' | ||||||||||||||||||||||||
(Thousands of Dollars) | 2013 | 2012 | |||||||||||||||||||||||
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost: | |||||||||||||||||||||||||
Net loss | $ | 1,549,474 | $ | 1,800,770 | |||||||||||||||||||||
Prior service credit | (12,624 | ) | (2,633 | ) | |||||||||||||||||||||
Total | $ | 1,536,850 | $ | 1,798,137 | |||||||||||||||||||||
Amounts Not Yet Recognized as Components of Net Periodic Benefit Costs Recorded on the Balance Sheet Based Upon Expected Recovery in Rates | ' | ||||||||||||||||||||||||
(Thousands of Dollars) | 2013 | 2012 | |||||||||||||||||||||||
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates: | |||||||||||||||||||||||||
Current regulatory assets | $ | 125,702 | $ | 115,811 | |||||||||||||||||||||
Noncurrent regulatory assets | 1,343,432 | 1,606,524 | |||||||||||||||||||||||
Deferred income taxes | 26,403 | 31,075 | |||||||||||||||||||||||
Net-of-tax accumulated OCI | 41,313 | 44,727 | |||||||||||||||||||||||
Total | $ | 1,536,850 | $ | 1,798,137 | |||||||||||||||||||||
Schedule of Assumptions Used | ' | ||||||||||||||||||||||||
2013 | 2012 | 2011 | |||||||||||||||||||||||
Significant Assumptions Used to Measure Costs: | |||||||||||||||||||||||||
Discount rate | 4 | % | 5 | % | 5.5 | % | |||||||||||||||||||
Expected average long-term increase in compensation level | 3.75 | 4 | 4 | ||||||||||||||||||||||
Expected average long-term rate of return on assets | 6.88 | 7.1 | 7.5 | ||||||||||||||||||||||
Measurement date | Dec. 31, 2013 | Dec. 31, 2012 | |||||||||||||||||||||||
2013 | 2012 | ||||||||||||||||||||||||
Significant Assumptions Used to Measure Benefit Obligations: | |||||||||||||||||||||||||
Discount rate for year-end valuation | 4.75 | % | 4 | % | |||||||||||||||||||||
Expected average long-term increase in compensation level | 3.75 | 3.75 | |||||||||||||||||||||||
Mortality table | RP 2000 | RP 2000 | |||||||||||||||||||||||
Components of Net Periodic Benefit Costs | ' | ||||||||||||||||||||||||
Benefit Costs — The components of Xcel Energy’s net periodic pension cost were: | |||||||||||||||||||||||||
(Thousands of Dollars) | 2013 | 2012 | 2011 | ||||||||||||||||||||||
Service cost | $ | 96,282 | $ | 86,364 | $ | 77,319 | |||||||||||||||||||
Interest cost | 140,690 | 157,035 | 161,412 | ||||||||||||||||||||||
Expected return on plan assets | (198,452 | ) | (207,095 | ) | (221,600 | ) | |||||||||||||||||||
Amortization of prior service cost | 5,871 | 21,065 | 22,533 | ||||||||||||||||||||||
Amortization of net loss | 144,151 | 108,982 | 78,510 | ||||||||||||||||||||||
Net periodic pension cost | 188,542 | 166,351 | 118,174 | ||||||||||||||||||||||
Costs not recognized due to effects of regulation | (36,724 | ) | (39,217 | ) | (37,198 | ) | |||||||||||||||||||
Net benefit cost recognized for financial reporting | $ | 151,818 | $ | 127,134 | $ | 80,976 | |||||||||||||||||||
Postretirement Benefit Plan | ' | ||||||||||||||||||||||||
Benefit Plans and Other Postretirement Benefits [Abstract] | ' | ||||||||||||||||||||||||
Target Asset Allocations and Plan Assets Measured at Fair Value | ' | ||||||||||||||||||||||||
The following tables present, for each of the fair value hierarchy levels, Xcel Energy’s postretirement benefit plan assets that are measured at fair value as of Dec. 31, 2013 and 2012: | |||||||||||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||||||||||
(Thousands of Dollars) | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||||||
Cash equivalents | $ | 20,438 | $ | — | $ | — | $ | 20,438 | |||||||||||||||||
Derivatives | — | (414 | ) | — | (414 | ) | |||||||||||||||||||
Government securities | — | 58,421 | — | 58,421 | |||||||||||||||||||||
Insurance contracts | — | 52,808 | — | 52,808 | |||||||||||||||||||||
Corporate bonds | — | 51,861 | — | 51,861 | |||||||||||||||||||||
Asset-backed securities | — | 3,358 | — | 3,358 | |||||||||||||||||||||
Mortgage-backed securities | — | 24,246 | — | 24,246 | |||||||||||||||||||||
Commingled funds | — | 298,258 | — | 298,258 | |||||||||||||||||||||
Other | — | (16,940 | ) | — | (16,940 | ) | |||||||||||||||||||
Total | $ | 20,438 | $ | 471,598 | $ | — | $ | 492,036 | |||||||||||||||||
Dec. 31, 2012 | |||||||||||||||||||||||||
(Thousands of Dollars) | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||||||
Cash equivalents | $ | 91,278 | $ | — | $ | — | $ | 91,278 | |||||||||||||||||
Derivatives | — | 4 | — | 4 | |||||||||||||||||||||
Government securities | — | 73,449 | — | 73,449 | |||||||||||||||||||||
Insurance contracts | — | 50,008 | — | 50,008 | |||||||||||||||||||||
Corporate bonds | — | 43,810 | — | 43,810 | |||||||||||||||||||||
Asset-backed securities | — | — | 757 | 757 | |||||||||||||||||||||
Mortgage-backed securities | — | — | 39,958 | 39,958 | |||||||||||||||||||||
Commingled funds | — | 228,423 | — | 228,423 | |||||||||||||||||||||
Other | — | (46,845 | ) | — | (46,845 | ) | |||||||||||||||||||
Total | $ | 91,278 | $ | 348,849 | $ | 40,715 | $ | 480,842 | |||||||||||||||||
Changes in Level 3 Plan Assets | ' | ||||||||||||||||||||||||
The following tables present the changes in Xcel Energy’s Level 3 postretirement benefit plan assets for the years ended Dec. 31, 2013, 2012 and 2011: | |||||||||||||||||||||||||
(Thousands of Dollars) | Jan. 1, 2013 | Net Realized | Net Unrealized | Purchases, | Transfers Out of Level 3 (a) | Dec. 31, 2013 | |||||||||||||||||||
Gains (Losses) | Gains (Losses) | Issuances and | |||||||||||||||||||||||
Settlements, Net | |||||||||||||||||||||||||
Asset-backed securities | $ | 757 | $ | — | $ | — | $ | — | $ | (757 | ) | $ | — | ||||||||||||
Mortgage-backed securities | 39,958 | — | — | — | (39,958 | ) | — | ||||||||||||||||||
Total | $ | 40,715 | $ | — | $ | — | $ | — | $ | (40,715 | ) | $ | — | ||||||||||||
(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 and were subsequently sold during 2013. | ||||||||||||||||||||||||
(Thousands of Dollars) | Jan. 1, 2012 | Net Realized | Net Unrealized | Purchases, | Transfers Out of Level 3 | Dec. 31, 2012 | |||||||||||||||||||
Gains (Losses) | Gains (Losses) | Issuances and | |||||||||||||||||||||||
Settlements, Net | |||||||||||||||||||||||||
Asset-backed securities | $ | 7,867 | $ | (331 | ) | $ | 1,481 | $ | (8,260 | ) | $ | — | $ | 757 | |||||||||||
Mortgage-backed securities | 27,253 | (724 | ) | 3,301 | 10,128 | — | 39,958 | ||||||||||||||||||
Private equity investments | 479 | — | (65 | ) | (414 | ) | — | — | |||||||||||||||||
Real estate | 144 | — | 35 | (179 | ) | — | — | ||||||||||||||||||
Total | $ | 35,743 | $ | (1,055 | ) | $ | 4,752 | $ | 1,275 | $ | — | $ | 40,715 | ||||||||||||
(Thousands of Dollars) | Jan. 1, 2011 | Net Realized | Net Unrealized | Purchases, | Transfers Out of Level 3 | Dec. 31, 2011 | |||||||||||||||||||
Gains (Losses) | Gains (Losses) | Issuances and | |||||||||||||||||||||||
Settlements, Net | |||||||||||||||||||||||||
Asset-backed securities | $ | 2,585 | $ | (10 | ) | $ | (664 | ) | $ | 5,956 | $ | — | $ | 7,867 | |||||||||||
Mortgage-backed securities | 19,212 | (1,669 | ) | 2,623 | 7,087 | — | 27,253 | ||||||||||||||||||
Private equity investments | — | 12 | 53 | 414 | — | 479 | |||||||||||||||||||
Real estate | — | (2 | ) | (34 | ) | 180 | — | 144 | |||||||||||||||||
Total | $ | 21,797 | $ | (1,669 | ) | $ | 1,978 | $ | 13,637 | $ | — | $ | 35,743 | ||||||||||||
Change in Projected Benefit Obligation | ' | ||||||||||||||||||||||||
Benefit Obligations — A comparison of the actuarially computed benefit obligation and plan assets for Xcel Energy is presented in the following table: | |||||||||||||||||||||||||
(Thousands of Dollars) | 2013 | 2012 | |||||||||||||||||||||||
Change in Projected Benefit Obligation: | |||||||||||||||||||||||||
Obligation at Jan. 1 | $ | 851,952 | $ | 776,847 | |||||||||||||||||||||
Service cost | 4,079 | 4,203 | |||||||||||||||||||||||
Interest cost | 32,141 | 37,861 | |||||||||||||||||||||||
Medicare subsidy reimbursements | 1,197 | 3,741 | |||||||||||||||||||||||
Plan amendments | (14,571 | ) | (41,128 | ) | |||||||||||||||||||||
Plan participants’ contributions | 9,580 | 14,241 | |||||||||||||||||||||||
Actuarial (gain) loss | (103,359 | ) | 119,949 | ||||||||||||||||||||||
Benefit payments | (49,591 | ) | (63,762 | ) | |||||||||||||||||||||
Obligation at Dec. 31 | $ | 731,428 | $ | 851,952 | |||||||||||||||||||||
Change in Fair Value of Plan Assets | ' | ||||||||||||||||||||||||
(Thousands of Dollars) | 2013 | 2012 | |||||||||||||||||||||||
Change in Fair Value of Plan Assets: | |||||||||||||||||||||||||
Fair value of plan assets at Jan. 1 | $ | 480,842 | $ | 426,835 | |||||||||||||||||||||
Actual return on plan assets | 33,644 | 56,385 | |||||||||||||||||||||||
Plan participants’ contributions | 9,580 | 14,241 | |||||||||||||||||||||||
Employer contributions | 17,561 | 47,143 | |||||||||||||||||||||||
Benefit payments | (49,591 | ) | (63,762 | ) | |||||||||||||||||||||
Fair value of plan assets at Dec. 31 | $ | 492,036 | $ | 480,842 | |||||||||||||||||||||
Funded Status of Plans | ' | ||||||||||||||||||||||||
(Thousands of Dollars) | 2013 | 2012 | |||||||||||||||||||||||
Funded Status of Plans at Dec. 31: | |||||||||||||||||||||||||
Funded status | $ | (239,392 | ) | $ | (371,110 | ) | |||||||||||||||||||
Current liabilities | (6,807 | ) | (6,070 | ) | |||||||||||||||||||||
Noncurrent liabilities | (232,585 | ) | (365,040 | ) | |||||||||||||||||||||
Net postretirement amounts recognized on consolidated balance sheets | $ | (239,392 | ) | $ | (371,110 | ) | |||||||||||||||||||
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost | ' | ||||||||||||||||||||||||
(Thousands of Dollars) | 2013 | 2012 | |||||||||||||||||||||||
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost: | |||||||||||||||||||||||||
Net loss | $ | 195,630 | $ | 321,946 | |||||||||||||||||||||
Prior service credit | (86,298 | ) | (84,228 | ) | |||||||||||||||||||||
Transition obligation | 2 | 827 | |||||||||||||||||||||||
Total | $ | 109,334 | $ | 238,545 | |||||||||||||||||||||
Amounts Not Yet Recognized as Components of Net Periodic Benefit Costs Recorded on the Balance Sheet Based Upon Expected Recovery in Rates | ' | ||||||||||||||||||||||||
(Thousands of Dollars) | 2013 | 2012 | |||||||||||||||||||||||
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates: | |||||||||||||||||||||||||
Current regulatory assets | $ | 12,102 | $ | 6,930 | |||||||||||||||||||||
Noncurrent regulatory assets | 99,071 | 226,052 | |||||||||||||||||||||||
Current regulatory liabilities | (319 | ) | (954 | ) | |||||||||||||||||||||
Noncurrent regulatory liabilities | (8,858 | ) | (3,453 | ) | |||||||||||||||||||||
Deferred income taxes | 2,965 | 4,050 | |||||||||||||||||||||||
Net-of-tax accumulated OCI | 4,373 | 5,920 | |||||||||||||||||||||||
Total | $ | 109,334 | $ | 238,545 | |||||||||||||||||||||
Schedule of Assumptions Used | ' | ||||||||||||||||||||||||
2013 | 2012 | 2011 | |||||||||||||||||||||||
Significant Assumptions Used to Measure Costs: | |||||||||||||||||||||||||
Discount rate | 4.1 | % | 5 | % | 5.5 | % | |||||||||||||||||||
Expected average long-term rate of return on assets | 7.11 | 6.75 | 7.5 | ||||||||||||||||||||||
Measurement date | Dec. 31, 2013 | Dec. 31, 2012 | |||||||||||||||||||||||
2013 | 2012 | ||||||||||||||||||||||||
Significant Assumptions Used to Measure Benefit Obligations: | |||||||||||||||||||||||||
Discount rate for year-end valuation | 4.82 | % | 4.1 | % | |||||||||||||||||||||
Mortality table | RP 2000 | RP 2000 | |||||||||||||||||||||||
Health care costs trend rate — initial | 7 | 7.5 | |||||||||||||||||||||||
Components of Net Periodic Benefit Costs | ' | ||||||||||||||||||||||||
Benefit Costs — The components of Xcel Energy’s net periodic postretirement benefit costs were: | |||||||||||||||||||||||||
(Thousands of Dollars) | 2013 | 2012 | 2011 | ||||||||||||||||||||||
Service cost | $ | 4,079 | $ | 4,203 | $ | 4,824 | |||||||||||||||||||
Interest cost | 32,141 | 37,861 | 42,086 | ||||||||||||||||||||||
Expected return on plan assets | (33,011 | ) | (28,409 | ) | (31,962 | ) | |||||||||||||||||||
Amortization of transition obligation | 825 | 14,320 | 14,444 | ||||||||||||||||||||||
Amortization of prior service credit | (12,501 | ) | (7,552 | ) | (4,932 | ) | |||||||||||||||||||
Amortization of net loss | 22,325 | 16,906 | 13,294 | ||||||||||||||||||||||
Net periodic postretirement benefit cost | 13,858 | 37,329 | 37,754 | ||||||||||||||||||||||
Additional cost recognized due to effects of regulation | — | 3,891 | 3,891 | ||||||||||||||||||||||
Net benefit cost recognized for financial reporting | $ | 13,858 | $ | 41,220 | $ | 41,645 | |||||||||||||||||||
Effects of One-Percent Change in Assumed Health Care Cost Trend Rate | ' | ||||||||||||||||||||||||
A one-percent change in the assumed health care cost trend rate would have the following effects on Xcel Energy: | |||||||||||||||||||||||||
One-Percentage Point | |||||||||||||||||||||||||
(Thousands of Dollars) | Increase | Decrease | |||||||||||||||||||||||
APBO | $ | 75,617 | $ | (63,360 | ) | ||||||||||||||||||||
Service and interest components | 3,580 | (2,826 | ) | ||||||||||||||||||||||
Other_Income_Net_Tables
Other Income, Net (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2013 | |||||||||||||
Other Income and Expenses [Abstract] | ' | ||||||||||||
Other Income, Net | ' | ||||||||||||
Other income, net for the years ended Dec. 31 consisted of the following: | |||||||||||||
(Thousands of Dollars) | 2013 | 2012 | 2011 | ||||||||||
Interest income | $ | 8,343 | $ | 10,327 | $ | 10,639 | |||||||
Other nonoperating income | 3,025 | 3,483 | 3,722 | ||||||||||
Insurance policy expense | (8,292 | ) | (7,365 | ) | (4,785 | ) | |||||||
Other nonoperating expense | (104 | ) | (270 | ) | (321 | ) | |||||||
Other income, net | $ | 2,972 | $ | 6,175 | $ | 9,255 | |||||||
Fair_Value_of_Financial_Assets1
Fair Value of Financial Assets and Liabilities (Tables) | 12 Months Ended | ||||||||||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||||||||||
Fair Value Disclosures [Abstract] | ' | ||||||||||||||||||||||||
Cost and Fair Value of Nuclear Decommissioning Fund Investments | ' | ||||||||||||||||||||||||
The following tables present the cost and fair value of Xcel Energy’s non-derivative instruments with recurring fair value measurements in the nuclear decommissioning fund at Dec. 31, 2013 and 2012: | |||||||||||||||||||||||||
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. | ||||||||||||||||||||||||
Dec. 31, 2012 | |||||||||||||||||||||||||
Fair Value | |||||||||||||||||||||||||
(Thousands of Dollars) | Cost | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||
Nuclear decommissioning fund (a) | |||||||||||||||||||||||||
Cash equivalents | $ | 246,904 | $ | 237,938 | $ | 8,966 | $ | — | $ | 246,904 | |||||||||||||||
Commingled funds | 396,681 | — | 417,583 | — | 417,583 | ||||||||||||||||||||
International equity funds | 66,452 | — | 69,481 | — | 69,481 | ||||||||||||||||||||
Private equity investments | 27,943 | — | — | 33,250 | 33,250 | ||||||||||||||||||||
Real estate | 32,561 | — | — | 39,074 | 39,074 | ||||||||||||||||||||
Debt securities: | |||||||||||||||||||||||||
Government securities | 21,092 | — | 21,521 | — | 21,521 | ||||||||||||||||||||
U.S. corporate bonds | 162,053 | — | 169,488 | — | 169,488 | ||||||||||||||||||||
International corporate bonds | 15,165 | — | 16,052 | — | 16,052 | ||||||||||||||||||||
Municipal bonds | 21,392 | — | 23,650 | — | 23,650 | ||||||||||||||||||||
Asset-backed securities | 2,066 | — | — | 2,067 | 2,067 | ||||||||||||||||||||
Mortgage-backed securities | 28,743 | — | — | 30,209 | 30,209 | ||||||||||||||||||||
Equity securities: | |||||||||||||||||||||||||
Common stock | 379,093 | 420,263 | — | — | 420,263 | ||||||||||||||||||||
Total | $ | 1,400,145 | $ | 658,201 | $ | 726,741 | $ | 104,600 | $ | 1,489,542 | |||||||||||||||
(a) | Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $91.2 million of equity investments in unconsolidated subsidiaries and $37.1 million of miscellaneous investments. | ||||||||||||||||||||||||
Changes in Level 3 Nuclear Decommissioning Fund Investments | ' | ||||||||||||||||||||||||
The following tables present the changes in Level 3 nuclear decommissioning fund investments: | |||||||||||||||||||||||||
(Thousands of Dollars) | Jan. 1, 2013 | Purchases | Settlements | Gains | Transfers Out of Level 3 (a) | Dec. 31, 2013 | |||||||||||||||||||
Recognized as | |||||||||||||||||||||||||
Regulatory Assets and Liabilities | |||||||||||||||||||||||||
Private equity investments | $ | 33,250 | $ | 24,201 | $ | — | $ | 5,245 | $ | — | $ | 62,696 | |||||||||||||
Real estate | 39,074 | 31,626 | (18,622 | ) | 5,290 | — | 57,368 | ||||||||||||||||||
Asset-backed securities | 2,067 | — | — | — | (2,067 | ) | — | ||||||||||||||||||
Mortgage-backed securities | 30,209 | — | — | — | (30,209 | ) | — | ||||||||||||||||||
Total | $ | 104,600 | $ | 55,827 | $ | (18,622 | ) | $ | 10,535 | $ | (32,276 | ) | $ | 120,064 | |||||||||||
(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 and were subsequently sold during 2013. | ||||||||||||||||||||||||
(Thousands of Dollars) | Jan. 1, 2012 | Purchases | Settlements | Gains (Losses) | Transfers Out of Level 3 | Dec. 31, 2012 | |||||||||||||||||||
Recognized as | |||||||||||||||||||||||||
Regulatory Assets and Liabilities | |||||||||||||||||||||||||
Private equity investments | $ | 9,203 | $ | 20,671 | $ | (1,931 | ) | $ | 5,307 | $ | — | $ | 33,250 | ||||||||||||
Real estate | 26,395 | 9,777 | (3,611 | ) | 6,513 | — | 39,074 | ||||||||||||||||||
Asset-backed securities | 16,501 | — | (14,450 | ) | 16 | — | 2,067 | ||||||||||||||||||
Mortgage-backed securities | 78,664 | 33,016 | (79,899 | ) | (1,572 | ) | — | 30,209 | |||||||||||||||||
Total | $ | 130,763 | $ | 63,464 | $ | (99,891 | ) | $ | 10,264 | $ | — | $ | 104,600 | ||||||||||||
(Thousands of Dollars) | Jan. 1, 2011 | Purchases | Settlements | Gains (Losses) | Transfers Out of Level 3 | Dec. 31, 2011 | |||||||||||||||||||
Recognized as | |||||||||||||||||||||||||
Regulatory Assets and Liabilities | |||||||||||||||||||||||||
Private equity investments | $ | — | $ | 9,203 | $ | — | $ | — | $ | — | $ | 9,203 | |||||||||||||
Real estate | — | 24,768 | — | 1,627 | — | 26,395 | |||||||||||||||||||
Asset-backed securities | 33,174 | 16,518 | (32,560 | ) | (631 | ) | — | 16,501 | |||||||||||||||||
Mortgage-backed securities | 72,589 | 168,688 | (161,134 | ) | (1,479 | ) | — | 78,664 | |||||||||||||||||
Total | $ | 105,763 | $ | 219,177 | $ | (193,694 | ) | $ | (483 | ) | $ | — | $ | 130,763 | |||||||||||
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 Dec. 31, 2013: | |||||||||||||||||||||||||
Final Contractual Maturity | |||||||||||||||||||||||||
(Thousands of Dollars) | Due in 1 Year | Due in 1 to 5 | Due in 5 to 10 | Due after 10 | Total | ||||||||||||||||||||
or Less | Years | Years | Years | ||||||||||||||||||||||
Government securities | $ | — | $ | — | $ | — | $ | 27,628 | $ | 27,628 | |||||||||||||||
U.S. corporate bonds | 780 | 17,850 | 63,089 | 1,819 | 83,538 | ||||||||||||||||||||
International corporate bonds | — | 2,222 | 13,136 | — | 15,358 | ||||||||||||||||||||
Municipal bonds | 3,554 | 25,663 | 33,109 | 169,690 | 232,016 | ||||||||||||||||||||
Debt securities | $ | 4,334 | $ | 45,735 | $ | 109,334 | $ | 199,137 | $ | 358,540 | |||||||||||||||
Gross Notional Amounts of Commodity Forwards, Options, and FTRs | ' | ||||||||||||||||||||||||
The following table details the gross notional amounts of commodity forwards, options and FTRs at Dec. 31, 2013 and 2012: | |||||||||||||||||||||||||
(Amounts in Thousands) (a)(b) | Dec. 31, 2013 | Dec. 31, 2012 | |||||||||||||||||||||||
MWh of electricity | 58,423 | 55,976 | |||||||||||||||||||||||
MMBtu of natural gas | 9,854 | 725 | |||||||||||||||||||||||
Gallons of vehicle fuel | 482 | 682 | |||||||||||||||||||||||
(a) | Amounts are not reflective of net positions in the underlying commodities. | ||||||||||||||||||||||||
(b) | Notional amounts for options are included on a gross basis, but are weighted for the probability of exercise. | ||||||||||||||||||||||||
Financial Impact of Qualifying Cash Flow Hedges on Accumulated Other Comprehensive Loss | ' | ||||||||||||||||||||||||
Financial Impact of Qualifying Cash Flow Hedges — The impact of qualifying interest rate and vehicle fuel cash flow hedges on Xcel Energy’s accumulated other comprehensive loss, included in the consolidated statements of common stockholders’ equity and in the consolidated statements of comprehensive income, is detailed in the following table: | |||||||||||||||||||||||||
(Thousands of Dollars) | 2013 | 2012 | 2011 | ||||||||||||||||||||||
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1 | $ | (61,241 | ) | $ | (45,738 | ) | $ | (8,094 | ) | ||||||||||||||||
After-tax net unrealized gains (losses) related to derivatives accounted for as hedges | 12 | (19,200 | ) | (38,292 | ) | ||||||||||||||||||||
After-tax net realized losses on derivative transactions reclassified into earnings | 1,476 | 3,697 | 648 | ||||||||||||||||||||||
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31 | $ | (59,753 | ) | $ | (61,241 | ) | $ | (45,738 | ) | ||||||||||||||||
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 years ended Dec. 31, 2013, 2012 and 2011, on accumulated other comprehensive loss, regulatory assets and liabilities, and income: | |||||||||||||||||||||||||
Year Ended Dec. 31, 2013 | |||||||||||||||||||||||||
Pre-Tax Fair Value | Pre-Tax (Gains) Losses | Pre-Tax Gains (Losses) | |||||||||||||||||||||||
Gains (Losses) Recognized | Reclassified into Income | Recognized | |||||||||||||||||||||||
During the Period in: | During the Period from: | During the Period in Income | |||||||||||||||||||||||
(Thousands of Dollars) | Accumulated | Regulatory | Accumulated | Regulatory | |||||||||||||||||||||
Other | (Assets) and Liabilities | Other | Assets and(Liabilities) | ||||||||||||||||||||||
Comprehensive Loss | Comprehensive Loss | ||||||||||||||||||||||||
Derivatives designated as cash flow hedges | |||||||||||||||||||||||||
Interest rate | $ | — | $ | — | $ | 4,107 | (a) | $ | — | $ | — | ||||||||||||||
Vehicle fuel and other commodity | 29 | — | (90 | ) | (b) | — | — | ||||||||||||||||||
Total | $ | 29 | $ | — | $ | 4,017 | $ | — | $ | — | |||||||||||||||
Other derivative instruments | |||||||||||||||||||||||||
Commodity trading | $ | — | $ | — | $ | — | $ | — | $ | 11,221 | (c) | ||||||||||||||
Electric commodity | — | 75,817 | — | (52,796 | ) | (d) | — | ||||||||||||||||||
Natural gas commodity | — | (3,088 | ) | — | 5,019 | (e) | (6,589 | ) | (d) | ||||||||||||||||
Total | $ | — | $ | 72,729 | $ | — | $ | (47,777 | ) | $ | 4,632 | ||||||||||||||
Year Ended Dec. 31, 2012 | |||||||||||||||||||||||||
Pre-Tax Fair Value | Pre-Tax (Gains) Losses | Pre-Tax Gains | |||||||||||||||||||||||
Gains (Losses) Recognized | Reclassified into Income | (Losses) Recognized | |||||||||||||||||||||||
During the Period in: | During the Period from: | During the Period in Income | |||||||||||||||||||||||
(Thousands of Dollars) | Accumulated | Regulatory | Accumulated | Regulatory | |||||||||||||||||||||
Other | (Assets) and Liabilities | Other | Assets and (Liabilities) | ||||||||||||||||||||||
Comprehensive Loss | Comprehensive Loss | ||||||||||||||||||||||||
Derivatives designated as cash flow hedges | |||||||||||||||||||||||||
Interest rate | $ | (31,913 | ) | $ | — | $ | 6,582 | (a) | $ | — | $ | — | |||||||||||||
Vehicle fuel and other commodity | 120 | — | (198 | ) | (b) | — | — | ||||||||||||||||||
Total | $ | (31,793 | ) | $ | — | $ | 6,384 | $ | — | $ | — | ||||||||||||||
Other derivative instruments | |||||||||||||||||||||||||
Commodity trading | $ | — | $ | — | $ | — | $ | — | $ | 12,226 | (c) | ||||||||||||||
Electric commodity | — | 44,162 | — | (39,999 | ) | (d) | — | ||||||||||||||||||
Natural gas commodity | — | (10,809 | ) | — | 80,902 | (e) | (137 | ) | (d) | ||||||||||||||||
Total | $ | — | $ | 33,353 | $ | — | $ | 40,903 | $ | 12,089 | |||||||||||||||
Year Ended Dec. 31, 2011 | |||||||||||||||||||||||||
Pre-Tax Fair Value | Pre-Tax (Gains) Losses | Pre-Tax Gains | |||||||||||||||||||||||
Gains (Losses) Recognized | Reclassified into Income | (Losses) Recognized | |||||||||||||||||||||||
During the Period in: | During the Period from: | During the Period in Income | |||||||||||||||||||||||
(Thousands of Dollars) | Accumulated | Regulatory | Accumulated | Regulatory | |||||||||||||||||||||
Other | (Assets) and Liabilities | Other | Assets and(Liabilities) | ||||||||||||||||||||||
Comprehensive Loss | Comprehensive Loss | ||||||||||||||||||||||||
Derivatives designated as cash flow hedges | |||||||||||||||||||||||||
Interest rate | $ | (63,573 | ) | $ | — | $ | 1,424 | (a) | $ | — | $ | — | |||||||||||||
Vehicle fuel and other commodity | 195 | — | (178 | ) | (b) | — | — | ||||||||||||||||||
Total | $ | (63,378 | ) | $ | — | $ | 1,246 | $ | — | $ | — | ||||||||||||||
Other derivative instruments | |||||||||||||||||||||||||
Commodity trading | $ | — | $ | — | $ | — | $ | — | $ | 6,418 | (c) | ||||||||||||||
Electric commodity | — | 49,818 | — | (40,492 | ) | (d) | — | ||||||||||||||||||
Natural gas commodity | — | (111,574 | ) | — | 91,743 | (e) | (382 | ) | (d) | ||||||||||||||||
Total | $ | — | $ | (61,756 | ) | $ | — | $ | 51,251 | $ | 6,036 | ||||||||||||||
(a) | Amounts are recorded to interest charges. | ||||||||||||||||||||||||
(b) | Amounts are recorded to O&M expenses. | ||||||||||||||||||||||||
(c) | Amounts are recorded to electric operating revenues. Portions of these gains and losses are subject to sharing with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate. | ||||||||||||||||||||||||
(d) | Amounts are recorded to electric fuel and purchased power. These derivative settlement gains and losses are shared with electric customers through fuel and purchased energy cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate. | ||||||||||||||||||||||||
(e) | Amounts for the years ended Dec. 31, 2012 and 2011 included $5.0 million and $12.7 million, respectively, of settlement losses on derivatives entered to mitigate natural gas price risk for electric generation, recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate. Such losses for the year ended Dec. 31, 2013 were immaterial. The remaining settlement losses for the years ended Dec. 31, 2013, 2012 and 2011 relate to natural gas operations and are recorded to cost of natural gas sold and transported. These losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset, as appropriate. | ||||||||||||||||||||||||
Derivative Assets and Liabilities Measured at Fair Value on a Recurring Basis by Hierarchy Level | ' | ||||||||||||||||||||||||
Recurring Fair Value Measurements — The following table presents for each of the fair value hierarchy levels, Xcel Energy’s derivative assets and liabilities measured at fair value on a recurring basis at Dec. 31, 2013: | |||||||||||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||||||||||
Fair Value | Fair Value Total | Counterparty | |||||||||||||||||||||||
(Thousands of Dollars) | Level 1 | Level 2 | Level 3 | Netting (b) | Total | ||||||||||||||||||||
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 | |||||||||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||||||||||
Fair Value | Fair Value Total | Counterparty | |||||||||||||||||||||||
(Thousands of Dollars) | Level 1 | Level 2 | Level 3 | Netting (b) | Total | ||||||||||||||||||||
Current derivative liabilities | |||||||||||||||||||||||||
Other derivative instruments: | |||||||||||||||||||||||||
Commodity trading | $ | — | $ | 10,546 | $ | 1,804 | $ | 12,350 | $ | (12,002 | ) | $ | 348 | ||||||||||||
Electric commodity | — | — | 8,210 | 8,210 | (8,210 | ) | — | ||||||||||||||||||
Total current derivative liabilities | $ | — | $ | 10,546 | $ | 10,014 | $ | 20,560 | $ | (20,212 | ) | 348 | |||||||||||||
PPAs (a) | 23,034 | ||||||||||||||||||||||||
Current derivative instruments | $ | 23,382 | |||||||||||||||||||||||
Noncurrent derivative liabilities | |||||||||||||||||||||||||
Other derivative instruments: | |||||||||||||||||||||||||
Commodity trading | $ | — | $ | 14,382 | $ | — | $ | 14,382 | $ | (9,087 | ) | $ | 5,295 | ||||||||||||
Total noncurrent derivative liabilities | $ | — | $ | 14,382 | $ | — | $ | 14,382 | $ | (9,087 | ) | 5,295 | |||||||||||||
PPAs (a) | 203,929 | ||||||||||||||||||||||||
Noncurrent derivative instruments | $ | 209,224 | |||||||||||||||||||||||
(a) | In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, Xcel Energy began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, Xcel Energy qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities. | ||||||||||||||||||||||||
(b) | Xcel Energy nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2013. At Dec. 31, 2013, derivative assets and liabilities include obligations to return cash collateral of $0.2 million and rights to reclaim cash collateral of $4.2 million. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements. | ||||||||||||||||||||||||
The following table presents for each of the fair value hierarchy levels, Xcel Energy’s derivative assets and liabilities measured at fair value on a recurring basis at Dec. 31, 2012: | |||||||||||||||||||||||||
Dec. 31, 2012 | |||||||||||||||||||||||||
Fair Value | Fair Value Total | Counterparty | |||||||||||||||||||||||
(Thousands of Dollars) | Level 1 | Level 2 | Level 3 | Netting (b) | Total | ||||||||||||||||||||
Current derivative assets | |||||||||||||||||||||||||
Derivatives designated as cash flow hedges: | |||||||||||||||||||||||||
Vehicle fuel and other commodity | $ | — | $ | 95 | $ | — | $ | 95 | $ | — | $ | 95 | |||||||||||||
Other derivative instruments: | |||||||||||||||||||||||||
Commodity trading | — | 26,303 | 692 | 26,995 | (6,675 | ) | 20,320 | ||||||||||||||||||
Electric commodity | — | — | 16,724 | 16,724 | (843 | ) | 15,881 | ||||||||||||||||||
Natural gas commodity | — | 7 | — | 7 | (7 | ) | — | ||||||||||||||||||
Total current derivative assets | $ | — | $ | 26,405 | $ | 17,416 | $ | 43,821 | $ | (7,525 | ) | 36,296 | |||||||||||||
PPAs (a) | 32,717 | ||||||||||||||||||||||||
Current derivative instruments | $ | 69,013 | |||||||||||||||||||||||
Noncurrent derivative assets | |||||||||||||||||||||||||
Derivatives designated as cash flow hedges: | |||||||||||||||||||||||||
Vehicle fuel and other commodity | $ | — | $ | 86 | $ | — | $ | 86 | $ | (47 | ) | $ | 39 | ||||||||||||
Other derivative instruments: | |||||||||||||||||||||||||
Commodity trading | — | 41,282 | 77 | 41,359 | (4,162 | ) | 37,197 | ||||||||||||||||||
Total noncurrent derivative assets | $ | — | $ | 41,368 | $ | 77 | $ | 41,445 | $ | (4,209 | ) | 37,236 | |||||||||||||
PPAs (a) | 89,061 | ||||||||||||||||||||||||
Noncurrent derivative instruments | $ | 126,297 | |||||||||||||||||||||||
Dec. 31, 2012 | |||||||||||||||||||||||||
Fair Value | Fair Value Total | Counterparty | |||||||||||||||||||||||
(Thousands of Dollars) | Level 1 | Level 2 | Level 3 | Netting (b) | Total | ||||||||||||||||||||
Current derivative liabilities | |||||||||||||||||||||||||
Other derivative instruments: | |||||||||||||||||||||||||
Commodity trading | $ | — | $ | 18,622 | $ | 1 | $ | 18,623 | $ | (9,112 | ) | $ | 9,511 | ||||||||||||
Electric commodity | — | — | 843 | 843 | (843 | ) | — | ||||||||||||||||||
Natural gas commodity | — | 98 | — | 98 | (7 | ) | 91 | ||||||||||||||||||
Total current derivative liabilities | $ | — | $ | 18,720 | $ | 844 | $ | 19,564 | $ | (9,962 | ) | 9,602 | |||||||||||||
PPAs (a) | 22,880 | ||||||||||||||||||||||||
Current derivative instruments | $ | 32,482 | |||||||||||||||||||||||
Noncurrent derivative liabilities | |||||||||||||||||||||||||
Other derivative instruments: | |||||||||||||||||||||||||
Commodity trading | $ | — | $ | 21,417 | $ | — | $ | 21,417 | $ | (4,210 | ) | $ | 17,207 | ||||||||||||
Total noncurrent derivative liabilities | $ | — | $ | 21,417 | $ | — | $ | 21,417 | $ | (4,210 | ) | 17,207 | |||||||||||||
PPAs (a) | 225,659 | ||||||||||||||||||||||||
Noncurrent derivative instruments | $ | 242,866 | |||||||||||||||||||||||
(a) | In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, Xcel Energy began recording several long-term 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, 2012. At Dec. 31, 2012, derivative assets and liabilities include obligations to return cash collateral of $0.6 million and rights to reclaim cash collateral of $3.0 million. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements. | ||||||||||||||||||||||||
Changes in Level 3 Commodity Derivatives | ' | ||||||||||||||||||||||||
The following table presents the changes in Level 3 commodity derivatives for the years ended Dec. 31, 2013, 2012 and 2011: | |||||||||||||||||||||||||
Year Ended Dec. 31 | |||||||||||||||||||||||||
(Thousands of Dollars) | 2013 | 2012 | 2011 | ||||||||||||||||||||||
Balance at Jan. 1 | $ | 16,649 | $ | 12,417 | $ | 2,392 | |||||||||||||||||||
Purchases | 61,474 | 37,595 | 33,609 | ||||||||||||||||||||||
Settlements | (45,199 | ) | (44,950 | ) | (36,555 | ) | |||||||||||||||||||
Net transactions recorded during the period: | |||||||||||||||||||||||||
Gains recognized in earnings (a) | 3,947 | 463 | 69 | ||||||||||||||||||||||
Gains recognized as regulatory assets and liabilities | 4,789 | 11,124 | 12,902 | ||||||||||||||||||||||
Balance at Dec. 31 | $ | 41,660 | $ | 16,649 | $ | 12,417 | |||||||||||||||||||
(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 Dec. 31, 2013 and 2012, other financial instruments for which the carrying amount did not equal fair value were as follows: | |||||||||||||||||||||||||
2013 | 2012 | ||||||||||||||||||||||||
(Thousands of Dollars) | Carrying Amount | Fair Value | Carrying Amount | Fair Value | |||||||||||||||||||||
Long-term debt, including current portion | $ | 11,191,517 | $ | 11,878,643 | $ | 10,402,060 | $ | 12,207,866 | |||||||||||||||||
Rate_Matters_Tables
Rate Matters (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2013 | |||||||||||||
Public Utilities, General Disclosures [Abstract] | ' | ||||||||||||
NSP-Minnesota's 2014 Electric Rate Case | ' | ||||||||||||
The rate request, moderation plan, interim rate adjustments, customer bill impacts and certain impacts on expenses are detailed in the table below: | |||||||||||||
(Millions of Dollars) | 2014 | Percentage | 2015 | Percentage | |||||||||
Increase | Increase | ||||||||||||
Pre-moderation deficiency | $ | 274 | $ | 81 | |||||||||
Moderation change compared to prior year: | |||||||||||||
Excess theoretical depreciation reserve | (81 | ) | 53 | ||||||||||
DOE settlement proceeds | — | (36 | ) | ||||||||||
Filed rate request | 193 | 6.90% | 98 | 3.50% | |||||||||
Interim rate adjustments | (66 | ) | 66 | ||||||||||
Impact on customer bill | 127 | 4.60% | 164 | 5.60% | |||||||||
Potential expense deferral (Monticello/Prairie Island EPU projects) | 16 | — | |||||||||||
Depreciation expense - reduction/(increase) | 81 | (46 | ) | ||||||||||
Recognition of DOE settlement proceeds | — | 36 | |||||||||||
Pre-tax impact on operating income | $ | 224 | $ | 154 | |||||||||
MPUC's Approval of 2013 Electric Rate Case | ' | ||||||||||||
The table below reconciles NSP-Minnesota’s original request to the final MPUC order: | |||||||||||||
(Millions of Dollars) | MPUC Order | ||||||||||||
NSP-Minnesota original request | $ | 285 | |||||||||||
ROE | (43 | ) | |||||||||||
Sherco Unit 3 | (34 | ) | |||||||||||
Reduced recovery for nuclear plants | (15 | ) | |||||||||||
Incentive compensation | (4 | ) | |||||||||||
Sales forecast | (26 | ) | |||||||||||
Pension | (13 | ) | |||||||||||
Employee benefits | (6 | ) | |||||||||||
Black Dog remediation | (5 | ) | |||||||||||
Estimated impact of the theoretical depreciation reserve | (24 | ) | |||||||||||
NSP-Wisconsin wholesale allocation | (7 | ) | |||||||||||
Other, net | (5 | ) | |||||||||||
Recommended rate increase | 103 | ||||||||||||
Estimated impact of cost deferrals | 20 | ||||||||||||
Estimated impact of the theoretical depreciation reserve | 24 | ||||||||||||
Impact on pre-tax income | $ | 147 | |||||||||||
NSP-Minnesota and NDPSC Settlement Agreement Rate Base Impact 2013 | ' | ||||||||||||
The table below reflects the amended settlement’s 2013 impact. | |||||||||||||
(Millions of Dollars) | Amended Settlement Impact | ||||||||||||
Proposed 12 month settlement base rate increase | $ | 9 | |||||||||||
Pre-effective period impact (Jan. 1, 2013 - Feb. 15, 2013) | (1.6 | ) | |||||||||||
Proposed settlement base rate increase | 7.4 | ||||||||||||
Retention of DOE settlement proceeds | 3.9 | ||||||||||||
Other, net | (0.3 | ) | |||||||||||
Amended settlement’s 2013 impact | $ | 11 | |||||||||||
CPUC decision in the PSCo Colorado 2013 Gas Rate Case | ' | ||||||||||||
The following table summarizes the CPUC decision: | |||||||||||||
(Millions of Dollars) | CPUC Decision | ||||||||||||
PSCo deficiency based on a FTY | $ | 44.8 | |||||||||||
HTY adjustment | (5.4 | ) | |||||||||||
ROE and capital structure adjustments | (8.3 | ) | |||||||||||
Revenue adjustments | (1.4 | ) | |||||||||||
Other | (0.1 | ) | |||||||||||
Recommendation | 29.6 | ||||||||||||
Neutralize PSIA - base rate transfer | (13.8 | ) | |||||||||||
Incremental base revenue | $ | 15.8 | |||||||||||
SPS' Texas 2014 Electric Rate Case | ' | ||||||||||||
SPS – Texas 2014 Electric Rate Case — On Jan. 7, 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 reflects a base rate increase, revenue credits transferred from base rates to rate riders or the fuel clause, and resetting the TCRF to zero when the final base rates become effective, as shown in the following table: | |||||||||||||
(Millions of Dollars) | SPS Request | ||||||||||||
Base rate increase | $ | 81.5 | |||||||||||
Resetting TCRF | (12.9 | ) | |||||||||||
Credit to customers for gain on sale to Lubbock moved to a rider | (4.9 | ) | |||||||||||
Net increase in base revenue | 63.7 | ||||||||||||
Fuel clause offsets | (11.0 | ) | |||||||||||
Retail customer net bill impact | $ | 52.7 | |||||||||||
New Mexico Public Regulation Commission (NMPRC) and New Mexico Attorney General (NMAG) recommendations to SPS' New Mexico 2014 Electric Rate Case | ' | ||||||||||||
The following table summarizes certain parties’ recommendations from SPS’ revised request: | |||||||||||||
(Millions of Dollars) | Staff | NMAG | |||||||||||
Testimony | Testimony | ||||||||||||
Aug-13 | Aug-13 | ||||||||||||
SPS revised request | $ | 43.3 | $ | 43.3 | |||||||||
Rate rider for renewable energy costs (a) | (14.5 | ) | (8.5 | ) | |||||||||
Present revenues (sales growth and weather) | (4.4 | ) | (6.4 | ) | |||||||||
ROE (9.8 percent and 8.63 percent, respectively) | (3.2 | ) | (8.1 | ) | |||||||||
Capital structure | (1.5 | ) | (1.1 | ) | |||||||||
Employee benefits | (2.8 | ) | (1.8 | ) | |||||||||
Reduced recovery for payroll expense | (0.1 | ) | (0.1 | ) | |||||||||
Gain on sale of transmission assets | — | (1.7 | ) | ||||||||||
Fuel clause revenue | 6 | — | |||||||||||
Other, net | (5.0 | ) | (6.6 | ) | |||||||||
Recommended rate increase | $ | 17.8 | $ | 9 | |||||||||
Means of recovery: | |||||||||||||
Base revenue | $ | 8.8 | $ | (6.0 | ) | ||||||||
Rider revenue | 7.3 | 13.3 | |||||||||||
Fuel cost adjustment revenue | 1.7 | 1.7 | |||||||||||
$ | 17.8 | $ | 9 | ||||||||||
(a) | Adjustments represent recommended deferrals, extended amortizations and moving costs from rider to fuel in base rates. |
Commitments_and_Contingencies_
Commitments and Contingencies (Tables) | 12 Months Ended | ||||||||||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||||||||||
Commitments and Contingencies Disclosure [Abstract] | ' | ||||||||||||||||||||||||
Estimated Minimum Purchases Under Fuel Contracts | ' | ||||||||||||||||||||||||
The estimated minimum purchases for Xcel Energy under these contracts as of Dec. 31, 2013 are as follows: | |||||||||||||||||||||||||
(Millions of Dollars) | Coal | Nuclear fuel | Natural gas supply | Natural gas | |||||||||||||||||||||
storage and | |||||||||||||||||||||||||
transportation | |||||||||||||||||||||||||
2014 | $ | 947.6 | $ | 128.8 | $ | 492.8 | $ | 272.3 | |||||||||||||||||
2015 | 770.7 | 79.9 | 234.4 | 266.4 | |||||||||||||||||||||
2016 | 500.2 | 121.5 | 232 | 207.5 | |||||||||||||||||||||
2017 | 221.3 | 127.5 | 225.4 | 164.2 | |||||||||||||||||||||
2018 | 73.2 | 69.4 | 278.4 | 106.6 | |||||||||||||||||||||
Thereafter | 428.6 | 697.6 | 1,211.30 | 1,214.20 | |||||||||||||||||||||
Total | $ | 2,941.60 | $ | 1,224.70 | $ | 2,674.30 | $ | 2,231.20 | |||||||||||||||||
Estimated Future Payments for Capacity and Energy Pursuant to Purchased Power Agreements | ' | ||||||||||||||||||||||||
Included in electric fuel and purchased power expenses for PPAs accounted for as executory contracts were payments for capacity of $217.0 million, $261.9 million and $325.3 million in 2013, 2012 and 2011, respectively. At Dec. 31, 2013, the estimated future payments for capacity and energy that the utility subsidiaries of Xcel Energy are obligated to purchase pursuant to these executory contracts, subject to availability, are as follows: | |||||||||||||||||||||||||
(Millions of Dollars) | Capacity | Energy (a) | |||||||||||||||||||||||
2014 | $ | 254.2 | $ | 121.9 | |||||||||||||||||||||
2015 | 254.5 | 120.5 | |||||||||||||||||||||||
2016 | 215.5 | 100.2 | |||||||||||||||||||||||
2017 | 186.1 | 90.4 | |||||||||||||||||||||||
2018 | 141.1 | 93.2 | |||||||||||||||||||||||
Thereafter | 571.3 | 866.7 | |||||||||||||||||||||||
Total | $ | 1,622.70 | $ | 1,392.90 | |||||||||||||||||||||
(a) | Excludes contingent energy payments for renewable PPAs. | ||||||||||||||||||||||||
Summary of Property Held Under Capital Leases | ' | ||||||||||||||||||||||||
PSCo records amortization for its capital leases as cost of natural gas sold and transported on the consolidated statements of income. Total amortization expenses under capital lease assets were approximately $6.3 million, $5.7 million and $3.2 million for 2013, 2012 and 2011, respectively. Following is a summary of property held under capital leases: | |||||||||||||||||||||||||
(Millions of Dollars) | 2013 | 2012 | |||||||||||||||||||||||
Storage, leaseholds and rights | $ | 200.5 | $ | 200.5 | |||||||||||||||||||||
Gas pipeline | 20.7 | 20.7 | |||||||||||||||||||||||
Property held under capital lease | 221.2 | 221.2 | |||||||||||||||||||||||
Accumulated depreciation | (41.8 | ) | (35.5 | ) | |||||||||||||||||||||
Total property held under capital leases, net | $ | 179.4 | $ | 185.7 | |||||||||||||||||||||
Future Commitments Under Operating and Capital Leases | ' | ||||||||||||||||||||||||
Future commitments under operating and capital leases are: | |||||||||||||||||||||||||
(Millions of Dollars) | Operating | PPA | Total | Capital Leases | |||||||||||||||||||||
Leases | Operating | Operating | |||||||||||||||||||||||
Leases (a) (b) | Leases | ||||||||||||||||||||||||
2014 | $ | 26.5 | $ | 214.2 | $ | 240.7 | $ | 18 | |||||||||||||||||
2015 | 25.4 | 207.4 | 232.8 | 17.8 | |||||||||||||||||||||
2016 | 22.4 | 197 | 219.4 | 17.1 | |||||||||||||||||||||
2017 | 17.2 | 192.7 | 209.9 | 15 | |||||||||||||||||||||
2018 | 16.1 | 194.4 | 210.5 | 14.7 | |||||||||||||||||||||
Thereafter | 143.6 | 1,771.90 | 1,915.50 | 289.1 | |||||||||||||||||||||
Total minimum obligation | 371.7 | ||||||||||||||||||||||||
Interest component of obligation | (264.3 | ) | |||||||||||||||||||||||
Present value of minimum obligation | $ | 107.4 | (c) | ||||||||||||||||||||||
(a) | Amounts do not include PPAs accounted for as executory contracts. | ||||||||||||||||||||||||
(b) | PPA operating leases contractually expire through 2033. | ||||||||||||||||||||||||
(c) | Future commitments exclude certain amounts related to Xcel Energy’s 50 percent ownership interest in WYCO. | ||||||||||||||||||||||||
Eloigne and NSP-Wisconsin Low-income Housing Limited Partnerships | ' | ||||||||||||||||||||||||
Amounts reflected in Xcel Energy’s consolidated balance sheets for the Eloigne and NSP-Wisconsin low-income housing limited partnerships include the following: | |||||||||||||||||||||||||
(Thousands of Dollars) | Dec. 31, 2013 | Dec. 31, 2012 | |||||||||||||||||||||||
Current assets | $ | 7,982 | $ | 3,380 | |||||||||||||||||||||
Property, plant and equipment, net | 65,451 | 72,489 | |||||||||||||||||||||||
Other noncurrent assets | 1,654 | 6,044 | |||||||||||||||||||||||
Total assets | $ | 75,087 | $ | 81,913 | |||||||||||||||||||||
Current liabilities | $ | 11,388 | $ | 8,458 | |||||||||||||||||||||
Mortgages and other long-term debt payable | 38,049 | 37,720 | |||||||||||||||||||||||
Other noncurrent liabilities | 707 | 7,678 | |||||||||||||||||||||||
Total liabilities | $ | 50,144 | $ | 53,856 | |||||||||||||||||||||
Committed Minimum Payments Under Technology Agreements | ' | ||||||||||||||||||||||||
Committed minimum payments under these obligations are as follows: | |||||||||||||||||||||||||
(Millions of Dollars) | IBM | Accenture | |||||||||||||||||||||||
Agreement | Agreement | ||||||||||||||||||||||||
2014 | $ | 35.5 | $ | 8.9 | |||||||||||||||||||||
2015 | 32.2 | 8.8 | |||||||||||||||||||||||
2016 | 31.5 | 8.8 | |||||||||||||||||||||||
2017 | 31.6 | — | |||||||||||||||||||||||
2018 | 31.1 | — | |||||||||||||||||||||||
Thereafter | 15.5 | — | |||||||||||||||||||||||
Guarantees and Bond Indemnities Issued and Outstanding | ' | ||||||||||||||||||||||||
The following table presents guarantees and bond indemnities issued and outstanding as of Dec. 31, 2013: | |||||||||||||||||||||||||
(Millions of Dollars) | Guarantor | Guarantee | Current | Triggering | |||||||||||||||||||||
Amount | Exposure | Event | |||||||||||||||||||||||
Guarantee of customer loans for the Farm Rewiring Program (a) | NSP-Wisconsin | $ | 1 | $ | 0.3 | (e) | |||||||||||||||||||
Guarantee of the indemnification obligations of Xcel Energy Services Inc. under the aircraft leases (b) | Xcel Energy Inc. | 9.2 | — | (f) | |||||||||||||||||||||
Guarantee of residual value of assets under the BTM Capital Corporation Equipment Leasing Agreement (c) | NSP-Minnesota | 9.2 | — | (g) | |||||||||||||||||||||
Total guarantees issued | $ | 19.4 | $ | 0.3 | |||||||||||||||||||||
Guarantee performance and payment of surety bonds for Xcel Energy Inc. and its subsidiaries (d) | Xcel Energy Inc. | $ | 32.1 | (i) | (h) | ||||||||||||||||||||
(a) | The term of this guarantee expires in 2017, which is the final scheduled repayment date for the loans. As of Dec. 31, 2013, no claims had been made by the lender. | ||||||||||||||||||||||||
(b) | The term of this guarantee expires in 2017 when the associated leases expire. | ||||||||||||||||||||||||
(c) | The terms of these guarantees expire in 2014 and 2015 when the associated leases expire. | ||||||||||||||||||||||||
(d) | The surety bonds primarily relate to workers compensation benefits and utility projects. The workers compensation bonds are renewed annually and the project based bonds expire in conjunction with the completion of the related projects. | ||||||||||||||||||||||||
(e) | The debtor becomes the subject of bankruptcy or other insolvency proceedings. | ||||||||||||||||||||||||
(f) | Nonperformance and/or nonpayment. | ||||||||||||||||||||||||
(g) | Actual fair value of leased assets is less than the guaranteed residual value amount at the end of the lease term. | ||||||||||||||||||||||||
(h) | Failure of Xcel Energy Inc. or one of its subsidiaries to perform under the agreement that is the subject of the relevant bond. In addition, per the indemnity agreement between Xcel Energy Inc. and the various surety companies, the surety companies have the discretion to demand that collateral be posted. | ||||||||||||||||||||||||
(i) | Due to the magnitude of projects associated with the surety bonds, the total current exposure of this indemnification cannot be determined. Xcel Energy Inc. believes the exposure to be significantly less than the total amount of the outstanding bonds. | ||||||||||||||||||||||||
Asset Retirement Obligations | ' | ||||||||||||||||||||||||
A reconciliation of Xcel Energy’s AROs is shown in the tables below for the years ended Dec. 31, 2013 and 2012: | |||||||||||||||||||||||||
(Thousands of Dollars) | Beginning | Liabilities | Liabilities | Accretion | Revisions | Ending | |||||||||||||||||||
Balance | Recognized | Settled | to Prior | Balance | |||||||||||||||||||||
Jan. 1, 2013 | Estimates | Dec. 31, 2013 | |||||||||||||||||||||||
Electric plant | |||||||||||||||||||||||||
Nuclear production decommissioning | $ | 1,546,358 | $ | — | $ | — | $ | 81,940 | $ | — | $ | 1,628,298 | |||||||||||||
Steam and other production ash containment | 61,735 | — | — | 2,105 | 15,513 | 79,353 | |||||||||||||||||||
Steam and other production asbestos | 45,461 | — | (1,059 | ) | 2,551 | 3,874 | 50,827 | ||||||||||||||||||
Wind production | 35,864 | — | — | 1,600 | — | 37,464 | |||||||||||||||||||
Electric distribution | 24,150 | — | — | 708 | (12,672 | ) | 12,186 | ||||||||||||||||||
Other | 3,152 | — | — | 240 | 159 | 3,551 | |||||||||||||||||||
Natural gas plant | |||||||||||||||||||||||||
Gas transmission and distribution | 1,258 | — | — | 81 | (141 | ) | 1,198 | ||||||||||||||||||
Gas gathering | — | 575 | — | — | — | 575 | |||||||||||||||||||
Common and other property | |||||||||||||||||||||||||
Common general plant asbestos | 1,197 | — | — | 66 | (783 | ) | 480 | ||||||||||||||||||
Common miscellaneous | 621 | — | — | 59 | 778 | 1,458 | |||||||||||||||||||
Total liability | $ | 1,719,796 | $ | 575 | $ | (1,059 | ) | $ | 89,350 | $ | 6,728 | $ | 1,815,390 | ||||||||||||
The aggregate fair value of NSP-Minnesota’s legally restricted assets, for purposes of funding future nuclear decommissioning, was $1.6 billion as of Dec. 31, 2013, consisting of external investment funds. | |||||||||||||||||||||||||
In 2013, Xcel Energy revised asbestos, ash containment facilities, radiation sources, miscellaneous electric production, electric transmission and distribution, natural gas transmission and distribution and general AROs due to revised estimated cash flows. Additionally, in 2013, an ARO was recorded to reflect the expected costs with the retirement of certain gas gathering facilities at PSCo and AROs were settled for the asbestos abatement at the Cameo and Riverview generating facilities at PSCo and SPS, respectively. | |||||||||||||||||||||||||
(Thousands of Dollars) | Beginning | Liabilities | Liabilities | Accretion | Revisions | Ending | |||||||||||||||||||
Balance | Recognized | Settled | to Prior | Balance | |||||||||||||||||||||
Jan. 1, 2012 | Estimates | Dec. 31, 2012 | |||||||||||||||||||||||
Electric plant | |||||||||||||||||||||||||
Nuclear production decommissioning | $ | 1,482,741 | $ | — | $ | — | $ | 75,301 | $ | (11,684 | ) | $ | 1,546,358 | ||||||||||||
Steam and other production ash containment | 41,278 | — | — | 1,614 | 18,843 | 61,735 | |||||||||||||||||||
Steam and other production asbestos | 54,342 | 1,962 | (9,372 | ) | 3,417 | (4,888 | ) | 45,461 | |||||||||||||||||
Wind production | 40,515 | 2,928 | — | 2,068 | (9,647 | ) | 35,864 | ||||||||||||||||||
Electric distribution | 27,592 | — | — | 1,000 | (4,442 | ) | 24,150 | ||||||||||||||||||
Other | 2,390 | — | — | 92 | 670 | 3,152 | |||||||||||||||||||
Natural gas plant | |||||||||||||||||||||||||
Gas transmission and distribution | 1,201 | — | — | 73 | (16 | ) | 1,258 | ||||||||||||||||||
Common and other property | |||||||||||||||||||||||||
Common general plant asbestos | 1,135 | — | — | 62 | — | 1,197 | |||||||||||||||||||
Common miscellaneous | 599 | — | — | 22 | — | 621 | |||||||||||||||||||
Total liability | $ | 1,651,793 | $ | 4,890 | $ | (9,372 | ) | $ | 83,649 | $ | (11,164 | ) | $ | 1,719,796 | |||||||||||
The aggregate fair value of NSP-Minnesota’s legally restricted assets, for purposes of funding future nuclear decommissioning, was $1.5 billion as of Dec. 31, 2012, consisting of external investment funds. | |||||||||||||||||||||||||
In 2012, revisions were made for nuclear decommissioning, asbestos, ash-containment facilities, wind facilities and electric transmission and distribution AROs due to revised estimated cash flows. | |||||||||||||||||||||||||
Plant Removal Costs | ' | ||||||||||||||||||||||||
The accumulated balances by entity were as follows at Dec. 31: | |||||||||||||||||||||||||
(Millions of Dollars) | 2013 | 2012 | |||||||||||||||||||||||
NSP-Minnesota | $ | 378 | $ | 377 | |||||||||||||||||||||
NSP-Wisconsin | 116 | 114 | |||||||||||||||||||||||
PSCo | 359 | 365 | |||||||||||||||||||||||
SPS | 53 | 67 | |||||||||||||||||||||||
Total Xcel Energy | $ | 906 | $ | 923 | |||||||||||||||||||||
Nuclear_Obligations_Tables
Nuclear Obligations (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2013 | |||||||||||||
Nuclear Obligations [Abstract] | ' | ||||||||||||
Funded Status of Nuclear Decommissioning Obligation [Table Text Block] | ' | ||||||||||||
As of Dec. 31, 2013, NSP-Minnesota has accumulated $1.6 billion of assets held in external decommissioning trusts. The following table summarizes the funded status of NSP-Minnesota’s decommissioning obligation based on approved regulatory recovery parameters from the most recently approved decommissioning study. Xcel Energy believes future decommissioning cost expense, if necessary, will continue to be recovered in customer rates. These amounts are not those recorded in the financial statements for the ARO. | |||||||||||||
Regulatory Basis | |||||||||||||
(Thousands of Dollars) | 2013 | 2012 | |||||||||||
Estimated decommissioning cost obligation from most recently approved study (2011 dollars) | $ | 2,694,079 | $ | 2,694,079 | |||||||||
Effect of escalating costs (to 2013 and 2012 dollars, respectively, at 3.63/2.63 percent) | 189,924 | 93,327 | |||||||||||
Estimated decommissioning cost obligation (in current dollars) | 2,884,003 | 2,787,406 | |||||||||||
Effect of escalating costs to payment date (3.63/2.63 percent) | 5,697,285 | 5,793,882 | |||||||||||
Estimated future decommissioning costs (undiscounted) | 8,581,288 | 8,581,288 | |||||||||||
Effect of discounting obligation (using risk-free interest rate) | (6,215,050 | ) | (6,243,332 | ) | |||||||||
Discounted decommissioning cost obligation | $ | 2,366,238 | $ | 2,337,956 | |||||||||
Assets held in external decommissioning trust | $ | 1,627,026 | $ | 1,489,542 | |||||||||
Underfunding of external decommissioning fund compared to the discounted decommissioning obligation | 739,212 | 848,414 | |||||||||||
Nuclear Decommissioning Expenses Recognized as Result of Regulation [Table Text Block] | ' | ||||||||||||
Decommissioning expenses recognized as a result of regulation include the following components: | |||||||||||||
(Thousands of Dollars) | 2013 | 2012 | 2011 | ||||||||||
Annual decommissioning recorded as depreciation expense: (a) | |||||||||||||
Externally funded | $ | 6,402 | $ | — | $ | — | |||||||
Internally funded (including interest costs) | — | (1,251 | ) | (456 | ) | ||||||||
Net decommissioning expense recorded | $ | 6,402 | $ | (1,251 | ) | $ | (456 | ) | |||||
(a) | Decommissioning expense does not include depreciation of the capitalized nuclear asset retirement costs. |
Regulatory_Assets_and_Liabilit1
Regulatory Assets and Liabilities (Tables) | 12 Months Ended | |||||||||||||||||||||
Dec. 31, 2013 | ||||||||||||||||||||||
Regulatory Assets and Liabilities Disclosure [Abstract] | ' | |||||||||||||||||||||
Regulatory Assets | ' | |||||||||||||||||||||
The components of regulatory assets shown on the consolidated balance sheets at Dec. 31, 2013 and 2012 are: | ||||||||||||||||||||||
(Thousands of Dollars) | See Note(s) | Remaining | Dec. 31, 2013 | Dec. 31, 2012 | ||||||||||||||||||
Amortization Period | ||||||||||||||||||||||
Regulatory Assets | Current | Noncurrent | Current | Noncurrent | ||||||||||||||||||
Pension and retiree medical obligations (a) | 9 | Various | $ | 118,179 | $ | 1,192,808 | $ | 100,713 | $ | 1,552,375 | ||||||||||||
Recoverable deferred taxes on AFUDC recorded in plant | 1 | Plant lives | — | 359,215 | — | 321,680 | ||||||||||||||||
Contract valuation adjustments (b) | 1, 11 | Term of related contract | 3,620 | 153,393 | 3,775 | 147,755 | ||||||||||||||||
Net AROs (c) | 1, 13, 14 | Plant lives | — | 160,544 | — | 178,146 | ||||||||||||||||
Conservation programs (d) | 1 | One to six years | 55,088 | 63,275 | 60,956 | 84,146 | ||||||||||||||||
Environmental remediation costs | 1, 13 | Various | 4,735 | 119,175 | 3,986 | 109,377 | ||||||||||||||||
Renewable resources and environmental initiatives | 13 | One to four years | 46,076 | 37,858 | 59,518 | 38,138 | ||||||||||||||||
Depreciation differences | 1 | One to seventeen years | 10,918 | 95,844 | 5,274 | 50,057 | ||||||||||||||||
Purchased power contract costs | 13 | Term of related contract | — | 68,182 | — | 63,134 | ||||||||||||||||
Losses on reacquired debt | 4 | Term of related debt | 5,525 | 36,534 | 5,917 | 42,060 | ||||||||||||||||
Nuclear refueling outage costs | 1 | One to two years | 86,333 | 36,477 | 56,035 | 22,647 | ||||||||||||||||
Gas pipeline inspection and remediation costs | 12 | Various | 5,416 | 33,884 | 5,416 | 27,560 | ||||||||||||||||
Recoverable purchased natural gas and electric energy costs | 1 | One to two years | 42,288 | 15,495 | 32,098 | 8,340 | ||||||||||||||||
Sherco Unit 3 deferral | Twenty-one years | 503 | 10,063 | — | — | |||||||||||||||||
State commission adjustments | 1 | Plant lives | 444 | 14,204 | 374 | 12,181 | ||||||||||||||||
Prairie Island EPU (e) | 12 | Pending rate cases | — | 69,668 | — | 67,590 | ||||||||||||||||
Property tax | Three years | 18,427 | 30,626 | 6,005 | 12,010 | |||||||||||||||||
Other | Various | 20,249 | 11,973 | 12,910 | 24,833 | |||||||||||||||||
Total regulatory assets | $ | 417,801 | $ | 2,509,218 | $ | 352,977 | $ | 2,762,029 | ||||||||||||||
(a) | Includes $303.3 million and $330.3 million for the regulatory recognition of the NSP-Minnesota pension expense of which $23.2 million and $24.3 million is included in the current asset at Dec. 31, 2013 and 2012, respectively. Also included are $17.7 million and $21.5 million of regulatory assets related to the nonqualified pension plan of which $2.2 million is included in the current asset at Dec. 31, 2013 and 2012, respectively. | |||||||||||||||||||||
(b) | Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases. | |||||||||||||||||||||
(c) | Includes amounts recorded for future recovery of AROs, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments. | |||||||||||||||||||||
(d) | Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions. | |||||||||||||||||||||
(e) | For the canceled Prairie Island EPU project, NSP-Minnesota plans to address recovery of incurred costs in the pending multi-year rate case. | |||||||||||||||||||||
Regulatory Liabilities | ' | |||||||||||||||||||||
The components of regulatory liabilities shown on the consolidated balance sheets at Dec. 31, 2013 and 2012 are: | ||||||||||||||||||||||
(Thousands of Dollars) | See Note(s) | Remaining | Dec. 31, 2013 | Dec. 31, 2012 | ||||||||||||||||||
Amortization Period | ||||||||||||||||||||||
Regulatory Liabilities | Current | Noncurrent | Current | Noncurrent | ||||||||||||||||||
Plant removal costs | 1, 13 | Plant lives | $ | — | $ | 906,403 | $ | — | $ | 922,963 | ||||||||||||
Deferred electric and steam production and natural gas costs | 1 | Less than one year | 96,574 | — | 90,454 | — | ||||||||||||||||
DOE settlement | 12 | One to two years | 44,208 | 1,131 | 22,700 | 1,131 | ||||||||||||||||
Investment tax credit deferrals | 1, 6 | Various | — | 56,535 | — | 59,052 | ||||||||||||||||
Deferred income tax adjustment | 1, 6 | Various | — | 43,581 | — | 44,667 | ||||||||||||||||
Conservation programs (b) | 1, 12 | Less than one year | 19,531 | — | 6,292 | — | ||||||||||||||||
Contract valuation adjustments (a) | 1, 11 | Term of related contract | 54,455 | 6,849 | 29,431 | 11,159 | ||||||||||||||||
Gain from asset sales | 12 | One to three years | 12,859 | 4,568 | 7,318 | 10,311 | ||||||||||||||||
Renewable resources and environmental initiatives | 12, 13 | Various | 2,499 | 1,412 | 256 | 1,412 | ||||||||||||||||
Low income discount program | Less than one year | 6,229 | — | 6,164 | — | |||||||||||||||||
PSCo earnings test | 12 | One to two years | 22,891 | 19,203 | 1,732 | 1,732 | ||||||||||||||||
Other | Various | 15,523 | 19,713 | 4,511 | 7,512 | |||||||||||||||||
Total regulatory liabilities | $ | 274,769 | $ | 1,059,395 | $ | 168,858 | $ | 1,059,939 | ||||||||||||||
(a) | Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases. | |||||||||||||||||||||
(b) | Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions. |
Other_Comprehensive_Income_Tab
Other Comprehensive Income (Tables) | 12 Months Ended | ||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||
Stockholders' Equity Note [Abstract] | ' | ||||||||||||||||
Changes in Accumulated Other Comprehensive Loss, Net of Tax | ' | ||||||||||||||||
Changes in accumulated other comprehensive loss, net of tax, for the year ended Dec. 31, 2013 were as follows: | |||||||||||||||||
(Thousands of Dollars) | Gains and | Unrealized | Defined Benefit | Total | |||||||||||||
Losses on Cash Flow Hedges | Gains and Losses | Pension and | |||||||||||||||
on Marketable | Postretirement | ||||||||||||||||
Securities | Items | ||||||||||||||||
Accumulated other comprehensive loss at Jan. 1 | $ | (61,241 | ) | $ | (99 | ) | $ | (51,313 | ) | $ | (112,653 | ) | |||||
Other comprehensive gain before reclassifications | 12 | 176 | 1,408 | 1,596 | |||||||||||||
Losses reclassified from net accumulated other comprehensive loss | 1,476 | — | 3,306 | 4,782 | |||||||||||||
Net current period OCI | 1,488 | 176 | 4,714 | 6,378 | |||||||||||||
Accumulated other comprehensive gain (loss) at Dec. 31 | $ | (59,753 | ) | $ | 77 | $ | (46,599 | ) | $ | (106,275 | ) | ||||||
Reclassifications out of Accumulated Other Comprehensive Loss | ' | ||||||||||||||||
Reclassifications from accumulated other comprehensive loss for the year ended Dec. 31, 2013 were as follows: | |||||||||||||||||
(Thousands of Dollars) | Amounts Reclassified from Accumulated Other Comprehensive Loss | ||||||||||||||||
(Gains) losses on cash flow hedges: | |||||||||||||||||
Interest rate derivatives | $ | 4,107 | (a) | ||||||||||||||
Vehicle fuel derivatives | (90 | ) | (b) | ||||||||||||||
Total, pre-tax | 4,017 | ||||||||||||||||
Tax benefit | (2,541 | ) | |||||||||||||||
Total, net of tax | 1,476 | ||||||||||||||||
Defined benefit pension and postretirement losses: | |||||||||||||||||
Amortization of net loss | 7,077 | (c) | |||||||||||||||
Prior service cost | 372 | (c) | |||||||||||||||
Transition obligation | 8 | (c) | |||||||||||||||
Total, pre-tax | 7,457 | ||||||||||||||||
Tax benefit | (4,151 | ) | |||||||||||||||
Total, net of tax | 3,306 | ||||||||||||||||
Total amounts reclassified, net of tax | $ | 4,782 | |||||||||||||||
(a) | Included in interest charges. | ||||||||||||||||
(b) | Included in O&M expenses. | ||||||||||||||||
(c) | Included in the computation of net periodic pension and post retirement benefit costs. See Note 9 for details regarding these benefit plans. |
Segments_and_Related_Informati1
Segments and Related Information (Tables) | 12 Months Ended | ||||||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||||||
Segment Reporting [Abstract] | ' | ||||||||||||||||||||
Results from Continuing Operations by Reportable Segment | ' | ||||||||||||||||||||
(Thousands of Dollars) | Regulated | Regulated | All Other | Reconciling | Consolidated | ||||||||||||||||
Electric | Natural Gas | Eliminations | Total | ||||||||||||||||||
2013 | |||||||||||||||||||||
Operating revenues from external customers | $ | 9,034,045 | $ | 1,804,679 | $ | 76,198 | $ | — | $ | 10,914,922 | |||||||||||
Intersegment revenues | 1,332 | 2,717 | — | (4,049 | ) | — | |||||||||||||||
Total revenues | $ | 9,035,377 | $ | 1,807,396 | $ | 76,198 | $ | (4,049 | ) | $ | 10,914,922 | ||||||||||
Depreciation and amortization | $ | 840,833 | $ | 128,186 | $ | 8,844 | $ | — | $ | 977,863 | |||||||||||
Interest charges and financing costs | 386,198 | 44,927 | 104,895 | — | 536,020 | ||||||||||||||||
Income tax expense (benefit) | 495,044 | 25,543 | (36,611 | ) | — | 483,976 | |||||||||||||||
Net income (loss) | 850,572 | 123,702 | (26,040 | ) | — | 948,234 | |||||||||||||||
(Thousands of Dollars) | Regulated | Regulated | All Other | Reconciling | Consolidated | ||||||||||||||||
Electric | Natural Gas | Eliminations | Total | ||||||||||||||||||
2012 | |||||||||||||||||||||
Operating revenues from external customers | $ | 8,517,296 | $ | 1,537,374 | $ | 73,553 | $ | — | $ | 10,128,223 | |||||||||||
Intersegment revenues | 1,169 | 1,425 | — | (2,594 | ) | — | |||||||||||||||
Total revenues | $ | 8,518,465 | $ | 1,538,799 | $ | 73,553 | $ | (2,594 | ) | $ | 10,128,223 | ||||||||||
Depreciation and amortization | $ | 801,649 | $ | 115,038 | $ | 9,366 | $ | — | $ | 926,053 | |||||||||||
Interest charges and financing costs | 397,457 | 49,456 | 119,324 | — | 566,237 | ||||||||||||||||
Income tax expense (benefit) | 465,626 | 50,322 | (65,745 | ) | — | 450,203 | |||||||||||||||
Net income (loss) | 851,929 | 98,061 | (44,761 | ) | — | 905,229 | |||||||||||||||
(Thousands of Dollars) | Regulated | Regulated | All Other | Reconciling | Consolidated | ||||||||||||||||
Electric | Natural Gas | Eliminations | Total | ||||||||||||||||||
2011 | |||||||||||||||||||||
Operating revenues from external customers | $ | 8,766,593 | $ | 1,811,926 | $ | 76,251 | $ | — | $ | 10,654,770 | |||||||||||
Intersegment revenues | 1,269 | 2,358 | — | (3,627 | ) | — | |||||||||||||||
Total revenues | $ | 8,767,862 | $ | 1,814,284 | $ | 76,251 | $ | (3,627 | ) | $ | 10,654,770 | ||||||||||
Depreciation and amortization | $ | 773,392 | $ | 106,870 | $ | 10,357 | $ | — | $ | 890,619 | |||||||||||
Interest charges and financing costs | 402,668 | 52,115 | 108,336 | — | 563,119 | ||||||||||||||||
Income tax expense (benefit) | 473,848 | 57,408 | (62,940 | ) | — | 468,316 | |||||||||||||||
Net income (loss) | 788,967 | 101,842 | (49,637 | ) | — | 841,172 | |||||||||||||||
Summarized_Quarterly_Financial1
Summarized Quarterly Financial Data (Unaudited) (Tables) | 12 Months Ended | ||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||
Quarterly Financial Information Disclosure [Abstract] | ' | ||||||||||||||||
Summarized Quarterly Financial Data (Unaudited) | ' | ||||||||||||||||
Quarter Ended | |||||||||||||||||
(Amounts in thousands, except per share data) | 31-Mar-13 | 30-Jun-13 | Sept. 30, 2013 | Dec. 31, 2013 | |||||||||||||
Operating revenues | $ | 2,782,849 | $ | 2,578,913 | $ | 2,822,338 | $ | 2,730,822 | |||||||||
Operating income | 454,624 | 402,236 | 665,113 | 325,582 | |||||||||||||
Net income | 236,570 | 196,857 | 364,752 | 150,055 | |||||||||||||
Earnings per share total — basic | $ | 0.48 | $ | 0.4 | $ | 0.73 | $ | 0.3 | |||||||||
Earnings per share total — diluted | 0.48 | 0.4 | 0.73 | 0.3 | |||||||||||||
Cash dividends declared per common share | 0.27 | 0.28 | 0.28 | 0.28 | |||||||||||||
Quarter Ended | |||||||||||||||||
(Amounts in thousands, except per share data) | 31-Mar-12 | 30-Jun-12 | Sept. 30, 2012 | Dec. 31, 2012 | |||||||||||||
Operating revenues | $ | 2,578,079 | $ | 2,274,668 | $ | 2,724,341 | $ | 2,551,135 | |||||||||
Operating income | 380,162 | 405,690 | 720,434 | 316,397 | |||||||||||||
Net income | 183,893 | 183,060 | 398,106 | 140,170 | |||||||||||||
Earnings per share total — basic | $ | 0.38 | $ | 0.38 | $ | 0.82 | $ | 0.29 | |||||||||
Earnings per share total — diluted | 0.38 | 0.38 | 0.81 | 0.29 | |||||||||||||
Cash dividends declared per common share | 0.26 | 0.27 | 0.27 | 0.27 | |||||||||||||
Schedule_I_Condensed_Financial1
Schedule I, Condensed Financial Statements of Xcel Energy Inc Schedule I, Condensed Financial Statements of Xcel Energy Inc (Tables) | 12 Months Ended | ||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||
Condensed Financial Information of Parent Company Only Disclosure [Abstract] | ' | ||||||||||||||||
Schedule of Related Party Transactions [Table Text Block] | ' | ||||||||||||||||
Related Party Transactions — Xcel Energy Inc. presents its related party receivables net of payables. Accounts receivable and payable with affiliates at Dec. 31 were: | |||||||||||||||||
2013 | 2012 | ||||||||||||||||
(Thousands of Dollars) | Accounts Receivable | Accounts Payable | Accounts Receivable | Accounts Payable | |||||||||||||
NSP-Minnesota | $ | 57,596 | $ | — | $ | 63,682 | $ | — | |||||||||
NSP-Wisconsin | 6,933 | — | 7,631 | — | |||||||||||||
PSCo | 74,739 | — | — | (3,362 | ) | ||||||||||||
SPS | 5,705 | — | 15,806 | — | |||||||||||||
Xcel Energy Services Inc. | 60,138 | — | 61,217 | — | |||||||||||||
Xcel Energy Ventures Inc. | 20,194 | — | 20,427 | — | |||||||||||||
Other subsidiaries of Xcel Energy Inc. | 15,145 | — | 30,037 | — | |||||||||||||
$ | 240,450 | $ | — | $ | 198,800 | $ | (3,362 | ) | |||||||||
Schedule of Short-term Debt [Table Text Block] | ' | ||||||||||||||||
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 | ||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||
Borrowing limit | $ | 2,450 | |||||||||||||||
Amount outstanding at period end | 759 | ||||||||||||||||
Average amount outstanding | 515 | ||||||||||||||||
Maximum amount outstanding | 759 | ||||||||||||||||
Weighted average interest rate, computed on a daily basis | 0.29 | % | |||||||||||||||
Weighted average interest rate at period end | 0.25 | ||||||||||||||||
(Amounts in Millions, Except Interest Rates) | Twelve Months Ended | Twelve Months Ended | Twelve Months Ended | ||||||||||||||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |||||||||||||||
Borrowing limit | $ | 2,450 | $ | 2,450 | $ | 2,450 | |||||||||||
Amount outstanding at period end | 759 | 602 | 219 | ||||||||||||||
Average amount outstanding | 481 | 403 | 430 | ||||||||||||||
Maximum amount outstanding | 1,160 | 634 | 824 | ||||||||||||||
Weighted average interest rate, computed on a daily basis | 0.31 | % | 0.35 | % | 0.36 | % | |||||||||||
Weighted average interest rate at end of period | 0.25 | 0.36 | 0.4 | ||||||||||||||
The following tables present money pool lending for Xcel Energy Inc.: | |||||||||||||||||
(Amounts in Millions, Except Interest Rates) | Three Months Ended Dec. 31, 2013 | ||||||||||||||||
Lending limit | $ | 250 | |||||||||||||||
Loan outstanding at period end | 72 | ||||||||||||||||
Average loan outstanding | 109.8 | ||||||||||||||||
Maximum loan outstanding | 182 | ||||||||||||||||
Weighted average interest rate, computed on a daily basis | 0.31 | % | |||||||||||||||
Weighted average interest rate at end of period | 0.25 | ||||||||||||||||
Money pool interest income | $ | 0.1 | |||||||||||||||
(Amounts in Millions, Except Interest Rates) | Twelve Months Ended Dec. 31, 2013 | Twelve Months Ended Dec. 31, 2012 | Twelve Months Ended Dec. 31, 2011 | ||||||||||||||
Lending limit | $ | 250 | $ | 250 | $ | 250 | |||||||||||
Loan outstanding at period end | 72 | — | 18 | ||||||||||||||
Average loan outstanding | 88.2 | 26.1 | 0.4 | ||||||||||||||
Maximum loan outstanding | 243 | 226 | 43 | ||||||||||||||
Weighted average interest rate, computed on a daily basis | 0.3 | % | 0.33 | % | 0.35 | % | |||||||||||
Weighted average interest rate at end of period | 0.25 | N/A | 0.35 | ||||||||||||||
Money pool interest income | $ | 0.3 | $ | 0.1 | $ | — | |||||||||||
Summary_of_Significant_Account2
Summary of Significant Accounting Policies Summary of Significant Accounting Policies (Details) | 12 Months Ended | ||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |
Conservation Programs [Abstract] | ' | ' | ' |
Maximum number of months following end of annual period in which revenues are earned to be included in incentive programs | '24 months | ' | ' |
Property, Plant and Equipment [Abstract] | ' | ' | ' |
Depreciation expense expressed as a percentage of average depreciable property | 2.90% | 2.80% | 2.90% |
Nuclear Decommissioning [Abstract] | ' | ' | ' |
Minimum amount of time between nuclear decommissioning studies (in years) | '3 years | ' | ' |
Cash and Cash Equivalents [Abstract] | ' | ' | ' |
Maximum number of months of remaining maturity at time of purchase to consider investments in certain instruments as cash equivalents | '3 months | ' | ' |
Balance_Sheet_Data_Accounts_Re
Balance Sheet Data, Accounts Receivable (Details) (USD $) | Dec. 31, 2013 | Dec. 31, 2012 |
In Thousands, unless otherwise specified | ||
Accounts receivable, net | ' | ' |
Accounts receivable | $797,267 | $769,440 |
Less allowance for bad debts | -53,107 | -51,394 |
Accounts receivable, net | $744,160 | $718,046 |
Selected_Balance_Sheet_Data_Ba
Selected Balance Sheet Data Balance Sheet Related Disclosures, Inventories (Details) (USD $) | Dec. 31, 2013 | Dec. 31, 2012 |
In Thousands, unless otherwise specified | ||
Public Utilities, Inventory [Line Items] | ' | ' |
Inventories | $576,538 | $535,574 |
Materials and supplies | ' | ' |
Public Utilities, Inventory [Line Items] | ' | ' |
Inventories | 225,308 | 213,739 |
Fuel | ' | ' |
Public Utilities, Inventory [Line Items] | ' | ' |
Inventories | 189,485 | 189,425 |
Natural gas | ' | ' |
Public Utilities, Inventory [Line Items] | ' | ' |
Inventories | $161,745 | $132,410 |
Selected_Balance_Sheet_Data_Ba1
Selected Balance Sheet Data Balance Sheet Related Disclosures, Property, Plant and Equipment (Details) (USD $) | Dec. 31, 2013 | Dec. 31, 2012 | ||
In Thousands, unless otherwise specified | ||||
Public Utility, Property, Plant and Equipment [Line Items] | ' | ' | ||
Property, plant and equipment, gross | $38,386,353 | $35,511,843 | ||
Less accumulated depreciation | -12,608,305 | -12,048,697 | ||
Property, plant and equipment, net | 26,122,159 | 23,809,348 | ||
Electric plant | ' | ' | ||
Public Utility, Property, Plant and Equipment [Line Items] | ' | ' | ||
Property, plant and equipment, gross | 30,341,310 | 28,285,031 | ||
Natural gas plant | ' | ' | ||
Public Utility, Property, Plant and Equipment [Line Items] | ' | ' | ||
Property, plant and equipment, gross | 4,086,651 | 3,836,335 | ||
Common and other property | ' | ' | ||
Public Utility, Property, Plant and Equipment [Line Items] | ' | ' | ||
Property, plant and equipment, gross | 1,485,547 | 1,480,558 | ||
Plant to be retired | ' | ' | ||
Public Utility, Property, Plant and Equipment [Line Items] | ' | ' | ||
Property, plant and equipment, gross | 101,279 | [1] | 152,730 | [1] |
CWIP | ' | ' | ||
Public Utility, Property, Plant and Equipment [Line Items] | ' | ' | ||
Property, plant and equipment, gross | 2,371,566 | 1,757,189 | ||
Nuclear fuel | ' | ' | ||
Public Utility, Property, Plant and Equipment [Line Items] | ' | ' | ||
Property, plant and equipment, gross | 2,186,799 | 2,090,801 | ||
Less accumulated depreciation | ($1,842,688) | ($1,744,599) | ||
[1] | As a result of the CPUC’s 2010 approval of PSCo’s CACJA compliance plan, subsequent CPCNs and the December 2013 approval of PSCo’s preferred plans for applicable generating resources, PSCo has received approval for early retirement of Cherokee Units 1, 2 and 3, Arapahoe Units 3 and 4 and Valmont Unit 5 between 2011 and 2017. In 2011, Cherokee Unit 2 was retired, in 2012, Cherokee Unit 1 was retired, and in 2013, Arapahoe Units 3 and 4 were retired. Amounts are presented net of accumulated depreciation. |
Borrowings_and_Other_Financing2
Borrowings and Other Financing Instruments, Commercial Paper (Details) (USD $) | 3 Months Ended | 12 Months Ended | ||
Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |
Commercial Paper [Abstract] | ' | ' | ' | ' |
Borrowing limit | $2,450,000,000 | $2,450,000,000 | $2,450,000,000 | $2,450,000,000 |
Amount outstanding at period end | 759,000,000 | 759,000,000 | 602,000,000 | 219,000,000 |
Average amount outstanding | 515,000,000 | 481,000,000 | 403,000,000 | 430,000,000 |
Maximum amount outstanding | $759,000,000 | $1,160,000,000 | $634,000,000 | $824,000,000 |
Weighted average interest rate, computed on a daily basis (in hundredths) | 0.29% | 0.31% | 0.35% | 0.36% |
Weighted average interest rate at period end (in hundredths) | 0.25% | 0.25% | 0.36% | 0.40% |
Borrowings_and_Other_Financing3
Borrowings and Other Financing Instruments, Letters of Credit (Details) (USD $) | 12 Months Ended | |
In Millions, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 |
Letters of Credit [Abstract] | ' | ' |
Terms of letters of credit (in years) | '1 year | ' |
Letters of credit outstanding under credit facilities | $47.80 | $14.20 |
Borrowings_and_Other_Financing4
Borrowings and Other Financing Instruments, Credit Facilities (Details) (USD $) | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | ||||||
Xcel Energy Inc. | Xcel Energy Inc. | NSP-Minnesota | NSP-Minnesota | NSP-Wisconsin | NSP-Wisconsin | PSCo | PSCo | SPS | SPS | ||||||||||
Credit Facilities [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||
Credit agreement term (in years) | ' | ' | ' | '5 years | ' | '5 years | ' | '5 years | ' | '5 years | ' | '5 years | ' | ||||||
Borrowing Limit | $2,450,000,000 | $2,450,000,000 | $2,450,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||
Number Of Additional Periods Revolving Termination Date Can Be Extended Subject To Majority Bank Group Approval | ' | ' | ' | 2 | ' | 2 | ' | 1 | ' | 2 | ' | 2 | ' | ||||||
Term Of Each Additional Period Revolving Termination Date Can Be Extended Subject To Majority Bank Group Approval | ' | ' | ' | '1 year | ' | '1 year | ' | '1 year | ' | '1 year | ' | '1 year | ' | ||||||
Maximum Amount Credit Facility May Be Increased | ' | ' | ' | 200,000,000 | ' | 100,000,000 | ' | ' | ' | 100,000,000 | ' | 50,000,000 | ' | ||||||
Maximum Debt To Total Capitalization Ratio Allowed (in hundredths) | ' | ' | ' | 65.00% | ' | 65.00% | ' | 65.00% | ' | 65.00% | ' | 65.00% | ' | ||||||
Debt To Total Capitalization Ratio (in hundredths) | ' | ' | ' | 56.00% | 56.00% | 47.00% | 48.00% | 47.00% | 50.00% | 45.00% | 45.00% | 49.00% | 49.00% | ||||||
Minimum Threshhold Percentage Of Subsidiary Assets To Consolidated Assets Required To Initiate Cross Default Provisions (in hundredths) | ' | ' | ' | 15.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||
Minimum Amount of Indebtedness in Default to Initiate Cross Default Provisions | ' | ' | ' | 75,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||
Minimum Borrowing Margin Based On Long Term Credit Ratings (in hundredths) | ' | ' | ' | 0.88% | ' | 0.88% | ' | 0.88% | ' | 0.88% | ' | 0.88% | ' | ||||||
Maximum Borrowing Margin Based On Long Term Credit Ratings (in hundredths) | ' | ' | ' | 1.75% | ' | 1.75% | ' | 1.75% | ' | 1.75% | ' | 1.75% | ' | ||||||
Minimum Commitment Fees Calculated On Unused Portion Of Lines Of Credit (in hundredths) | ' | ' | ' | 0.08% | ' | 0.08% | ' | 0.08% | ' | 0.08% | ' | 0.08% | ' | ||||||
Maximum Commitment Fees Calculated On Unused Portion Of Lines Of Credit (in hundredths) | ' | ' | ' | 0.28% | ' | 0.28% | ' | 0.28% | ' | 0.28% | ' | 0.28% | ' | ||||||
Credit facility | 2,450,000,000 | [1] | ' | ' | 800,000,000 | [1] | ' | 500,000,000 | [1] | ' | 150,000,000 | [1] | ' | 700,000,000 | [1] | ' | 300,000,000 | [1] | ' |
Drawn | 806,800,000 | [2] | ' | ' | 476,000,000 | [2] | ' | 146,900,000 | [2] | ' | 68,000,000 | [2] | ' | 6,400,000 | [2] | ' | 109,500,000 | [2] | ' |
Available | 1,643,200,000 | ' | ' | 324,000,000 | ' | 353,100,000 | ' | 82,000,000 | ' | 693,600,000 | ' | 190,500,000 | ' | ||||||
Credit facility bank borrowings outstanding | ' | ' | ' | $0 | $0 | $0 | $0 | $0 | $0 | $0 | $0 | $0 | $0 | ||||||
[1] | These credit facilities expire in July 2017. | ||||||||||||||||||
[2] | Includes outstanding commercial paper and letters of credit. |
Borrowings_and_Other_Financing5
Borrowings and Other Financing Instruments, Long-Term Borrowings and Other Financing Instruments (Details) (USD $) | Dec. 31, 2013 | 31-May-13 | Dec. 31, 2013 | Dec. 31, 2012 | Mar. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Mar. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Sep. 30, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Sep. 30, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Oct. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | 31-May-13 | Dec. 31, 2013 | Dec. 31, 2012 | Aug. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Aug. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Aug. 31, 2013 | Jun. 30, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 |
Xcel Energy Inc. | Xcel Energy Inc. | Xcel Energy Inc. | PSCo | PSCo | PSCo | PSCo | PSCo | PSCo | PSCo | PSCo | PSCo | PSCo | PSCo | PSCo | PSCo | PSCo | NSP-Wisconsin | NSP-Wisconsin | NSP-Wisconsin | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | SPS | SPS | SPS | SPS | SPS | ||
Senior Unsecured Notes | Senior Unsecured Notes | Senior Unsecured Notes | First Mortgage Bonds | First Mortgage Bonds | First Mortgage Bonds | First Mortgage Bonds | First Mortgage Bonds | First Mortgage Bonds | First Mortgage Bonds | First Mortgage Bonds | First Mortgage Bonds | First Mortgage Bonds | First Mortgage Bonds | First Mortgage Bonds | First Mortgage Bonds | First Mortgage Bonds | First Mortgage Bonds | First Mortgage Bonds | First Mortgage Bonds | First Mortgage Bonds | First Mortgage Bonds | First Mortgage Bonds | First Mortgage Bonds | First Mortgage Bonds | First Mortgage Bonds | First Mortgage Bonds | First Mortgage Bonds | First Mortgage Bonds | First Mortgage Bonds | First Mortgage Bonds | First Mortgage Bonds | First Mortgage Bonds | Senior Unsecured Notes | ||
Series Due May 9, 2016 | Series Due May 9, 2016 | Series Due May 9, 2016 | Series Due March 15, 2023 | Series Due March 15, 2023 | Series Due March 15, 2023 | Series Due March 15, 2043 | Series Due March 15, 2043 | Series Due March 15, 2043 | Series Due Aug. 15, 2041 | Series Due Aug. 15, 2041 | Series Due Sept. 15, 2022 | Series Due Sept. 15, 2022 | Series Due Sept. 15, 2022 | Series Due Sept. 15, 2042 | Series Due Sept. 15, 2042 | Series Due Sept. 15, 2042 | Series Due Oct. 1, 2042 | Series Due Oct. 1, 2042 | Series Due Oct. 1, 2042 | Series Due May 15, 2023 | Series Due May 15, 2023 | Series Due May 15, 2023 | Series Due Aug. 15, 2022 | Series Due Aug. 15, 2022 | Series Due Aug. 15, 2022 | Series Due Aug. 15, 2042 | Series Due Aug. 15, 2042 | Series Due Aug. 15, 2042 | Series Due Aug. 15, 2041 | Series Due Aug. 15, 2041 | Series Due Aug. 15, 2041 | Series Due Aug. 15, 2041 | Series Due Aug. 15, 2041 | ||
Maturities of Long-Term Debt [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
2014 | $281,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
2015 | 256,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
2016 | 656,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
2017 | 388,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
2018 | 1,206,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Long-Term Borrowings and Other Financing Instruments [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Face amount | ' | 450,000,000 | ' | ' | 250,000,000 | ' | ' | 250,000,000 | ' | ' | ' | ' | 300,000,000 | ' | ' | 500,000,000 | ' | ' | 100,000,000 | ' | ' | 400,000,000 | ' | ' | 300,000,000 | ' | ' | 500,000,000 | ' | ' | 100,000,000 | 100,000,000 | ' | ' | ' |
Interest rate, stated percentage (in hundredths) | ' | 0.75% | 0.75% | ' | 2.50% | 2.50% | ' | 3.95% | 3.95% | ' | 4.75% | ' | 2.25% | 2.25% | ' | 3.60% | 3.60% | ' | 3.70% | 3.70% | ' | 2.60% | 2.60% | ' | 2.15% | 2.15% | ' | 3.40% | 3.40% | ' | 4.50% | 4.50% | ' | ' | 4.50% |
Maturity date | ' | 9-May-16 | 9-May-16 | ' | 15-Mar-23 | 15-Mar-23 | ' | 15-Mar-43 | 15-Mar-43 | ' | 15-Aug-41 | ' | 15-Sep-22 | 15-Sep-22 | ' | 15-Sep-42 | 15-Sep-42 | ' | 1-Oct-42 | 1-Oct-42 | ' | 15-May-23 | 15-May-23 | ' | 15-Aug-22 | 15-Aug-22 | ' | 15-Aug-42 | 15-Aug-42 | ' | 15-Aug-41 | 15-Aug-41 | ' | ' | 15-Aug-41 |
Principal outstanding | ' | ' | $450,000,000 | $0 | ' | $250,000,000 | $0 | ' | $250,000,000 | $0 | $250,000,000 | $250,000,000 | ' | $300,000,000 | $300,000,000 | ' | $500,000,000 | $500,000,000 | ' | $100,000,000 | $100,000,000 | ' | $400,000,000 | $0 | ' | $300,000,000 | $300,000,000 | ' | $500,000,000 | $500,000,000 | ' | ' | $400,000,000 | $300,000,000 | ' |
Borrowings_and_Other_Financing6
Borrowings and Other Financing Instruments, Issuances of Common Stock (Details) (At-the-Market Program, USD $) | 1 Months Ended | 8 Months Ended |
Mar. 31, 2013 | Dec. 31, 2013 | |
At-the-Market Program | ' | ' |
Issuances of Common Stock [Abstract] | ' | ' |
Maximum aggregate gross sales price of common stock that can be offered and sold | $400,000,000 | ' |
Issuances of common stock (in shares) | ' | 0 |
Shares of common stock issued (in shares) | ' | 7,700,000 |
Net cash proceeds from issuance of common stock | ' | 223,000,000 |
Fees and commissions | ' | $3,000,000 |
Borrowings_and_Other_Financing7
Borrowings and Other Financing Instruments, Debt Redemption (Details) (USD $) | 1 Months Ended | 12 Months Ended | ||
31-May-13 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |
Long-Term Borrowings and Other Financing Instruments [Abstract] | ' | ' | ' | ' |
Interest charges and financing costs | ' | $575,199,000 | $601,552,000 | $591,300,000 |
Xcel Energy Inc. | ' | ' | ' | ' |
Long-Term Borrowings and Other Financing Instruments [Abstract] | ' | ' | ' | ' |
Interest charges and financing costs | 6,300,000 | 102,914,000 | 116,731,000 | 104,499,000 |
Xcel Energy Inc. | Junior Subordinated Notes | Series Due Jan. 1, 2068 [Member] | ' | ' | ' | ' |
Long-Term Borrowings and Other Financing Instruments [Abstract] | ' | ' | ' | ' |
Repurchased debt | $400,000,000 | ' | ' | ' |
Interest rate, stated percentage (in hundredths) | 7.60% | ' | ' | ' |
Borrowings_and_Other_Financing8
Borrowings and Other Financing Instruments Borrowings and Other Financing Instruments, Deferred Financing Costs (Details) (USD $) | Dec. 31, 2013 | Dec. 31, 2012 |
In Millions, unless otherwise specified | ||
Debt Disclosure [Abstract] | ' | ' |
Deferred Finance Costs, Noncurrent, Net | $83 | $85 |
Borrowings_and_Other_Financing9
Borrowings and Other Financing Instruments Borrowings and Other Financing Instruments, Capital Stock (Details) (USD $) | 12 Months Ended | |||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Jun. 30, 2013 | |
Capital Stock [Abstract] | ' | ' | ' | ' |
Preferred stock, redemption purchase price | ' | ' | $108,000,000 | ' |
Preferred Stock Redemption Premium | 0 | 0 | 3,260,000 | ' |
Common Stock, Shares Authorized (in shares) | 1,000,000,000 | 1,000,000,000 | ' | ' |
Common Stock, Par Value (in dollars per share) | $2.50 | $2.50 | ' | ' |
Common Stock, Shares Outstanding (in shares) | 497,971,508 | 487,959,516 | ' | 497,295,719 |
Xcel Energy Inc. | ' | ' | ' | ' |
Capital Stock [Abstract] | ' | ' | ' | ' |
Preferred Stock, Shares Authorized (in shares) | 7,000,000 | ' | ' | ' |
Preferred Stock, Par Value (in dollars per share) | $100 | ' | ' | ' |
Preferred Stock, Shares Outstanding (in shares) | 0 | 0 | ' | ' |
Preferred Stock Redemption Premium | $0 | $0 | $3,260,000 | ' |
PSCo | ' | ' | ' | ' |
Capital Stock [Abstract] | ' | ' | ' | ' |
Preferred Stock, Shares Authorized (in shares) | 10,000,000 | ' | ' | ' |
Preferred Stock, Par Value (in dollars per share) | $0.01 | ' | ' | ' |
Preferred Stock, Shares Outstanding (in shares) | 0 | 0 | ' | ' |
SPS | ' | ' | ' | ' |
Capital Stock [Abstract] | ' | ' | ' | ' |
Preferred Stock, Shares Authorized (in shares) | 10,000,000 | ' | ' | ' |
Preferred Stock, Par Value (in dollars per share) | $1 | ' | ' | ' |
Preferred Stock, Shares Outstanding (in shares) | 0 | 0 | ' | ' |
Recovered_Sheet1
Borrowings and Other Financing Instruments Borrowings and Other Financing Instruments, Dividend and Other Capital-Related Restrictions (Details) (USD $) | Dec. 31, 2013 | Dec. 31, 2012 |
Xcel Energy Inc. | ' | ' |
Dividend and Other Capital-Related Restrictions [Abstract] | ' | ' |
Preferred Stock, Shares Outstanding (in shares) | 0 | 0 |
PSCo | ' | ' |
Dividend and Other Capital-Related Restrictions [Abstract] | ' | ' |
Preferred Stock, Shares Outstanding (in shares) | 0 | 0 |
Maximum additional long term debt authorized for issuance | 1,000,000,000 | ' |
Maximum additional short term debt authorized for issuance | 800,000,000 | ' |
NSP-Minnesota | ' | ' |
Dividend and Other Capital-Related Restrictions [Abstract] | ' | ' |
Additional Cash Dividends On Common Stock Which Could Have Been Paid Per First Mortgage Indenture | 1,400,000,000 | 1,300,000,000 |
Equity to total capitalization ratio, low end of range (in hundredths) | 46.80% | ' |
Equity to total capitalization ratio, high end of range (in hundredths) | 57.20% | ' |
Equity to total capitalization ratio | 52.50% | ' |
Unrestricted Retained Earnings Per State Regulatory Commissions Dividend Restrictions | 912,000,000 | ' |
Capitalization, Short term debt, long term debt and equity | 8,500,000,000 | ' |
Maximum total capitalization | 9,000,000,000 | ' |
Maximum percentage of short term debt to total capitalization (in hundredths) | 15.00% | ' |
NSP-Wisconsin | ' | ' |
Dividend and Other Capital-Related Restrictions [Abstract] | ' | ' |
Unrestricted Retained Earnings Per State Regulatory Commissions Dividend Restrictions | 17,100,000 | ' |
Maximum annual dividends that can be paid if equity capitalization ratio condition is not met | 31,200,000 | ' |
Minimum calendar year average equity to total capitalization ratio authorized by state commission (in hundredths) | 52.50% | ' |
Calendar year average equity to total capitalization ratio (in hundredths) | 52.80% | ' |
Maximum additional long term debt authorized for issuance | 150,000,000 | ' |
Maximum additional short term debt authorized for issuance | 150,000,000 | ' |
SPS | ' | ' |
Dividend and Other Capital-Related Restrictions [Abstract] | ' | ' |
Preferred Stock, Shares Outstanding (in shares) | 0 | 0 |
Unrestricted Retained Earnings Per State Regulatory Commissions Dividend Restrictions | 359,000,000 | ' |
Equity to total capitalization ratio (excluding short-term debt), low end of range (in hundredths) | 45.00% | ' |
Equity to total capitalization ratio (excluding short-term debt), high end of range (in hundredths) | 55.00% | ' |
Equity to total capitalization ratio (excluding short-term debt) (in hundredths) | 53.20% | ' |
Maximum additional short term debt authorized for issuance | 400,000,000 | ' |
Joint_Ownership_of_Generation_2
Joint Ownership of Generation, Transmission and Gas Facilities (Details) (USD $) | 12 Months Ended |
In Thousands, unless otherwise specified | Dec. 31, 2013 |
NSP-Minnesota | ' |
Jointly Owned Utility Plant [Abstract] | ' |
Plant in service | $1,097,663 |
Accumulated depreciation | 541,126 |
Construction work in progress | 508,308 |
Generating capacity (in MW) | 500 |
NSP-Minnesota | Electric Generation | Sherco Unit 3 | ' |
Jointly Owned Utility Plant [Abstract] | ' |
Plant in service | 596,314 |
Accumulated depreciation | 371,925 |
Construction work in progress | 4,533 |
Ownership % (in hundredths) | 59.00% |
NSP-Minnesota | Electric Generation | Sherco Common Facilities Units 1, 2 and 3 | ' |
Jointly Owned Utility Plant [Abstract] | ' |
Plant in service | 145,579 |
Accumulated depreciation | 87,289 |
Construction work in progress | 61 |
Ownership % (in hundredths) | 80.00% |
NSP-Minnesota | Electric Generation | Sherco Substation | ' |
Jointly Owned Utility Plant [Abstract] | ' |
Plant in service | 4,790 |
Accumulated depreciation | 2,884 |
Construction work in progress | 0 |
Ownership % (in hundredths) | 59.00% |
NSP-Minnesota | Electric Transmission | Grand Meadow Line and Substation | ' |
Jointly Owned Utility Plant [Abstract] | ' |
Plant in service | 10,647 |
Accumulated depreciation | 1,225 |
Construction work in progress | 0 |
Ownership % (in hundredths) | 50.00% |
NSP-Minnesota | Electric Transmission | CapX2020 Transmission | ' |
Jointly Owned Utility Plant [Abstract] | ' |
Plant in service | 340,333 |
Accumulated depreciation | 77,803 |
Construction work in progress | 503,714 |
Ownership % (in hundredths) | 53.30% |
NSP-Wisconsin | ' |
Jointly Owned Utility Plant [Abstract] | ' |
Plant in service | 13,337 |
Accumulated depreciation | 4,659 |
Construction work in progress | 35,630 |
NSP-Wisconsin | Electric Transmission | CapX2020 Transmission | ' |
Jointly Owned Utility Plant [Abstract] | ' |
Plant in service | 13,337 |
Accumulated depreciation | 4,659 |
Construction work in progress | 30,199 |
Ownership % (in hundredths) | 77.90% |
NSP-Wisconsin | Electric Transmission | La Crosse, Wis. to Madison, Wis. | ' |
Jointly Owned Utility Plant [Abstract] | ' |
Plant in service | 0 |
Accumulated depreciation | 0 |
Construction work in progress | 5,431 |
Ownership % (in hundredths) | 50.00% |
PSCo | ' |
Jointly Owned Utility Plant [Abstract] | ' |
Plant in service | 1,416,114 |
Accumulated depreciation | 319,241 |
Construction work in progress | 9,818 |
Generating capacity (in MW) | 820 |
PSCo | Electric Generation | Hayden Unit 1 | ' |
Jointly Owned Utility Plant [Abstract] | ' |
Plant in service | 97,879 |
Accumulated depreciation | 63,474 |
Construction work in progress | 53 |
Ownership % (in hundredths) | 75.50% |
PSCo | Electric Generation | Hayden Unit 2 | ' |
Jointly Owned Utility Plant [Abstract] | ' |
Plant in service | 119,972 |
Accumulated depreciation | 57,875 |
Construction work in progress | 5,563 |
Ownership % (in hundredths) | 37.40% |
PSCo | Electric Generation | Hayden Common Facilities | ' |
Jointly Owned Utility Plant [Abstract] | ' |
Plant in service | 36,916 |
Accumulated depreciation | 16,055 |
Construction work in progress | 2 |
Ownership % (in hundredths) | 53.10% |
PSCo | Electric Generation | Craig Units 1 and 2 | ' |
Jointly Owned Utility Plant [Abstract] | ' |
Plant in service | 60,089 |
Accumulated depreciation | 34,754 |
Construction work in progress | 537 |
Ownership % (in hundredths) | 9.70% |
PSCo | Electric Generation | Craig Common Facilities 1, 2 and 3 | ' |
Jointly Owned Utility Plant [Abstract] | ' |
Plant in service | 37,177 |
Accumulated depreciation | 17,247 |
Construction work in progress | 0 |
Ownership % (in hundredths) | 6.50% |
PSCo | Electric Generation | Comanche Unit 3 | ' |
Jointly Owned Utility Plant [Abstract] | ' |
Plant in service | 877,489 |
Accumulated depreciation | 63,963 |
Construction work in progress | 581 |
Ownership % (in hundredths) | 66.70% |
PSCo | Electric Generation | Comanche Common Facilities | ' |
Jointly Owned Utility Plant [Abstract] | ' |
Plant in service | 19,812 |
Accumulated depreciation | 711 |
Construction work in progress | 2,255 |
Ownership % (in hundredths) | 82.00% |
PSCo | Electric Transmission | Transmission and Other Facilities, including Substations | ' |
Jointly Owned Utility Plant [Abstract] | ' |
Plant in service | 150,502 |
Accumulated depreciation | 59,118 |
Construction work in progress | 827 |
Ownership % | 'Various |
PSCo | Gas Transportation | Rifle to Avon | ' |
Jointly Owned Utility Plant [Abstract] | ' |
Plant in service | 16,278 |
Accumulated depreciation | 6,044 |
Construction work in progress | $0 |
Ownership % (in hundredths) | 60.00% |
Income_Taxes_Details
Income Taxes (Details) (USD $) | 3 Months Ended | 12 Months Ended | 1 Months Ended | 3 Months Ended | 12 Months Ended | 3 Months Ended | 12 Months Ended | 3 Months Ended | 12 Months Ended | |||||||||||
Sep. 30, 2012 | Mar. 31, 2010 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Mar. 31, 2013 | Dec. 31, 2013 | Sep. 30, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Mar. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | |||
Internal Revenue Service (IRS) | Internal Revenue Service (IRS) | Internal Revenue Service (IRS) | Internal Revenue Service (IRS) | Colorado | Colorado | Minnesota | Texas | Wisconsin | Wisconsin | State and Local Jurisdiction | State and Local Jurisdiction | |||||||||
American Taxpayer Relief Act of 2012 [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Original top tax rate for dividends | ' | ' | 15.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
New top tax rate for dividends | ' | ' | 20.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Bonus depreciation rate | ' | ' | 50.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Number of years bonus depreciation was extended | ' | ' | '1 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Research and experimentation benefit recorded | ' | ' | ' | ' | ' | $5,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Estimated research and experimentation benefit | ' | ' | 6,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Prescription Drug Tax Benefit and Medicare Part D [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Income tax expense (benefit) related to retiree prescription drug benefits | -17,000,000 | 17,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Number of applicable provisions addressing deductibility of retiree health care costs | ' | 1 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Federal Tax Loss Carryback Claims [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Number Of Years Of Tax Loss Carryback Period | ' | ' | '2 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Tax Adjustments, Settlements, and Unusual Provisions | ' | ' | -12,000,000 | -15,000,000 | ' | ' | 10,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Tax Audits [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Year(s) no longer subject to audit as statute of limitations has expired | ' | ' | ' | ' | ' | ' | ' | ' | '2008 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Earliest year subject to examination | ' | ' | ' | ' | ' | ' | ' | ' | '2009 | ' | ' | '2009 | '2009 | '2008 | ' | '2009 | ' | ' | ||
Year(s) under examination | ' | ' | ' | ' | ' | ' | ' | '2010 and 2011 | ' | ' | ' | 'None | 'None | 'None | '2009 through 2011 | ' | ' | ' | ||
Tax Adjustments, Settlements, and Unusual Provisions | ' | ' | -12,000,000 | -15,000,000 | ' | ' | 10,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Tax year(s) for which income tax examination has been completed | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '2006 through 2009 | ' | ' | ' | ' | ' | ' | ' | ||
Operating Loss Carryforwards | ' | ' | ' | ' | ' | ' | 1,311,000,000 | ' | 1,311,000,000 | 969,000,000 | ' | ' | ' | ' | ' | ' | 1,706,000,000 | 1,465,000,000 | ||
Tax Credit Carryforward, Amount | ' | ' | ' | ' | ' | ' | 294,000,000 | ' | 294,000,000 | 257,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ||
Operating Loss Carryforwards, Valuation Allowance | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -51,000,000 | -52,000,000 | ||
Tax Credit Carryforward Net Of Federal Detriment | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 17,000,000 | [1] | 17,000,000 | [1] |
Federal detriment | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 9,000,000 | 9,000,000 | ||
Carryforward expiration date range, low | ' | ' | ' | ' | ' | ' | ' | ' | '2021 | ' | ' | ' | ' | ' | ' | ' | '2014 | ' | ||
Carryforward expiration date range, high | ' | ' | ' | ' | ' | ' | ' | ' | '2033 | ' | ' | ' | ' | ' | ' | ' | '2033 | ' | ||
Unrecognized Tax Benefits [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Unrecognized tax benefit — Permanent tax positions | ' | ' | 12,900,000 | 4,700,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Unrecognized tax benefit — Temporary tax positions | ' | ' | 28,300,000 | 29,800,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Total unrecognized tax benefit | ' | ' | 41,200,000 | 34,500,000 | 34,700,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Balance at Jan. 1 | ' | ' | 34,500,000 | 34,700,000 | 40,500,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Unrecognized Tax Benefits, Increase Resulting from Current Period Tax Positions | ' | ' | 15,100,000 | 5,200,000 | 11,900,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Unrecognized Tax Benefits, Decrease Resulting from Current Period Tax Positions | ' | ' | -400,000 | -5,700,000 | -1,900,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Unrecognized Tax Benefits Increases Resulting From Prior Period Tax Positions | ' | ' | 21,600,000 | 9,600,000 | 14,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Unrecognized Tax Benefits Decreases Resulting From Prior Period Tax Positions | ' | ' | -4,800,000 | -9,300,000 | -2,400,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Unrecognized Tax Benefits, Decrease Resulting from Settlements with Taxing Authorities | ' | ' | -24,800,000 | 0 | -27,300,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Unrecognized Tax Benefits, Reduction Resulting from Lapse of Applicable Statute of Limitations | ' | ' | 0 | 0 | -100,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Balance at Dec. 31 | ' | ' | 41,200,000 | 34,500,000 | 34,700,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Tax Benefits Associated With NOL And Tax Credit Carryforwards [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
NOL and tax credit carryforwards | ' | ' | -27,100,000 | -33,500,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Upper bound of decrease in unrecognized tax benefit that is reasonably possible | ' | ' | -20,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Amounts accrued for penalties related to unrecognized tax benefits | ' | ' | 0 | 0 | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Effective Income Tax Rate Reconciliation, Percent [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent | ' | ' | 35.00% | 35.00% | 35.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Effective Income Tax Rate Reconciliation, Tax Credit, Percent | ' | ' | -2.60% | -2.20% | -2.60% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Effective Income Tax Rate Reconciliation Regulatory Differences Utility Plant Items | ' | ' | -1.60% | -1.00% | -0.80% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Effective Income Tax Reconciliation, Net operating loss carryback | ' | ' | -0.80% | -1.10% | 0.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Percent | ' | ' | 4.10% | 4.00% | 4.30% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Effective Income Tax Rate Reconciliation Change In Unrecognized Tax Benefits | ' | ' | 0.60% | 0.00% | -0.10% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Effective Income Tax Rate Reconciliation, Deduction, Medicare Prescription Drug Benefit, Percent | ' | ' | 0.00% | -1.20% | 0.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Effective Income Tax Rate Reconciliation, Other Adjustments, Percent | ' | ' | -0.90% | -0.30% | 0.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Effective Income Tax Rate Reconciliation, Percent | ' | ' | 33.80% | 33.20% | 35.80% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Current Federal Tax Expense (Benefit) | ' | ' | -46,173,000 | 7,876,000 | 3,399,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Current State and Local Tax Expense (Benefit) | ' | ' | 7,678,000 | 31,478,000 | 9,971,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Current Change In Unrecognized Tax Expense (Benefit) | ' | ' | 13,162,000 | -1,704,000 | -8,266,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Deferred Federal Income Tax Expense (Benefit) | ' | ' | 439,085,000 | 366,409,000 | 383,931,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Deferred State and Local Income Tax Expense (Benefit) | ' | ' | 80,907,000 | 50,741,000 | 78,770,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Deferred Change In Unrecognized Tax Expense (Benefit) | ' | ' | -4,930,000 | 2,013,000 | 6,705,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Deferred investment tax credits | ' | ' | -5,753,000 | -6,610,000 | -6,194,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Income Tax Expense (Benefit) | ' | ' | 483,976,000 | 450,203,000 | 468,316,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Deferred Income Tax Expense (Benefit), Continuing Operations [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Deferred tax expense (benefit) excluding selected items | ' | ' | 588,053,000 | 559,860,000 | 446,893,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities | ' | ' | -64,420,000 | -63,862,000 | -7,108,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Other Comprehensive Income (Loss), Tax | ' | ' | -8,572,000 | 12,102,000 | 26,798,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Deferred income tax expense (benefit), other | ' | ' | 1,000 | -6,000 | -16,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Deferred Income Tax Expense (Benefit) | ' | ' | 515,062,000 | 508,094,000 | 466,567,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Deferred Tax Liabilities, Gross [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Deferred Tax Liabilities, Property, Plant and Equipment | ' | ' | 5,562,446,000 | 4,867,142,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Deferred Tax Liabilities, Regulatory Assets | ' | ' | 321,636,000 | 293,367,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Deferred Tax Liabilities, Other | ' | ' | 254,639,000 | 220,781,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Deferred Tax Liabilities, Net | ' | ' | 6,138,721,000 | 5,381,290,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Deferred Tax Assets, Gross [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Deferred Tax Assets, Operating Loss Carryforwards | ' | ' | 532,774,000 | 430,765,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Deferred Tax Assets Tax credit carryforward | ' | ' | 311,388,000 | 273,776,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Deferred Tax Assets Unbilled Revenue Fuel Costs | ' | ' | 58,908,000 | 60,068,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Deferred Tax Assets Rate Refund | ' | ' | 49,804,000 | 8,109,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Deferred Tax Assets Environmental Remediation | ' | ' | 42,886,000 | 44,549,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Deferred Tax Assets Regulatory Liabilities | ' | ' | 40,947,000 | 34,471,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Deferred Tax Assets Deferred Investment Tax Credits | ' | ' | 34,231,000 | 35,767,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Deferred Tax Assets, Other | ' | ' | 81,202,000 | 95,308,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Deferred Tax Assets, Valuation Allowance | ' | ' | -3,263,000 | -3,314,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Deferred Tax Assets, Net of Valuation Allowance | ' | ' | 1,148,877,000 | 979,499,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Deferred Tax Assets, Net | ' | ' | $4,989,844,000 | $4,401,791,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
[1] | State tax credit carryforwards are net of federal detriment of $9 million as of Dec. 31, 2013 and 2012 |
Earnings_Per_Share_Details
Earnings Per Share (Details) (USD $) | 1 Months Ended | 3 Months Ended | 12 Months Ended | ||||||||||
In Thousands, except Share data, unless otherwise specified | Mar. 31, 2012 | Feb. 29, 2012 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2012 | Sep. 30, 2012 | Jun. 30, 2012 | Mar. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Dilutive Impact of Common Stock Equivalents on Earnings per Share (Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Net income | ' | ' | $150,055 | $364,752 | $196,857 | $236,570 | $140,170 | $398,106 | $183,060 | $183,893 | $948,234 | $905,229 | $841,172 |
Preferred Stock Dividends, Income Statement Impact | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 0 | -3,534 |
Preferred Stock Redemption Premium | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 0 | -3,260 |
Basic earnings per share [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Earnings available to common shareholders | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 948,234 | 905,229 | 834,378 |
Weighted average common shares outstanding - basic (in shares) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 496,073,000 | 487,899,000 | 485,039,000 |
Earnings available to common shareholders - basic (in dollars per share) | ' | ' | $0.30 | $0.73 | $0.40 | $0.48 | $0.29 | $0.82 | $0.38 | $0.38 | $1.91 | $1.86 | $1.72 |
Effect of dilutive securities [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
401(k) equity awards (in shares) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 459,000 | 535,000 | 576,000 |
Diluted earnings per share [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Earnings available to common shareholders | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $948,234 | $905,229 | $834,378 |
Weighted average common shares outstanding - diluted (in shares) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 496,532,000 | 488,434,000 | 485,615,000 |
Earnings available to common shareholders - diluted (in dollars per share) | ' | ' | $0.30 | $0.73 | $0.40 | $0.48 | $0.29 | $0.81 | $0.38 | $0.38 | $1.91 | $1.85 | $1.72 |
Share Repurchase [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Number of shares of common stock approved to be repurchased (in shares) | ' | 700,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Number of shares of common stock repurchased (in shares) | 700,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Average purchase price per share of common stock repurchased (in dollars per share) | $26.42 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Number of shares of common stock purchased for settlement of equity awards (in shares) | ' | 900,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Stock Options | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 0 | 2,100,000 |
ShareBased_Compensation_Stock_
Share-Based Compensation, Stock Options (Details) (Employee Stock Option [Member], USD $) | 12 Months Ended | |||
In Thousands, except Share data, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |
Employee Stock Option [Member] | ' | ' | ' | |
Stock Options Activity [Roll Forward] | ' | ' | ' | |
Outstanding at Jan. 1 (in shares) | 0 | 0 | 2,498,000 | |
Exercisable at Jan. 1 (in shares) | 0 | 0 | 2,498,000 | |
Exercised (in shares) | 0 | 0 | -1,173,000 | |
Expired (in shares) | 0 | 0 | -1,325,000 | |
Outstanding at Dec. 31 (in shares) | 0 | 0 | 0 | |
Exercisable at Dec. 31 (in shares) | 0 | 0 | 0 | |
Stock Options, Average Exercise Price [Abstract] | ' | ' | ' | |
Outstanding at Jan. 1, average exercise price (in dollars per share) | ' | $0 | $30.42 | |
Exercisable at Jan. 1, average exercise price | ' | $0 | $30.42 | |
Exercised, average exercise price (in dollars per share) | ' | ' | $25.90 | |
Expired, average exercise price (in dollars per share) | ' | ' | $34.42 | |
Outstanding at Dec. 31, average exercise price (in dollars per share) | ' | ' | $0 | |
Exercisable at Dec. 31, average exercise price | ' | ' | $0 | |
Total Market Value and Total Intrinsic Value of Stock Options Exercised [Abstract] | ' | ' | ' | |
Market value of exercises | ' | ' | $30,761 | |
Intrinsic value of options exercised | ' | ' | 380 | [1] |
Cash received from stock options exercised | ' | ' | 30,381 | |
Tax benefit realized for the tax deductions from stock options exercised | ' | ' | $157 | |
[1] | Intrinsic value is calculated as market price at exercise date less the option exercise price. |
ShareBased_Compensation_Restri
Share-Based Compensation, Restricted Stock (Details) (Restricted Stock [Member], USD $) | 12 Months Ended | ||
In Thousands, except Per Share data, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Restricted Stock [Member] | ' | ' | ' |
Equity Instruments Other than Options Activity [Roll Forward] | ' | ' | ' |
Balance at January 1 (in shares) | 54 | ' | ' |
Granted (in shares) | 33 | 33 | 15 |
Vested (in shares) | -27 | ' | ' |
Dividend equivalents (in shares) | 2 | ' | ' |
Balance at December 31 (in shares) | 62 | 54 | ' |
Equity Instruments Other than Options, Weighted Average Grant Date Fair Value [Abstract] | ' | ' | ' |
Balance at January 1, weighted average grant date fair value (in dollars per share) | $24.85 | ' | ' |
Granted, weighted average grant date fair value (in dollars per share) | $28.30 | $26.43 | $23.62 |
Vested, weighted average grant date fair value (in dollars per share) | $23.65 | ' | ' |
Dividend equivalents, weighted average grant date fair value (in dollars per share) | $28.88 | ' | ' |
Balance at December 31, weighted average grant date fair value (in dollars per share) | $27.33 | $24.85 | ' |
Equity Instruments Other than Options, Additional Disclosures [Abstract] | ' | ' | ' |
Award Vesting Period (in years) | '3 years | ' | ' |
ShareBased_Compensation_Restri1
Share-Based Compensation, Restricted Stock Units (RSUs) (Details) (Restricted Stock Units (RSUs) [Member], USD $) | 12 Months Ended | ||
In Millions, except Share data in Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Equity Instruments Other than Options Activity [Roll Forward] | ' | ' | ' |
Balance at January 1 (in shares) | 1,155 | ' | ' |
Granted (in shares) | 774 | 591 | 828 |
Forfeited (in shares) | -81 | ' | ' |
Vested (in shares) | -600 | -100 | -1,100 |
Dividend equivalents (in shares) | 64 | ' | ' |
Balance at December 31 (in shares) | 1,312 | 1,155 | ' |
Equity Instruments Other than Options, Weighted Average Grant Date Fair Value [Abstract] | ' | ' | ' |
Balance at January 1, weighted average grant date fair value (in dollars per share) | $25.41 | ' | ' |
Granted, weighted average grant date fair value (in dollars per share) | $27.65 | $27.35 | $23.63 |
Forfeited, weighted average grant date fair value (in dollars per share) | $26.32 | ' | ' |
Vested, weighted average grant date fair value (in dollars per share) | $23.62 | ' | ' |
Dividend equivalents, weighted average grant date fair value (in dollars per share) | $26.11 | ' | ' |
Balance at December 31, weighted average grant date fair value (in dollars per share) | $27.53 | $25.41 | ' |
Equity Instruments Other than Options, Additional Disclosures [Abstract] | ' | ' | ' |
Total fair value of nonvested RSUs | $36.70 | ' | ' |
Weighted average remaining contractual life of nonvested RSUs (in years) | '1 year 8 months | ' | ' |
Total fair value of RSUs vested during the period | $16.80 | $1.20 | $30.10 |
Performance-based awards [Member] | ' | ' | ' |
Equity Instruments Other than Options, Additional Disclosures [Abstract] | ' | ' | ' |
Share Based Compensation Arrangement By Share Based Payment Award 2010 Rsus Forfeiture Period | '4 years | ' | ' |
Award Vesting Period (in years) | '3 years | ' | ' |
Share Based Compensation Arrangement By Share Based Payment Award Number of performance criteria payout of RSUs and lapsing of restrictions on transfer of units are based | 1 | ' | ' |
Share Based Compensation Arrangement By Share Based Payment Award Total number of performance criteria used to evaluate payout of RSUs and lapsing of restrictions on transfer of units | 2 | ' | ' |
Performance-based awards [Member] | Minimum | ' | ' | ' |
Equity Instruments Other than Options, Additional Disclosures [Abstract] | ' | ' | ' |
Percentage payout for performance-based RSUs | 0.00% | ' | ' |
Performance-based awards [Member] | Maximum | ' | ' | ' |
Equity Instruments Other than Options, Additional Disclosures [Abstract] | ' | ' | ' |
Percentage payout for performance-based RSUs | 150.00% | ' | ' |
Service-based awards [Member] | ' | ' | ' |
Equity Instruments Other than Options Activity [Roll Forward] | ' | ' | ' |
Granted (in shares) | 200 | ' | ' |
ShareBased_Compensation_Stock_1
Share-Based Compensation, Stock Equivalent Unit Plan (Details) (Stock Equivalent Units [Member], USD $) | 12 Months Ended | ||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |
Stock Equivalent Units [Member] | ' | ' | ' |
Equity Instruments Other than Options Activity [Roll Forward] | ' | ' | ' |
Balance at January 1 (in shares) | 577,000 | ' | ' |
Granted (in shares) | 69,000 | 65,000 | 60,000 |
Units distributed (in shares) | -32,000 | ' | ' |
Dividend equivalents (in shares) | 22,000 | ' | ' |
Balance at December 31 (in shares) | 636,000 | 577,000 | ' |
Equity Instruments Other than Options, Weighted Average Grant Date Fair Value [Abstract] | ' | ' | ' |
Balance at January 1, weighted average grant date fair value (in dollars per share) | $21.71 | ' | ' |
Granted, weighted average grant date fair value (in dollars per share) | $29.52 | $27.41 | $25.12 |
Units distributed, weighted average grant date fair value (in dollars per share) | $18.23 | ' | ' |
Dividend equivalents, weighted average grant date fair value (in dollars per share) | $29.06 | ' | ' |
Balance at December 31, weighted average grant date fair value (in dollars per share) | $22.98 | $21.71 | ' |
Equity Instruments Other than Options, Additional Disclosures [Abstract] | ' | ' | ' |
Number of shares of common stock into which the share-based compensation can be converted (in shares) | 1 | ' | ' |
ShareBased_Compensation_PSP_Aw
Share-Based Compensation, PSP Awards (Details) (PSP Awards [Member], USD $) | 12 Months Ended | ||
Share data in Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Equity Instruments Other than Options Activity [Roll Forward] | ' | ' | ' |
Granted (in shares) | 215 | 161 | 311 |
Equity Instruments Other than Options, Additional Disclosures [Abstract] | ' | ' | ' |
Award Vesting Period (in years) | '3 years | ' | ' |
Amount of cash used to settle PSP awards | $1,500,000 | $3,800,000 | $3,600,000 |
Awards settled (in shares) | 108 | 286 | 305 |
Settlement amount (cash and common stock) | $3,057,000 | $7,554,000 | $7,200,000 |
Minimum | ' | ' | ' |
Equity Instruments Other than Options, Additional Disclosures [Abstract] | ' | ' | ' |
Percentage payout for PSP awards | 0.00% | ' | ' |
Maximum | ' | ' | ' |
Equity Instruments Other than Options, Additional Disclosures [Abstract] | ' | ' | ' |
Percentage payout for PSP awards | 200.00% | ' | ' |
ShareBased_Compensation_ShareB
Share-Based Compensation, Share-Based Compensation Expense (Details) (USD $) | 12 Months Ended | |||||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | ||||
Share-Based Compensation Expense [Abstract] | ' | ' | ' | |||
Compensation cost for share-based awards | $24,613,000 | [1],[2],[3] | $26,970,000 | [1],[2],[3] | $45,006,000 | [1],[2],[3] |
Tax benefit recognized in income | 9,571,000 | 10,513,000 | 17,559,000 | |||
Capitalized compensation cost for share-based awards | 1,698,000 | 4,270,000 | 3,857,000 | |||
Matching contributions related to the Xcel Energy 401(k) plan included in compensation cost for share-based awards | 7,000,000 | 22,200,000 | 21,600,000 | |||
Unrecognized compensation cost related to nonvested share-based compensation awards | $22,100,000 | $15,300,000 | ' | |||
Weighted-average period for recognition of unrecognized compensation cost related to nonvested share-based compensation awards (in years) | '1 year 9 months | ' | ' | |||
Xcel Energy Inc. Long-Term Incentive Plan [Member] | ' | ' | ' | |||
Share-Based Compensation Expense [Abstract] | ' | ' | ' | |||
Number of shares of common stock approved for issuance (in shares) | 8,300,000 | ' | ' | |||
Xcel Energy Inc. Executive Annual Incentive Award Plan [Member] | ' | ' | ' | |||
Share-Based Compensation Expense [Abstract] | ' | ' | ' | |||
Number of shares of common stock approved for issuance (in shares) | 1,200,000 | ' | ' | |||
Restricted Stock Units (RSUs) [Member] | ' | ' | ' | |||
Share-Based Compensation Expense [Abstract] | ' | ' | ' | |||
Granted (in shares) | 774,000 | 591,000 | 828,000 | |||
Restricted Stock Units (RSUs) [Member] | Service-based awards [Member] | ' | ' | ' | |||
Share-Based Compensation Expense [Abstract] | ' | ' | ' | |||
Granted (in shares) | 200,000 | ' | ' | |||
[1] | Included in compensation cost for share-based awards are matching contributions related to the Xcel Energy 401(k) plan, which totaled $7.0 million, $22.2 million and $21.6 million for the years ended 2013, 2012 and 2011, respectively. | |||||
[2] | Compensation costs for share-based payment arrangements is included in O&M expense in the consolidated statements of income. | |||||
[3] | In October 2013, Xcel Energy determined that it would settle the 2013 401(k) employer match in cash instead of common stock for all employee groups except PSCo bargaining 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. |
Benefit_Plans_and_Other_Postre2
Benefit Plans and Other Postretirement Benefits, Employees Represented by Local Labor Unions (Details) | Dec. 31, 2013 |
Employees Represented by Local Labor Unions Under Collective Bargaining Agreements Receiving Benefits [Abstract] | ' |
Approximate percent of employees receiving benefits who are represented by local labor unions under collective bargaining agreements (in hundredths) | 48.00% |
NSP-Minnesota | ' |
Employees Represented by Local Labor Unions Under Collective Bargaining Agreements Receiving Benefits [Abstract] | ' |
Number of bargaining employees receiving benefits under several collective bargaining agreements | 2,022 |
Number of nuclear operation bargaining employees receiving benefits under collective bargaining-agreements | 248 |
NSP-Wisconsin | ' |
Employees Represented by Local Labor Unions Under Collective Bargaining Agreements Receiving Benefits [Abstract] | ' |
Number of bargaining employees receiving benefits under several collective bargaining agreements | 399 |
PSCo | ' |
Employees Represented by Local Labor Unions Under Collective Bargaining Agreements Receiving Benefits [Abstract] | ' |
Number of bargaining employees receiving benefits under several collective bargaining agreements | 2,086 |
SPS | ' |
Employees Represented by Local Labor Unions Under Collective Bargaining Agreements Receiving Benefits [Abstract] | ' |
Number of bargaining employees receiving benefits under several collective bargaining agreements | 832 |
Benefit_Plans_and_Other_Postre3
Benefit Plans and Other Postretirement Benefits, Fair Value Hierarchy (Details) | 12 Months Ended |
Dec. 31, 2013 | |
Commingled funds | Minimum | ' |
Defined Benefit Plan Disclosure [Line Items] | ' |
Notice period for investment redemption (in days) | '1 |
Commingled funds | Maximum | ' |
Defined Benefit Plan Disclosure [Line Items] | ' |
Notice period for investment redemption (in days) | '90 |
Real estate funds | Minimum | ' |
Defined Benefit Plan Disclosure [Line Items] | ' |
Notice period for investment redemption (in days) | '45 |
Real estate funds | Maximum | ' |
Defined Benefit Plan Disclosure [Line Items] | ' |
Notice period for investment redemption (in days) | '90 |
Benefit_Plans_and_Other_Postre4
Benefit Plans and Other Postretirement Benefits, Pension Benefits (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Supplemental Executive Retirement Plan (SERP) and Nonqualified Pension Plan | ' | ' | ' |
Pension Benefits [Abstract] | ' | ' | ' |
Total benefit obligation | $36,500 | $39,400 | ' |
Net benefit cost recognized for financial reporting | 6,600 | 15,600 | ' |
Pension Plans | ' | ' | ' |
Pension Benefits [Abstract] | ' | ' | ' |
Total benefit obligation | 3,440,704 | 3,639,530 | 3,226,219 |
Net benefit cost recognized for financial reporting | $151,818 | $127,134 | $80,976 |
Minimum number of years historical achieved weighted average annual returns are used to determine investment return assumptions (in years) | '20 years | ' | ' |
Expected average long-term rate of return on assets (in hundredths) | 6.88% | 7.10% | 7.50% |
Expected average long-term rate of return on assets for next fiscal year (in hundredths) | 7.05% | ' | ' |
Target Pension Asset Allocations [Abstract] | ' | ' | ' |
Target pension asset allocations (in hundredths) | 100.00% | 100.00% | ' |
Pension Plans | Domestic and international equity securities | ' | ' | ' |
Target Pension Asset Allocations [Abstract] | ' | ' | ' |
Target pension asset allocations (in hundredths) | 30.00% | 25.00% | ' |
Pension Plans | Long-duration fixed income and interest rate swap securities | ' | ' | ' |
Target Pension Asset Allocations [Abstract] | ' | ' | ' |
Target pension asset allocations (in hundredths) | 33.00% | 40.00% | ' |
Pension Plans | Short-to-intermediate fixed income securities | ' | ' | ' |
Target Pension Asset Allocations [Abstract] | ' | ' | ' |
Target pension asset allocations (in hundredths) | 15.00% | 10.00% | ' |
Pension Plans | Alternative investments | ' | ' | ' |
Target Pension Asset Allocations [Abstract] | ' | ' | ' |
Target pension asset allocations (in hundredths) | 20.00% | 23.00% | ' |
Pension Plans | Cash | ' | ' | ' |
Target Pension Asset Allocations [Abstract] | ' | ' | ' |
Target pension asset allocations (in hundredths) | 2.00% | 2.00% | ' |
Benefit_Plans_and_Other_Postre5
Benefit Plans and Other Postretirement Benefits, Fair Value of Pension Plan Assets (Details) (Pension Plans, USD $) | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2010 |
In Thousands, unless otherwise specified | ||||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | $3,010,140 | $2,943,783 | $2,670,280 | ' |
Level 1 | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 209,046 | 237,343 | ' | ' |
Level 2 | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 2,600,692 | 2,428,802 | ' | ' |
Level 3 | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 200,402 | 277,638 | 301,359 | 336,328 |
Cash equivalents | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 109,700 | 164,096 | ' | ' |
Cash equivalents | Level 1 | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 109,700 | 164,096 | ' | ' |
Cash equivalents | Level 2 | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 0 | 0 | ' | ' |
Cash equivalents | Level 3 | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 0 | 0 | ' | ' |
Derivatives | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 29,759 | 12,955 | ' | ' |
Derivatives | Level 1 | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 0 | 0 | ' | ' |
Derivatives | Level 2 | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 29,759 | 12,955 | ' | ' |
Derivatives | Level 3 | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 0 | 0 | ' | ' |
Government securities | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 230,212 | 298,141 | ' | ' |
Government securities | Level 1 | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 0 | 0 | ' | ' |
Government securities | Level 2 | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 230,212 | 298,141 | ' | ' |
Government securities | Level 3 | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 0 | 0 | ' | ' |
Corporate bonds | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 547,715 | 622,597 | ' | ' |
Corporate bonds | Level 1 | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 0 | 0 | ' | ' |
Corporate bonds | Level 2 | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 547,715 | 622,597 | ' | ' |
Corporate bonds | Level 3 | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 0 | 0 | ' | ' |
Asset-backed securities | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 6,754 | 14,639 | ' | ' |
Asset-backed securities | Level 1 | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 0 | 0 | ' | ' |
Asset-backed securities | Level 2 | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 6,754 | 0 | ' | ' |
Asset-backed securities | Level 3 | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 0 | 14,639 | 31,368 | 26,986 |
Mortgage-backed securities | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 15,025 | 39,904 | ' | ' |
Mortgage-backed securities | Level 1 | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 0 | 0 | ' | ' |
Mortgage-backed securities | Level 2 | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 15,025 | 0 | ' | ' |
Mortgage-backed securities | Level 3 | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 0 | 39,904 | 73,522 | 113,418 |
Common stock | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 99,346 | 73,247 | ' | ' |
Common stock | Level 1 | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 99,346 | 73,247 | ' | ' |
Common stock | Level 2 | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 0 | 0 | ' | ' |
Common stock | Level 3 | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 0 | 0 | ' | ' |
Private equity investments | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 152,849 | 158,498 | ' | ' |
Private equity investments | Level 1 | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 0 | 0 | ' | ' |
Private equity investments | Level 2 | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 0 | 0 | ' | ' |
Private equity investments | Level 3 | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 152,849 | 158,498 | 159,363 | 122,223 |
Commingled funds | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 1,769,076 | 1,524,563 | ' | ' |
Commingled funds | Level 1 | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 0 | 0 | ' | ' |
Commingled funds | Level 2 | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 1,769,076 | 1,524,563 | ' | ' |
Commingled funds | Level 3 | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 0 | 0 | ' | ' |
Real estate | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 47,553 | 64,597 | ' | ' |
Real estate | Level 1 | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 0 | 0 | ' | ' |
Real estate | Level 2 | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 0 | 0 | ' | ' |
Real estate | Level 3 | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 47,553 | 64,597 | 37,106 | 73,701 |
Securities lending collateral obligation and other | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 2,151 | -29,454 | ' | ' |
Securities lending collateral obligation and other | Level 1 | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 0 | 0 | ' | ' |
Securities lending collateral obligation and other | Level 2 | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 2,151 | -29,454 | ' | ' |
Securities lending collateral obligation and other | Level 3 | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | $0 | $0 | ' | ' |
Benefit_Plans_and_Other_Postre6
Benefit Plans and Other Postretirement Benefits, Changes in Level 3 Pension Plan Assets (Details) (Pension Plans, USD $) | 12 Months Ended | |||
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |
Changes in Level 3 Plan Assets [Roll Forward] | ' | ' | ' | |
Fair value of plan assets at Dec. 31 | $3,010,140 | $2,943,783 | $2,670,280 | |
Level 3 | ' | ' | ' | |
Changes in Level 3 Plan Assets [Roll Forward] | ' | ' | ' | |
Fair value of plan assets at Jan. 1 | 277,638 | 301,359 | 336,328 | |
Net realized gains (losses) | 19,399 | 23,264 | 6,836 | |
Net unrealized gains (losses) | -15,645 | -24,029 | 24,253 | |
Purchases, issuances and settlements, net | 5,945 | -22,956 | -66,058 | |
Transfers in (out) of Level 3 | -86,935 | [1] | 0 | 0 |
Fair value of plan assets at Dec. 31 | 200,402 | 277,638 | 301,359 | |
Asset-backed securities | ' | ' | ' | |
Changes in Level 3 Plan Assets [Roll Forward] | ' | ' | ' | |
Fair value of plan assets at Dec. 31 | 6,754 | 14,639 | ' | |
Asset-backed securities | Level 3 | ' | ' | ' | |
Changes in Level 3 Plan Assets [Roll Forward] | ' | ' | ' | |
Fair value of plan assets at Jan. 1 | 14,639 | 31,368 | 26,986 | |
Net realized gains (losses) | 0 | 3,886 | 2,391 | |
Net unrealized gains (losses) | 0 | -5,363 | -2,504 | |
Purchases, issuances and settlements, net | 0 | -15,252 | 4,495 | |
Transfers in (out) of Level 3 | -14,639 | [1] | 0 | 0 |
Fair value of plan assets at Dec. 31 | 0 | 14,639 | 31,368 | |
Mortgage-backed securities | ' | ' | ' | |
Changes in Level 3 Plan Assets [Roll Forward] | ' | ' | ' | |
Fair value of plan assets at Dec. 31 | 15,025 | 39,904 | ' | |
Mortgage-backed securities | Level 3 | ' | ' | ' | |
Changes in Level 3 Plan Assets [Roll Forward] | ' | ' | ' | |
Fair value of plan assets at Jan. 1 | 39,904 | 73,522 | 113,418 | |
Net realized gains (losses) | 0 | 1,822 | 1,103 | |
Net unrealized gains (losses) | 0 | -2,127 | -5,926 | |
Purchases, issuances and settlements, net | 0 | -33,313 | -35,073 | |
Transfers in (out) of Level 3 | -39,904 | [1] | 0 | 0 |
Fair value of plan assets at Dec. 31 | 0 | 39,904 | 73,522 | |
Private equity investments | ' | ' | ' | |
Changes in Level 3 Plan Assets [Roll Forward] | ' | ' | ' | |
Fair value of plan assets at Dec. 31 | 152,849 | 158,498 | ' | |
Private equity investments | Level 3 | ' | ' | ' | |
Changes in Level 3 Plan Assets [Roll Forward] | ' | ' | ' | |
Fair value of plan assets at Jan. 1 | 158,498 | 159,363 | 122,223 | |
Net realized gains (losses) | 22,058 | 17,537 | 3,971 | |
Net unrealized gains (losses) | -24,335 | -22,587 | 12,412 | |
Purchases, issuances and settlements, net | -3,372 | 4,185 | 20,757 | |
Transfers in (out) of Level 3 | 0 | [1] | 0 | 0 |
Fair value of plan assets at Dec. 31 | 152,849 | 158,498 | 159,363 | |
Real estate | ' | ' | ' | |
Changes in Level 3 Plan Assets [Roll Forward] | ' | ' | ' | |
Fair value of plan assets at Dec. 31 | 47,553 | 64,597 | ' | |
Real estate | Level 3 | ' | ' | ' | |
Changes in Level 3 Plan Assets [Roll Forward] | ' | ' | ' | |
Fair value of plan assets at Jan. 1 | 64,597 | 37,106 | 73,701 | |
Net realized gains (losses) | -2,659 | 19 | -629 | |
Net unrealized gains (losses) | 8,690 | 6,048 | 20,271 | |
Purchases, issuances and settlements, net | 9,317 | 21,424 | -56,237 | |
Transfers in (out) of Level 3 | -32,392 | [1] | 0 | 0 |
Fair value of plan assets at Dec. 31 | $47,553 | $64,597 | $37,106 | |
[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 and were subsequently sold during 2013. |
Benefit_Plans_and_Other_Postre7
Benefit Plans and Other Postretirement Benefits, Pension Plan Benefit Obligations, Cash Flows and Benefit Costs (Details) (Pension Plans, USD $) | 1 Months Ended | 12 Months Ended | ||||
Jan. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |||
Plan | Plan | Plan | Plan | |||
Pension Plans | ' | ' | ' | ' | ||
Defined Benefit Plan Disclosure [Line Items] | ' | ' | ' | ' | ||
Accumulated Benefit Obligation at Dec. 31 | ' | $3,282,651,000 | $3,475,154,000 | ' | ||
Change in Projected Benefit Obligation [Roll Forward] | ' | ' | ' | ' | ||
Obligation at Jan. 1 | 3,440,704,000 | 3,639,530,000 | 3,226,219,000 | ' | ||
Service cost | ' | 96,282,000 | 86,364,000 | 77,319,000 | ||
Interest cost | ' | 140,690,000 | 157,035,000 | 161,412,000 | ||
Plan amendments | ' | -4,120,000 | 6,240,000 | ' | ||
Actuarial (gain) loss | ' | -153,338,000 | 400,429,000 | ' | ||
Benefit payments | ' | -278,340,000 | -236,757,000 | ' | ||
Obligation at Dec. 31 | ' | 3,440,704,000 | 3,639,530,000 | 3,226,219,000 | ||
Change in Fair Value of Plan Assets [Roll Forward] | ' | ' | ' | ' | ||
Fair value of plan assets at Jan. 1 | 3,010,140,000 | 2,943,783,000 | 2,670,280,000 | ' | ||
Actual return (loss) on plan assets | ' | 152,259,000 | 312,167,000 | ' | ||
Employer contributions | ' | 192,438,000 | 198,093,000 | ' | ||
Benefit payments | ' | -278,340,000 | -236,757,000 | ' | ||
Fair value of plan assets at Dec. 31 | ' | 3,010,140,000 | 2,943,783,000 | 2,670,280,000 | ||
Funded Status of Plans at Dec. 31 [Abstract] | ' | ' | ' | ' | ||
Funded status | ' | -430,564,000 | [1] | -695,747,000 | [1] | ' |
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost [Abstract] | ' | ' | ' | ' | ||
Net loss | ' | 1,549,474,000 | 1,800,770,000 | ' | ||
Prior service (credit) cost | ' | -12,624,000 | -2,633,000 | ' | ||
Total | ' | 1,536,850,000 | 1,798,137,000 | ' | ||
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates [Abstract] | ' | ' | ' | ' | ||
Current regulatory assets | ' | 125,702,000 | 115,811,000 | ' | ||
Noncurrent regulatory assets | ' | 1,343,432,000 | 1,606,524,000 | ' | ||
Deferred income taxes | ' | 26,403,000 | 31,075,000 | ' | ||
Net-of-tax accumulated other comprehensive income | ' | 41,313,000 | 44,727,000 | ' | ||
Total | ' | 1,536,850,000 | 1,798,137,000 | ' | ||
Significant Assumptions Used to Measure Benefit Obligations [Abstract] | ' | ' | ' | ' | ||
Measurement date | ' | '12/31/2013 | '12/31/2012 | ' | ||
Discount rate for year-end valuation (in hundredths) | ' | 4.75% | 4.00% | ' | ||
Expected average long-term increase in compensation level (in hundredths) | ' | 3.75% | 3.75% | ' | ||
Mortality table | ' | 'RP 2000 | 'RP 2000 | ' | ||
Cash Flows [Abstract] | ' | ' | ' | ' | ||
Total contributions to Xcel Energy's pension plans during the period | 130,000,000 | 192,400,000 | 198,100,000 | 137,300,000 | ||
Number of pension plans to which contributions were made | 3 | 4 | 4 | 3 | ||
Components of Net Periodic Benefit Cost (Credit) [Abstract] | ' | ' | ' | ' | ||
Service cost | ' | 96,282,000 | 86,364,000 | 77,319,000 | ||
Interest cost | ' | 140,690,000 | 157,035,000 | 161,412,000 | ||
Expected return on plan assets | ' | -198,452,000 | -207,095,000 | -221,600,000 | ||
Amortization of prior service cost (credit) | ' | 5,871,000 | 21,065,000 | 22,533,000 | ||
Amortization of net loss | ' | 144,151,000 | 108,982,000 | 78,510,000 | ||
Net periodic benefit cost | ' | 188,542,000 | 166,351,000 | 118,174,000 | ||
(Costs) credits not recognized due to effects of regulation | ' | -36,724,000 | -39,217,000 | -37,198,000 | ||
Net benefit cost recognized for financial reporting | ' | $151,818,000 | $127,134,000 | $80,976,000 | ||
Significant Assumptions Used to Measure Costs [Abstract] | ' | ' | ' | ' | ||
Discount rate (in hundredths) | ' | 4.00% | 5.00% | 5.50% | ||
Expected average long-term increase in compensation level (in hundredths) | ' | 3.75% | 4.00% | 4.00% | ||
Expected average long-term rate of return on assets (in hundredths) | ' | 6.88% | 7.10% | 7.50% | ||
Expected average long-term rate of return on assets for next fiscal year (in hundredths) | ' | 7.05% | ' | ' | ||
[1] | Amounts are recognized in noncurrent liabilities on Xcel Energy’s consolidated balance sheets. |
Benefit_Plans_and_Other_Postre8
Benefit Plans and Other Postretirement Benefits, Defined Contribution Plans (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Defined Contribution Plans [Abstract] | ' | ' | ' |
Contributions to 401(k) and other defined contribution plans | $30.30 | $28 | $27.10 |
Benefit_Plans_and_Other_Postre9
Benefit Plans and Other Postretirement Benefits, Postretirement Health Care Benefits (Details) (Postretirement Benefit Plan) | 12 Months Ended | |
Dec. 31, 2013 | Dec. 31, 2012 | |
PSCo | ||
Postretirement Health Care Benefits [Abstract] | ' | ' |
Amortization period for unrecognized accumulated postretirement benefit obligation (in years) | '20 years | '15 years |
Recovered_Sheet2
Benefit Plans and Other Postretirement Benefits, Fair Value of Postretirement Benefit Plan Assets (Details) (Postretirement Benefit Plan, USD $) | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2010 |
In Thousands, unless otherwise specified | ||||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | $492,036 | $480,842 | $426,835 | ' |
Level 1 | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 20,438 | 91,278 | ' | ' |
Level 2 | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 471,598 | 348,849 | ' | ' |
Level 3 | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 0 | 40,715 | 35,743 | 21,797 |
Cash equivalents | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 20,438 | 91,278 | ' | ' |
Cash equivalents | Level 1 | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 20,438 | 91,278 | ' | ' |
Cash equivalents | Level 2 | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 0 | 0 | ' | ' |
Cash equivalents | Level 3 | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 0 | 0 | ' | ' |
Derivatives | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | -414 | 4 | ' | ' |
Derivatives | Level 1 | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 0 | 0 | ' | ' |
Derivatives | Level 2 | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | -414 | 4 | ' | ' |
Derivatives | Level 3 | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 0 | 0 | ' | ' |
Government securities | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 58,421 | 73,449 | ' | ' |
Government securities | Level 1 | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 0 | 0 | ' | ' |
Government securities | Level 2 | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 58,421 | 73,449 | ' | ' |
Government securities | Level 3 | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 0 | 0 | ' | ' |
Insurance contracts | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 52,808 | 50,008 | ' | ' |
Insurance contracts | Level 1 | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 0 | 0 | ' | ' |
Insurance contracts | Level 2 | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 52,808 | 50,008 | ' | ' |
Insurance contracts | Level 3 | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 0 | 0 | ' | ' |
Corporate bonds | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 51,861 | 43,810 | ' | ' |
Corporate bonds | Level 1 | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 0 | 0 | ' | ' |
Corporate bonds | Level 2 | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 51,861 | 43,810 | ' | ' |
Corporate bonds | Level 3 | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 0 | 0 | ' | ' |
Asset-backed securities | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 3,358 | 757 | ' | ' |
Asset-backed securities | Level 1 | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 0 | 0 | ' | ' |
Asset-backed securities | Level 2 | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 3,358 | 0 | ' | ' |
Asset-backed securities | Level 3 | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 0 | 757 | 7,867 | 2,585 |
Mortgage-backed securities | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 24,246 | 39,958 | ' | ' |
Mortgage-backed securities | Level 1 | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 0 | 0 | ' | ' |
Mortgage-backed securities | Level 2 | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 24,246 | 0 | ' | ' |
Mortgage-backed securities | Level 3 | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 0 | 39,958 | 27,253 | 19,212 |
Private equity investments | Level 3 | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | ' | 0 | 479 | 0 |
Commingled funds | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 298,258 | 228,423 | ' | ' |
Commingled funds | Level 1 | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 0 | 0 | ' | ' |
Commingled funds | Level 2 | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 298,258 | 228,423 | ' | ' |
Commingled funds | Level 3 | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 0 | 0 | ' | ' |
Real estate | Level 3 | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | ' | 0 | 144 | 0 |
Other | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | -16,940 | -46,845 | ' | ' |
Other | Level 1 | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | 0 | 0 | ' | ' |
Other | Level 2 | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | -16,940 | -46,845 | ' | ' |
Other | Level 3 | ' | ' | ' | ' |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ' | ' | ' | ' |
Fair value of plan assets | $0 | $0 | ' | ' |
Recovered_Sheet3
Benefit Plans and Other Postretirement Benefits, Changes in Level 3 Postretirement Benefit Plan Assets (Details) (Postretirement Benefit Plan, USD $) | 12 Months Ended | |||
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |
Changes in Level 3 Plan Assets [Roll Forward] | ' | ' | ' | |
Fair value of plan assets at Dec. 31 | $492,036 | $480,842 | $426,835 | |
Level 3 | ' | ' | ' | |
Changes in Level 3 Plan Assets [Roll Forward] | ' | ' | ' | |
Fair value of plan assets at Jan. 1 | 40,715 | 35,743 | 21,797 | |
Net realized gains (losses) | 0 | -1,055 | -1,669 | |
Net unrealized gains (losses) | 0 | 4,752 | 1,978 | |
Purchases, issuances and settlements, net | 0 | 1,275 | 13,637 | |
Transfers in (out) of Level 3 | -40,715 | [1] | 0 | 0 |
Fair value of plan assets at Dec. 31 | 0 | 40,715 | 35,743 | |
Asset-backed securities | ' | ' | ' | |
Changes in Level 3 Plan Assets [Roll Forward] | ' | ' | ' | |
Fair value of plan assets at Dec. 31 | 3,358 | 757 | ' | |
Asset-backed securities | Level 3 | ' | ' | ' | |
Changes in Level 3 Plan Assets [Roll Forward] | ' | ' | ' | |
Fair value of plan assets at Jan. 1 | 757 | 7,867 | 2,585 | |
Net realized gains (losses) | 0 | -331 | -10 | |
Net unrealized gains (losses) | 0 | 1,481 | -664 | |
Purchases, issuances and settlements, net | 0 | -8,260 | 5,956 | |
Transfers in (out) of Level 3 | -757 | [1] | 0 | 0 |
Fair value of plan assets at Dec. 31 | 0 | 757 | 7,867 | |
Mortgage-backed securities | ' | ' | ' | |
Changes in Level 3 Plan Assets [Roll Forward] | ' | ' | ' | |
Fair value of plan assets at Dec. 31 | 24,246 | 39,958 | ' | |
Mortgage-backed securities | Level 3 | ' | ' | ' | |
Changes in Level 3 Plan Assets [Roll Forward] | ' | ' | ' | |
Fair value of plan assets at Jan. 1 | 39,958 | 27,253 | 19,212 | |
Net realized gains (losses) | 0 | -724 | -1,669 | |
Net unrealized gains (losses) | 0 | 3,301 | 2,623 | |
Purchases, issuances and settlements, net | 0 | 10,128 | 7,087 | |
Transfers in (out) of Level 3 | -39,958 | [1] | 0 | 0 |
Fair value of plan assets at Dec. 31 | 0 | 39,958 | 27,253 | |
Private equity investments | Level 3 | ' | ' | ' | |
Changes in Level 3 Plan Assets [Roll Forward] | ' | ' | ' | |
Fair value of plan assets at Jan. 1 | ' | 479 | 0 | |
Net realized gains (losses) | ' | 0 | 12 | |
Net unrealized gains (losses) | ' | -65 | 53 | |
Purchases, issuances and settlements, net | ' | -414 | 414 | |
Transfers in (out) of Level 3 | ' | 0 | 0 | |
Fair value of plan assets at Dec. 31 | ' | 0 | 479 | |
Real estate | Level 3 | ' | ' | ' | |
Changes in Level 3 Plan Assets [Roll Forward] | ' | ' | ' | |
Fair value of plan assets at Jan. 1 | ' | 144 | 0 | |
Net realized gains (losses) | ' | 0 | -2 | |
Net unrealized gains (losses) | ' | 35 | -34 | |
Purchases, issuances and settlements, net | ' | -179 | 180 | |
Transfers in (out) of Level 3 | ' | 0 | 0 | |
Fair value of plan assets at Dec. 31 | ' | $0 | $144 | |
[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 and were subsequently sold during 2013. |
Recovered_Sheet4
Benefit Plans and Other Postretirement Benefits, Postretirement Benefit Plan Benefit Obligations, Cash Flows and Benefit Costs (Details) (USD $) | 12 Months Ended | ||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |
Funded Status of Plans at Dec. 31 [Abstract] | ' | ' | ' |
Noncurrent liabilities | ($769,222,000) | ($1,163,265,000) | ' |
Postretirement Benefit Plan | ' | ' | ' |
Change in Projected Benefit Obligation [Roll Forward] | ' | ' | ' |
Obligation at Jan. 1 | 851,952,000 | 776,847,000 | ' |
Service cost | 4,079,000 | 4,203,000 | 4,824,000 |
Interest cost | 32,141,000 | 37,861,000 | 42,086,000 |
Medicare subsidy reimbursements | 1,197,000 | 3,741,000 | ' |
Plan amendments | -14,571,000 | -41,128,000 | ' |
Plan participants' contributions | 9,580,000 | 14,241,000 | ' |
Actuarial (gain) loss | -103,359,000 | 119,949,000 | ' |
Benefit payments | -49,591,000 | -63,762,000 | ' |
Obligation at Dec. 31 | 731,428,000 | 851,952,000 | 776,847,000 |
Change in Fair Value of Plan Assets [Roll Forward] | ' | ' | ' |
Fair value of plan assets at Jan. 1 | 480,842,000 | 426,835,000 | ' |
Actual return (loss) on plan assets | 33,644,000 | 56,385,000 | ' |
Plan participants' contributions | 9,580,000 | 14,241,000 | ' |
Employer contributions | 17,561,000 | 47,143,000 | ' |
Benefit payments | -49,591,000 | -63,762,000 | ' |
Fair value of plan assets at Dec. 31 | 492,036,000 | 480,842,000 | 426,835,000 |
Funded Status of Plans at Dec. 31 [Abstract] | ' | ' | ' |
Funded status | -239,392,000 | -371,110,000 | ' |
Current liabilities | -6,807,000 | -6,070,000 | ' |
Noncurrent liabilities | -232,585,000 | -365,040,000 | ' |
Net postretirement amounts recognized on consolidated balance sheets | -239,392,000 | -371,110,000 | ' |
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost [Abstract] | ' | ' | ' |
Net loss | 195,630,000 | 321,946,000 | ' |
Prior service (credit) cost | -86,298,000 | -84,228,000 | ' |
Transition obligation | 2,000 | 827,000 | ' |
Total | 109,334,000 | 238,545,000 | ' |
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates [Abstract] | ' | ' | ' |
Current regulatory assets | 12,102,000 | 6,930,000 | ' |
Noncurrent regulatory assets | 99,071,000 | 226,052,000 | ' |
Current regulatory liabilities | -319,000 | -954,000 | ' |
Noncurrent regulatory liabilities | -8,858,000 | -3,453,000 | ' |
Deferred income taxes | 2,965,000 | 4,050,000 | ' |
Net-of-tax accumulated other comprehensive income | 4,373,000 | 5,920,000 | ' |
Total | 109,334,000 | 238,545,000 | ' |
Significant Assumptions Used to Measure Benefit Obligations [Abstract] | ' | ' | ' |
Measurement date | '12/31/2013 | '12/31/2012 | ' |
Discount rate for year-end valuation (in hundredths) | 4.82% | 4.10% | ' |
Mortality table | 'RP 2000 | 'RP 2000 | ' |
Health care costs trend rate - initial (in hundredths) | 7.00% | 7.50% | ' |
Ultimate health care trend assumption rate (in hundredths) | 4.50% | 4.50% | ' |
Period until ultimate trend rate is reached (in years) | '5 years | ' | ' |
Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rate [Abstract] | ' | ' | ' |
One-percent increase in APBO | 75,617,000 | ' | ' |
One-percent decrease in APBO | -63,360,000 | ' | ' |
One-percent increase in service and interest components | 3,580,000 | ' | ' |
One-percent decrease in service and interest components | -2,826,000 | ' | ' |
Cash Flows [Abstract] | ' | ' | ' |
Total contributions to Xcel Energy's postretirement health care plans during the year | 17,600,000 | 47,100,000 | 49,000,000 |
Expected contribution to postretirement health care plans during 2014 | 13,300,000 | ' | ' |
Components of Net Periodic Benefit Cost (Credit) [Abstract] | ' | ' | ' |
Service cost | 4,079,000 | 4,203,000 | 4,824,000 |
Interest cost | 32,141,000 | 37,861,000 | 42,086,000 |
Expected return on plan assets | -33,011,000 | -28,409,000 | -31,962,000 |
Amortization of transition obligation | 825,000 | 14,320,000 | 14,444,000 |
Amortization of prior service cost (credit) | -12,501,000 | -7,552,000 | -4,932,000 |
Amortization of net loss | 22,325,000 | 16,906,000 | 13,294,000 |
Net periodic benefit cost | 13,858,000 | 37,329,000 | 37,754,000 |
Additional cost recognized due to effects of regulation | 0 | 3,891,000 | 3,891,000 |
Net benefit cost recognized for financial reporting | $13,858,000 | $41,220,000 | $41,645,000 |
Significant Assumptions Used to Measure Costs [Abstract] | ' | ' | ' |
Discount rate (in hundredths) | 4.10% | 5.00% | 5.50% |
Expected average long-term rate of return on assets (in hundredths) | 7.11% | 6.75% | 7.50% |
Recovered_Sheet5
Benefit Plans and Other Postretirement Benefits, Projected Benefit Payments (Details) (USD $) | Dec. 31, 2013 |
In Thousands, unless otherwise specified | |
Pension Plans | ' |
Defined Benefit Plan, Gross Projected Benefit Payments [Abstract] | ' |
2014 | $313,226 |
2015 | 266,802 |
2016 | 267,186 |
2017 | 269,526 |
2018 | 272,908 |
2019-2023 | 1,339,764 |
Postretirement Benefit Plan | ' |
Defined Benefit Plan, Gross Projected Benefit Payments [Abstract] | ' |
2014 | 53,516 |
2015 | 54,576 |
2016 | 55,965 |
2017 | 56,513 |
2018 | 58,181 |
2019-2023 | 282,860 |
Expected Medicare Part D Subsidies [Abstract] | ' |
2014 | 2,627 |
2015 | 2,806 |
2016 | 2,969 |
2017 | 3,135 |
2018 | 3,291 |
2019-2023 | 18,274 |
Defined Benefit Plan, Net Projected Benefit Payments [Abstract] | ' |
2014 | 50,889 |
2015 | 51,770 |
2016 | 52,996 |
2017 | 53,378 |
2018 | 54,890 |
2019-2023 | $264,586 |
Recovered_Sheet6
Benefit Plans and Other Postretirement Benefits, Multiemployer Plans (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Multiemployer Plans [Abstract] | ' | ' | ' |
Number of employers that must be exceeded during a given period in order for certain union workers to participate in multiemployer plans | 1 | ' | ' |
Multiemployer Pension Plans | ' | ' | ' |
Multiemployer Plans [Abstract] | ' | ' | ' |
Multiemployer contributions | $23,645 | $15,147 | $17,980 |
Multiemployer Pension Plans | NSP-Minnesota | ' | ' | ' |
Multiemployer Plans [Abstract] | ' | ' | ' |
Average number of NSP-Minnesota union employees covered by the multiemployer pension plan | '1100 | '800 | ' |
Multiemployer contributions | 23,515 | 14,984 | 17,811 |
Multiemployer Pension Plans | NSP-Wisconsin | ' | ' | ' |
Multiemployer Plans [Abstract] | ' | ' | ' |
Multiemployer contributions | 130 | 163 | 169 |
Multiemployer Postretirement Benefit Plans | ' | ' | ' |
Multiemployer Plans [Abstract] | ' | ' | ' |
Multiemployer contributions | 390 | 197 | 336 |
Multiemployer Postretirement Benefit Plans | NSP-Minnesota | ' | ' | ' |
Multiemployer Plans [Abstract] | ' | ' | ' |
Multiemployer contributions | $390 | $197 | $336 |
Other_Income_Net_Details
Other Income, Net (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Other Income and Expenses [Abstract] | ' | ' | ' |
Interest income | $8,343 | $10,327 | $10,639 |
Other nonoperating income | 3,025 | 3,483 | 3,722 |
Insurance policy expense | -8,292 | -7,365 | -4,785 |
Other nonoperating expense | -104 | -270 | -321 |
Other income, net | $2,972 | $6,175 | $9,255 |
Fair_Value_of_Financial_Assets2
Fair Value of Financial Assets and Liabilities Fair Value of Financial Assets and Liabilities (Details) | 12 Months Ended |
Dec. 31, 2013 | |
Minimum | Commingled and international equity funds | ' |
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items] | ' |
Notice period for investment redemption (in days) | '1 |
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 |
Maximum | Commingled and international equity funds | ' |
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items] | ' |
Notice period for investment redemption (in days) | '90 |
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 |
Fair_Value_of_Financial_Assets3
Fair Value of Financial Assets and Liabilities, Cost and Fair Value of Nuclear Decommissioning Fund (Details) (USD $) | 12 Months Ended | |||
Dec. 31, 2013 | Dec. 31, 2012 | |||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Gross Unrealized Gain | $240,300,000 | $135,800,000 | ||
Available-for-sale Securities, Gross Unrealized Loss | 58,500,000 | 46,400,000 | ||
Investments [Abstract] | ' | ' | ||
Equity investments in unconsolidated subsidiaries | 87,100,000 | 91,200,000 | ||
Miscellaneous investments | 41,900,000 | 37,100,000 | ||
Nuclear Decommissioning Fund | Cost [Member] | ' | ' | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' | ||
Cash equivalents | 33,281,000 | [1] | ' | |
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities | 1,445,197,000 | [2] | ' | |
Nuclear Decommissioning Fund | Cost [Member] | Commingled funds | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities | 457,986,000 | [1] | ' | |
Nuclear Decommissioning Fund | Cost [Member] | International equity funds | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities | 78,812,000 | [1] | ' | |
Nuclear Decommissioning Fund | Cost [Member] | Private equity investments | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities | 52,143,000 | [1] | ' | |
Nuclear Decommissioning Fund | Cost [Member] | Real estate | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities | 45,564,000 | [1] | ' | |
Nuclear Decommissioning Fund | Cost [Member] | Government securities | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Debt Securities | 34,304,000 | [1] | ' | |
Nuclear Decommissioning Fund | Cost [Member] | U.S. Corporate Bonds | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Debt Securities | 80,275,000 | [1] | ' | |
Nuclear Decommissioning Fund | Cost [Member] | International Corporate Bonds | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Debt Securities | 15,025,000 | [1] | ' | |
Nuclear Decommissioning Fund | Cost [Member] | Municipal Bonds | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Debt Securities | 241,112,000 | [1] | ' | |
Nuclear Decommissioning Fund | Cost [Member] | Common stock | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Equity Securities | 406,695,000 | [1] | ' | |
Nuclear Decommissioning Fund | Fair Value, Measurements, Recurring [Member] | Cost [Member] | ' | ' | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' | ||
Cash equivalents | ' | 246,904,000 | [1] | |
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities | ' | 1,400,145,000 | [1] | |
Nuclear Decommissioning Fund | Fair Value, Measurements, Recurring [Member] | Cost [Member] | Commingled funds | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities | ' | 396,681,000 | [1] | |
Nuclear Decommissioning Fund | Fair Value, Measurements, Recurring [Member] | Cost [Member] | International equity funds | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities | ' | 66,452,000 | [1] | |
Nuclear Decommissioning Fund | Fair Value, Measurements, Recurring [Member] | Cost [Member] | Private equity investments | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities | ' | 27,943,000 | [1] | |
Nuclear Decommissioning Fund | Fair Value, Measurements, Recurring [Member] | Cost [Member] | Real estate | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities | ' | 32,561,000 | [1] | |
Nuclear Decommissioning Fund | Fair Value, Measurements, Recurring [Member] | Cost [Member] | Government securities | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Debt Securities | ' | 21,092,000 | [1] | |
Nuclear Decommissioning Fund | Fair Value, Measurements, Recurring [Member] | Cost [Member] | U.S. Corporate Bonds | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Debt Securities | ' | 162,053,000 | [1] | |
Nuclear Decommissioning Fund | Fair Value, Measurements, Recurring [Member] | Cost [Member] | International Corporate Bonds | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Debt Securities | ' | 15,165,000 | [1] | |
Nuclear Decommissioning Fund | Fair Value, Measurements, Recurring [Member] | Cost [Member] | Municipal Bonds | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Debt Securities | ' | 21,392,000 | [1] | |
Nuclear Decommissioning Fund | Fair Value, Measurements, Recurring [Member] | Cost [Member] | Asset-backed Securities | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Debt Securities | ' | 2,066,000 | [1] | |
Nuclear Decommissioning Fund | Fair Value, Measurements, Recurring [Member] | Cost [Member] | Mortgage-backed securities | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Debt Securities | ' | 28,743,000 | [1] | |
Nuclear Decommissioning Fund | Fair Value, Measurements, Recurring [Member] | Cost [Member] | Common stock | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Equity Securities | ' | 379,093,000 | [1] | |
Nuclear Decommissioning Fund | Fair Value, Measurements, Recurring [Member] | Fair Value [Member] | ' | ' | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' | ||
Cash equivalents | 33,281,000 | [2] | 246,904,000 | [1] |
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities | 1,627,026,000 | [2] | 1,489,542,000 | [1] |
Nuclear Decommissioning Fund | Fair Value, Measurements, Recurring [Member] | Fair Value [Member] | Commingled funds | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities | 452,227,000 | [2] | 417,583,000 | [1] |
Nuclear Decommissioning Fund | Fair Value, Measurements, Recurring [Member] | Fair Value [Member] | International equity funds | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities | 81,671,000 | [2] | 69,481,000 | [1] |
Nuclear Decommissioning Fund | Fair Value, Measurements, Recurring [Member] | Fair Value [Member] | Private equity investments | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities | 62,696,000 | [2] | 33,250,000 | [1] |
Nuclear Decommissioning Fund | Fair Value, Measurements, Recurring [Member] | Fair Value [Member] | Real estate | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities | 57,368,000 | [2] | 39,074,000 | [1] |
Nuclear Decommissioning Fund | Fair Value, Measurements, Recurring [Member] | Fair Value [Member] | Government securities | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Debt Securities | 27,628,000 | [2] | 21,521,000 | [1] |
Nuclear Decommissioning Fund | Fair Value, Measurements, Recurring [Member] | Fair Value [Member] | U.S. Corporate Bonds | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Debt Securities | 83,538,000 | [2] | 169,488,000 | [1] |
Nuclear Decommissioning Fund | Fair Value, Measurements, Recurring [Member] | Fair Value [Member] | International Corporate Bonds | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Debt Securities | 15,358,000 | [2] | 16,052,000 | [1] |
Nuclear Decommissioning Fund | Fair Value, Measurements, Recurring [Member] | Fair Value [Member] | Municipal Bonds | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Debt Securities | 232,016,000 | [2] | 23,650,000 | [1] |
Nuclear Decommissioning Fund | Fair Value, Measurements, Recurring [Member] | Fair Value [Member] | Asset-backed Securities | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Debt Securities | ' | 2,067,000 | [1] | |
Nuclear Decommissioning Fund | Fair Value, Measurements, Recurring [Member] | Fair Value [Member] | Mortgage-backed securities | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Debt Securities | ' | 30,209,000 | [1] | |
Nuclear Decommissioning Fund | Fair Value, Measurements, Recurring [Member] | Fair Value [Member] | Common stock | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Equity Securities | 581,243,000 | [2] | 420,263,000 | [1] |
Nuclear Decommissioning Fund | Fair Value, Measurements, Recurring [Member] | Fair Value [Member] | Level 1 | ' | ' | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' | ||
Cash equivalents | 33,281,000 | [2] | 237,938,000 | [1] |
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities | 614,524,000 | [2] | 658,201,000 | [1] |
Nuclear Decommissioning Fund | Fair Value, Measurements, Recurring [Member] | Fair Value [Member] | Level 1 | Commingled funds | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities | 0 | [2] | 0 | [1] |
Nuclear Decommissioning Fund | Fair Value, Measurements, Recurring [Member] | Fair Value [Member] | Level 1 | International equity funds | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities | 0 | [2] | 0 | [1] |
Nuclear Decommissioning Fund | Fair Value, Measurements, Recurring [Member] | Fair Value [Member] | Level 1 | Private equity investments | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities | 0 | [2] | 0 | [1] |
Nuclear Decommissioning Fund | Fair Value, Measurements, Recurring [Member] | Fair Value [Member] | Level 1 | Real estate | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities | 0 | [2] | 0 | [1] |
Nuclear Decommissioning Fund | Fair Value, Measurements, Recurring [Member] | Fair Value [Member] | Level 1 | Government securities | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Debt Securities | 0 | [2] | 0 | [1] |
Nuclear Decommissioning Fund | Fair Value, Measurements, Recurring [Member] | Fair Value [Member] | Level 1 | U.S. Corporate Bonds | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Debt Securities | 0 | [2] | 0 | [1] |
Nuclear Decommissioning Fund | Fair Value, Measurements, Recurring [Member] | Fair Value [Member] | Level 1 | International Corporate Bonds | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Debt Securities | 0 | [2] | 0 | [1] |
Nuclear Decommissioning Fund | Fair Value, Measurements, Recurring [Member] | Fair Value [Member] | Level 1 | Municipal Bonds | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Debt Securities | 0 | [2] | 0 | [1] |
Nuclear Decommissioning Fund | Fair Value, Measurements, Recurring [Member] | Fair Value [Member] | Level 1 | Asset-backed Securities | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Debt Securities | ' | 0 | [1] | |
Nuclear Decommissioning Fund | Fair Value, Measurements, Recurring [Member] | Fair Value [Member] | Level 1 | Mortgage-backed securities | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Debt Securities | ' | 0 | [1] | |
Nuclear Decommissioning Fund | Fair Value, Measurements, Recurring [Member] | Fair Value [Member] | Level 1 | Common stock | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Equity Securities | 581,243,000 | [2] | 420,263,000 | [1] |
Nuclear Decommissioning Fund | Fair Value, Measurements, Recurring [Member] | Fair Value [Member] | Level 2 | ' | ' | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' | ||
Cash equivalents | 0 | [2] | 8,966,000 | [1] |
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities | 892,438,000 | [2] | 726,741,000 | [1] |
Nuclear Decommissioning Fund | Fair Value, Measurements, Recurring [Member] | Fair Value [Member] | Level 2 | Commingled funds | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities | 452,227,000 | [2] | 417,583,000 | [1] |
Nuclear Decommissioning Fund | Fair Value, Measurements, Recurring [Member] | Fair Value [Member] | Level 2 | International equity funds | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities | 81,671,000 | [2] | 69,481,000 | [1] |
Nuclear Decommissioning Fund | Fair Value, Measurements, Recurring [Member] | Fair Value [Member] | Level 2 | Private equity investments | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities | 0 | [2] | 0 | [1] |
Nuclear Decommissioning Fund | Fair Value, Measurements, Recurring [Member] | Fair Value [Member] | Level 2 | Real estate | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities | 0 | [2] | 0 | [1] |
Nuclear Decommissioning Fund | Fair Value, Measurements, Recurring [Member] | Fair Value [Member] | Level 2 | Government securities | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Debt Securities | 27,628,000 | [2] | 21,521,000 | [1] |
Nuclear Decommissioning Fund | Fair Value, Measurements, Recurring [Member] | Fair Value [Member] | Level 2 | U.S. Corporate Bonds | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Debt Securities | 83,538,000 | [2] | 169,488,000 | [1] |
Nuclear Decommissioning Fund | Fair Value, Measurements, Recurring [Member] | Fair Value [Member] | Level 2 | International Corporate Bonds | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Debt Securities | 15,358,000 | [2] | 16,052,000 | [1] |
Nuclear Decommissioning Fund | Fair Value, Measurements, Recurring [Member] | Fair Value [Member] | Level 2 | Municipal Bonds | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Debt Securities | 232,016,000 | [2] | 23,650,000 | [1] |
Nuclear Decommissioning Fund | Fair Value, Measurements, Recurring [Member] | Fair Value [Member] | Level 2 | Asset-backed Securities | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Debt Securities | ' | 0 | [1] | |
Nuclear Decommissioning Fund | Fair Value, Measurements, Recurring [Member] | Fair Value [Member] | Level 2 | Mortgage-backed securities | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Debt Securities | ' | 0 | [1] | |
Nuclear Decommissioning Fund | Fair Value, Measurements, Recurring [Member] | Fair Value [Member] | Level 2 | Common stock | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Equity Securities | 0 | [2] | 0 | [1] |
Nuclear Decommissioning Fund | Fair Value, Measurements, Recurring [Member] | Fair Value [Member] | Level 3 | ' | ' | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' | ||
Cash equivalents | 0 | [2] | 0 | [1] |
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities | 120,064,000 | [2] | 104,600,000 | [1] |
Nuclear Decommissioning Fund | Fair Value, Measurements, Recurring [Member] | Fair Value [Member] | Level 3 | Commingled funds | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities | 0 | [2] | 0 | [1] |
Nuclear Decommissioning Fund | Fair Value, Measurements, Recurring [Member] | Fair Value [Member] | Level 3 | International equity funds | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities | 0 | [2] | 0 | [1] |
Nuclear Decommissioning Fund | Fair Value, Measurements, Recurring [Member] | Fair Value [Member] | Level 3 | Private equity investments | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities | 62,696,000 | [2] | 33,250,000 | [1] |
Nuclear Decommissioning Fund | Fair Value, Measurements, Recurring [Member] | Fair Value [Member] | Level 3 | Real estate | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities | 57,368,000 | [2] | 39,074,000 | [1] |
Nuclear Decommissioning Fund | Fair Value, Measurements, Recurring [Member] | Fair Value [Member] | Level 3 | Government securities | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Debt Securities | 0 | [2] | 0 | [1] |
Nuclear Decommissioning Fund | Fair Value, Measurements, Recurring [Member] | Fair Value [Member] | Level 3 | U.S. Corporate Bonds | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Debt Securities | 0 | [2] | 0 | [1] |
Nuclear Decommissioning Fund | Fair Value, Measurements, Recurring [Member] | Fair Value [Member] | Level 3 | International Corporate Bonds | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Debt Securities | 0 | [2] | 0 | [1] |
Nuclear Decommissioning Fund | Fair Value, Measurements, Recurring [Member] | Fair Value [Member] | Level 3 | Municipal Bonds | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Debt Securities | 0 | [2] | 0 | [1] |
Nuclear Decommissioning Fund | Fair Value, Measurements, Recurring [Member] | Fair Value [Member] | Level 3 | Asset-backed Securities | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Debt Securities | ' | 2,067,000 | [1] | |
Nuclear Decommissioning Fund | Fair Value, Measurements, Recurring [Member] | Fair Value [Member] | Level 3 | Mortgage-backed securities | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Debt Securities | ' | 30,209,000 | [1] | |
Nuclear Decommissioning Fund | Fair Value, Measurements, Recurring [Member] | Fair Value [Member] | Level 3 | Common stock | ' | ' | ||
Available-for-sale Securities [Abstract] | ' | ' | ||
Available-for-sale Securities, Equity Securities | $0 | [2] | $0 | [1] |
[1] | Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $91.2 million of equity investments in unconsolidated subsidiaries and $37.1 million of miscellaneous investments. | |||
[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 $) | 12 Months Ended | ||||
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | ||
Changes in Level 3 Nuclear Decommissioning Fund Assets [Roll Forward] | ' | ' | ' | ||
Balance at beginning of period | $104,600 | $130,763 | $105,763 | ||
Purchases | 55,827 | 63,464 | 219,177 | ||
Settlements | -18,622 | -99,891 | -193,694 | ||
Gains (losses) recognized as regulatory assets and liabilities | 10,535 | 10,264 | -483 | ||
Transfers out of Level 3 | -32,276 | [1] | 0 | [1] | 0 |
Balance at end of period | 120,064 | 104,600 | 130,763 | ||
Private equity investments | ' | ' | ' | ||
Changes in Level 3 Nuclear Decommissioning Fund Assets [Roll Forward] | ' | ' | ' | ||
Balance at beginning of period | 33,250 | 9,203 | 0 | ||
Purchases | 24,201 | 20,671 | 9,203 | ||
Settlements | 0 | -1,931 | 0 | ||
Gains (losses) recognized as regulatory assets and liabilities | 5,245 | 5,307 | 0 | ||
Transfers out of Level 3 | 0 | [1] | 0 | [1] | 0 |
Balance at end of period | 62,696 | 33,250 | 9,203 | ||
Real estate | ' | ' | ' | ||
Changes in Level 3 Nuclear Decommissioning Fund Assets [Roll Forward] | ' | ' | ' | ||
Balance at beginning of period | 39,074 | 26,395 | 0 | ||
Purchases | 31,626 | 9,777 | 24,768 | ||
Settlements | -18,622 | -3,611 | 0 | ||
Gains (losses) recognized as regulatory assets and liabilities | 5,290 | 6,513 | 1,627 | ||
Transfers out of Level 3 | 0 | [1] | 0 | [1] | 0 |
Balance at end of period | 57,368 | 39,074 | 26,395 | ||
Asset-backed Securities | ' | ' | ' | ||
Changes in Level 3 Nuclear Decommissioning Fund Assets [Roll Forward] | ' | ' | ' | ||
Balance at beginning of period | 2,067 | 16,501 | 33,174 | ||
Purchases | 0 | 0 | 16,518 | ||
Settlements | 0 | -14,450 | -32,560 | ||
Gains (losses) recognized as regulatory assets and liabilities | 0 | 16 | -631 | ||
Transfers out of Level 3 | -2,067 | [1] | 0 | [1] | 0 |
Balance at end of period | 0 | 2,067 | 16,501 | ||
Mortgage-backed securities | ' | ' | ' | ||
Changes in Level 3 Nuclear Decommissioning Fund Assets [Roll Forward] | ' | ' | ' | ||
Balance at beginning of period | 30,209 | 78,664 | 72,589 | ||
Purchases | 0 | 33,016 | 168,688 | ||
Settlements | 0 | -79,899 | -161,134 | ||
Gains (losses) recognized as regulatory assets and liabilities | 0 | -1,572 | -1,479 | ||
Transfers out of Level 3 | -30,209 | [1] | 0 | [1] | 0 |
Balance at end of period | $0 | $30,209 | $78,664 | ||
[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 and were subsequently sold during 2013. |
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 $) | Dec. 31, 2013 |
In Thousands, unless otherwise specified | |
Final Contractual Maturity [Abstract] | ' |
Due in 1 Year or Less | $4,334 |
Due in 1 to 5 Years | 45,735 |
Due in 5 to 10 Years | 109,334 |
Due after 10 Years | 199,137 |
Total | 358,540 |
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 | 27,628 |
Total | 27,628 |
U.S. Corporate Bonds | ' |
Final Contractual Maturity [Abstract] | ' |
Due in 1 Year or Less | 780 |
Due in 1 to 5 Years | 17,850 |
Due in 5 to 10 Years | 63,089 |
Due after 10 Years | 1,819 |
Total | 83,538 |
International Corporate Bonds | ' |
Final Contractual Maturity [Abstract] | ' |
Due in 1 Year or Less | 0 |
Due in 1 to 5 Years | 2,222 |
Due in 5 to 10 Years | 13,136 |
Due after 10 Years | 0 |
Total | 15,358 |
Municipal Bonds | ' |
Final Contractual Maturity [Abstract] | ' |
Due in 1 Year or Less | 3,554 |
Due in 1 to 5 Years | 25,663 |
Due in 5 to 10 Years | 33,109 |
Due after 10 Years | 169,690 |
Total | $232,016 |
Fair_Value_of_Financial_Assets6
Fair Value of Financial Assets and Liabilities, Derivative Instruments (Details) (USD $) | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Aug. 31, 2012 | Sep. 30, 2012 | ||||||
In Millions, unless otherwise specified | Credit Concentration Risk [Member] | Credit Concentration Risk [Member] | Credit Concentration Risk [Member] | Interest Rate Swap [Member] | Electric Commodity [Member] | Electric Commodity [Member] | Natural Gas Commodity [Member] | Natural Gas Commodity [Member] | Vehicle Fuel Commodity [Member] | Vehicle Fuel Commodity [Member] | NSP-Minnesota | PSCo | |||||||
Counterparty | Investment Grade Ratings from Standard & Poor's, Moody's, or Fitch Ratings [Member] | No Investment Grade Ratings from External Credit Rating Agencies [Member] | MWh | MWh | MMBTU | MMBTU | gal | gal | Interest Rate Swap [Member] | Interest Rate Swap [Member] | |||||||||
Counterparty | Counterparty | ||||||||||||||||||
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 | ' | ' | ' | ' | ($2.30) | ' | ' | ' | ' | ' | ' | ' | ' | ||||||
Notional Amount of Interest Rate Derivatives | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 225 | 250 | ||||||
Cash payments to settle interest rate hedging instruments | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 45 | 44.7 | ||||||
Commodity Derivatives [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||
Amount of accumulated other comprehensive gains (losses) related to commodity derivatives expected to be reclassified into earnings within the next twelve months | 0.1 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||
Gross Notional Amounts of Commodity Forwards, Options and FTRs [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||
Derivative, Nonmonetary Notional amount | ' | ' | ' | ' | ' | 58,423,000 | [1],[2] | 55,976,000 | [1],[2] | 9,854,000 | [1],[2] | 725,000 | [1],[2] | 482,000 | [1],[2] | 682,000 | [1],[2] | ' | ' |
Consideration of Credit Risk and Concentrations [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure | ' | 10 | 4 | 6 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties | ' | ' | $49.30 | $68.10 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths) | ' | ' | 18.00% | 25.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||
[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, Financial Impact of Qualifying Cash Flow Hedges (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Financial Impact of Qualifying Cash Flow Hedges on Accumulated Other Comprehensive Income (Loss) [Roll Forward] | ' | ' | ' |
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1 | ($61,241) | ($45,738) | ($8,094) |
After-tax net unrealized gains (losses) related to derivatives accounted for as hedges | 12 | -19,200 | -38,292 |
After-tax net realized losses on derivative transactions reclassified into earnings | 1,476 | 3,697 | 648 |
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31 | ($59,753) | ($61,241) | ($45,738) |
Fair_Value_of_Financial_Assets8
Fair Value of Financial Assets and Liabilities, Impact of Derivative Activity (Details) (USD $) | 12 Months Ended | |||||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | ||||
Financial Impact of Qualifying Fair Value Hedges on Earnings [Abstract] | ' | ' | ' | |||
Derivative instruments designated as fair value hedges | $0 | $0 | $0 | |||
Recognized gains (losses) from fair value hedges or related hedged transactions | 0 | 0 | 0 | |||
Cash Flow Hedges [Member] | ' | ' | ' | |||
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract] | ' | ' | ' | |||
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss | 29,000 | -31,793,000 | -63,378,000 | |||
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities | 0 | 0 | 0 | |||
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss | 4,017,000 | 6,384,000 | 1,246,000 | |||
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities) | 0 | 0 | 0 | |||
Pre-tax gains (losses) recognized during the period in income | 0 | 0 | 0 | |||
Cash Flow Hedges [Member] | Interest Rate [Member] | ' | ' | ' | |||
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract] | ' | ' | ' | |||
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss | 0 | -31,913,000 | -63,573,000 | |||
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities | 0 | 0 | 0 | |||
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss | 4,107,000 | [1] | 6,582,000 | [1] | 1,424,000 | [1] |
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities) | 0 | 0 | 0 | |||
Pre-tax gains (losses) recognized during the period in income | 0 | 0 | 0 | |||
Cash Flow Hedges [Member] | Vehicle Fuel And Other Commodity [Member] | ' | ' | ' | |||
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract] | ' | ' | ' | |||
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss | 29,000 | 120,000 | 195,000 | |||
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities | 0 | 0 | 0 | |||
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss | -90,000 | [2] | -198,000 | [2] | -178,000 | [2] |
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities) | 0 | 0 | 0 | |||
Pre-tax gains (losses) recognized during the period in income | 0 | 0 | 0 | |||
Other Derivative Instruments [Member] | ' | ' | ' | |||
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract] | ' | ' | ' | |||
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss | 0 | 0 | 0 | |||
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities | 72,729,000 | 33,353,000 | -61,756,000 | |||
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss | 0 | 0 | 0 | |||
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities) | -47,777,000 | 40,903,000 | 51,251,000 | |||
Pre-tax gains (losses) recognized during the period in income | 4,632,000 | 12,089,000 | 6,036,000 | |||
Other Derivative Instruments [Member] | Commodity Trading [Member] | ' | ' | ' | |||
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract] | ' | ' | ' | |||
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss | 0 | 0 | 0 | |||
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities | 0 | 0 | 0 | |||
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss | 0 | 0 | 0 | |||
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities) | 0 | 0 | 0 | |||
Pre-tax gains (losses) recognized during the period in income | 11,221,000 | [3] | 12,226,000 | [3] | 6,418,000 | [3] |
Other Derivative Instruments [Member] | Electric Commodity [Member] | ' | ' | ' | |||
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract] | ' | ' | ' | |||
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss | 0 | 0 | 0 | |||
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities | 75,817,000 | 44,162,000 | 49,818,000 | |||
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss | 0 | 0 | 0 | |||
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities) | -52,796,000 | [4] | -39,999,000 | [4] | -40,492,000 | [4] |
Pre-tax gains (losses) recognized during the period in income | 0 | 0 | 0 | |||
Other Derivative Instruments [Member] | Natural Gas Commodity [Member] | ' | ' | ' | |||
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract] | ' | ' | ' | |||
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss | 0 | 0 | 0 | |||
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities | -3,088,000 | -10,809,000 | -111,574,000 | |||
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss | 0 | 0 | 0 | |||
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities) | 5,019,000 | [5] | 80,902,000 | [5] | 91,743,000 | [5] |
Pre-tax gains (losses) recognized during the period in income | -6,589,000 | [4] | -137,000 | [4] | -382,000 | [4] |
Other Derivative Instruments [Member] | Natural Gas Commodity for Electric Generation [Member] | ' | ' | ' | |||
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract] | ' | ' | ' | |||
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities) | ' | $5,000,000 | $12,700,000 | |||
[1] | Amounts are recorded to interest charges. | |||||
[2] | Amounts are recorded to O&M expenses. | |||||
[3] | Amounts are recorded to electric operating revenues. Portions of these gains and losses are subject to sharing with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate. | |||||
[4] | Amounts are recorded to electric fuel and purchased power. These derivative settlement gains and losses are shared with electric customers through fuel and purchased energy cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate. | |||||
[5] | Amounts for the years ended Dec. 31, 2012 and 2011 included $5.0 million and $12.7 million, respectively, of settlement losses on derivatives entered to mitigate natural gas price risk for electric generation, recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate. Such losses for the year ended Dec. 31, 2013 were immaterial. The remaining settlement losses for the years ended Dec. 31, 2013, 2012 and 2011 relate to natural gas operations and are recorded to cost of natural gas sold and transported. These losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset, as appropriate. |
Fair_Value_of_Financial_Assets9
Fair Value of Financial Assets and Liabilities, Credit Related Contingent Features (Details) (USD $) | Dec. 31, 2013 | Dec. 31, 2012 |
Fair Value Disclosures [Abstract] | ' | ' |
Derivative instruments in a gross liability position | $1,400,000 | $4,600,000 |
Payments required if credit ratings were downgraded below investment grade | 1,400,000 | 4,600,000 |
Collateral posted on derivative instruments | 0 | 0 |
Collateral posted related to adequate assurance clauses in derivative contracts | $0 | $0 |
Recovered_Sheet7
Fair Value of Financial Assets and Liabilities, Derivative Assets and Liabilities at Fair Value (Details) (USD $) | Dec. 31, 2013 | Dec. 31, 2012 | ||
Other Current Assets [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | $91,707,000 | $69,013,000 | ||
Other Noncurrent Assets [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 84,842,000 | 126,297,000 | ||
Other Current Liabilities [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 23,382,000 | 32,482,000 | ||
Other Noncurrent Liabilities [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 209,224,000 | 242,866,000 | ||
Counterparty Netting [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Collateral, Right to Reclaim Cash, Offset | 4,200,000 | 3,000,000 | ||
Derivative Asset, Collateral, Obligation to Return Cash, Offset | 200,000 | 600,000 | ||
Fair Value Measured on a Recurring Basis | Other Current Assets [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 58,679,000 | 36,296,000 | ||
Fair Value Measured on a Recurring Basis | Other Current Assets [Member] | Designated as Hedging Instrument [Member] | Vehicle Fuel And Other Commodity [Member] | Cash Flow Hedges [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 88,000 | 95,000 | ||
Fair Value Measured on a Recurring Basis | Other Current Assets [Member] | Other Derivative Instruments [Member] | Commodity Trading | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 13,783,000 | 20,320,000 | ||
Fair Value Measured on a Recurring Basis | Other Current Assets [Member] | Other Derivative Instruments [Member] | Electric Commodity [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 38,902,000 | 15,881,000 | ||
Fair Value Measured on a Recurring Basis | Other Current Assets [Member] | Other Derivative Instruments [Member] | Natural Gas Commodity [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 5,906,000 | 0 | ||
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 26,411,000 | 37,236,000 | ||
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets [Member] | Designated as Hedging Instrument [Member] | Vehicle Fuel And Other Commodity [Member] | Cash Flow Hedges [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 13,000 | 39,000 | ||
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets [Member] | Other Derivative Instruments [Member] | Commodity Trading | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 26,398,000 | 37,197,000 | ||
Fair Value Measured on a Recurring Basis | Other Current Liabilities [Member] | Other Derivative Instruments [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 348,000 | 9,602,000 | ||
Fair Value Measured on a Recurring Basis | Other Current Liabilities [Member] | Other Derivative Instruments [Member] | Commodity Trading | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 348,000 | 9,511,000 | ||
Fair Value Measured on a Recurring Basis | Other Current Liabilities [Member] | Other Derivative Instruments [Member] | Electric Commodity [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 0 | 0 | ||
Fair Value Measured on a Recurring Basis | Other Current Liabilities [Member] | Other Derivative Instruments [Member] | Natural Gas Commodity [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | ' | 91,000 | ||
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities [Member] | Other Derivative Instruments [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 5,295,000 | 17,207,000 | ||
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities [Member] | Other Derivative Instruments [Member] | Commodity Trading | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 5,295,000 | 17,207,000 | ||
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 | ||
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets [Member] | Designated as Hedging Instrument [Member] | Vehicle Fuel And Other Commodity [Member] | Cash Flow Hedges [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 | ||
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets [Member] | Other Derivative Instruments [Member] | Commodity Trading | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 | ||
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets [Member] | Other Derivative Instruments [Member] | Electric Commodity [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 | ||
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets [Member] | Other Derivative Instruments [Member] | Natural Gas Commodity [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 | ||
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Assets [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 | ||
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Assets [Member] | Designated as Hedging Instrument [Member] | Vehicle Fuel And Other Commodity [Member] | Cash Flow Hedges [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 | ||
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Assets [Member] | Other Derivative Instruments [Member] | Commodity Trading | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 | ||
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities [Member] | Other Derivative Instruments [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 0 | 0 | ||
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities [Member] | Other Derivative Instruments [Member] | Commodity Trading | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 0 | 0 | ||
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities [Member] | Other Derivative Instruments [Member] | Electric Commodity [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 0 | 0 | ||
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities [Member] | Other Derivative Instruments [Member] | Natural Gas Commodity [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | ' | 0 | ||
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Liabilities [Member] | Other Derivative Instruments [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 0 | 0 | ||
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Liabilities [Member] | Other Derivative Instruments [Member] | Commodity Trading | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 0 | 0 | ||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 26,604,000 | 26,405,000 | ||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets [Member] | Designated as Hedging Instrument [Member] | Vehicle Fuel And Other Commodity [Member] | Cash Flow Hedges [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 88,000 | 95,000 | ||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets [Member] | Other Derivative Instruments [Member] | Commodity Trading | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 20,610,000 | 26,303,000 | ||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets [Member] | Other Derivative Instruments [Member] | Electric Commodity [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 | ||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets [Member] | Other Derivative Instruments [Member] | Natural Gas Commodity [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 5,906,000 | 7,000 | ||
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Assets [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 32,103,000 | 41,368,000 | ||
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Assets [Member] | Designated as Hedging Instrument [Member] | Vehicle Fuel And Other Commodity [Member] | Cash Flow Hedges [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 29,000 | 86,000 | ||
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Assets [Member] | Other Derivative Instruments [Member] | Commodity Trading | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 32,074,000 | 41,282,000 | ||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities [Member] | Other Derivative Instruments [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 10,546,000 | 18,720,000 | ||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities [Member] | Other Derivative Instruments [Member] | Commodity Trading | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 10,546,000 | 18,622,000 | ||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities [Member] | Other Derivative Instruments [Member] | Electric Commodity [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 0 | 0 | ||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities [Member] | Other Derivative Instruments [Member] | Natural Gas Commodity [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | ' | 98,000 | ||
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Liabilities [Member] | Other Derivative Instruments [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 14,382,000 | 21,417,000 | ||
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Liabilities [Member] | Other Derivative Instruments [Member] | Commodity Trading | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 14,382,000 | 21,417,000 | ||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 48,279,000 | 17,416,000 | ||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets [Member] | Designated as Hedging Instrument [Member] | Vehicle Fuel And Other Commodity [Member] | Cash Flow Hedges [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 | ||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets [Member] | Other Derivative Instruments [Member] | Commodity Trading | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 1,167,000 | 692,000 | ||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets [Member] | Other Derivative Instruments [Member] | Electric Commodity [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 47,112,000 | 16,724,000 | ||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets [Member] | Other Derivative Instruments [Member] | Natural Gas Commodity [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 | ||
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Assets [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 3,395,000 | 77,000 | ||
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Assets [Member] | Designated as Hedging Instrument [Member] | Vehicle Fuel And Other Commodity [Member] | Cash Flow Hedges [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 | ||
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Assets [Member] | Other Derivative Instruments [Member] | Commodity Trading | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 3,395,000 | 77,000 | ||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities [Member] | Other Derivative Instruments [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 10,014,000 | 844,000 | ||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities [Member] | Other Derivative Instruments [Member] | Commodity Trading | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 1,804,000 | 1,000 | ||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities [Member] | Other Derivative Instruments [Member] | Electric Commodity [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 8,210,000 | 843,000 | ||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities [Member] | Other Derivative Instruments [Member] | Natural Gas Commodity [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | ' | 0 | ||
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Liabilities [Member] | Other Derivative Instruments [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 0 | 0 | ||
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Liabilities [Member] | Other Derivative Instruments [Member] | Commodity Trading | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 0 | 0 | ||
Fair Value Measured on a Recurring Basis | Fair Value Total [Member] | Other Current Assets [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 74,883,000 | 43,821,000 | ||
Fair Value Measured on a Recurring Basis | Fair Value Total [Member] | Other Current Assets [Member] | Designated as Hedging Instrument [Member] | Vehicle Fuel And Other Commodity [Member] | Cash Flow Hedges [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 88,000 | 95,000 | ||
Fair Value Measured on a Recurring Basis | Fair Value Total [Member] | Other Current Assets [Member] | Other Derivative Instruments [Member] | Commodity Trading | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 21,777,000 | 26,995,000 | ||
Fair Value Measured on a Recurring Basis | Fair Value Total [Member] | Other Current Assets [Member] | Other Derivative Instruments [Member] | Electric Commodity [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 47,112,000 | 16,724,000 | ||
Fair Value Measured on a Recurring Basis | Fair Value Total [Member] | Other Current Assets [Member] | Other Derivative Instruments [Member] | Natural Gas Commodity [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 5,906,000 | 7,000 | ||
Fair Value Measured on a Recurring Basis | Fair Value Total [Member] | Other Noncurrent Assets [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 35,498,000 | 41,445,000 | ||
Fair Value Measured on a Recurring Basis | Fair Value Total [Member] | Other Noncurrent Assets [Member] | Designated as Hedging Instrument [Member] | Vehicle Fuel And Other Commodity [Member] | Cash Flow Hedges [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 29,000 | 86,000 | ||
Fair Value Measured on a Recurring Basis | Fair Value Total [Member] | Other Noncurrent Assets [Member] | Other Derivative Instruments [Member] | Commodity Trading | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 35,469,000 | 41,359,000 | ||
Fair Value Measured on a Recurring Basis | Fair Value Total [Member] | Other Current Liabilities [Member] | Other Derivative Instruments [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 20,560,000 | 19,564,000 | ||
Fair Value Measured on a Recurring Basis | Fair Value Total [Member] | Other Current Liabilities [Member] | Other Derivative Instruments [Member] | Commodity Trading | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 12,350,000 | 18,623,000 | ||
Fair Value Measured on a Recurring Basis | Fair Value Total [Member] | Other Current Liabilities [Member] | Other Derivative Instruments [Member] | Electric Commodity [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 8,210,000 | 843,000 | ||
Fair Value Measured on a Recurring Basis | Fair Value Total [Member] | Other Current Liabilities [Member] | Other Derivative Instruments [Member] | Natural Gas Commodity [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | ' | 98,000 | ||
Fair Value Measured on a Recurring Basis | Fair Value Total [Member] | Other Noncurrent Liabilities [Member] | Other Derivative Instruments [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 14,382,000 | 21,417,000 | ||
Fair Value Measured on a Recurring Basis | Fair Value Total [Member] | Other Noncurrent Liabilities [Member] | Other Derivative Instruments [Member] | Commodity Trading | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 14,382,000 | 21,417,000 | ||
Fair Value Measured on a Recurring Basis | Counterparty Netting [Member] | Other Current Assets [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | -16,204,000 | [1] | -7,525,000 | [2] |
Fair Value Measured on a Recurring Basis | Counterparty Netting [Member] | Other Current Assets [Member] | Designated as Hedging Instrument [Member] | Vehicle Fuel And Other Commodity [Member] | Cash Flow Hedges [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 0 | [1] | 0 | [2] |
Fair Value Measured on a Recurring Basis | Counterparty Netting [Member] | Other Current Assets [Member] | Other Derivative Instruments [Member] | Commodity Trading | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | -7,994,000 | [1] | -6,675,000 | [2] |
Fair Value Measured on a Recurring Basis | Counterparty Netting [Member] | Other Current Assets [Member] | Other Derivative Instruments [Member] | Electric Commodity [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | -8,210,000 | [1] | -843,000 | [2] |
Fair Value Measured on a Recurring Basis | Counterparty Netting [Member] | Other Current Assets [Member] | Other Derivative Instruments [Member] | Natural Gas Commodity [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 0 | [1] | -7,000 | [2] |
Fair Value Measured on a Recurring Basis | Counterparty Netting [Member] | Other Noncurrent Assets [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | -9,087,000 | [1] | -4,209,000 | [2] |
Fair Value Measured on a Recurring Basis | Counterparty Netting [Member] | Other Noncurrent Assets [Member] | Designated as Hedging Instrument [Member] | Vehicle Fuel And Other Commodity [Member] | Cash Flow Hedges [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | -16,000 | [1] | -47,000 | [2] |
Fair Value Measured on a Recurring Basis | Counterparty Netting [Member] | Other Noncurrent Assets [Member] | Other Derivative Instruments [Member] | Commodity Trading | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | -9,071,000 | [1] | -4,162,000 | [2] |
Fair Value Measured on a Recurring Basis | Counterparty Netting [Member] | Other Current Liabilities [Member] | Other Derivative Instruments [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | -20,212,000 | [1] | -9,962,000 | [2] |
Fair Value Measured on a Recurring Basis | Counterparty Netting [Member] | Other Current Liabilities [Member] | Other Derivative Instruments [Member] | Commodity Trading | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | -12,002,000 | [1] | -9,112,000 | [2] |
Fair Value Measured on a Recurring Basis | Counterparty Netting [Member] | Other Current Liabilities [Member] | Other Derivative Instruments [Member] | Electric Commodity [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | -8,210,000 | [1] | -843,000 | [2] |
Fair Value Measured on a Recurring Basis | Counterparty Netting [Member] | Other Current Liabilities [Member] | Other Derivative Instruments [Member] | Natural Gas Commodity [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | ' | -7,000 | [2] | |
Fair Value Measured on a Recurring Basis | Counterparty Netting [Member] | Other Noncurrent Liabilities [Member] | Other Derivative Instruments [Member] | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | -9,087,000 | [1] | -4,210,000 | [2] |
Fair Value Measured on a Recurring Basis | Counterparty Netting [Member] | Other Noncurrent Liabilities [Member] | Other Derivative Instruments [Member] | Commodity Trading | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | -9,087,000 | [1] | -4,210,000 | [2] |
Fair Value, Measurements, Nonrecurring [Member] | Other Current Assets [Member] | Purchased Power Agreements | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 33,028,000 | [3] | 32,717,000 | [3] |
Fair Value, Measurements, Nonrecurring [Member] | Other Noncurrent Assets [Member] | Purchased Power Agreements | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Asset, Fair Value, Gross Asset | 58,431,000 | [3] | 89,061,000 | [3] |
Fair Value, Measurements, Nonrecurring [Member] | Other Current Liabilities [Member] | Purchased Power Agreements | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | 23,034,000 | [3] | 22,880,000 | [3] |
Fair Value, Measurements, Nonrecurring [Member] | Other Noncurrent Liabilities [Member] | Purchased Power Agreements | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ||
Derivative Liability, Fair Value, Gross Liability | $203,929,000 | [3] | $225,659,000 | [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 Dec. 31, 2013. At Dec. 31, 2013, derivative assets and liabilities include obligations to return cash collateral of $0.2 million and rights to reclaim cash collateral of $4.2 million. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements. | |||
[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, 2012. At Dec. 31, 2012, derivative assets and liabilities include obligations to return cash collateral of $0.6 million and rights to reclaim cash collateral of $3.0 million. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements. | |||
[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_Sheet8
Fair Value of Financial Assets and Liabilities, Changes in Level 3 Commodity Derivatives (Details) (Commodity Contract [Member], USD $) | 12 Months Ended | |||||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | ||||
Commodity Contract [Member] | ' | ' | ' | |||
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward] | ' | ' | ' | |||
Balance at beginning of period | $16,649,000 | $12,417,000 | $2,392,000 | |||
Purchases | 61,474,000 | 37,595,000 | 33,609,000 | |||
Settlements | -45,199,000 | -44,950,000 | -36,555,000 | |||
Gains recognized in earnings | 3,947,000 | [1] | 463,000 | [1] | 69,000 | [1] |
Gains recognized as regulatory assets and liabilities | 4,789,000 | 11,124,000 | 12,902,000 | |||
Balance at end of period | 41,660,000 | 16,649,000 | 12,417,000 | |||
Transfers into Level 3 | 0 | 0 | 0 | |||
Transfers out of Level 3 | $0 | $0 | $0 | |||
[1] | These amounts relate to commodity derivatives held at the end of the period. |
Recovered_Sheet9
Fair Value of Financial Assets and Liabilities, Fair Value of Long-Term Debt (Details) (USD $) | Dec. 31, 2013 | Dec. 31, 2012 |
In Thousands, unless otherwise specified | ||
Carrying Amount [Member] | ' | ' |
Financial Liabilities, Balance Sheet Groupings [Abstract] | ' | ' |
Long-term debt, including current portion | $11,191,517 | $10,402,060 |
Fair Value [Member] | ' | ' |
Financial Liabilities, Balance Sheet Groupings [Abstract] | ' | ' |
Long-term debt, including current portion | $11,878,643 | $12,207,866 |
Rate_Matters_NSPMinnesota_Deta
Rate Matters, NSP-Minnesota (Details) (USD $) | 12 Months Ended | 1 Months Ended | 0 Months Ended | 1 Months Ended | 12 Months Ended | 1 Months Ended | 0 Months Ended | 1 Months Ended | 0 Months Ended | 1 Months Ended | ||||||||||||||||||||||||||||||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Oct. 31, 2013 | Sep. 19, 2013 | Sep. 30, 2013 | 31-May-13 | Jan. 31, 2013 | Nov. 30, 2012 | Dec. 31, 2013 | Jan. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 12, 2013 | Nov. 04, 2013 | Nov. 04, 2013 | Nov. 04, 2013 | Dec. 31, 2012 | Dec. 31, 2012 | Nov. 30, 2013 | Oct. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Aug. 31, 2013 | Jan. 31, 2013 | Dec. 31, 2012 | Feb. 28, 2014 | Dec. 31, 2013 | Feb. 28, 2014 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Oct. 02, 2013 | Dec. 31, 2013 | Mar. 31, 2013 | |
Nuclear Project Prudency Investigation | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | ||||
Minnesota Public Utilities Commission | Minnesota Public Utilities Commission | Minnesota Public Utilities Commission | Minnesota Public Utilities Commission | Minnesota Public Utilities Commission | Minnesota Public Utilities Commission | Minnesota Public Utilities Commission | Minnesota Public Utilities Commission | Minnesota Public Utilities Commission | Minnesota Public Utilities Commission | Minnesota Public Utilities Commission | Minnesota Public Utilities Commission | Minnesota Public Utilities Commission | Minnesota Public Utilities Commission | Minnesota Public Utilities Commission | Minnesota Public Utilities Commission | Minnesota Public Utilities Commission | Minnesota Public Utilities Commission | Minnesota Public Utilities Commission | Minnesota Public Utilities Commission | Minnesota Public Utilities Commission | Minnesota Public Utilities Commission | North Dakota Public Service Commission | North Dakota Public Service Commission | North Dakota Public Service Commission | North Dakota Public Service Commission | North Dakota Public Service Commission | NDPSC Advocacy Staff | NDPSC Advocacy Staff | NDPSC Advocacy Staff | NDPSC Advocacy Staff | NDPSC Advocacy Staff | NDPSC Advocacy Staff | South Dakota Public Utilities Commission | South Dakota Public Utilities Commission | South Dakota Public Utilities Commission | |||||
Electric Rate Case 2013 | Electric Rate Case 2013 | Electric Rate Case 2013 | Electric Rate Case 2013 | Electric Rate Case 2013 | Transmission Cost Recovery Rate Filing 2012 | Transmission Cost Recovery Rate Filing 2012 | Transmission Cost Recovery Rate Filing 2012 | Transmission Cost Recovery Rate Filing 2013 | Transmission Cost Recovery Rate Filing 2014 | Prairie Island Nuclear Plant Extended Power Uprate | Prairie Island Nuclear Plant Extended Power Uprate | Electric Rate Case 2014 | Electric Rate Case 2014 | Electric Rate Case 2014, Rates 2014 | Electric Rate Case 2014, Rates 2015 | Electric Conservation Improvement Program (CIP) Rider 2013 through 2015 | Natural Gas Conservation Improvement Program (CIP) Rider 2013 through 2015 | Electric Conservation Improvement Program (CIP) Rider 2012 | Natural Gas Conservation Improvement Program (CIP) Rider 2012 | Electric Conservation Improvement Program (CIP) Rider 2013 | Natural Gas Conservation Improvement Program (CIP) Rider 2013 | Electric Rate Case 2013 | Electric Rate Case 2013 | Electric Rate Case 2013 | Electric Rate Case 2013 | Electric Rate Case 2013 | Electric Rate Case 2013 | Electric Rate Case 2013 | Electric Rate Case 2013, ROE 2013 | Electric Rate Case 2013, ROE 2014 | Electric Rate Case 2013, ROE 2015 | Electric Rate Case 2013, ROE 2016 | Electric Rate Case 2012 | Electric Rate Case 2012 | Electric Rate Case 2012 | |||||
Subsequent Event | MW | Subsequent Event | ||||||||||||||||||||||||||||||||||||||
Rate Matters [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Proposed 12-Month Settlement Base Rate Increase, Amount | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $9,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Pre-Effective Period Rate Impact, Amount | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -1,600,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, 2013 Proposed Settlement Base Rate Increase | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 7,400,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Adjustment to Requested Rate Increase (Decrease) Related to Retail Revenue, Percentage | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 5.00% | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Estimated 2013 Settlement Impact | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 11,600,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Number of Rate Rider Tariff Mechanisms | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2 | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Revenue deficiency based on a forecast test year | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 274,000,000 | 81,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Interim Rate Refund, Amount | ' | ' | ' | ' | 132,200,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Earnings Sharing Mechanism, Percentage | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 50.00% | ' | ' | ' | ' | ' | ' | ' | ' |
Number of Megawatts constructed for thermal generation | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 400 | ' | ' | ' | ' | ' | ' | ' | ' |
Amortization of Rate Deferral | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 16,000,000 | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Approved Rate Increase (Decrease), Amount | ' | ' | ' | ' | ' | 103,000,000 | ' | ' | ' | 22,700,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 11,600,000 |
Public Utilities, Projected incremental revenue from rider in 2014 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 8,700,000 | ' | ' |
Public Utilities, Approved Incremental Revenue from Rider | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 8,500,000 | ' |
Public Utilities, Approved Rate Increase (Decrease), Percentage | ' | ' | ' | ' | ' | 3.80% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Approved Return on Equity, Percentage | ' | ' | ' | ' | ' | 9.83% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Approved Equity Capital Structure, Percentage | ' | ' | ' | ' | ' | 52.56% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Authorized Deferrals - reduction to expense | ' | ' | ' | ' | ' | 20,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Approved Rate Increase (Decrease) - impact on pre-tax income, Amount | ' | ' | ' | ' | ' | 147,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Adjustment to approved rate increase (decrease) related to depreciation expense | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 81,000,000 | -46,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Estimated cost of project | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 294,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Regulatory Asset, Noncurrent | 2,509,218,000 | 2,762,029,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 78,900,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Allowance for funds used during construction | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 12,800,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Pretax charge for project costs | 0 | 20,766,000 | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10,100,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Estimated average annual incentives | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 30,600,000 | 3,600,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, CIP expenses recovered through rate rider | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 54,000,000 | 2,700,000 | 83,900,000 | 11,700,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, CIP expenses recovered through base rates | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 87,200,000 | 3,100,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Estimated 2013 Settlement Impact | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 11,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Requested Rate Increase (Decrease), Amount | ' | ' | ' | ' | ' | ' | ' | ' | 285,000,000 | ' | 29,600,000 | ' | 20,700,000 | 37,300,000 | ' | ' | ' | ' | 193,000,000 | 98,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | 16,900,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Requested Rate Increase (Decrease), Percentage | ' | ' | ' | ' | ' | ' | ' | ' | 10.70% | ' | ' | ' | ' | ' | ' | ' | ' | ' | 6.90% | 3.50% | ' | ' | ' | ' | ' | ' | ' | ' | ' | 9.25% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Adjustment to requested interim rate increase (decrease), amount | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -66,000,000 | 66,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Impact on Customer Bill, Increase (Decrease), Percentage | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 4.60% | 5.60% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Requested Return on Equity, Percentage | ' | ' | ' | ' | ' | ' | 10.60% | ' | 10.60% | ' | ' | ' | ' | ' | ' | ' | ' | 10.25% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10.60% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Requested Rate Base, Amount | ' | ' | ' | ' | ' | ' | 6,300,000,000 | ' | 6,300,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | 6,670,000,000 | 412,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | 377,600,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Requested Equity Capital Structure, Percentage | ' | ' | ' | ' | ' | ' | 52.56% | ' | 52.56% | ' | ' | ' | ' | ' | ' | ' | ' | 52.50% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 52.56% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Interim Rate Increase (Decrease), Amount | ' | ' | ' | ' | ' | ' | ' | 251,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | 127,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 14,700,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Impact on Customer Bill, Increase (Decrease), Amount | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 127,000,000 | 164,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount | ' | ' | ' | ' | ' | ' | 209,000,000 | ' | ' | ' | ' | 22,900,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 14,900,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Requested Return on Equity, Revised, Percentage | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10.25% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Proposed duration of rate plan, years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '4 years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Requested Rate Increase (Decrease), Amended, Percentage | ' | ' | ' | ' | ' | ' | 7.80% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Return on equity recommended by third parties | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 9.75% | 10.00% | 10.00% | 10.25% | ' | ' | ' |
Public Utilities, Requested Rate Increase (Decrease) Including Deferral Mechanisms | ' | ' | ' | ' | ' | ' | 259,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Deferral Mechanisms for Rate Mitigation | ' | ' | ' | ' | ' | ' | 50,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Approved Rate Increase (Decrease) due to return on equity, Amount | ' | ' | ' | ' | ' | -43,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Approved Rate Increase (Decrease) due to Sherco Unit 3, Amount | ' | ' | ' | ' | ' | -34,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Approved Rate Increase (Decrease) due to reduced recovery for nuclear plants, Amount | ' | ' | ' | ' | ' | -15,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Approved Rate Increase (Decrease) due to incentive compensation, Amount | ' | ' | ' | ' | ' | -4,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Approved Rate Increase (Decrease) due to sales forecast, Amount | ' | ' | ' | ' | ' | -26,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Approved Rate Increase (Decrease) due to pension, Amount | ' | ' | ' | ' | ' | -13,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Approved Rate Increase (Decrease) due to employee benefits, Amount | ' | ' | ' | ' | ' | -6,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Approved Rate Increase (Decrease) due to Black Dog remedation, Amount | ' | ' | ' | ' | ' | -5,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Adjustment requested by public utility to rate increase (decrease) related to theoretical depreciation reserve | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -81,000,000 | 53,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public utilities, Adjustment to requested rate increase (decrease) related to DOE settlement proceeds, amount | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 36,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3,900,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, impact of theoretical depreciation reserve | ' | ' | ' | ' | ' | -24,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, impact of theoretical depreciation reserve - reduction to expense | ' | ' | ' | ' | ' | 24,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Approved Rate Increase (Decrease) due to NSP-Wisconsin wholesale allocation, Amount | ' | ' | ' | ' | ' | -7,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Adjustment requested by public utility to rate increase (decrease) related to other costs | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -300,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Approved Rate Increase (Decrease) due to other, Amount | ' | ' | ' | ' | ' | -5,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Number of factors attributable to project cost increases | ' | ' | ' | 3 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Number of years for the application process | ' | ' | ' | '5 years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Recommended rate increase (decrease) impact on pre-tax income | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $224,000,000 | $154,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Number of months used for coincident peak demand allocator for certain rate base and operation expenses | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 12 | ' | ' | ' | ' | ' | ' | ' | ' |
Proposed time commitment to develop a generation cost allocation mechanism | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '0 years 16 months | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Revised Adjustment to Requested Rate Increase (Decrease) Related to Retail Revenue, Percentage | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 4.90% | ' | ' | ' | ' | ' | ' | ' |
Rate_Matters_NSPWisconsin_Deta
Rate Matters, NSP-Wisconsin (Details) (Public Service Commission of Wisconsin (PSCW), NSP-Wisconsin, USD $) | 1 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2013 | Oct. 31, 2013 | 31-May-13 |
Electric and Gas Rate Case 2014, Electric Rates | ' | ' | ' |
Rate Matters [Abstract] | ' | ' | ' |
Public utilities, Adjustment to requested rate increase (decrease) related to DOE settlement proceeds, amount | ' | ' | ($4.50) |
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount | ' | 34.3 | ' |
Public Utilities, Requested Rate Increase (Decrease), Amount | ' | ' | 40 |
Public Utilities, Requested Rate Increase (Decrease), Percentage | ' | ' | 6.50% |
Public Utilities, Authorized Deferrals | 4.1 | ' | ' |
Public Utilities, Approved Rate Increase (Decrease), Amount | 19.5 | ' | ' |
Public Utilities, Approved Rate Increase (Decrease), Percentage | 3.10% | ' | ' |
Public Utilities, Approved Return on Equity, Percentage | 10.20% | ' | ' |
Public Utilities, Approved Equity Capital Structure, Percentage | 52.50% | ' | ' |
Electric and Gas Rate Case 2014, Gas Rates | ' | ' | ' |
Rate Matters [Abstract] | ' | ' | ' |
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount | ' | 0 | ' |
Public Utilities, Requested Rate Increase (Decrease), Amount | ' | ' | 4.7 |
Public Utilities, Requested Rate Increase (Decrease), Percentage | ' | ' | 3.80% |
Electric and Gas Rate Case 2014 | ' | ' | ' |
Rate Matters [Abstract] | ' | ' | ' |
Public Utilities, Requested Return on Equity, Percentage | ' | 10.40% | 10.40% |
Public Utilities, Requested Equity Capital Structure, Percentage | ' | ' | 52.50% |
Forecasted Average Net Investment Rate Base, Electric Utility | ' | ' | 895.3 |
Forecasted Average Net Investment Rate Base, Natural Gas Utility | ' | ' | $89.80 |
Rate_Matters_PSCo_Details
Rate Matters, PSCo (Details) (USD $) | 12 Months Ended | 1 Months Ended | 12 Months Ended | 1 Months Ended | 12 Months Ended | 1 Months Ended | 12 Months Ended | 0 Months Ended | 12 Months Ended | 1 Months Ended | 12 Months Ended | 1 Months Ended | 12 Months Ended | 1 Months Ended | 0 Months Ended | 1 Months Ended | |||||||||||||||||||||||||||||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2013 | Apr. 30, 2013 | Dec. 31, 2012 | Apr. 30, 2013 | Dec. 31, 2012 | Apr. 30, 2013 | Dec. 31, 2012 | Apr. 30, 2013 | Dec. 31, 2012 | Dec. 31, 2012 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2012 | Oct. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2012 | Jun. 30, 2013 | Dec. 31, 2013 | Feb. 28, 2011 | Dec. 31, 2012 | Dec. 31, 2010 | Jul. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 20, 2013 | Dec. 31, 2013 | Mar. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Mar. 31, 2012 | 31-May-11 | Mar. 31, 2012 | 31-May-11 | Jul. 31, 2013 | Dec. 31, 2013 | Aug. 31, 2013 | Dec. 03, 2013 | Jun. 30, 2012 | Apr. 30, 2012 | Jan. 31, 2014 | Jan. 31, 2014 | |
PSCo | PSCo | PSCo | PSCo | PSCo | PSCo | PSCo | PSCo | PSCo | PSCo | PSCo | PSCo | PSCo | PSCo | PSCo | PSCo | PSCo | PSCo | PSCo | PSCo | PSCo | PSCo | PSCo | PSCo | PSCo | PSCo | PSCo | PSCo | PSCo | PSCo | PSCo | PSCo | PSCo | PSCo | PSCo | PSCo | PSCo | PSCo | PSCo | PSCo | Subsequent Event | Subsequent Event | ||||
Colorado Public Utilities Commission (CPUC) | Colorado Public Utilities Commission (CPUC) | Colorado Public Utilities Commission (CPUC) | Colorado Public Utilities Commission (CPUC) | Colorado Public Utilities Commission (CPUC) | Colorado Public Utilities Commission (CPUC) | Colorado Public Utilities Commission (CPUC) | Colorado Public Utilities Commission (CPUC) | Colorado Public Utilities Commission (CPUC) | Colorado Public Utilities Commission (CPUC) | Colorado Public Utilities Commission (CPUC) | Colorado Public Utilities Commission (CPUC) | Colorado Public Utilities Commission (CPUC) | Colorado Public Utilities Commission (CPUC) | Colorado Public Utilities Commission (CPUC) | Colorado Public Utilities Commission (CPUC) | Colorado Public Utilities Commission (CPUC) | Colorado Public Utilities Commission (CPUC) | Colorado Public Utilities Commission (CPUC) | Colorado Public Utilities Commission (CPUC) | Colorado Public Utilities Commission (CPUC) | Colorado Public Utilities Commission (CPUC) | Colorado Public Utilities Commission (CPUC) | Colorado Public Utilities Commission (CPUC) | Colorado Public Utilities Commission (CPUC) | Colorado Public Utilities Commission (CPUC) | Colorado Public Utilities Commission (CPUC) | Colorado Public Utilities Commission (CPUC) | Colorado Public Utilities Commission (CPUC) | Colorado Public Utilities Commission (CPUC) | Colorado Public Utilities Commission (CPUC) | Colorado Public Utilities Commission (CPUC) | Colorado Public Utilities Commission (CPUC) | Colorado Public Utilities Commission (CPUC) | Colorado Public Utilities Commission (CPUC) | Colorado Public Utilities Commission (CPUC) | Federal Energy Regulatory Commission (FERC) | Federal Energy Regulatory Commission (FERC) | Federal Energy Regulatory Commission (FERC) | Federal Energy Regulatory Commission (FERC) | PSCo | PSCo | ||||
2013 Gas Rate Case | 2013 Gas Rate Case | 2013 Gas Rate Case | Gas Rate Case 2013, Gas Rates 2013 | Gas Rate Case 2013, Gas Rates 2013 | Gas Rate Case 2013, Gas Rates 2014 | Gas Rate Case 2013, Gas Rates 2014 | Gas Rate Case 2013, Gas Rates 2015 | Gas Rate Case 2013, Gas Rates 2015 | Gas Rate Case 2013, Pipeline System Integrity Adjustment 2014 | Gas Rate Case 2013, Pipeline System Integrity Adjustment 2015 | Gas Rate Case 2013 Net of Pipeline System Integrity Adjustment Based on Historical Test Year | 2013 Steam Rate Case | Steam Rate Case 2013, Steam Rates 2013 | Steam Rate Case 2013, Steam Rates 2014 | Steam Rate Case 2013, Steam Rates 2014 | Steam Rate Case 2013, Steam Rates 2015 | Annual Electric Earnings Test | Annual Electric Earnings Test | Smart Grid City Cost Recovery | Smart Grid City Cost Recovery | Smart Grid City Cost Recovery | Demand Side Management Cost Adjustment | Demand Side Management Cost Adjustment | Demand Side Management Cost Adjustment, 2013 | Demand Side Management Cost Adjustment, 2014 | Demand Side Management Cost Adjustment, 2014 | Renewable Energy Credit Sharing | Renewable Energy Credit Sharing | Renewable Energy Credit Sharing | Renewable Energy Credit Sharing | Renewable Energy Credit Sharing | Renewable Energy Credit Sharing | Renewable Energy Credit Sharing | Electric Commodity Adjustment / RESA Adjustment | Electric Commodity Adjustment / RESA Adjustment | Production Formula Rate ROE Complaint | Transmission Formula Rate Case | Transmission Formula Rate Case | Transmission Formula Rate Case | Office of Consumer Counsel | Administrative Law Judge | ||||
MWh | MWh | Shareholders | Shareholders | Customers | Customers | 2012 PSIA Report | Electric Commodity Adjustment / RESA Adjustment | ||||||||||||||||||||||||||||||||||||||
Rate Matters [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Requested Rate Increase (Decrease), Amount | ' | ' | ' | ' | ' | ' | ' | $48,500,000 | ' | $9,900,000 | ' | $12,100,000 | $26,800,000 | $24,700,000 | ' | ' | $1,600,000 | ' | $900,000 | $2,300,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $2,000,000 | ' | ' |
Public Utilities, Requested Return on Equity, Percentage | ' | ' | ' | ' | 10.30% | 10.50% | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10.50% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10.25% | 10.25% | ' | ' | ' |
Public Utilities, Requested Rate Base, Amount | ' | ' | ' | ' | ' | 1,300,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | 21,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Requested Equity Capital Structure, Percentage | ' | ' | ' | ' | ' | 56.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | 56.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount | ' | ' | ' | ' | ' | ' | 44,800,000 | ' | 9,000,000 | ' | 10,900,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Revenue deficiency based on a forecast test year | ' | ' | ' | ' | ' | ' | 30,600,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Approved Rate Increase (Decrease), Amount | ' | ' | ' | 15,800,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,200,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Approved Return on Equity, Percentage | ' | ' | ' | 9.72% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Approved Equity Capital Structure, Percentage | ' | ' | ' | 56.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Entity's Recorded Provision for Revenue Subject To Refund | ' | ' | ' | 20,900,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Adjustment for historic test year | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -5,400,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Adjustment to requested rate increase (decrease) approved by third parties related to return on equity and capital structure adjustments | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -8,300,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Adjustment to requested rate increase (decrease) approved by third parties related to revenue adjustments | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -1,400,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Adjustment to requested rate increase (decrease) approved by third parties related to other costs | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -100,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Rate increase (decrease) approved by third parties excluding PSIA adjustment | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 29,600,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Adjustment to requested rate increase (decrease) approved by third parties related to neutralization of PSIA - base rate transfer | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -13,800,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Return on equity used in weather normalized earnings test | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Refund to customers due to weather normalized earnings test | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 8,200,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Estimated cost of project | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 45,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Annual operating and maintenance costs associated with project | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 4,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Cost of project allowed for recovery | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 28,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Pretax charge for project costs | 0 | 20,766,000 | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10,700,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Cost disallowance recommended by third parties related to capital expenditures | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3,700,000 | ' |
Public Utilities, Total cost disallowances recommended by third parties | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 600,000 | ' |
Public Utilities, Maximum savings goal | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 356,000 | ' | 384,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Percentage of net economic benefits on which incentive is earned | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 11.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Maximum annual incentive | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 30,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Electric demand side management budget | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 115,500,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Gas demand side management budget | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 13,300,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Demand side management costs to be collected in cost adjustment rates | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 26,800,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Number of parties not in agreement with settlement | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Electric demand side management budget requested | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 87,800,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Gas demand side management budget requested | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 12,300,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Initial percentage of margin associated with stand alone REC transactions | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 20.00% | ' | 80.00% | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Ultimate percentage of margin associated with stand alone REC transactions | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10.00% | ' | 90.00% | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Margin threshold determining percentage of margin sharing | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 20,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Percentage of margin on hybrid REC approved for first 20 million of margins | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 20.00% | ' | 80.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Percentage of margin on hybrid REC approved for margins in excess of 20 million | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10.00% | ' | 90.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Customers share of margins credited against RESA regulatory asset balance | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 22,000,000 | 46,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Cumulative credit against RESA regulatory asset balance | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 104,500,000 | 82,800,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Proposed transfer between ECA and RESA deferred accounts | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 26,200,000 | ' | ' | ' | ' | ' | ' | 26,200,000 |
Proposed Amortization Period For Recovery Of Deferred Costs (in months) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 12 | ' | ' | ' | ' | ' | ' | 12 |
Interest Income, Other | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 4,400,000 | ' | ' | ' | ' | ' | ' |
Increase (decrease) in interest rate recommended by third parties | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 7.40% |
Recommended increase (decrease) in interest income resulting from a change in interest rates, Amount | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -4,300,000 |
Return on equity for third parties, lower bound | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10.10% | ' | ' | ' | ' | ' |
Return on equity for third parties, upper bound | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10.40% | ' | ' | ' | ' | ' |
Public Utilities, Return on equity requested by third parties | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 9.04% | ' | 9.15% | ' | ' | ' |
Potential prospective annual revenue increase (decrease) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -2,000,000 | ' | ' | ' | ' | ' |
Public Utilities, Rate increase (decrease) requested by third parties | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ($1,800,000) | ' | ' | ' |
Public Utilities, Return on equity requested by third parties, July 1, 2012 through Nov. 16, 2012 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 9.07% | ' | ' | ' | ' |
Public Utilities, Return on equity requested by third parties, Nov. 17, 2012 and thereafter | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 8.92% | ' | ' | ' | ' |
Rate_Matters_SPS_Details
Rate Matters, SPS (Details) (USD $) | 12 Months Ended | 0 Months Ended | 1 Months Ended | |||||||||||||||||||||||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Jan. 07, 2014 | Nov. 30, 2012 | Jun. 30, 2013 | Jun. 30, 2013 | Nov. 30, 2013 | Sep. 30, 2013 | Aug. 31, 2013 | Jun. 30, 2013 | Dec. 31, 2012 | Aug. 31, 2013 | Feb. 28, 2014 | Jan. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Oct. 31, 2013 | Aug. 31, 2013 | Aug. 31, 2013 | Aug. 31, 2013 | Apr. 30, 2012 | |||
SPS | SPS | SPS | SPS | SPS | SPS | SPS | SPS | SPS | SPS | SPS | SPS | SPS | SPS | SPS | SPS | SPS | SPS | SPS | SPS | SPS | ||||||
Public Utility Commission of Texas (PUCT) | Public Utility Commission of Texas (PUCT) | Public Utility Commission of Texas (PUCT) | Public Utility Commission of Texas (PUCT) | Public Utility Commission of Texas (PUCT) | New Mexico Public Regulation Commission (NMPRC) | New Mexico Public Regulation Commission (NMPRC) | New Mexico Public Regulation Commission (NMPRC) | New Mexico Public Regulation Commission (NMPRC) | New Mexico Attorney General (NMAG) | Hearing Examiner | Hearing Examiner | Federal Energy Regulatory Commission (FERC) | Federal Energy Regulatory Commission (FERC) | Federal Energy Regulatory Commission (FERC) | Federal Energy Regulatory Commission (FERC) | Federal Energy Regulatory Commission (FERC) | Federal Energy Regulatory Commission (FERC) | Federal Energy Regulatory Commission (FERC) | Federal Energy Regulatory Commission (FERC) | Federal Energy Regulatory Commission (FERC) | ||||||
Electric Rate Case 2014 | Electric Rate Case 2012 | Electric Rate Case 2012, Settlement Rates Effective May 1, 2013 | Electric Rate Case 2012, Settlement Rates Effective September 1, 2013 | Transmission Cost Recovery Factor (TCRF) Rider | Electric Rate Case 2014 | Electric Rate Case 2014 | Electric Rate Case 2014 | Electric Rate Case 2014 | Electric Rate Case 2014 | Electric Rate Case 2014 | Electric Rate Case 2014 | Sale of Texas Transmission Assets | Sale of Texas Transmission Assets | Sale of Texas Transmission Assets | Sale of Texas Transmission Assets | Federal Energy Regulatory Commission (FERC) Orders | Federal Energy Regulatory Commission (FERC) Orders | FERC Orders, Settlement Impact Through May 31, 2015 | FERC Orders, Settlement Impact Effective June 1, 2015 | Wholesale Electric Rate Complaint | ||||||
Subsequent Event | Subsequent Event | Subsequent Event | Customers | Shareholders | Factor | |||||||||||||||||||||
Rate Matters [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
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), Amount | ' | ' | ' | 81,500,000 | 90,200,000 | ' | ' | ' | ' | ' | ' | 45,900,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Public Utilities, Adjustment requested by public utility to rate increase (decrease) related to resetting TCRF to zero | ' | ' | ' | -12,900,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Public Utilities, Adjustment requested by public utility to rate increase (decrease) related to customer credit for gain on sale | ' | ' | ' | -4,900,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Public Utilities, Requested base revenue increase (decrease) excluding fuel clause offsets | ' | ' | ' | 63,700,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Public Utilities, Adjustment requested by public utility to rate increase (decrease) related to fuel offsets | ' | ' | ' | -11,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Public Utilities, Requested Return on Equity, Percentage | ' | ' | ' | 10.40% | 10.65% | ' | ' | ' | 10.25% | ' | ' | 10.65% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Public Utilities, Requested Rate Base, Amount | ' | ' | ' | 1,270,000,000 | 1,150,000,000 | ' | ' | ' | ' | ' | ' | 479,800,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Public Utilities, Requested Equity Capital Structure, Percentage | ' | ' | ' | 53.89% | 52.00% | ' | ' | ' | ' | ' | ' | 53.89% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Public Utilities, Approved Rate Increase (Decrease), Amount | ' | ' | ' | ' | ' | 37,000,000 | 13,800,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Public Utilities, Portion of requested rate increase (decrease) related to depreciation expense | ' | ' | ' | 16,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Public Utilities, Number of months included in test year for rate filing | ' | ' | ' | ' | '12 months | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Public Utilities, Requested increase (decrease) to rider revenue | ' | ' | ' | ' | ' | ' | ' | 13,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount | ' | ' | ' | ' | ' | ' | ' | ' | 32,500,000 | ' | 43,300,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Public Utilities, Adjustment to requested rate increase (decrease) recommended by third parties related to the rate rider for renewable energy costs | ' | ' | ' | ' | ' | ' | ' | ' | ' | -14,500,000 | [1] | ' | ' | -8,500,000 | [1] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Adjustment to requested rate increase (decrease) requested by third parties related to revenue adjustments | ' | ' | ' | ' | ' | ' | ' | ' | ' | -4,400,000 | ' | ' | -6,400,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Public Utilities, Adjustment recommended by third parties related to return on equity | ' | ' | ' | ' | ' | ' | ' | ' | ' | -3,200,000 | ' | ' | -8,100,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Public Utilities, ROE recommended by third parties | ' | ' | ' | ' | ' | ' | ' | ' | ' | 9.80% | ' | ' | 8.63% | ' | 9.73% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Public Utilities, rider revenue increase (decrease) recommended by third parties | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 12,100,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Public Utilities, Adjustment to requested rate increase (decrease) related to change in capital structure | ' | ' | ' | ' | ' | ' | ' | ' | ' | -1,500,000 | ' | ' | -1,100,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Public Utilities, Adjustment to requested rate increase (decrease) requested by third parties related to reduced recovery for employee benefits | ' | ' | ' | ' | ' | ' | ' | ' | ' | -2,800,000 | ' | ' | -1,800,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Public Utilities, Adjustment to requested rate increase (decrease) recommended by third parties related to reduced recovery for payroll expense | ' | ' | ' | ' | ' | ' | ' | ' | ' | -100,000 | ' | ' | -100,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Public Utilities, Adjustment to requested rate increase (decrease) recommended by third parties related to gain on sale of assets | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | ' | ' | -1,700,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Public Utilities, Adjustment to requested rate increase (decrease) recommended by third parties related to fuel clause revenue | ' | ' | ' | ' | ' | ' | ' | ' | ' | 6,000,000 | ' | ' | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Public Utilities, Adjustment to requested rate increase (decrease) requested by third parties related to other costs | ' | ' | ' | ' | ' | ' | ' | ' | ' | -5,000,000 | ' | ' | -6,600,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Public Utilities, Addition (reduction) to revised requested rate increase (decrease) recommended by third parties | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -6,200,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Public Utilities, Rate increase (decrease) recommended by third parties | ' | ' | ' | ' | ' | ' | ' | ' | ' | 17,800,000 | ' | ' | 9,000,000 | ' | 14,700,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Public Utilities, Equity capital structure recommended by third parties | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 53.89% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Public Utilities, portion of rate increase (decrease) recommended by third parties to be recovered in base revenue | ' | ' | ' | ' | ' | ' | ' | ' | ' | 8,800,000 | ' | ' | -6,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Public Utilities, portion of rate increase (decrease) recommended by third parties to be recovered in rider revenue | ' | ' | ' | ' | ' | ' | ' | ' | ' | 7,300,000 | ' | ' | 13,300,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Public Utilities, portion of rate increase (decrease) recommended by third parties to be recovered in fuel cost adjustment revenue | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,700,000 | ' | ' | 1,700,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Public Utilities, portion of revised rate increase (decrease) related to base and fuel revenue. | ' | ' | ' | ' | ' | ' | ' | ' | 20,900,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Public Utilities, portion of revised rate increase (decrease) related to rider revenue | ' | ' | ' | ' | ' | ' | ' | ' | 12,100,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Public Utilities, portion of revised rate increase (decrease) related to other costs | ' | ' | ' | ' | ' | ' | ' | ' | -500,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Number of components included in regulatory proceeding | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2 | ' | ' | ' | ||
Number of coincident peaks used as demand allocator, revised | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3 | 3 | ' | ' | ' | ||
Number of coincident peaks used as demand allocator, original | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 12 | ' | ' | ' | ||
Current year pre-tax earnings impact of regulatory proceedings | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 13,600,000 | ' | -36,000,000 | ' | ' | ' | ||
Public Utilities, Annual increase (decrease) in revenues resulting from regulatory proceeding | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -6,000,000 | -4,000,000 | -3,100,000 | ||
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, Percentage | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 9.15% | ||
Public Utilities, Rate increase (decrease) requested by third parties | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -3,300,000 | ||
Public Utilities, Return on equity incentive related to transmission formula rates (in basis points) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 50 | ||
Number of substations included in purchase and sale agreement | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2 | ' | ' | ' | ' | ' | ' | ' | ||
Proceeds from Sale of Property, Plant, and Equipment | 37,118,000 | 0 | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 37,100,000 | ' | ' | ' | ' | ' | ' | ' | ' | ||
Public Utilities, Regulatory liabilities recognized for jurisdictional gain sharing | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $7,200,000 | ' | ' | ' | ' | ' | ' | ||
[1] | Adjustments represent recommended deferrals, extended amortizations and moving costs from rider to fuel in base rates. |
Commitments_and_Contingencies_1
Commitments and Contingencies, Capital Commitments (Details) (Capital Commitments [Member]) | 12 Months Ended | 1 Months Ended | 12 Months Ended | ||
Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Oct. 31, 2013 | Dec. 31, 2013 | |
Southeast New Mexico Transmission Development [Member] | CapX2020 [Member] | Clean Air, Clean Jobs Act (CACJA) [Member] | Minnesota Owned Wind Projects | TUCO to Woodward District Extra High Voltage Interchange [Member] | |
Line | MW | kV | |||
Capital Commitments [Abstract] | ' | ' | ' | ' | ' |
Number of projects for which notices to construct are anticipated | 4 | ' | ' | ' | ' |
Number of transmission lines in Group 1 project | ' | 4 | ' | ' | ' |
Percentage reduction in annual emissions of NOx from 2008 levels, low end of range (in hundredths) | ' | ' | 70.00% | ' | ' |
Percentage reduction in annual emissions of NOx from 2008 levels, high end of range (in hundredths) | ' | ' | 80.00% | ' | ' |
Number of Minnesota owned wind projects | ' | ' | ' | 2 | ' |
Capacity Increases | ' | ' | ' | 350 | ' |
Voltage capacity for transmission line (in kV) | ' | ' | ' | ' | 345 |
Commitments_and_Contingencies_2
Commitments and Contingencies, Fuel Contracts (Details) (USD $) | Dec. 31, 2013 |
In Millions, unless otherwise specified | |
Coal [Member] | ' |
Fuel Contracts [Abstract] | ' |
2014 | $947.60 |
2015 | 770.7 |
2016 | 500.2 |
2017 | 221.3 |
2018 | 73.2 |
Thereafter | 428.6 |
Total | 2,941.60 |
Nuclear Fuel [Member] | ' |
Fuel Contracts [Abstract] | ' |
2014 | 128.8 |
2015 | 79.9 |
2016 | 121.5 |
2017 | 127.5 |
2018 | 69.4 |
Thereafter | 697.6 |
Total | 1,224.70 |
Natural Gas Supply [Member] | ' |
Fuel Contracts [Abstract] | ' |
2014 | 492.8 |
2015 | 234.4 |
2016 | 232 |
2017 | 225.4 |
2018 | 278.4 |
Thereafter | 1,211.30 |
Total | 2,674.30 |
Natural Gas Storage and Transportation [Member] | ' |
Fuel Contracts [Abstract] | ' |
2014 | 272.3 |
2015 | 266.4 |
2016 | 207.5 |
2017 | 164.2 |
2018 | 106.6 |
Thereafter | 1,214.20 |
Total | $2,231.20 |
Commitments_and_Contingencies_3
Commitments and Contingencies, Purchased Power Agreements (Details) (USD $) | 12 Months Ended | |||
In Millions, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |
Capacity | ' | ' | ' | |
Purchased Power Agreements (PPAs) [Abstract] | ' | ' | ' | |
Payments for capacity | $217 | $261.90 | $325.30 | |
Estimated Future Payments Under PPAs [Abstract] | ' | ' | ' | |
2014 | 254.2 | ' | ' | |
2015 | 254.5 | ' | ' | |
2016 | 215.5 | ' | ' | |
2017 | 186.1 | ' | ' | |
2018 | 141.1 | ' | ' | |
Thereafter | 571.3 | ' | ' | |
Total | 1,622.70 | ' | ' | |
Energy | ' | ' | ' | |
Estimated Future Payments Under PPAs [Abstract] | ' | ' | ' | |
2014 | 121.9 | [1] | ' | ' |
2015 | 120.5 | [1] | ' | ' |
2016 | 100.2 | [1] | ' | ' |
2017 | 90.4 | [1] | ' | ' |
2018 | 93.2 | [1] | ' | ' |
Thereafter | 866.7 | [1] | ' | ' |
Total | $1,392.90 | [1] | ' | ' |
[1] | Excludes contingent energy payments for renewable PPAs. |
Commitments_and_Contingencies_4
Commitments and Contingencies, Leases (Details) (USD $) | 12 Months Ended | |||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | ||
Lease | ||||
Capital Leases [Abstract] | ' | ' | ' | |
Number of leases qualifying as capital leases | 3 | ' | ' | |
Amortization expense under capital lease assets | $6,300,000 | $5,700,000 | $3,200,000 | |
Property Held Under Capital Leases, Net [Abstract] | ' | ' | ' | |
Property held under capital lease | 221,200,000 | 221,200,000 | ' | |
Accumulated depreciation | -41,800,000 | -35,500,000 | ' | |
Total property held under capital leases, net | 179,400,000 | 185,700,000 | ' | |
Operating Leases, Future Minimum Payments Due [Abstract] | ' | ' | ' | |
2014 | 240,700,000 | ' | ' | |
2015 | 232,800,000 | ' | ' | |
2016 | 219,400,000 | ' | ' | |
2017 | 209,900,000 | ' | ' | |
2018 | 210,500,000 | ' | ' | |
Thereafter | 1,915,500,000 | ' | ' | |
Capital Leases, Future Minimum Payments Due [Abstract] | ' | ' | ' | |
2014 | 18,000,000 | ' | ' | |
2015 | 17,800,000 | ' | ' | |
2016 | 17,100,000 | ' | ' | |
2017 | 15,000,000 | ' | ' | |
2018 | 14,700,000 | ' | ' | |
Thereafter | 289,100,000 | ' | ' | |
Total minimum obligation | 371,700,000 | ' | ' | |
Interest component of obligation | -264,300,000 | ' | ' | |
Present value of minimum obligation | 107,400,000 | [1] | ' | ' |
Purchased Power Agreements [Member] | ' | ' | ' | |
Operating Leases [Abstract] | ' | ' | ' | |
Payments for capacity for PPAs under operating lease obligations | 197,700,000 | 174,400,000 | 160,500,000 | |
Operating Leases, Future Minimum Payments Due [Abstract] | ' | ' | ' | |
2014 | 214,200,000 | [2],[3] | ' | ' |
2015 | 207,400,000 | [2],[3] | ' | ' |
2016 | 197,000,000 | [2],[3] | ' | ' |
2017 | 192,700,000 | [2],[3] | ' | ' |
2018 | 194,400,000 | [2],[3] | ' | ' |
Thereafter | 1,771,900,000 | [2],[3] | ' | ' |
WYCO Totem Gas Storage Facilities [Member] | ' | ' | ' | |
Capital Leases [Abstract] | ' | ' | ' | |
Ownership interest in joint venture | 50.00% | ' | ' | |
Capital lease obligations | 144,200,000 | 148,700,000 | ' | |
Percentage of the capital lease obligation related to WYCO eliminated (in hundredths) | 50.00% | ' | ' | |
Office Space and Other Equipment [Member] | ' | ' | ' | |
Operating Leases [Abstract] | ' | ' | ' | |
Total expenses under operating lease obligations | 242,100,000 | 217,800,000 | 204,800,000 | |
Operating Leases, Future Minimum Payments Due [Abstract] | ' | ' | ' | |
2014 | 26,500,000 | ' | ' | |
2015 | 25,400,000 | ' | ' | |
2016 | 22,400,000 | ' | ' | |
2017 | 17,200,000 | ' | ' | |
2018 | 16,100,000 | ' | ' | |
Thereafter | 143,600,000 | ' | ' | |
Storage, Leaseholds and Rights [Member] | ' | ' | ' | |
Property Held Under Capital Leases, Net [Abstract] | ' | ' | ' | |
Property held under capital lease | 200,500,000 | 200,500,000 | ' | |
Gas Pipeline [Member] | ' | ' | ' | |
Property Held Under Capital Leases, Net [Abstract] | ' | ' | ' | |
Property held under capital lease | $20,700,000 | $20,700,000 | ' | |
[1] | Future commitments exclude certain amounts related to Xcel Energy’s 50 percent ownership interest in WYCO. | |||
[2] | PPA operating leases contractually expire through 2033. | |||
[3] | Amounts do not include PPAs accounted for as executory contracts. |
Commitments_and_Contingencies_5
Commitments and Contingencies, Variable Interest Entities (Details) (USD $) | Dec. 31, 2013 | Dec. 31, 2012 |
In Thousands, unless otherwise specified | MW | MW |
Independent Power Producing Entities | ' | ' |
Purchased Power Agreements [Abstract] | ' | ' |
Generating capacity (in MW) | 3,338 | 3,324 |
Low-Income Housing Limited Partnerships | ' | ' |
Amounts Reflected in Consolidated Balance Sheets [Abstract] | ' | ' |
Current assets | 7,982 | 3,380 |
Property, plant and equipment, net | 65,451 | 72,489 |
Other noncurrent assets | 1,654 | 6,044 |
Total assets | 75,087 | 81,913 |
Current liabilities | 11,388 | 8,458 |
Mortgages and other long-term debt payable | 38,049 | 37,720 |
Other noncurrent liabilities | 707 | 7,678 |
Total liabilities | 50,144 | 53,856 |
Commitments_and_Contingencies_6
Commitments and Contingencies, Technology Agreements (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
IBM Agreement [Member] | ' | ' | ' |
Technology Agreements [Abstract] | ' | ' | ' |
Percent of contract value to be paid if contract is terminated (in hundredths) | 50.00% | ' | ' |
Amount capitalized or expensed under technology agreement | $90.30 | $86.50 | $93.60 |
Technology Agreements, Minimum Payments Due [Abstract] | ' | ' | ' |
2014 | 35.5 | ' | ' |
2015 | 32.2 | ' | ' |
2016 | 31.5 | ' | ' |
2017 | 31.6 | ' | ' |
2018 | 31.1 | ' | ' |
Thereafter | 15.5 | ' | ' |
Accenture Agreement [Member] | ' | ' | ' |
Technology Agreements [Abstract] | ' | ' | ' |
Amount capitalized or expensed under technology agreement | 23.7 | 18.3 | 15.2 |
Technology Agreements, Minimum Payments Due [Abstract] | ' | ' | ' |
2014 | 8.9 | ' | ' |
2015 | 8.8 | ' | ' |
2016 | 8.8 | ' | ' |
2017 | 0 | ' | ' |
2018 | 0 | ' | ' |
Thereafter | $0 | ' | ' |
Commitments_and_Contingencies_7
Commitments and Contingencies, Guarantees and Indemnifications (Details) (USD $) | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | ||||
Payment or Performance Guarantee | Payment or Performance Guarantee | Payment or Performance Guarantee | Payment or Performance Guarantee | Payment or Performance Guarantee | Indemnification Agreement [Member] | |||||||
Customer Loans for Farm Rewiring Program [Member] | Customer Loans for Farm Rewiring Program [Member] | Obligations Under Aircraft Leases [Member] | Obligations under railcar leases [Member] | Surety Bonds | Obligations Under Sale Of Sharyland [Member] | |||||||
NSP-Wisconsin | Xcel Energy Services Inc. | NSP-Minnesota | ||||||||||
Guarantees [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Guarantor | ' | ' | ' | 'NSP-Wisconsin | 'Xcel Energy Inc. | 'NSP-Minnesota | 'Xcel Energy Inc. | ' | ||||
Claims made under guarantee | ' | ' | $0 | ' | ' | ' | ' | ' | ||||
Assets held as collateral | 0 | 0 | ' | ' | ' | ' | ' | ' | ||||
Guarantees issued and outstanding | 19,400,000 | ' | ' | 1,000,000 | [1],[2] | 9,200,000 | [3],[4] | 9,200,000 | [5],[6] | 32,100,000 | [7],[8],[9] | 37,100,000 |
Current exposure under these guarantees | 300,000 | ' | ' | 300,000 | [1],[2] | 0 | [3],[4] | 0 | [5],[6] | ' | ' | |
Guarantor Obligations, Current Carrying Value | ' | ' | ' | ' | ' | ' | ' | $400,000 | ||||
[1] | The term of this guarantee expires in 2017, which is the final scheduled repayment date for the loans. As of Dec. 31, 2013, no claims had been made by the lender. | |||||||||||
[2] | The debtor becomes the subject of bankruptcy or other insolvency proceedings. | |||||||||||
[3] | The term of this guarantee expires in 2017 when the associated leases expire. | |||||||||||
[4] | Nonperformance and/or nonpayment. | |||||||||||
[5] | Actual fair value of leased assets is less than the guaranteed residual value amount at the end of the lease term. | |||||||||||
[6] | The terms of these guarantees expire in 2014 and 2015 when the associated leases expire. | |||||||||||
[7] | Failure of Xcel Energy Inc. or one of its subsidiaries to perform under the agreement that is the subject of the relevant bond. In addition, per the indemnity agreement between Xcel Energy Inc. and the various surety companies, the surety companies have the discretion to demand that collateral be posted. | |||||||||||
[8] | Due to the magnitude of projects associated with the surety bonds, the total current exposure of this indemnification cannot be determined. Xcel Energy Inc. believes the exposure to be significantly less than the total amount of the outstanding bonds. | |||||||||||
[9] | The surety bonds primarily relate to workers compensation benefits and utility projects. The workers compensation bonds are renewed annually and the project based bonds expire in conjunction with the completion of the related projects. |
Commitments_and_Contingencies_8
Commitments and Contingencies, Environmental Contingencies - Site Contingencies (Details) (USD $) | 12 Months Ended | |
In Millions, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 |
Site | ||
Ashland MGP Site | NSP-Wisconsin | ' | ' |
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 | $104.60 | $103.70 |
Liability for estimated cost of remediating sites, current | 25.2 | 20.1 |
Amortization period for recovery of remediation costs in natural gas rates, low end of range (in years) | '4 years | ' |
Amortization period for recovery of remediation costs in natural gas rates, high end of range (in years) | '6 years | ' |
Ashland MGP Site - Phase I Project Area | NSP-Wisconsin | ' | ' |
Manufactured Gas Plant (MGP) Site [Abstract] | ' | ' |
Liability for estimated cost of remediating sites | 40 | ' |
Number of acres of land conveyed to the State of Wisconsin and tribal trustees (in acres) | 1,390 | ' |
Approved amortization period for recovery of remediation costs in natural gas rates (in years) | '10 years | ' |
Carrying cost percentage to be applied to the unamortized regulatory asset for MGP remediation (in hundredths) | 3.00% | ' |
Approved increase (decrease) in amortization expense granted by a regulatory body | 1.1 | ' |
Ashland MGP Site - Sediments | NSP-Wisconsin | ' | ' |
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% | ' |
Other MGP Sites | ' | ' |
Manufactured Gas Plant (MGP) Site [Abstract] | ' | ' |
Liability for estimated cost of remediating sites | $5.10 | $3 |
Number of identified MGP sites under current investigation and/or remediation | 7 | ' |
Commitments_and_Contingencies_9
Commitments and Contingencies, Environmental Contingencies - Unrecorded Unconditional Purchase Obligation (Details) (USD $) | Jun. 30, 2013 | Dec. 31, 2013 | Apr. 30, 2012 | Dec. 31, 2010 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 |
In Millions, unless otherwise specified | Federal Clean Water Act | EPA GHG Regulation | Electric Generating Unit Mercury And Air Toxics Standards Rule | PSCo | Capital Commitments | Capital Commitments | Capital Commitments | Capital Commitments |
Regulation | MW | Regional Haze Rules | NSP-Minnesota | NSP-Minnesota | NSP-Wisconsin | PSCo | ||
Group | Minnesota Mercury Legislation | Regional Haze Rules | Industrial Boiler Maximum Achievable Control Technology Rules | Regional Haze Rules | ||||
Boiler | ||||||||
Kiln | ||||||||
Environmental Requirements [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' |
Number of potential regulatory options under the proposed Effluent Limitations Guidelines rule | 4 | ' | ' | ' | ' | ' | ' | ' |
Number of issues granted review by the U.S. Supreme Court | ' | 1 | ' | ' | ' | ' | ' | ' |
Generating capacity (in MW) | ' | ' | 25 | ' | ' | ' | ' | ' |
Number of years before affected facilities must demonstrate compliance, low end of range | ' | ' | '3 years | ' | ' | ' | ' | ' |
Number of years before affected facilities must demonstrate compliance, high end of range | ' | ' | '4 years | ' | ' | ' | ' | ' |
Liability for estimated cost to comply with regulation | ' | ' | ' | ' | $12 | $50 | $17.20 | $359.50 |
Number of environmental groups who petitioned the U.S. Department of the Interior | ' | ' | ' | 2 | ' | ' | ' | ' |
Number of coal-fired boilers in Colorado | ' | ' | ' | 12 | ' | ' | ' | ' |
Number of coal-fired cement kilns in Colorado | ' | ' | ' | 1 | ' | ' | ' | ' |
Estimated amount spent on projects to reduce NOx emissions on Sherco Units 1 and 2 | ' | ' | ' | ' | ' | $40.30 | ' | ' |
Recovered_Sheet10
Commitments and Contingencies, Asset Retirement Obligations (Details) (USD $) | 12 Months Ended | |
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ' | ' |
Beginning balance | $1,719,796 | $1,651,793 |
Liabilities recognized | 575 | 4,890 |
Liabilities settled | -1,059 | -9,372 |
Accretion | 89,350 | 83,649 |
Revisions to prior estimates | 6,728 | -11,164 |
Ending balance | 1,815,390 | 1,719,796 |
Legally restricted assets, for purposes of funding future nuclear decommissioning | 1,627,026 | 1,489,542 |
Electric Plant Nuclear Production Decommissioning [Member] | ' | ' |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ' | ' |
Beginning balance | 1,546,358 | 1,482,741 |
Liabilities recognized | 0 | 0 |
Liabilities settled | 0 | 0 |
Accretion | 81,940 | 75,301 |
Revisions to prior estimates | 0 | -11,684 |
Ending balance | 1,628,298 | 1,546,358 |
Electric Plant Steam and Other Production Ash Containment [Member] | ' | ' |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ' | ' |
Beginning balance | 61,735 | 41,278 |
Liabilities recognized | 0 | 0 |
Liabilities settled | 0 | 0 |
Accretion | 2,105 | 1,614 |
Revisions to prior estimates | 15,513 | 18,843 |
Ending balance | 79,353 | 61,735 |
Electric Plant Steam and Other Production Asbestos [Member] | ' | ' |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ' | ' |
Beginning balance | 45,461 | 54,342 |
Liabilities recognized | 0 | 1,962 |
Liabilities settled | -1,059 | -9,372 |
Accretion | 2,551 | 3,417 |
Revisions to prior estimates | 3,874 | -4,888 |
Ending balance | 50,827 | 45,461 |
Electric Plant Wind Production [Member] | ' | ' |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ' | ' |
Beginning balance | 35,864 | 40,515 |
Liabilities recognized | 0 | 2,928 |
Liabilities settled | 0 | 0 |
Accretion | 1,600 | 2,068 |
Revisions to prior estimates | 0 | -9,647 |
Ending balance | 37,464 | 35,864 |
Electric Plant Electric Distribution [Member] | ' | ' |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ' | ' |
Beginning balance | 24,150 | 27,592 |
Liabilities recognized | 0 | 0 |
Liabilities settled | 0 | 0 |
Accretion | 708 | 1,000 |
Revisions to prior estimates | -12,672 | -4,442 |
Ending balance | 12,186 | 24,150 |
Electric Plant Other [Member] | ' | ' |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ' | ' |
Beginning balance | 3,152 | 2,390 |
Liabilities recognized | 0 | 0 |
Liabilities settled | 0 | 0 |
Accretion | 240 | 92 |
Revisions to prior estimates | 159 | 670 |
Ending balance | 3,551 | 3,152 |
Natural Gas Plant Gas Transmission and Distribution [Member] | ' | ' |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ' | ' |
Beginning balance | 1,258 | 1,201 |
Liabilities recognized | 0 | 0 |
Liabilities settled | 0 | 0 |
Accretion | 81 | 73 |
Revisions to prior estimates | -141 | -16 |
Ending balance | 1,198 | 1,258 |
Gas Gathering [Member] | ' | ' |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ' | ' |
Beginning balance | 0 | ' |
Liabilities recognized | 575 | ' |
Liabilities settled | 0 | ' |
Accretion | 0 | ' |
Revisions to prior estimates | 0 | ' |
Ending balance | 575 | ' |
Common and Other Property Common General Plant Asbestos [Member] | ' | ' |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ' | ' |
Beginning balance | 1,197 | 1,135 |
Liabilities recognized | 0 | 0 |
Liabilities settled | 0 | 0 |
Accretion | 66 | 62 |
Revisions to prior estimates | -783 | 0 |
Ending balance | 480 | 1,197 |
Common and Other Property Common Miscellaneous [Member] | ' | ' |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ' | ' |
Beginning balance | 621 | 599 |
Liabilities recognized | 0 | 0 |
Liabilities settled | 0 | 0 |
Accretion | 59 | 22 |
Revisions to prior estimates | 778 | 0 |
Ending balance | $1,458 | $621 |
Recovered_Sheet11
Commitments and Contingencies, Removal Costs (Details) (Plant Removal Costs [Member], USD $) | Dec. 31, 2013 | Dec. 31, 2012 |
In Millions, unless otherwise specified | ||
Regulatory Liabilities [Line Items] | ' | ' |
Regulatory liabilities | $906 | $923 |
NSP-Minnesota | ' | ' |
Regulatory Liabilities [Line Items] | ' | ' |
Regulatory liabilities | 378 | 377 |
NSP-Wisconsin | ' | ' |
Regulatory Liabilities [Line Items] | ' | ' |
Regulatory liabilities | 116 | 114 |
PSCo | ' | ' |
Regulatory Liabilities [Line Items] | ' | ' |
Regulatory liabilities | 359 | 365 |
SPS | ' | ' |
Regulatory Liabilities [Line Items] | ' | ' |
Regulatory liabilities | $53 | $67 |
Recovered_Sheet12
Commitments and Contingencies, Nuclear Insurance (Details) (NSP-Minnesota, Nuclear Insurance [Member], USD $) | 12 Months Ended |
Dec. 31, 2013 | |
Site | |
Reactor | |
NSP-Minnesota | Nuclear Insurance [Member] | ' |
Nuclear Insurance [Abstract] | ' |
Maximum possible loss contingency | $13,600,000,000 |
Nuclear insurance coverage secured for the company's public liability exposure | 375,000,000 |
Nuclear insurance coverage exposure funded by the Secondary Financial Protection Program | 13,200,000,000 |
Maximum assessments per reactor per accident | 127,300,000 |
Number of owned and licensed reactors | 3 |
Maximum funding requirement per reactor for any one year | 19,000,000 |
Term for maximum installment payment assessment per reactor (in years) | '1 year |
Insurance coverage limits for NSP-Minnesota's nuclear plant sites | 2,300,000,000 |
Number of nuclear plant sites operated by NSP-Minnesota | 2 |
Maximum assessments for business interruption insurance each calendar year | 16,100,000 |
Maximum assessment for property damage insurance NSP-Minnesota is subject to each calendar year | $40,200,000 |
Recovered_Sheet13
Commitments and Contingencies, Legal Contingencies (Details) (USD $) | 3 Months Ended | 12 Months Ended | 1 Months Ended | 12 Months Ended | 13 Months Ended | 1 Months Ended | |||||||||||||||||||
Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2012 | Sep. 30, 2012 | Jun. 30, 2012 | Mar. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2013 | 31-May-11 | Apr. 30, 2011 | Mar. 31, 2011 | Nov. 30, 2013 | Oct. 31, 2012 | Mar. 31, 2012 | Aug. 31, 2011 | Sep. 30, 2007 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Jun. 30, 2001 | Oct. 31, 2013 | |
NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | NSP-Minnesota | SPS | PSCo | PSCo | Xcel Energy, Inc. | ||||||||||||
Merricourt Wind Project Litigation [Member] | Merricourt Wind Project Litigation [Member] | Merricourt Wind Project Litigation [Member] | Merricourt Wind Project Litigation [Member] | Nuclear Waste Disposal Litigation | Nuclear Waste Disposal Litigation | Nuclear Waste Disposal Litigation | Nuclear Waste Disposal Litigation | Nuclear Waste Disposal Litigation | Nuclear Waste Disposal Litigation | Exelon Wind Complaint [Member] | Pacific Northwest FERC Refund Proceeding [Member] | Pacific Northwest FERC Refund Proceeding [Member] | Fru-Con Construction Corporation Litigation [Member] | ||||||||||||
MW | Dispute | Factor | |||||||||||||||||||||||
Site | |||||||||||||||||||||||||
Legal Contingencies [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Accrual for legal contingency | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | $0 | $0 | ' | ' |
Expired indemnification obligations | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 17,500,000 |
Generating capacity (in MW) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 150 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Merricourt deposit | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 101,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Minimum amount of damages claimed by plaintiff | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 240,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | 34,000,000 | ' | ' |
Number of main areas of dispute | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2 | ' | ' | ' |
Number of wind facilities | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 12 | ' | ' | ' |
Sales to the City of Seattle | 2,730,822,000 | 2,822,338,000 | 2,578,913,000 | 2,782,849,000 | 2,551,135,000 | 2,724,341,000 | 2,274,668,000 | 2,578,079,000 | 10,914,922,000 | 10,128,223,000 | 10,654,770,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 50,000,000 | ' |
Estimated City of Seattle's claim for refunds not including interest | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 28,000,000 | ' | ' |
Number of factors considered in assessment | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2 | ' | ' |
Damages awarded | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 116,500,000 | ' | ' | ' | ' | ' |
Storage costs for spent nuclear fuel | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 100,000,000 | ' | ' | ' | ' |
Cash payment received under settlement agreement | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $42,600,000 | $20,700,000 | $18,600,000 | $100,000,000 | ' | ' | ' | ' | ' | ' |
Nuclear_Obligations_Details
Nuclear Obligations (Details) (USD $) | 1 Months Ended | 12 Months Ended | ||||||
Jan. 31, 2014 | Nov. 30, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | ||||
Canister | ||||||||
Cask | ||||||||
Fuel Disposal [Abstract] | ' | ' | ' | ' | ' | |||
Fuel disposal fee charge (in dollars per KWh) | ' | ' | 0.001 | ' | ' | |||
Number of continuous session days in Congress before fuel disposal fee adjustment become effective unless new resolution is approved | '90 days | ' | ' | ' | ' | |||
DOE Fuel Disposal Assessments Included In Fuel Expense | ' | ' | $10,000,000 | $12,000,000 | $11,000,000 | |||
Cumulative Fuel Disposal Assessments Paid To Doe | ' | ' | 444,800,000 | ' | ' | |||
Regulatory Plant Decommissioning Recovery [Abstract] | ' | ' | ' | ' | ' | |||
Number Of Years Of Extended Operation At Nuclear Plant | ' | ' | '20 years | ' | ' | |||
Number Of Authorized Canisters Filled And Placed In Dry Cask Nuclear Storage Facility | ' | ' | 15 | ' | ' | |||
Number Of Authorized Canisters In Dry Cask Nuclear Storage Facility | ' | ' | 30 | ' | ' | |||
Number of authorized casks filled and placed in dry cask nuclear storage facility | ' | ' | 35 | ' | ' | |||
Number of additional authorized casks for dry cask nuclear storage facility | ' | ' | 64 | ' | ' | |||
Assumed annual escalation rate during operations and radiological portion of decommissioning | ' | ' | 3.63% | ' | ' | |||
Assumed annual escalation rate during independent fuel storage installation and site restoration portion of decommissioning | ' | ' | 2.63% | ' | ' | |||
Assumed after tax rate of return used to determine funding for external decommissioning trust fund, low end of range | ' | ' | 4.57% | ' | ' | |||
Assumed after tax rate of return used to determine funding for external decommissioning trust fund, high end of range | ' | ' | 5.53% | ' | ' | |||
Percentage of total obligation for decommissioning expected to be funded by external decommissioning trust fund | ' | ' | 100.00% | ' | ' | |||
Number of years approved for use in decommissioning scenario (in years) | ' | '60 years | ' | ' | ' | |||
Approved annual accrual for decommissioning costs for next year | ' | 14,200,000 | ' | ' | ' | |||
Funded Status of Nuclear Decommissioning Obligation [Abstract] | ' | ' | ' | ' | ' | |||
Estimated decommissioning cost obligation from most recently approved study (2011 dollars) | ' | ' | 2,694,079,000 | 2,694,079,000 | ' | |||
Effect of escalating costs (to 2013 and 2012 dollars, respectively, at 3.63/2.63 percent) | ' | ' | 189,924,000 | 93,327,000 | ' | |||
Estimated decommissioning cost obligation (in current dollars) | ' | ' | 2,884,003,000 | 2,787,406,000 | ' | |||
Effect of escalating costs to payment date (3.63/2.63 percent) | ' | ' | 5,697,285,000 | 5,793,882,000 | ' | |||
Estimated future decommissioning costs (undiscounted) | ' | ' | 8,581,288,000 | 8,581,288,000 | ' | |||
Effect of discounting obligation (using risk-free interest rate) | ' | ' | -6,215,050,000 | -6,243,332,000 | ' | |||
Discounted decommissioning cost obligation | ' | ' | 2,366,238,000 | 2,337,956,000 | ' | |||
Assets held in external decommissioning trust | ' | ' | 1,627,026,000 | 1,489,542,000 | ' | |||
Underfunding of external decommissioning fund compared to the discounted decommissioning obligation | ' | ' | 739,212,000 | 848,414,000 | ' | |||
Annual Decommissioning Recorded As Depreciation Expense [Abstract] | ' | ' | ' | ' | ' | |||
Externally funded | ' | ' | 6,402,000 | [1] | 0 | [1] | 0 | [1] |
Internally funded (including interest costs) | ' | ' | 0 | [1] | -1,251,000 | [1] | -456,000 | [1] |
Net decommissioning expense recorded | ' | ' | 6,402,000 | [1] | -1,251,000 | [1] | -456,000 | [1] |
Balance in internally funded decommissioning account | ' | ' | $0 | ' | ' | |||
[1] | (a)Â Decommissioning expense does not include depreciation of the capitalized nuclear asset retirement costs. |
Regulatory_Assets_and_Liabilit2
Regulatory Assets and Liabilities, Regulatory Assets (Details) (USD $) | 12 Months Ended | |||
Dec. 31, 2013 | Dec. 31, 2012 | |||
Regulatory Assets [Line Items] | ' | ' | ||
Regulatory Asset, Current | $417,801,000 | $352,977,000 | ||
Regulatory Asset, Noncurrent | 2,509,218,000 | 2,762,029,000 | ||
Past expenditures not currently earning a return | 306,000,000 | 275,000,000 | ||
Pension and Retiree Medical Obligations | ' | ' | ||
Regulatory Assets [Line Items] | ' | ' | ||
Regulatory Asset, Current | 118,179,000 | [1] | 100,713,000 | [1] |
Regulatory Asset, Noncurrent | 1,192,808,000 | [1] | 1,552,375,000 | [1] |
Regulatory asset, remaining amortization period | 'Various | ' | ||
Pension Costs | NSP-Minnesota | ' | ' | ||
Regulatory Assets [Line Items] | ' | ' | ||
Regulatory Asset, Current | 23,200,000 | 24,300,000 | ||
Regulatory Asset | 303,300,000 | 330,300,000 | ||
Non Qualified Pension Plan | ' | ' | ||
Regulatory Assets [Line Items] | ' | ' | ||
Regulatory Asset, Current | 2,200,000 | 2,200,000 | ||
Regulatory Asset | 17,700,000 | 21,500,000 | ||
Recoverable Deferred Taxes on AFUDC Recorded in Plant | ' | ' | ||
Regulatory Assets [Line Items] | ' | ' | ||
Regulatory Asset, Current | 0 | 0 | ||
Regulatory Asset, Noncurrent | 359,215,000 | 321,680,000 | ||
Regulatory asset, remaining amortization period | 'Plant lives | ' | ||
Contract Valuation Adjustments | ' | ' | ||
Regulatory Assets [Line Items] | ' | ' | ||
Regulatory Asset, Current | 3,620,000 | [2] | 3,775,000 | [2] |
Regulatory Asset, Noncurrent | 153,393,000 | [2] | 147,755,000 | [2] |
Regulatory asset, remaining amortization period | 'Term of related contract | ' | ||
Net AROs | ' | ' | ||
Regulatory Assets [Line Items] | ' | ' | ||
Regulatory Asset, Current | 0 | [3] | 0 | [3] |
Regulatory Asset, Noncurrent | 160,544,000 | [3] | 178,146,000 | [3] |
Regulatory asset, remaining amortization period | 'Plant lives | ' | ||
Conservation Programs | ' | ' | ||
Regulatory Assets [Line Items] | ' | ' | ||
Regulatory Asset, Current | 55,088,000 | [4] | 60,956,000 | [4] |
Regulatory Asset, Noncurrent | 63,275,000 | [4] | 84,146,000 | [4] |
Regulatory asset, remaining amortization period, minimum | '1 year | ' | ||
Regulatory asset, remaining amortization period, maximum | '6 years | ' | ||
Environmental Remediation Costs | ' | ' | ||
Regulatory Assets [Line Items] | ' | ' | ||
Regulatory Asset, Current | 4,735,000 | 3,986,000 | ||
Regulatory Asset, Noncurrent | 119,175,000 | 109,377,000 | ||
Regulatory asset, remaining amortization period | 'Various | ' | ||
Renewable Resources and Environmental Initiatives | ' | ' | ||
Regulatory Assets [Line Items] | ' | ' | ||
Regulatory Asset, Current | 46,076,000 | 59,518,000 | ||
Regulatory Asset, Noncurrent | 37,858,000 | 38,138,000 | ||
Regulatory asset, remaining amortization period, minimum | '1 year | ' | ||
Regulatory asset, remaining amortization period, maximum | '4 years | ' | ||
Depreciation Differences | ' | ' | ||
Regulatory Assets [Line Items] | ' | ' | ||
Regulatory Asset, Current | 10,918,000 | 5,274,000 | ||
Regulatory Asset, Noncurrent | 95,844,000 | 50,057,000 | ||
Regulatory asset, remaining amortization period, minimum | '1 year | ' | ||
Regulatory asset, remaining amortization period, maximum | '17 years | ' | ||
Purchased Power Agreements | ' | ' | ||
Regulatory Assets [Line Items] | ' | ' | ||
Regulatory Asset, Current | 0 | 0 | ||
Regulatory Asset, Noncurrent | 68,182,000 | 63,134,000 | ||
Regulatory asset, remaining amortization period | 'Term of related contract | ' | ||
Losses on Reacquired Debt | ' | ' | ||
Regulatory Assets [Line Items] | ' | ' | ||
Regulatory Asset, Current | 5,525,000 | 5,917,000 | ||
Regulatory Asset, Noncurrent | 36,534,000 | 42,060,000 | ||
Regulatory asset, remaining amortization period | 'Term of related debt | ' | ||
Nuclear Refueling Outage Costs | ' | ' | ||
Regulatory Assets [Line Items] | ' | ' | ||
Regulatory Asset, Current | 86,333,000 | 56,035,000 | ||
Regulatory Asset, Noncurrent | 36,477,000 | 22,647,000 | ||
Regulatory asset, remaining amortization period, minimum | '1 year | ' | ||
Regulatory asset, remaining amortization period, maximum | '2 years | ' | ||
Gas Pipeline Inspection and Remediation Costs | ' | ' | ||
Regulatory Assets [Line Items] | ' | ' | ||
Regulatory Asset, Current | 5,416,000 | 5,416,000 | ||
Regulatory Asset, Noncurrent | 33,884,000 | 27,560,000 | ||
Regulatory asset, remaining amortization period | 'Various | ' | ||
Recoverable Purchased Natural Gas and Electric Energy Costs | ' | ' | ||
Regulatory Assets [Line Items] | ' | ' | ||
Regulatory Asset, Current | 42,288,000 | 32,098,000 | ||
Regulatory Asset, Noncurrent | 15,495,000 | 8,340,000 | ||
Regulatory asset, remaining amortization period, minimum | '1 year | ' | ||
Regulatory asset, remaining amortization period, maximum | '2 years | ' | ||
Sherco Unit 3 Deferral | ' | ' | ||
Regulatory Assets [Line Items] | ' | ' | ||
Regulatory Asset, Current | 503,000 | 0 | ||
Regulatory Asset, Noncurrent | 10,063,000 | 0 | ||
Regulatory asset, remaining amortization period | '21 years | ' | ||
State Commission Adjustments | ' | ' | ||
Regulatory Assets [Line Items] | ' | ' | ||
Regulatory Asset, Current | 444,000 | 374,000 | ||
Regulatory Asset, Noncurrent | 14,204,000 | 12,181,000 | ||
Regulatory asset, remaining amortization period | 'Plant lives | ' | ||
Prairie Island EPU | ' | ' | ||
Regulatory Assets [Line Items] | ' | ' | ||
Regulatory Asset, Current | 0 | [5] | 0 | [5] |
Regulatory Asset, Noncurrent | 69,668,000 | [5] | 67,590,000 | [5] |
Regulatory asset, remaining amortization period | 'Pending rate cases | ' | ||
Property Tax | ' | ' | ||
Regulatory Assets [Line Items] | ' | ' | ||
Regulatory Asset, Current | 18,427,000 | 6,005,000 | ||
Regulatory Asset, Noncurrent | 30,626,000 | 12,010,000 | ||
Regulatory asset, remaining amortization period | '3 years | ' | ||
Other Regulatory Assets | ' | ' | ||
Regulatory Assets [Line Items] | ' | ' | ||
Regulatory Asset, Current | 20,249,000 | 12,910,000 | ||
Regulatory Asset, Noncurrent | $11,973,000 | $24,833,000 | ||
Regulatory asset, remaining amortization period | 'Various | ' | ||
[1] | Includes $303.3 million and $330.3 million for the regulatory recognition of the NSP-Minnesota pension expense of which $23.2 million and $24.3 million is included in the current asset at Dec. 31, 2013 and 2012, respectively. Also included are $17.7 million and $21.5 million of regulatory assets related to the nonqualified pension plan of which $2.2 million is included in the current asset at Dec. 31, 2013 and 2012, respectively. | |||
[2] | Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases. | |||
[3] | Includes amounts recorded for future recovery of AROs, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments. | |||
[4] | Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions. | |||
[5] | For the canceled Prairie Island EPU project, NSP-Minnesota plans to address recovery of incurred costs in the pending multi-year rate case. |
Regulatory_Assets_and_Liabilit3
Regulatory Assets and Liabilities, Regulatory Liabilities (Details) (USD $) | 12 Months Ended | |||
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | ||
Regulatory Liabilities [Line Items] | ' | ' | ||
Regulatory Liability, Current | $274,769 | $168,858 | ||
Regulatory Liability, Noncurrent | 1,059,395 | 1,059,939 | ||
Plant Removal Costs | ' | ' | ||
Regulatory Liabilities [Line Items] | ' | ' | ||
Regulatory Liability, Current | 0 | 0 | ||
Regulatory Liability, Noncurrent | 906,403 | 922,963 | ||
Regulatory liability, remaining amortization period | 'Plant lives | ' | ||
Deferred Electric, Gas, and Steam Production Costs | ' | ' | ||
Regulatory Liabilities [Line Items] | ' | ' | ||
Regulatory Liability, Current | 96,574 | 90,454 | ||
Regulatory Liability, Noncurrent | 0 | 0 | ||
Regulatory liability, remaining amortization period | 'Less than one year | ' | ||
DOE Settlement | ' | ' | ||
Regulatory Liabilities [Line Items] | ' | ' | ||
Regulatory Liability, Current | 44,208 | 22,700 | ||
Regulatory Liability, Noncurrent | 1,131 | 1,131 | ||
Regulatory liability remaining amortization period, minimum | '1 year | ' | ||
Regulatory liability remaining amortization period, maximum | '2 years | ' | ||
Investment Tax Credit Deferrals | ' | ' | ||
Regulatory Liabilities [Line Items] | ' | ' | ||
Regulatory Liability, Current | 0 | 0 | ||
Regulatory Liability, Noncurrent | 56,535 | 59,052 | ||
Regulatory liability, remaining amortization period | 'Various | ' | ||
Deferred Income Tax Adjustment | ' | ' | ||
Regulatory Liabilities [Line Items] | ' | ' | ||
Regulatory Liability, Current | 0 | 0 | ||
Regulatory Liability, Noncurrent | 43,581 | 44,667 | ||
Regulatory liability, remaining amortization period | 'Various | ' | ||
Conservation Programs | ' | ' | ||
Regulatory Liabilities [Line Items] | ' | ' | ||
Regulatory Liability, Current | 19,531 | [1] | 6,292 | [1] |
Regulatory Liability, Noncurrent | 0 | [1] | 0 | [1] |
Regulatory liability, remaining amortization period | 'Less than one year | ' | ||
Contract Valuation Adjustments | ' | ' | ||
Regulatory Liabilities [Line Items] | ' | ' | ||
Regulatory Liability, Current | 54,455 | [2] | 29,431 | [2] |
Regulatory Liability, Noncurrent | 6,849 | [2] | 11,159 | [2] |
Regulatory liability, remaining amortization period | 'Term of related contract | ' | ||
Gain From Asset Sales | ' | ' | ||
Regulatory Liabilities [Line Items] | ' | ' | ||
Regulatory Liability, Current | 12,859 | 7,318 | ||
Regulatory Liability, Noncurrent | 4,568 | 10,311 | ||
Regulatory liability remaining amortization period, minimum | '1 year | ' | ||
Regulatory liability remaining amortization period, maximum | '3 years | ' | ||
Renewable Resources and Environmental Initiatives | ' | ' | ||
Regulatory Liabilities [Line Items] | ' | ' | ||
Regulatory Liability, Current | 2,499 | 256 | ||
Regulatory Liability, Noncurrent | 1,412 | 1,412 | ||
Regulatory liability, remaining amortization period | 'Various | ' | ||
Low Income Discount Program | ' | ' | ||
Regulatory Liabilities [Line Items] | ' | ' | ||
Regulatory Liability, Current | 6,229 | 6,164 | ||
Regulatory Liability, Noncurrent | 0 | 0 | ||
Regulatory liability, remaining amortization period | 'Less than one year | ' | ||
PSCo Earnings Test | ' | ' | ||
Regulatory Liabilities [Line Items] | ' | ' | ||
Regulatory Liability, Current | 22,891 | 1,732 | ||
Regulatory Liability, Noncurrent | 19,203 | 1,732 | ||
Regulatory liability remaining amortization period, minimum | '1 year | ' | ||
Regulatory liability remaining amortization period, maximum | '2 years | ' | ||
Other Regulatory Liabilities | ' | ' | ||
Regulatory Liabilities [Line Items] | ' | ' | ||
Regulatory Liability, Current | 15,523 | 4,511 | ||
Regulatory Liability, Noncurrent | $19,713 | $7,512 | ||
Regulatory liability, remaining amortization period | 'Various | ' | ||
[1] | Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions. | |||
[2] | Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases. |
Other_Comprehensive_Income_Det
Other Comprehensive Income (Details) (USD $) | 12 Months Ended | |||
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |
Accumulated Other Comprehensive Income [Roll Forward] | ' | ' | ' | |
Accumulated other comprehensive loss at beginning of period | ($112,653) | ' | ' | |
Other comprehensive gain (loss) before reclassifications | 1,596 | ' | ' | |
Losses reclassified from net accumulated other comprehensive loss | 4,782 | ' | ' | |
Net current period other comprehensive income | 6,378 | ' | ' | |
Accumulated other comprehensive loss at end of period | -106,275 | -112,653 | ' | |
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | ' | ' | ' | |
Operating and maintenance expenses | 2,273,532 | 2,176,095 | 2,140,289 | |
Total, pre-tax | -1,432,210 | -1,355,432 | -1,309,488 | |
Income tax expense (benefit) | 483,976 | 450,203 | 468,316 | |
Amounts Reclassified from Accumulated Other Comprehensive Loss [Member] | ' | ' | ' | |
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | ' | ' | ' | |
Total, net of tax | 4,782 | ' | ' | |
Gains and Losses on Cash Flow Hedges [Member] | ' | ' | ' | |
Accumulated Other Comprehensive Income [Roll Forward] | ' | ' | ' | |
Accumulated other comprehensive loss at beginning of period | -61,241 | ' | ' | |
Other comprehensive gain (loss) before reclassifications | 12 | ' | ' | |
Losses reclassified from net accumulated other comprehensive loss | 1,476 | ' | ' | |
Net current period other comprehensive income | 1,488 | ' | ' | |
Accumulated other comprehensive loss at end of period | -59,753 | ' | ' | |
Gains and Losses on Cash Flow Hedges [Member] | Amounts Reclassified from Accumulated Other Comprehensive Loss [Member] | ' | ' | ' | |
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | ' | ' | ' | |
Total, pre-tax | 4,017 | ' | ' | |
Income tax expense (benefit) | -2,541 | ' | ' | |
Total, net of tax | 1,476 | ' | ' | |
Gains and Losses on Cash Flow Hedges [Member] | Interest Rate Derivatives [Member] | Amounts Reclassified from Accumulated Other Comprehensive Loss [Member] | ' | ' | ' | |
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | ' | ' | ' | |
Interest charges and financing costs | 4,107 | [1] | ' | ' |
Gains and Losses on Cash Flow Hedges [Member] | Vehicle Fuel And Other Commodity Derivatives [Member] | Amounts Reclassified from Accumulated Other Comprehensive Loss [Member] | ' | ' | ' | |
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | ' | ' | ' | |
Operating and maintenance expenses | -90 | [2] | ' | ' |
Accumulated Net Unrealized Investment Gain (Loss) [Member] | ' | ' | ' | |
Accumulated Other Comprehensive Income [Roll Forward] | ' | ' | ' | |
Accumulated other comprehensive loss at beginning of period | -99 | ' | ' | |
Other comprehensive gain (loss) before reclassifications | 176 | ' | ' | |
Losses reclassified from net accumulated other comprehensive loss | 0 | ' | ' | |
Net current period other comprehensive income | 176 | ' | ' | |
Accumulated other comprehensive loss at end of period | 77 | ' | ' | |
Defined Benefit Pension and Postretirement Items [Member] | ' | ' | ' | |
Accumulated Other Comprehensive Income [Roll Forward] | ' | ' | ' | |
Accumulated other comprehensive loss at beginning of period | -51,313 | ' | ' | |
Other comprehensive gain (loss) before reclassifications | 1,408 | ' | ' | |
Losses reclassified from net accumulated other comprehensive loss | 3,306 | ' | ' | |
Net current period other comprehensive income | 4,714 | ' | ' | |
Accumulated other comprehensive loss at end of period | -46,599 | ' | ' | |
Defined Benefit Pension and Postretirement Items [Member] | Amounts Reclassified from Accumulated Other Comprehensive Loss [Member] | ' | ' | ' | |
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | ' | ' | ' | |
Amortization of net loss | 7,077 | [3] | ' | ' |
Prior service cost | 372 | [3] | ' | ' |
Transition obligation | 8 | [3] | ' | ' |
Total, pre-tax | 7,457 | ' | ' | |
Income tax expense (benefit) | -4,151 | ' | ' | |
Total, net of tax | $3,306 | ' | ' | |
[1] | Included in interest charges. | |||
[2] | Included in O&M expenses. | |||
[3] | Included in the computation of net periodic pension and post retirement benefit costs. See Note 9 for details regarding these benefit plans. |
Segments_and_Related_Informati2
Segments and Related Information (Details) (USD $) | 3 Months Ended | 12 Months Ended | |||||||||
In Thousands, unless otherwise specified | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2012 | Sep. 30, 2012 | Jun. 30, 2012 | Mar. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Equity investments in unconsolidated subsidiaries | $87,100 | ' | ' | ' | $91,200 | ' | ' | ' | $87,100 | $91,200 | ' |
Operating revenues | 2,730,822 | 2,822,338 | 2,578,913 | 2,782,849 | 2,551,135 | 2,724,341 | 2,274,668 | 2,578,079 | 10,914,922 | 10,128,223 | 10,654,770 |
Depreciation and amortization | ' | ' | ' | ' | ' | ' | ' | ' | 977,863 | 926,053 | 890,619 |
Total interest charges and financing costs | ' | ' | ' | ' | ' | ' | ' | ' | 536,020 | 566,237 | 563,119 |
Income tax expense (benefit) | ' | ' | ' | ' | ' | ' | ' | ' | 483,976 | 450,203 | 468,316 |
Net income (loss) | 150,055 | 364,752 | 196,857 | 236,570 | 140,170 | 398,106 | 183,060 | 183,893 | 948,234 | 905,229 | 841,172 |
Regulated Electric | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Operating revenues | ' | ' | ' | ' | ' | ' | ' | ' | 9,035,377 | 8,518,465 | 8,767,862 |
Depreciation and amortization | ' | ' | ' | ' | ' | ' | ' | ' | 840,833 | 801,649 | 773,392 |
Total interest charges and financing costs | ' | ' | ' | ' | ' | ' | ' | ' | 386,198 | 397,457 | 402,668 |
Income tax expense (benefit) | ' | ' | ' | ' | ' | ' | ' | ' | 495,044 | 465,626 | 473,848 |
Net income (loss) | ' | ' | ' | ' | ' | ' | ' | ' | 850,572 | 851,929 | 788,967 |
Regulated Natural Gas | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Equity investments in unconsolidated subsidiaries | 87,100 | ' | ' | ' | 91,200 | ' | ' | ' | 87,100 | 91,200 | ' |
Operating revenues | ' | ' | ' | ' | ' | ' | ' | ' | 1,807,396 | 1,538,799 | 1,814,284 |
Depreciation and amortization | ' | ' | ' | ' | ' | ' | ' | ' | 128,186 | 115,038 | 106,870 |
Total interest charges and financing costs | ' | ' | ' | ' | ' | ' | ' | ' | 44,927 | 49,456 | 52,115 |
Income tax expense (benefit) | ' | ' | ' | ' | ' | ' | ' | ' | 25,543 | 50,322 | 57,408 |
Net income (loss) | ' | ' | ' | ' | ' | ' | ' | ' | 123,702 | 98,061 | 101,842 |
All Other | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Operating revenues | ' | ' | ' | ' | ' | ' | ' | ' | 76,198 | 73,553 | 76,251 |
Depreciation and amortization | ' | ' | ' | ' | ' | ' | ' | ' | 8,844 | 9,366 | 10,357 |
Total interest charges and financing costs | ' | ' | ' | ' | ' | ' | ' | ' | 104,895 | 119,324 | 108,336 |
Income tax expense (benefit) | ' | ' | ' | ' | ' | ' | ' | ' | -36,611 | -65,745 | -62,940 |
Net income (loss) | ' | ' | ' | ' | ' | ' | ' | ' | -26,040 | -44,761 | -49,637 |
Operating Segments | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Operating revenues | ' | ' | ' | ' | ' | ' | ' | ' | 10,914,922 | 10,128,223 | 10,654,770 |
Operating Segments | Regulated Electric | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Operating revenues | ' | ' | ' | ' | ' | ' | ' | ' | 9,034,045 | 8,517,296 | 8,766,593 |
Operating Segments | Regulated Natural Gas | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Operating revenues | ' | ' | ' | ' | ' | ' | ' | ' | 1,804,679 | 1,537,374 | 1,811,926 |
Operating Segments | All Other | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Operating revenues | ' | ' | ' | ' | ' | ' | ' | ' | 76,198 | 73,553 | 76,251 |
Intersegment Eliminations | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Operating revenues | ' | ' | ' | ' | ' | ' | ' | ' | -4,049 | -2,594 | -3,627 |
Depreciation and amortization | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 0 | 0 |
Total interest charges and financing costs | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 0 | 0 |
Income tax expense (benefit) | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 0 | 0 |
Net income (loss) | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 0 | 0 |
Intersegment Eliminations | Regulated Electric | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Operating revenues | ' | ' | ' | ' | ' | ' | ' | ' | 1,332 | 1,169 | 1,269 |
Intersegment Eliminations | Regulated Natural Gas | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Operating revenues | ' | ' | ' | ' | ' | ' | ' | ' | 2,717 | 1,425 | 2,358 |
Intersegment Eliminations | All Other | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Operating revenues | ' | ' | ' | ' | ' | ' | ' | ' | $0 | $0 | $0 |
Summarized_Quarterly_Financial2
Summarized Quarterly Financial Data (Unaudited) (Details) (USD $) | 3 Months Ended | 12 Months Ended | |||||||||
In Thousands, except Per Share data, unless otherwise specified | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2012 | Sep. 30, 2012 | Jun. 30, 2012 | Mar. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Quarterly Financial Information Disclosure [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Operating revenues | $2,730,822 | $2,822,338 | $2,578,913 | $2,782,849 | $2,551,135 | $2,724,341 | $2,274,668 | $2,578,079 | $10,914,922 | $10,128,223 | $10,654,770 |
Operating income | 325,582 | 665,113 | 402,236 | 454,624 | 316,397 | 720,434 | 405,690 | 380,162 | 1,847,555 | 1,822,683 | 1,781,602 |
Net income | 150,055 | 364,752 | 196,857 | 236,570 | 140,170 | 398,106 | 183,060 | 183,893 | 948,234 | 905,229 | 841,172 |
Earnings available to common shareholders | ' | ' | ' | ' | ' | ' | ' | ' | $948,234 | $905,229 | $834,378 |
Basic (in dollars per share) | $0.30 | $0.73 | $0.40 | $0.48 | $0.29 | $0.82 | $0.38 | $0.38 | $1.91 | $1.86 | $1.72 |
Diluted (in dollars per share) | $0.30 | $0.73 | $0.40 | $0.48 | $0.29 | $0.81 | $0.38 | $0.38 | $1.91 | $1.85 | $1.72 |
Cash dividends declared per common share (in dollars per share) | $0.28 | $0.28 | $0.28 | $0.27 | $0.27 | $0.27 | $0.27 | $0.26 | $1.11 | $1.07 | $1.03 |
Schedule_I_Condensed_Financial2
Schedule I, Condensed Financial Statements of Xcel Energy Inc, Notes to Condensed Financial Statements (Details) (Xcel Energy Inc., USD $) | 3 Months Ended | 12 Months Ended | ||
Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |
Accounts Receivable and Payable with Affiliates [Abstract] | ' | ' | ' | ' |
Accounts Receivable | $240,450,000 | $240,450,000 | $198,800,000 | ' |
Accounts Payable | 0 | 0 | -3,362,000 | ' |
Dividends [Abstract] | ' | ' | ' | ' |
Cash dividends paid to Xcel Energy by subsidiaries | ' | 606,000,000 | 757,000,000 | 626,000,000 |
Money Pool [Abstract] | ' | ' | ' | ' |
Lending limit | 250,000,000 | 250,000,000 | 250,000,000 | 250,000,000 |
Loan outstanding at period end | 72,000,000 | 72,000,000 | 0 | 18,000,000 |
Average loan outstanding | 109,800,000 | 88,200,000 | 26,100,000 | 400,000 |
Maximum loan outstanding | 182,000,000 | 243,000,000 | 226,000,000 | 43,000,000 |
Weighted average interest rate, computed on a daily basis (in hundredths) | 0.31% | 0.30% | 0.33% | 0.35% |
Weighted average interest rate at end of period (in hundredths) | 0.25% | 0.25% | ' | 0.35% |
Money pool interest income | 100,000 | 300,000 | 100,000 | 0 |
NSP-Minnesota | ' | ' | ' | ' |
Accounts Receivable and Payable with Affiliates [Abstract] | ' | ' | ' | ' |
Accounts Receivable | 57,596,000 | 57,596,000 | 63,682,000 | ' |
Accounts Payable | 0 | 0 | 0 | ' |
NSP-Wisconsin | ' | ' | ' | ' |
Accounts Receivable and Payable with Affiliates [Abstract] | ' | ' | ' | ' |
Accounts Receivable | 6,933,000 | 6,933,000 | 7,631,000 | ' |
Accounts Payable | 0 | 0 | 0 | ' |
PSCo | ' | ' | ' | ' |
Accounts Receivable and Payable with Affiliates [Abstract] | ' | ' | ' | ' |
Accounts Receivable | 74,739,000 | 74,739,000 | 0 | ' |
Accounts Payable | 0 | 0 | -3,362,000 | ' |
SPS | ' | ' | ' | ' |
Accounts Receivable and Payable with Affiliates [Abstract] | ' | ' | ' | ' |
Accounts Receivable | 5,705,000 | 5,705,000 | 15,806,000 | ' |
Accounts Payable | 0 | 0 | 0 | ' |
Xcel Energy Services Inc. | ' | ' | ' | ' |
Accounts Receivable and Payable with Affiliates [Abstract] | ' | ' | ' | ' |
Accounts Receivable | 60,138,000 | 60,138,000 | 61,217,000 | ' |
Accounts Payable | 0 | 0 | 0 | ' |
Xcel Energy Ventures Inc. | ' | ' | ' | ' |
Accounts Receivable and Payable with Affiliates [Abstract] | ' | ' | ' | ' |
Accounts Receivable | 20,194,000 | 20,194,000 | 20,427,000 | ' |
Accounts Payable | 0 | 0 | 0 | ' |
Other Subsidiaries | ' | ' | ' | ' |
Accounts Receivable and Payable with Affiliates [Abstract] | ' | ' | ' | ' |
Accounts Receivable | 15,145,000 | 15,145,000 | 30,037,000 | ' |
Accounts Payable | $0 | $0 | $0 | ' |
Schedule_I_Condensed_Financial3
Schedule I, Condensed Financial Statements of Xcel Energy Inc, Condensed Statements of Income (Details) (USD $) | 3 Months Ended | 12 Months Ended | 1 Months Ended | 12 Months Ended | |||||||||||
In Thousands, except Per Share data, unless otherwise specified | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2012 | Sep. 30, 2012 | Jun. 30, 2012 | Mar. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | 31-May-13 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Xcel Energy Inc. | Xcel Energy Inc. | Xcel Energy Inc. | Xcel Energy Inc. | ||||||||||||
Income | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Equity earnings of subsidiaries | ' | ' | ' | ' | ' | ' | ' | ' | $30,020 | $29,971 | $30,527 | ' | $1,018,783 | $976,395 | $904,315 |
Total income | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,018,783 | 976,395 | 904,315 |
Expenses and other deductions | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Operating expenses | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 18,513 | 15,948 | 14,513 |
Other income | ' | ' | ' | ' | ' | ' | ' | ' | -2,972 | -6,175 | -9,255 | ' | -206 | -652 | -760 |
Interest charges and financing costs | ' | ' | ' | ' | ' | ' | ' | ' | 575,199 | 601,552 | 591,300 | 6,300 | 102,914 | 116,731 | 104,499 |
Total expenses and other deductions | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 121,221 | 132,027 | 118,252 |
Income before income taxes | ' | ' | ' | ' | ' | ' | ' | ' | 1,432,210 | 1,355,432 | 1,309,488 | ' | 897,562 | 844,368 | 786,063 |
Income tax benefit | ' | ' | ' | ' | ' | ' | ' | ' | 483,976 | 450,203 | 468,316 | ' | -50,672 | -60,861 | -55,109 |
Net income | 150,055 | 364,752 | 196,857 | 236,570 | 140,170 | 398,106 | 183,060 | 183,893 | 948,234 | 905,229 | 841,172 | ' | 948,234 | 905,229 | 841,172 |
Dividend requirements on preferred stock | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 0 | 3,534 | ' | 0 | 0 | 3,534 |
Premium on redemption of preferred stock | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 0 | 3,260 | ' | 0 | 0 | 3,260 |
Earnings available to common shareholders | ' | ' | ' | ' | ' | ' | ' | ' | 948,234 | 905,229 | 834,378 | ' | 948,234 | 905,229 | 834,378 |
Other Comprehensive Income (Loss), Net of Tax [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Pension and retiree medical benefits, net of tax of $5,897, $(2,331) and $(2,247), respectively | ' | ' | ' | ' | ' | ' | ' | ' | 1,408 | -7,005 | -6,367 | ' | 4,714 | -3,311 | -3,205 |
Derivative instruments, net of tax of $2,558, $(9,906) and $(24,488), respectively | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,488 | -15,503 | -37,644 |
Other, net of tax of $117, $135 and $(63), respectively | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 176 | 196 | -93 |
Other Comprehensive Income (Loss), Net of Tax | ' | ' | ' | ' | ' | ' | ' | ' | 6,378 | ' | ' | ' | 6,378 | -18,618 | -40,942 |
Comprehensive Income, Net of Tax | ' | ' | ' | ' | ' | ' | ' | ' | $954,612 | $886,611 | $800,230 | ' | $954,612 | $886,611 | $793,436 |
Weighted average common shares outstanding: | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Basic (in shares) | ' | ' | ' | ' | ' | ' | ' | ' | 496,073 | 487,899 | 485,039 | ' | 496,073 | 487,899 | 485,039 |
Diluted (in shares) | ' | ' | ' | ' | ' | ' | ' | ' | 496,532 | 488,434 | 485,615 | ' | 496,532 | 488,434 | 485,615 |
Earnings per average common share: | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Basic (in dollars per share) | $0.30 | $0.73 | $0.40 | $0.48 | $0.29 | $0.82 | $0.38 | $0.38 | $1.91 | $1.86 | $1.72 | ' | $1.91 | $1.86 | $1.72 |
Diluted (in dollars per share) | $0.30 | $0.73 | $0.40 | $0.48 | $0.29 | $0.81 | $0.38 | $0.38 | $1.91 | $1.85 | $1.72 | ' | $1.91 | $1.85 | $1.72 |
Cash dividends declared per common share (in dollars per share) | $0.28 | $0.28 | $0.28 | $0.27 | $0.27 | $0.27 | $0.27 | $0.26 | $1.11 | $1.07 | $1.03 | ' | $1.11 | $1.07 | $1.03 |
Schedule_I_Condensed_Financial4
Schedule I, Condensed Financial Statements of Xcel Energy Inc, Condensed Statements of Cash Flows (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Operating activities | ' | ' | ' |
Net cash provided by operating activities | $2,584,036 | $2,004,756 | $2,405,522 |
Investing activities | ' | ' | ' |
Net cash used in investing activities | -3,213,384 | -2,332,942 | -2,247,801 |
Financing activities | ' | ' | ' |
Proceeds from (repayments of) short-term borrowings, net | 157,000 | 383,000 | -247,400 |
Proceeds from issuance of long-term debt | 1,431,895 | 1,790,131 | 688,598 |
Repayment of long-term debt | -652,451 | -1,302,763 | -105,623 |
Proceeds from issuance of common stock | 231,767 | 8,050 | 38,691 |
Repurchase of common stock | 0 | -18,529 | 0 |
Purchase of common stock for settlement of equity awards | 0 | -23,307 | 0 |
Redemption of preferred stock | 0 | 0 | -104,980 |
Dividends paid | -514,042 | -486,757 | -474,760 |
Net cash provided by (used in) financing activities | 654,169 | 349,825 | -205,474 |
Net change in cash and cash equivalents | 24,821 | 21,639 | -47,753 |
Cash and cash equivalents at beginning of period | 82,323 | 60,684 | 108,437 |
Cash and cash equivalents at end of period | 107,144 | 82,323 | 60,684 |
Xcel Energy Inc. | ' | ' | ' |
Operating activities | ' | ' | ' |
Net cash provided by operating activities | 545,177 | 815,209 | 595,732 |
Investing activities | ' | ' | ' |
Capital contributions to subsidiaries | -535,653 | -366,783 | -287,495 |
Investments in the utility money pool | -1,778,000 | -640,000 | 0 |
Return of investments in the utility money pool | 1,706,000 | 658,000 | 0 |
Net cash used in investing activities | -607,653 | -348,783 | -287,495 |
Financing activities | ' | ' | ' |
Proceeds from (repayments of) short-term borrowings, net | 297,000 | 52,000 | -21,000 |
Proceeds from issuance of long-term debt | 447,595 | 0 | 246,877 |
Repayment of long-term debt | -400,000 | 0 | 0 |
Proceeds from issuance of common stock | 231,767 | 8,050 | 38,691 |
Repurchase of common stock | 0 | -18,529 | 0 |
Purchase of common stock for settlement of equity awards | 0 | -23,307 | 0 |
Redemption of preferred stock | 0 | 0 | -104,980 |
Dividends paid | -514,042 | -486,757 | -474,760 |
Net cash provided by (used in) financing activities | 62,320 | -468,543 | -315,172 |
Net change in cash and cash equivalents | -156 | -2,117 | -6,935 |
Cash and cash equivalents at beginning of period | 602 | 2,719 | 9,654 |
Cash and cash equivalents at end of period | $446 | $602 | $2,719 |
Schedule_I_Condensed_Financial5
Schedule I, Condensed Financial Statements of Xcel Energy Inc, Condensed Balance Sheets (Details) (USD $) | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2010 |
In Thousands, unless otherwise specified | ||||
Assets | ' | ' | ' | ' |
Cash and cash equivalents | $107,144 | $82,323 | $60,684 | $108,437 |
Total current assets | 3,218,040 | 2,625,139 | ' | ' |
Investment in subsidiaries | 87,100 | 91,200 | ' | ' |
Other assets | 217,241 | 200,008 | ' | ' |
Total other assets | 4,567,291 | 4,706,199 | ' | ' |
Total assets | 33,907,490 | 31,140,686 | ' | ' |
Liabilities and Equity | ' | ' | ' | ' |
Dividends payable | 139,432 | 131,748 | ' | ' |
Short-term debt | 759,000 | 602,000 | 219,000 | ' |
Other current liabilities | 377,776 | 287,802 | ' | ' |
Total current liabilities | 3,654,498 | 2,937,073 | ' | ' |
Other liabilities | 237,217 | 229,207 | ' | ' |
Total deferred credits and other liabilities | 9,776,288 | 9,185,631 | ' | ' |
Commitments and contingencies | ' | ' | ' | ' |
Capitalization | ' | ' | ' | ' |
Common stockholders' equity | 9,565,950 | 8,874,077 | ' | ' |
Total liabilities and equity | 33,907,490 | 31,140,686 | ' | ' |
Xcel Energy Inc. | ' | ' | ' | ' |
Assets | ' | ' | ' | ' |
Cash and cash equivalents | 446 | 602 | 2,719 | 9,654 |
Accounts receivable from subsidiaries | 240,450 | 195,438 | ' | ' |
Other current assets | 51,086 | 11,497 | ' | ' |
Total current assets | 291,982 | 207,537 | ' | ' |
Investment in subsidiaries | 11,613,032 | 10,643,694 | ' | ' |
Other assets | 105,073 | 143,760 | ' | ' |
Total other assets | 11,718,105 | 10,787,454 | ' | ' |
Total assets | 12,010,087 | 10,994,991 | ' | ' |
Liabilities and Equity | ' | ' | ' | ' |
Dividends payable | 139,432 | 131,748 | ' | ' |
Short-term debt | 476,000 | 179,000 | ' | ' |
Other current liabilities | 6,954 | 31,032 | ' | ' |
Total current liabilities | 622,386 | 341,780 | ' | ' |
Other liabilities | 25,475 | 34,360 | ' | ' |
Total deferred credits and other liabilities | 25,475 | 34,360 | ' | ' |
Commitments and contingencies | ' | ' | ' | ' |
Capitalization | ' | ' | ' | ' |
Long-term debt | 1,796,276 | 1,744,774 | ' | ' |
Common stockholders' equity | 9,565,950 | 8,874,077 | ' | ' |
Total capitalization | 11,362,226 | 10,618,851 | ' | ' |
Total liabilities and equity | $12,010,087 | $10,994,991 | ' | ' |
Schedule_I_Condensed_Financial6
Schedule I, Condensed Financial Statements of Xcel Energy Inc, Condensed Statements of Income (Parenthetical) (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Condensed Financial Information of Parent Company Only Disclosure [Abstract] | ' | ' | ' |
Pension and retiree medical benefits, tax expense(benefit) | $5,897 | ($2,331) | ($2,247) |
Derivative instruments, tax expense(benefit) | 2,558 | -9,906 | -24,488 |
Other , tax tax expense(benefit) | $117 | $135 | ($63) |
Schedule_II_Valuation_and_Qual1
Schedule II, Valuation and Qualifying Accounts (Details) (USD $) | 12 Months Ended | |||||
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |||
Allowance for Bad Debts | ' | ' | ' | |||
Movement in Valuation Allowances and Reserves [Roll Forward] | ' | ' | ' | |||
Balance at Jan. 1 | $51,394 | $58,565 | $54,563 | |||
Charged to costs and expenses | 37,627 | 33,808 | 44,521 | |||
Charged to other accounts | 14,469 | [1] | 16,033 | [1] | 15,636 | [1] |
Deductions from reserves | 50,383 | [2] | 57,012 | [2] | 56,155 | [2] |
Balance at Dec. 31 | 53,107 | 51,394 | 58,565 | |||
NOL and Tax Credit Valuation Allowances | ' | ' | ' | |||
Movement in Valuation Allowances and Reserves [Roll Forward] | ' | ' | ' | |||
Balance at Jan. 1 | 3,314 | 5,683 | 1,927 | |||
Charged to costs and expenses | 0 | 32 | 4,379 | |||
Charged to other accounts | 0 | 0 | 0 | |||
Deductions from reserves | 51 | [3] | 2,401 | [3] | 623 | [3] |
Balance at Dec. 31 | $3,263 | $3,314 | $5,683 | |||
[1] | Recovery of amounts previously written off as related to allowance for bad debts. | |||||
[2] | Principally bad debts written off as related to allowance for bad debts. | |||||
[3] | Reductions to valuation allowances for NOL and tax credit carryforwards primarily due to changes in tax laws, expirations of certain carryforwards and identification of various tax planning strategies. |