Document and Entity Information
Document and Entity Information - shares | 9 Months Ended | |
Sep. 30, 2015 | Oct. 26, 2015 | |
Document and Entity Information [Abstract] | ||
Entity Registrant Name | XCEL ENERGY INC | |
Entity Central Index Key | 72,903 | |
Current Fiscal Year End Date | --12-31 | |
Entity Well-known Seasoned Issuer | Yes | |
Entity Voluntary Filers | No | |
Entity Current Reporting Status | Yes | |
Entity Filer Category | Large Accelerated Filer | |
Entity Common Stock, Shares Outstanding | 507,496,978 | |
Document Fiscal Year Focus | 2,015 | |
Document Fiscal Period Focus | Q3 | |
Document Type | 10-Q | |
Amendment Flag | false | |
Document Period End Date | Sep. 30, 2015 |
CONSOLIDATED STATEMENTS OF INCO
CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) - USD ($) shares in Thousands, $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | |
Operating revenues | ||||
Electric | $ 2,667,480 | $ 2,616,351 | $ 7,105,803 | $ 7,215,699 |
Natural gas | 216,019 | 236,649 | 1,216,146 | 1,485,464 |
Other | 17,813 | 16,807 | 56,716 | 56,344 |
Total operating revenues | 2,901,312 | 2,869,807 | 8,378,665 | 8,757,507 |
Operating expenses | ||||
Electric fuel and purchased power | 1,014,726 | 1,079,855 | 2,869,563 | 3,188,498 |
Cost of natural gas sold and transported | 66,071 | 99,344 | 665,109 | 934,073 |
Cost of sales — other | 8,203 | 8,012 | 26,416 | 24,783 |
Operating and maintenance expenses | 565,984 | 568,391 | 1,746,093 | 1,714,138 |
Conservation and demand side management program expenses | 57,314 | 75,172 | 165,260 | 223,552 |
Depreciation and amortization | 280,121 | 255,395 | 827,821 | 756,645 |
Taxes (other than income taxes) | 123,081 | 117,958 | 389,438 | 358,938 |
Loss on Monticello LCM/EPU project | 0 | 0 | 129,463 | 0 |
Total operating expenses | 2,115,500 | 2,204,127 | 6,819,163 | 7,200,627 |
Operating income | 785,812 | 665,680 | 1,559,502 | 1,556,880 |
Other income, net | 1,626 | 1,404 | 5,748 | 4,687 |
Equity earnings of unconsolidated subsidiaries | 8,162 | 7,401 | 24,360 | 22,650 |
Allowance for funds used during construction — equity | 15,427 | 23,337 | 40,728 | 68,852 |
Interest charges and financing costs | ||||
Interest charges — includes other financing costs of $6,260, $5,737, $17,819 and $17,144, respectively | 152,566 | 143,219 | 441,728 | 421,713 |
Allowance for funds used during construction — debt | (7,031) | (9,948) | (19,340) | (29,609) |
Total interest charges and financing costs | 145,535 | 133,271 | 422,388 | 392,104 |
Income before income taxes | 665,492 | 564,551 | 1,207,950 | 1,260,965 |
Income taxes | 239,029 | 195,969 | 432,490 | 435,998 |
Net income | $ 426,463 | $ 368,582 | $ 775,460 | $ 824,967 |
Weighted average common shares outstanding: | ||||
Basic (in shares) | 508,031 | 506,082 | 507,585 | 502,983 |
Diluted (in shares) | 508,427 | 506,365 | 507,976 | 503,213 |
Earnings per average common share: | ||||
Basic (in dollars per share) | $ 0.84 | $ 0.73 | $ 1.53 | $ 1.64 |
Diluted (in dollars per share) | 0.84 | 0.73 | 1.53 | 1.64 |
Cash dividends declared per common share (in dollars per share) | $ 0.32 | $ 0.30 | $ 0.96 | $ 0.90 |
CONSOLIDATED STATEMENTS OF INC3
CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) (Parenthetical) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | |
Interest charges and financing costs | ||||
Other financing costs | $ 6,260 | $ 5,737 | $ 17,819 | $ 17,144 |
CONSOLIDATED STATEMENTS OF COMP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | |
Comprehensive income: | ||||
Net income | $ 426,463 | $ 368,582 | $ 775,460 | $ 824,967 |
Pension and retiree medical benefits: | ||||
Amortization of losses included in net periodic benefit cost, net of tax of $559, $567, $1,689 and $1,666, respectively | 884 | 847 | 2,643 | 2,575 |
Derivative instruments: | ||||
Net fair value decrease, net of tax of $(28), $(27), $(24) and $(22), respectively | (42) | (42) | (35) | (34) |
Reclassification of losses to net income, net of tax of $446, $393, $1,210 and $1,115, respectively | 706 | 558 | 1,891 | 1,693 |
Total derivative instruments, net of tax | 664 | 516 | 1,856 | 1,659 |
Marketable securities: | ||||
Net fair value (decrease) increase, net of tax of $0, $1, $1 and $26, respectively | (1) | 2 | 1 | 40 |
Other comprehensive income | 1,547 | 1,365 | 4,500 | 4,274 |
Comprehensive income | $ 428,010 | $ 369,947 | $ 779,960 | $ 829,241 |
CONSOLIDATED STATEMENTS OF COM5
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) (Parenthetical) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | |
Pension and retiree medical benefits: | ||||
Amortization of losses included in net periodic benefit cost, tax | $ 559 | $ 567 | $ 1,689 | $ 1,666 |
Derivative instruments: | ||||
Net fair value increase (decrease), tax | (28) | (27) | (24) | (22) |
Reclassification of losses to net income, tax | 446 | 393 | 1,210 | 1,115 |
Marketable securities: | ||||
Net fair value increase (decrease), tax | $ 0 | $ 1 | $ 1 | $ 26 |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) - USD ($) $ in Thousands | 9 Months Ended | |
Sep. 30, 2015 | Sep. 30, 2014 | |
Operating activities | ||
Net income | $ 775,460 | $ 824,967 |
Adjustments to reconcile net income to cash provided by operating activities: | ||
Depreciation and amortization | 841,360 | 769,706 |
Conservation and demand side management program amortization | 4,063 | 4,582 |
Nuclear fuel amortization | 82,627 | 92,278 |
Deferred income taxes | 429,091 | 433,224 |
Amortization of investment tax credits | (4,151) | (4,329) |
Allowance for equity funds used during construction | (40,728) | (68,852) |
Equity earnings of unconsolidated subsidiaries | (24,360) | (22,650) |
Dividends from unconsolidated subsidiaries | 29,434 | 27,130 |
Share-based compensation expense | 29,765 | 16,536 |
Loss on Monticello LCM/EPU project | 129,463 | 0 |
Net realized and unrealized hedging and derivative transactions | 18,808 | (1,354) |
Changes in operating assets and liabilities: | ||
Accounts receivable | 85,276 | (16,080) |
Accrued unbilled revenues | 182,425 | 112,406 |
Inventories | (47,659) | (57,677) |
Other current assets | 72,445 | (25,901) |
Accounts payable | (116,137) | (155,788) |
Net regulatory assets and liabilities | 116,068 | 162,134 |
Other current liabilities | 60,293 | 14,683 |
Pension and other employee benefit obligations | (82,013) | (111,463) |
Change in other noncurrent assets | 2,374 | 44,009 |
Change in other noncurrent liabilities | (53,982) | (33,220) |
Net cash provided by operating activities | 2,489,922 | 2,004,341 |
Investing activities | ||
Utility capital/construction expenditures | (2,186,369) | (2,301,339) |
Proceeds from insurance recoveries | 27,237 | 6,000 |
Allowance for equity funds used during construction | 40,728 | 68,852 |
Purchases of investments in external decommissioning fund | (773,260) | (499,493) |
Proceeds from the sale of investments in external decommissioning fund | 753,924 | 494,554 |
Investment in WYCO Development LLC | (832) | (2,220) |
Other, net | (676) | (1,110) |
Net cash used in investing activities | (2,139,248) | (2,234,756) |
Financing activities | ||
Repayments of short-term borrowings, net | (955,500) | (62,000) |
Proceeds from issuance of long-term debt | 1,627,190 | 837,794 |
Repayments of long-term debt | (250,644) | (275,708) |
Proceeds from issuance of common stock | 5,298 | 178,639 |
Dividends paid | (452,217) | (417,586) |
Net cash (used in) provided by financing activities | (25,873) | 261,139 |
Net change in cash and cash equivalents | 324,801 | 30,724 |
Cash and cash equivalents at beginning of period | 79,608 | 107,144 |
Cash and cash equivalents at end of period | 404,409 | 137,868 |
Supplemental disclosure of cash flow information: | ||
Cash paid for interest (net of amounts capitalized) | (424,878) | (407,186) |
Cash received (paid) for income taxes, net | 57,632 | (4,950) |
Supplemental disclosure of non-cash investing and financing transactions: | ||
Property, plant and equipment additions in accounts payable | 284,864 | 407,706 |
Issuance of common stock for reinvested dividends and 401(k) plans | $ 39,169 | $ 42,772 |
CONSOLIDATED BALANCE SHEETS (UN
CONSOLIDATED BALANCE SHEETS (UNAUDITED) - USD ($) $ in Thousands | Sep. 30, 2015 | Dec. 31, 2014 |
Current assets | ||
Cash and cash equivalents | $ 404,409 | $ 79,608 |
Accounts receivable, net | 741,230 | 826,506 |
Accrued unbilled revenues | 546,067 | 728,492 |
Inventories | 644,963 | 597,183 |
Regulatory assets | 347,122 | 444,058 |
Derivative instruments | 48,110 | 85,723 |
Deferred income taxes | 352,712 | 246,210 |
Prepaid taxes | 117,012 | 185,488 |
Prepayments and other | 142,797 | 171,112 |
Total current assets | 3,344,422 | 3,364,380 |
Property, plant and equipment, net | 29,828,609 | 28,756,916 |
Other assets | ||
Nuclear decommissioning fund and other investments | 1,807,692 | 1,832,640 |
Regulatory assets | 2,812,172 | 2,774,216 |
Derivative instruments | 54,743 | 53,775 |
Other | 182,058 | 175,957 |
Total other assets | 4,856,665 | 4,836,588 |
Total assets | 38,029,696 | 36,957,884 |
Current liabilities | ||
Current portion of long-term debt | 457,474 | 257,726 |
Short-term debt | 64,000 | 1,019,500 |
Accounts payable | 924,260 | 1,173,006 |
Regulatory liabilities | 365,853 | 410,729 |
Taxes accrued | 379,103 | 396,615 |
Accrued interest | 143,124 | 158,536 |
Dividends payable | 162,324 | 151,720 |
Derivative instruments | 27,303 | 21,632 |
Other | 561,579 | 475,119 |
Total current liabilities | 3,085,020 | 4,064,583 |
Deferred credits and other liabilities | ||
Deferred income taxes | 6,390,162 | 5,852,988 |
Deferred investment tax credits | 69,545 | 73,696 |
Regulatory liabilities | 1,169,294 | 1,163,429 |
Asset retirement obligations | 2,550,930 | 2,446,631 |
Derivative instruments | 173,588 | 183,936 |
Customer advances | 228,479 | 256,945 |
Pension and employee benefit obligations | 863,645 | 936,907 |
Other | 263,452 | 264,653 |
Total deferred credits and other liabilities | $ 11,709,095 | $ 11,179,185 |
Commitments and contingencies | ||
Capitalization | ||
Long-term debt | $ 12,690,751 | $ 11,499,634 |
Common stock — 1,000,000,000 shares authorized of $2.50 par value; 507,267,264 and 505,733,267 shares outstanding at Sept. 30, 2015 and Dec. 31, 2014, respectively | 1,268,168 | 1,264,333 |
Additional paid in capital | 5,873,440 | 5,837,330 |
Retained earnings | 3,506,861 | 3,220,958 |
Accumulated other comprehensive loss | (103,639) | (108,139) |
Total common stockholders’ equity | 10,544,830 | 10,214,482 |
Total liabilities and equity | $ 38,029,696 | $ 36,957,884 |
CONSOLIDATED BALANCE SHEETS (U8
CONSOLIDATED BALANCE SHEETS (UNAUDITED) (Parenthetical) - $ / shares | Sep. 30, 2015 | Dec. 31, 2014 |
Capitalization, Long-term Debt and Equity [Abstract] | ||
Common stock, shares authorized (in shares) | 1,000,000,000 | 1,000,000,000 |
Common stock, par value (in dollars per share) | $ 2.50 | $ 2.50 |
Common stock, shares outstanding (in shares) | 507,267,264 | 505,733,267 |
CONSOLIDATED STATEMENTS OF COMM
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY (UNAUDITED) - USD ($) $ in Thousands | Total | Common Stock | Additional Paid In Capital | Retained Earnings | Accumulated Other Comprehensive Loss |
Beginning balance at Dec. 31, 2013 | $ 9,565,950 | $ 1,244,929 | $ 5,619,313 | $ 2,807,983 | $ (106,275) |
Balance (in shares) at Dec. 31, 2013 | 497,972,000 | ||||
Increase (Decrease) in Stockholders' Equity | |||||
Net income | 824,967 | 824,967 | |||
Other comprehensive income | 4,274 | 4,274 | |||
Dividends declared on common stock | (455,563) | (455,563) | |||
Issuances of common stock | 194,591 | $ 18,631 | 175,960 | ||
Issuances of common stock (in shares) | 7,452,000 | ||||
Share-based compensation | 20,441 | 20,441 | |||
Ending balance at Sep. 30, 2014 | 10,154,660 | $ 1,263,560 | 5,815,714 | 3,177,387 | (102,001) |
Balance (in shares) at Sep. 30, 2014 | 505,424,000 | ||||
Beginning balance at Jun. 30, 2014 | 9,920,772 | $ 1,262,764 | 5,799,968 | 2,961,406 | (103,366) |
Balance (in shares) at Jun. 30, 2014 | 505,106,000 | ||||
Increase (Decrease) in Stockholders' Equity | |||||
Net income | 368,582 | 368,582 | |||
Other comprehensive income | 1,365 | 1,365 | |||
Dividends declared on common stock | (152,601) | (152,601) | |||
Issuances of common stock | 9,931 | $ 796 | 9,135 | ||
Issuances of common stock (in shares) | 318,000 | ||||
Share-based compensation | 6,611 | 6,611 | |||
Ending balance at Sep. 30, 2014 | 10,154,660 | $ 1,263,560 | 5,815,714 | 3,177,387 | (102,001) |
Balance (in shares) at Sep. 30, 2014 | 505,424,000 | ||||
Beginning balance at Dec. 31, 2014 | $ 10,214,482 | $ 1,264,333 | 5,837,330 | 3,220,958 | (108,139) |
Balance (in shares) at Dec. 31, 2014 | 505,733,267 | 505,733,000 | |||
Increase (Decrease) in Stockholders' Equity | |||||
Net income | $ 775,460 | 775,460 | |||
Other comprehensive income | 4,500 | 4,500 | |||
Dividends declared on common stock | (489,557) | (489,557) | |||
Issuances of common stock | 22,709 | $ 3,835 | 18,874 | ||
Issuances of common stock (in shares) | 1,534,000 | ||||
Share-based compensation | 17,236 | 17,236 | |||
Ending balance at Sep. 30, 2015 | $ 10,544,830 | $ 1,268,168 | 5,873,440 | 3,506,861 | (103,639) |
Balance (in shares) at Sep. 30, 2015 | 507,267,264 | 507,267,000 | |||
Beginning balance at Jun. 30, 2015 | $ 10,269,066 | $ 1,267,398 | 5,863,209 | 3,243,645 | (105,186) |
Balance (in shares) at Jun. 30, 2015 | 506,959,000 | ||||
Increase (Decrease) in Stockholders' Equity | |||||
Net income | 426,463 | 426,463 | |||
Other comprehensive income | 1,547 | 1,547 | |||
Dividends declared on common stock | (163,247) | (163,247) | |||
Issuances of common stock | 9,435 | $ 770 | 8,665 | ||
Issuances of common stock (in shares) | 308,000 | ||||
Share-based compensation | 1,566 | 1,566 | |||
Ending balance at Sep. 30, 2015 | $ 10,544,830 | $ 1,268,168 | $ 5,873,440 | $ 3,506,861 | $ (103,639) |
Balance (in shares) at Sep. 30, 2015 | 507,267,264 | 507,267,000 |
Management's Opinion
Management's Opinion | 9 Months Ended |
Sep. 30, 2015 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Management's Opinion | In the opinion of management, the accompanying unaudited consolidated financial statements contain all adjustments necessary to present fairly, in accordance with accounting principles generally accepted in the United States of America (GAAP), the financial position of Xcel Energy Inc. and its subsidiaries as of Sept. 30, 2015 and Dec. 31, 2014 ; the results of its operations, including the components of net income and comprehensive income, and changes in stockholders’ equity for the three and nine months ended Sept. 30, 2015 and 2014 ; and its cash flows for the nine months ended Sept. 30, 2015 and 2014 . All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after Sept. 30, 2015 up to the date of issuance of these consolidated financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation. The Dec. 31, 2014 balance sheet information has been derived from the audited 2014 consolidated financial statements included in the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, 2014 . These notes to the consolidated financial statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with GAAP on an annual basis have been condensed or omitted pursuant to such rules and regulations. For further information, refer to the consolidated financial statements and notes thereto, included in the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, 2014 , filed with the SEC on Feb. 20, 2015. Due to the seasonality of Xcel Energy’s electric and natural gas sales, interim results are not necessarily an appropriate base from which to project annual results. |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 9 Months Ended |
Sep. 30, 2015 | |
Accounting Policies [Abstract] | |
Summary of Significant Accounting Policies | Summary of Significant Accounting Policies The significant accounting policies set forth in Note 1 to the consolidated financial statements in the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, 2014 , appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference. |
Accounting Pronouncements
Accounting Pronouncements | 9 Months Ended |
Sep. 30, 2015 | |
New Accounting Pronouncements and Changes in Accounting Principles [Abstract] | |
Accounting Pronouncements | Accounting Pronouncements Recently Issued Revenue Recognition — In May 2014, the Financial Accounting Standards Board (FASB) issued Revenue from Contracts with Customers, Topic 606 (Accounting Standards Update (ASU) No. 2014-09) , which provides a framework for the recognition of revenue, with the objective that recognized revenues properly reflect amounts an entity is entitled to receive in exchange for goods and services. The new guidance also includes additional disclosure requirements regarding revenue, cash flows and obligations related to contracts with customers. As a result of the FASB’s deferral of the standard’s required implementation date in July 2015, the guidance is effective for interim and annual reporting periods beginning after Dec. 15, 2017. Xcel Energy is currently evaluating the impact of adopting ASU 2014-09 on its consolidated financial statements. Consolidation — In February 2015, the FASB issued Amendments to the Consolidation Analysis, Topic 810 (ASU No. 2015-02) , which reduces the number of consolidation models and amends certain consolidation principles related to variable interest entities. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2015, and early adoption is permitted. Xcel Energy does not expect the implementation of ASU 2015-02 to have a material impact on its consolidated financial statements. Presentation of Debt Issuance Costs — In April 2015, the FASB issued Simplifying the Presentation of Debt Issuance Costs, Subtopic 835-30 (ASU No. 2015-03) , which amends existing guidance to require the presentation of debt issuance costs on the balance sheet as a deduction from the carrying amount of the related debt, instead of an asset. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2015, and early adoption is permitted. Other than the prescribed reclassification of assets to an offset of debt on the consolidated balance sheets, Xcel Energy does not expect the implementation of ASU 2015-03 to have a material impact on its consolidated financial statements. Fair Value Measurement — In May 2015, the FASB issued Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share (or Its Equivalent), Topic 820 (ASU No. 2015-07), which removes the requirement to categorize within the fair value hierarchy the fair values for investments measured using a net asset value methodology. This guidance will be effective on a retrospective basis for interim and annual reporting periods beginning after Dec. 15, 2015, and early adoption is permitted. Other than the reduced disclosure requirements, Xcel Energy does not expect the implementation of ASU 2015-07 to have a material impact on its consolidated financial statements. |
Selected Balance Sheet Data
Selected Balance Sheet Data | 9 Months Ended |
Sep. 30, 2015 | |
Balance Sheet Related Disclosures [Abstract] | |
Selected Balance Sheet Data | Selected Balance Sheet Data (Thousands of Dollars) Sept. 30, 2015 Dec. 31, 2014 Accounts receivable, net Accounts receivable $ 793,188 $ 884,225 Less allowance for bad debts (51,958 ) (57,719 ) $ 741,230 $ 826,506 (Thousands of Dollars) Sept. 30, 2015 Dec. 31, 2014 Inventories Materials and supplies $ 291,301 $ 244,099 Fuel 212,728 183,249 Natural gas 140,934 169,835 $ 644,963 $ 597,183 (Thousands of Dollars) Sept. 30, 2015 Dec. 31, 2014 Property, plant and equipment, net Electric plant $ 35,022,960 $ 33,203,139 Natural gas plant 4,818,049 4,643,452 Common and other property 1,615,290 1,611,486 Plant to be retired (a) 42,336 71,534 Construction work in progress 1,679,178 2,005,531 Total property, plant and equipment 43,177,813 41,535,142 Less accumulated depreciation (13,724,333 ) (13,168,418 ) Nuclear fuel 2,414,986 2,347,422 Less accumulated amortization (2,039,857 ) (1,957,230 ) $ 29,828,609 $ 28,756,916 (a) PSCo’s Cherokee Unit 3 was retired in August 2015. In 2017, PSCo expects to both early retire Valmont Unit 5 and convert Cherokee Unit 4 from a coal-fueled generating facility to natural gas, as approved by the Colorado Public Utilities Commission (CPUC). Amounts are presented net of accumulated depreciation. |
Income Taxes
Income Taxes | 9 Months Ended |
Sep. 30, 2015 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | Income Taxes Except to the extent noted below, Note 6 to the consolidated financial statements included in Xcel Energy Inc.’s Annual Report on Form 10-K for the year ended Dec. 31, 2014 appropriately represents, in all material respects, the current status of other income tax matters, and are incorporated herein by reference. Federal Audit — Xcel Energy files a consolidated federal income tax return. In the third quarter of 2012, the Internal Revenue Service (IRS) commenced an examination of tax years 2010 and 2011 , including the 2009 carryback claim. As of Sept. 30, 2015, the IRS had proposed an adjustment to the federal tax loss carryback claims that would result in $13 million of income tax expense for the 2009 through 2011 claims, the recently filed 2013 claim, and the anticipated claim for 2014. As of Sept. 30, 2015, the IRS had begun the appeals process; however, the outcome and timing of a resolution is uncertain. The statute of limitations applicable to Xcel Energy’s 2009-2011 federal income tax returns expires in December 2016 following an extension to allow additional time for the appeals process. In the third quarter of 2015, the IRS commenced an examination of tax years 2012 and 2013 . As of Sept. 30, 2015, the IRS had not proposed any material adjustments to tax years 2012 and 2013. State Audits — Xcel Energy files consolidated state tax returns based on income in its major operating jurisdictions of Colorado, Minnesota, Texas, and Wisconsin, and various other state income-based tax returns. As of Sept. 30, 2015, Xcel Energy’s earliest open tax years that are subject to examination by state taxing authorities in its major operating jurisdictions were as follows: State Year Colorado 2009 Minnesota 2009 Texas 2009 Wisconsin 2011 As of Sept. 30, 2015, there were no state income tax audits in progress. Unrecognized Tax Benefits — The unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the annual effective tax rate (ETR). In addition, the unrecognized tax benefit balance includes temporary tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. A change in the period of deductibility would not affect the ETR but would accelerate the payment of cash to the taxing authority to an earlier period. A reconciliation of the amount of unrecognized tax benefit is as follows: (Millions of Dollars) Sept. 30, 2015 Dec. 31, 2014 Unrecognized tax benefit — Permanent tax positions $ 15.8 $ 16.2 Unrecognized tax benefit — Temporary tax positions 60.6 50.3 Total unrecognized tax benefit $ 76.4 $ 66.5 The unrecognized tax benefit amounts were reduced by the tax benefits associated with net operating loss (NOL) and tax credit carryforwards. The amounts of tax benefits associated with NOL and tax credit carryforwards are as follows: (Millions of Dollars) Sept. 30, 2015 Dec. 31, 2014 NOL and tax credit carryforwards $ (39.2 ) $ (28.5 ) It is reasonably possible that Xcel Energy’s amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS appeals process and audit progress and state audits resume. As the IRS appeals process moves closer to completion, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $10 million . The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. The payables for interest related to unrecognized tax benefits at Sept. 30, 2015 and Dec. 31, 2014 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of Sept. 30, 2015 or Dec. 31, 2014. |
Rate Matters
Rate Matters | 9 Months Ended |
Sep. 30, 2015 | |
Public Utilities, General Disclosures [Abstract] | |
Rate Matters | Rate Matters Except to the extent noted below, the circumstances set forth in Note 12 to the consolidated financial statements included in Xcel Energy Inc.’s Annual Report on Form 10-K for the year ended Dec. 31, 2014 and in Note 5 to the consolidated financial statements included in Xcel Energy Inc.’s Quarterly Reports on Form 10-Q for the quarterly periods ended March 31, 2015 and June 30, 2015, appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference. NSP-Minnesota Pending and Recently Concluded Regulatory Proceedings — Minnesota Public Utilities Commission ( MPUC) NSP-Minnesota – Minnesota 2014 Multi-Year Electric Rate Case — In November 2013, NSP-Minnesota filed a two -year electric rate case with the MPUC. The rate case was based on a requested return on equity (ROE) of 10.25 percent , a 52.5 percent equity ratio, a 2014 average electric rate base of $6.67 billion and an additional average rate base of $412 million in 2015. The NSP-Minnesota electric rate case initially reflected a requested increase in revenues of approximately $193 million , or 6.9 percent , in 2014 and an additional $98 million , or 3.5 percent , in 2015. The request included a proposed rate moderation plan for 2014 and 2015. In December 2013, the MPUC approved interim rates of $127 million , effective Jan. 3, 2014, subject to refund. In 2014, NSP-Minnesota revised its requested rate increase to $115.3 million for 2014 and to $106.0 million for 2015, for a total combined unadjusted increase of $221.3 million . In May 2015, the MPUC ordered a 2014 rate increase and a 2015 step increase. The total increase was estimated to be $166.1 million , or 5.9 percent , consisting of $58.9 million and $125.2 million in 2014 and 2015, respectively, and an $18.0 million adjustment related to disallowance of certain Monticello Life Cycle Management (LCM)/Extended Power Uprate (EPU) costs. The MPUC also approved a three -year, decoupling pilot with a 3 percent cap on base revenue for the residential and small commercial and industrial classes, based on actual sales, effective Jan. 1, 2016. The decoupling mechanism would eliminate the impact of changes in electric sales due to conservation and weather variability for these classes. In July 2015, the MPUC deliberated on requests for reconsideration of its order and determined the Monticello EPU project was not yet used-and-useful, as final approval related to the full EPU uprate condition had not been received from the Nuclear Regulatory Commission (NRC) as of June 30, 2015. As a result, $13.8 million was excluded from final rates. Monticello subsequently received final NRC compliance approval in July 2015. The MPUC also approved 2015 interim rates effective March 3, 2015 and stated that the 2014 interim rate refund obligation be netted against the 2015 interim rate revenue under-collections. The MPUC’s decisions resulted in a total estimated 2014 and 2015 annual rate increase of $149.4 million , or 5.3 percent . The following table outlines the impact of the MPUC’s July decision: (Millions of Dollars) MPUC July Decision 2014 and 2015 step increase - based on MPUC May order $ 166.1 Reconsideration/clarification adjustments: 2015 Monticello EPU used-and-useful adjustment (13.8 ) 2014 property tax final true-up (3.1 ) Other, net 0.2 Total 2014 and 2015 step increase $ 149.4 Impact of interim rate effective March 3, 2015 (3.6 ) Estimated revenue impact $ 145.8 NSP-Minnesota – Nuclear Project Prudence Investigation — In 2013, NSP-Minnesota completed the Monticello LCM/EPU project. The multi-year project extended the life of the facility and increased the capacity from 600 to 671 megawatts (MW). Monticello LCM/EPU project expenditures were approximately $665 million . Total capitalized costs were approximately $748 million , which includes allowance for funds used during construction (AFUDC). In 2008, project expenditures were initially estimated at approximately $320 million , excluding AFUDC. In 2013, the MPUC initiated an investigation to determine whether the final costs for the Monticello LCM/EPU project were prudent. In March 2015, the MPUC voted to allow for full recovery, including a return, on approximately $415 million of the total plant costs (inclusive of AFUDC), but only allow recovery of the remaining $333 million of costs with no return on this portion of the investment over the remaining life of the plant. Further, the MPUC determined that only 50 percent of the investment was considered used-and-useful for 2014. As a result of these determinations and assuming the other state commissions within the NSP System jurisdictions adopt the MPUC’s decisions, Xcel Energy recorded an estimated pre-tax loss of $129 million in the first quarter of 2015. The remaining book value of the Monticello project represents the present value of the estimated future cash flows allowed for by the MPUC. NSP-Minnesota – 2016 Transmission Cost Recovery (TCR) Rate Filing — In October 2015, NSP-Minnesota submitted its 2016 TCR filing with the MPUC, requesting recovery of $19.2 million of 2016 transmission investment costs not included in electric base rates. The 2016 TCR rider filing includes an option to keep within the TCR rider approximately $59.1 million of revenue requirements associated with two CapX2020 projects completed in 2015 or to include these revenue requirements in electric base rates during the interim rate implementation of the next electric rate case. If the MPUC opts to maintain the projects in the rider, the TCR rider revenue requirements would increase to $78.3 million . Pending Regulatory Proceedings — South Dakota Public Utilities Commission (SDPUC) NSP-Minnesota – South Dakota Infrastructure Rider — In October 2015, NSP-Minnesota filed its 2016 infrastructure rider filing with the SDPUC, requesting approval for recovery of $10.3 million in 2016 revenue requirements for rates effective Jan. 1, 2016. As part of the South Dakota 2015 electric rate case, the infrastructure rider was refreshed with new projects and was also expanded as a mechanism to allow for possible recovery of other investments related to generation, transmission, and distribution. A SDPUC decision is expected in the fourth quarter of 2015. NSP-Wisconsin Pending Regulatory Proceedings — Public Service Commission of Wisconsin (PSCW) Wisconsin 2016 Electric and Gas Rate Case — In May 2015, NSP-Wisconsin filed a request with the PSCW to increase rates for electric and natural gas service effective Jan. 1, 2016. NSP-Wisconsin requested an overall increase in annual electric rates of $27.4 million , or 3.9 percent , and an increase in natural gas rates of $5.9 million , or 5.0 percent . The rate filing is based on a 2016 forecast test year, a ROE of 10.2 percent , an equity ratio of 52.5 percent and a forecasted average net investment rate base of approximately $1.2 billion for the electric utility and $111.2 million for the natural gas utility. On Oct. 1, 2015, the PSCW Staff and other intervenors, including the Citizens Utility Board, filed their direct testimony in the case. The PSCW Staff recommended an electric rate increase of $10.4 million , or 1.5 percent , and a gas rate increase of $3.0 million , or 2.5 percent , based on a ROE of 10.0 percent and an equity ratio of 52.5 percent . The Citizens Utility Board recommended a ROE of 8.75 percent . None of the intervenors presented a complete revenue requirements analysis. The majority of the PSCW Staff adjustments relate to ROE, compensation issues and capital related forecast disputes. Key dates in the procedural schedule are as follows: • Initial Brief — Nov. 12, 2015; • Reply Brief — Nov. 19, 2015; • A PSCW decision is anticipated in December 2015; and • New rates effective on or about Jan. 1, 2016. PSCo Pending Regulatory Proceedings — CPUC PSCo – Colorado 2015 Multi-Year Gas Rate Case — In March 2015, PSCo filed a multi-year request with the CPUC to increase Colorado retail natural gas base rates by $40.5 million , or 3.5 percent , in 2015, with subsequent step increases of $7.6 million , or 0.7 percent , in 2016 and $18.1 million , or 1.5 percent , in 2017. The request is based on a historic test year (HTY) ended June 30, 2014 adjusted for known and measurable expenses and capital additions for each of the subsequent periods in the multi-year plan (MYP) and an equity ratio of 56 percent . The rate case requests a ROE of 10.1 percent for 2015 and 2016 and 10.3 percent for 2017, and a rate base of $1.26 billion for 2015, $1.31 billion for 2016 and $1.36 billion for 2017. PSCo also proposed a stay-out provision, in which PSCo would not request implementation of new rates prior to January 2018, and implementation of an earnings test for 2016 through 2017. In addition, PSCo requested an extension of its pipeline system integrity adjustment (PSIA) rider through 2020 to recover costs associated with its pipeline integrity efforts. The request to extend and modify the PSIA rider has an expected negative revenue impact of approximately $0.1 million in 2015 and would provide incremental revenue of $21.7 million for 2016 and $21.2 million for 2017. The following table summarizes the request: (Millions of Dollars) 2015 2016 Step 2017 Step Total base rate increase $ 40.5 $ 7.6 $ 18.1 Incremental PSIA rider revenues (0.1 ) 21.7 21.2 Total revenue impact $ 40.4 $ 29.3 $ 39.3 In June 2015, the CPUC Staff (Staff) and the Office of Consumer Counsel (OCC) issued their 2015 base rate recommendations. The following table reflects the current positions of Staff and OCC: (Millions of Dollars) Staff OCC PSCo’s filed 2015 base rate request $ 40.5 $ 40.5 ROE (12.8 ) (13.7 ) Capital structure and cost of debt (12.8 ) (4.8 ) Cherokee pipeline adjustment (11.2 ) 4.8 Move to 2014 HTY (10.5 ) (16.4 ) Operating and maintenance (O&M) expenses (3.5 ) (2.7 ) Other, net (4.4 ) (1.9 ) Total adjustments $ (55.2 ) $ (34.7 ) Recommended (decrease) increase $ (14.7 ) $ 5.8 The Staff’s recommendation for the PSIA rider is as follows: (Millions of Dollars) 2016 2017 PSCo’s filed incremental PSIA request $ 21.7 $ 21.2 Transfer PSIA O&M to base rates (24.1 ) (2.0 ) ROE and capital structure (8.2 ) (3.6 ) Transfer meter replacement program from base rates to PSIA 1.7 1.7 Total $ (8.9 ) $ 17.3 In July 2015, PSCo filed rebuttal testimony, maintaining its request for a multi-year plan and requested ROEs and reflecting the most recent sales forecast. PSCo’s rebuttal testimony, compared to its initial filed base rate and rider request are summarized as follows: (Millions of Dollars) 2015 2016 Step 2017 Step PSCo’s filed base rate request $ 40.5 $ 7.6 $ 18.1 Shift O&M expenses between PSIA and base rates — 7.0 6.4 Rebuttal corrections and adjustments — — (7.7 ) Total base rate request $ 40.5 $ 14.6 $ 16.8 Incremental PSIA rider revenues (0.1 ) 14.7 21.7 Total revenue impact from rebuttal $ 40.4 $ 29.3 $ 38.5 If PSCo’s revised request is accepted, PSIA revenue is projected to be $67.0 million in 2015, $81.7 million in 2016 and $103.4 million in 2017. Interim rates, subject to refund, were also implemented, effective Oct. 1, 2015, based on PSCo’s direct testimony. PSCo is expecting the ALJ’s Recommended Decision in November 2015. The final CPUC decision is expected no later than January 2016. PSCo — Annual Electric Earnings Test — In February 2015, in the Colorado 2014 Electric Rate Case, the CPUC approved an annual earnings test, in which PSCo shares with customers’ earnings that exceed the authorized ROE threshold of 9.83 percent for 2015 through 2017. As of Sept. 30, 2015, PSCo has recognized management’s best estimate of the expected customer refund obligation for the 2015 earnings test, based on annual forecasted information. Electric, Purchased Gas and Resource Adjustment Clauses Demand Side Management (DSM) and the Demand Side Management Cost Adjustment (DSMCA) — The CPUC approved higher savings goals and a lower financial incentive mechanism for PSCo’s electric DSM energy efficiency programs starting in 2015. Energy efficiency and DSM costs are recovered through a combination of the DSMCA riders and base rates. DSMCA riders are adjusted biannually to capture program costs, performance incentives, and any over- or under-recoveries are trued-up in the following year. Savings goals were 384 gigawatt hours (GWh) in 2014 and are 400 GWh in 2015 with incentives awarded in the year following plan achievements. PSCo is able to earn $5 million upon reaching its annual savings goal along with an incentive on five percent of net economic benefits up to a maximum annual incentive of $30 million . For the years 2015 through 2020, the annual electric energy savings goal is 400 GWh per year with an annual earnings limit of $84.3 million . In July 2015, the CPUC approved PSCo’s 2015-2016 DSM plan: • A 2015 DSM electric budget of $81.6 million ; • A 2015 DSM gas budget of $13.1 million ; • A 2016 DSM electric budget of $78.7 million ; and • A 2016 DSM gas budget of $13.6 million . SPS Pending Regulatory Proceedings — Public Utility Commission of Texas (PUCT) SPS – Texas 2015 Electric Rate Case — In December 2014, SPS filed a retail electric rate case in Texas seeking an overall increase in annual revenue of approximately $64.8 million , or 6.7 percent . The filing was based on a HTY ending June 2014, adjusted for known and measurable changes, a ROE of 10.25 percent , an electric rate base of approximately $1.6 billion and an equity ratio of 53.97 percent . In March 2015, SPS revised its requested increase to $58.9 million based on updated information. SPS is seeking a waiver of the PUCT post-test year adjustment rule which would allow for inclusion of $392 million (SPS total company) additional capital investment for the period July 1, 2014 through Dec. 31, 2014. In June 2015, SPS filed rebuttal testimony supporting a revised rate increase of approximately $42.1 million , or 4.4 percent . On Oct. 12, 2015, the administrative law judges (ALJs) issued their Proposal for Decision (PFD) and recommended a rate increase of approximately $1.2 million , based on a ROE of 9.70 percent and an equity ratio of 53.97 percent . The following table reflects the positions of Alliance of Xcel Municipalities (AXM), the Office of Public Utility Counsel (OPUC), the PUCT Staff (Staff), SPS as well as the estimated recommendation of the ALJs: SPS Rebuttal Testimony ALJs’ PFD (a) (Millions of Dollars) AXM OPUC Staff SPS’ revised rate request $ 58.9 $ 58.9 $ 58.9 $ 58.9 $ 42.1 Investment for capital expenditures — post-test year adjustments (11.3 ) (23.8 ) (23.8 ) — (16.7 ) Lower ROE (10.9 ) (13.5 ) (12.1 ) — (6.3 ) Rate base adjustments (largely the removal of the prepaid pension asset) (6.2 ) (6.8 ) — — — O&M expense adjustments (13.7 ) (11.0 ) (7.9 ) (1.6 ) (5.3 ) Depreciation expense (13.3 ) — — — (3.9 ) Property taxes — (1.2 ) (4.4 ) (1.8 ) (3.7 ) Revenue adjustments (2.2 ) (0.2 ) — — — Wholesale load reductions (13.2 ) — (11.1 ) — — Southwest Power Pool (SPP) transmission expansion plan — — — (7.3 ) (4.2 ) Other, net (1.7 ) (0.6 ) (2.2 ) (1.8 ) (0.6 ) Total recommendation $ (13.6 ) $ 1.8 $ (2.6 ) $ 46.4 $ 1.4 Adjustment to move rate case expenses to a separate docket — — — (4.3 ) (0.2 ) Recommendation, excluding rate case expenses $ (13.6 ) $ 1.8 $ (2.6 ) $ 42.1 $ 1.2 (a) The ALJs’ recommendation reflects proposed adjustments to SPS’ rebuttal testimony, as of Oct. 12, 2015, which supports a $42.1 million rate increase. SPS subsequently filed a letter notifying the PUCT it had concerns regarding the calculation. On Oct. 28, 2015, the Staff issued a revised calculation reflecting corrections to the PFD. The ALJs’ revised recommended rate increase is $14.4 million . New rates will be made effective retroactive to June 11, 2015 as established by the PUCT. A PUCT decision is expected in December 2015. Pending Regulatory Proceedings — New Mexico Public Regulation Commission (NMPRC) SPS – New Mexico 2015 Electric Rate Case — In October 2015, SPS filed an electric rate case with the NMPRC for a net increase in base rates of approximately $24.3 million for the New Mexico retail jurisdiction. The proposed net amount reflects an increase in non-fuel base rates of $45.4 million and a decrease in base fuel revenue of approximately $21.1 million . The decrease in base fuel revenue will be reflected in adjustments collected through the fuel and purchased power adjustment clause. The rate filing is based on a June 30, 2015 HTY adjusted for known and measurable changes, a requested ROE of 10.25 percent , an electric jurisdictional rate base of approximately $734 million and an equity ratio of 53.97 percent . The major components of the requested rate increase are summarized below: (Millions of Dollars) Request 2015 base period deficiency $ 19.7 Capital expenditures — post-test year adjustments 12.3 Depreciation, higher rates reflecting changes in depreciable lives, interim retirements and net salvage 3.7 Transmission revenue and expense, including charges paid to SPP for construction of regionally shared transmission projects 2.0 ROE, reflecting an increase from 9.96 percent to 10.25 percent 1.6 Rider revenue adjustments - gross receipts tax 1.3 Other, net 4.8 Requested rate increase $ 45.4 A NMPRC decision and implementation of final rates is anticipated in the second half of 2016. In June 2015, the NMPRC dismissed a rate case filing using a future test year based on new precedent. SPS has appealed that decision to the New Mexico Supreme Court. Pending and Recently Concluded Regulatory Proceedings — Federal Energy Regulatory Commission (FERC) Midcontinent Independent System Operator, Inc. (MISO) ROE Complaints/ROE Adder — In November 2013, a group of customers filed a complaint at the FERC against certain MISO transmission owners (TOs), including NSP-Minnesota and NSP-Wisconsin. The complaint argued for a reduction in the ROE in transmission formula rates in the MISO region from 12.38 percent to 9.15 percent , a prohibition on capital structures in excess of 50 percent equity, and the removal of ROE adders (including those for regional transmission organization (RTO) membership and being an independent transmission company), effective Nov. 12, 2013. Subsequently, the FERC issued and upheld an order adopting a new ROE methodology, which requires electric utilities to use a two -step discounted cash flow analysis that incorporates both short-term and long-term growth projections to estimate the cost of equity. The ROE complaint was set for full hearing procedures. The complainants and intervenors filed testimony recommending a ROE between 8.67 percent and 9.54 percent . The FERC staff recommended a ROE of 8.68 percent . The MISO TOs recommended a ROE not less than 10.8 percent . An ALJ initial decision is anticipated to be issued by November 2015 and a FERC order is expected to be issued no earlier than 2016. Certain MISO TOs requested FERC approval of a 50 basis point RTO membership ROE adder, which was approved effective Jan. 6, 2015, subject to the outcome of the ROE complaint. The total ROE, including the RTO membership adder, may not exceed the top of the discounted cash flow range under the new ROE methodology. Certain intervenors sought rehearing of the FERC order granting the ROE adder; FERC action is pending. Certain intervenors filed a second complaint in February 2015 to reduce the MISO region ROE to 8.67 percent , prior to an adder. A hearing has been set, and a refund effective date of Feb. 12, 2015 was established. The complainants and intervenors filed direct testimony in September 2015 recommending ROEs between 8.72 percent and 9.13 percent . The MISO TOs filed answering testimony on Oct. 20, 2015, recommending a ROE of not less than 10.75 percent . FERC staff is expected to file testimony in November 2015, and a hearing is scheduled for February 2016. An ALJ initial decision is expected in June 2016 with a FERC decision in late 2016 or in 2017. Currently, the ROE refund obligation initiated under the November 2013 complaint is effective through May 2016. The MISO TOs sought rehearing of the FERC decision to allow back-to-back complaints. NSP-Minnesota and NSP-Wisconsin sought rehearing of the FERC’s decision not to order changes to the ROE used by non-jurisdictional MISO transmission owners (more than 20 municipal, cooperative and other utilities who are not respondents to the ROE complaints), which equals the ROE presently used by the jurisdictional MISO TOs. FERC action is pending. NSP-Minnesota recorded a current liability representing the current best estimate of a refund obligation associated with the new ROE as of Sept. 30, 2015. The new FERC ROE methodology is estimated to reduce transmission revenue, net of expense, between $7 million and $9 million annually for the NSP System. SPS – Global Settlement Agreement — In August 2015, SPS, Golden Spread Electric Cooperative, Inc. (Golden Spread), four New Mexico Cooperatives, West Texas Municipal Power Agency (WTMPA), Public Service Company of New Mexico (PNM) and Tri-County Electric Cooperative, Inc. (Tri-County) filed a settlement agreement with the FERC that would provide a comprehensive resolution of nine pending matters in dispute between SPS and these wholesale production and transmission customers, including the 2004 FERC Complaint Case , the Wholesale Rate Complaints , the 2015 Formula Rate Change Filing and the Sale of Texas Transmission Assets as discussed below. Key terms of the settlement agreement include: • A settlement payment to Golden Spread for $44.9 million and withdrawal of the SPS and the New Mexico Cooperatives’ requests for rehearing of the August 2013 FERC order ruling that SPS is a 3 coincident peak (CP) system; • A settlement payment to PNM of $4.2 million and the withdrawal of the PNM request for rehearing of the August 2013 FERC order denying PNM’s challenge to the 2008 FERC ruling regarding SPS’ fuel cost adjustment practices; • Withdrawal of the Golden Spread Wholesale Rate Complaints, resulting in no change to the then-effective production and transmission ROEs for the period April 20, 2012 through Oct. 19, 2014, and withdrawal of the SPS appeal of the FERC orders in those proceedings to the United States District Court of Appeals for the District of Columbia Circuit (D.C. Circuit); • A reduction in the SPS transmission ROE to 10.5 percent (including the 50 basis point SPP regional transmission organization membership adder) and the production ROE in the Golden Spread and New Mexico Cooperatives production formula rates to 10.0 percent effective Oct. 20, 2014, and establishment of a limited moratorium that precludes any increase or decrease in these effective ROEs through 2019; • Utilization of the 12 CP production cost allocation methodology in the Golden Spread, New Mexico Cooperatives and WTMPA production formula rates and a moratorium precluding all settlement parties from seeking to change from the 12 CP methodology during the remaining term of the Golden Spread production contract (currently scheduled to expire in May 2019); • SPS agrees to reduce its production formula rates retroactive to Jan. 1, 2015 to reflect full year implementation of reduced depreciation and certain other costs; the FERC had allowed these reductions to be effective July 1, 2015; • SPS agrees to make certain revisions to its transmission formula rate, effective Jan. 1, 2016, to provide for a sharing of the wholesale portion of any gain on a future sale of transmission assets; other parties agree not to challenge the non-sharing of the gain SPS recorded on prior and current transmission asset transactions with Sharyland Distribution and Transmission Services, LLC (Sharyland) and Oncor Electric Delivery Company LLC; • SPS agrees not to file with FERC to increase transmission depreciation rate rates effective prior to Jan. 1, 2017; and • SPS agrees not to transfer Tri-County from its current stated rate production service agreement to a production formula rate effective prior to Jan. 1, 2017. Tri-County agrees that it will not contest implementation of the formula rate as of that date. On Oct. 29, 2015, the FERC issued an order approving the settlement agreement. The terms are effective 30 days after issuance. As a result of the settlement, SPS expects to recognize a net gain of approximately $7.9 million in the fourth quarter of 2015. The settlement also resolves the following: 2004 FERC Complaint Case Orders — In August 2013, the FERC issued an order related to a 2004 complaint case brought by Golden Spread, a wholesale cooperative customer, and PNM, a former wholesale customer, and also issued an Order on Initial Decision in a subsequent 2006 production rate case filed by SPS. The original complaints included two key components: 1) a base rate complaint, including the appropriate demand-related CP cost allocator; and 2) a claim regarding alleged inappropriate fuel cost adjustment practices. The FERC had determined in April 2008 that the demand-related cost allocator and fuel cost adjustment practices utilized by SPS were appropriate. In the August 2013 Orders, the FERC reversed its prior demand-related cost allocator decision. The FERC stated that it had erred in its initial analysis and concluded that the SPS system was a 3 CP rather than a 12 CP system. The FERC also clarified its previous ruling on fuel cost adjustment practices and reaffirmed that the refunds in question should only apply to firm requirements customers. In September 2013, SPS, the New Mexico Cooperatives and PNM each filed requests for rehearing of the FERC ruling on the CP allocation and/or refund decision. As of Dec. 31, 2014, SPS had accrued $50.4 million related to the August 2013 Orders and an additional $1.9 million of principal and interest has been accrued during 2015. Wholesale Rate Complaints — In April 2012, Golden Spread filed a rate complaint alleging that the base ROE included in the SPS production formula rate for Golden Spread of 10.25 percent , and the SPS transmission formula rate ROE of 11.27 percent are unjust and unreasonable, and requested that the base ROEs be reduced to 9.15 percent and 9.65 percent , respectively, effective April 20, 2012. In July 2013, Golden Spread filed a second complaint, again asking that the base ROE in the SPS production formula rate for Golden Spread and transmission formula rates be reduced to 9.15 percent and 9.65 percent , respectively, effective July 19, 2013. In June 2014, the FERC issued orders consolidating these ROE complaints, setting the complaints for hearing procedures and granting the complainant’s requested refund effective dates. SPS subsequently sought rehearing. In May 2015, FERC denied rehearing. In July 2015, SPS appealed the FERC orders to the D.C. Circuit. A third ROE rate complaint was filed in October 2014 by Golden Spread, along with the New Mexico Cooperatives and WTMPA, requesting that the ROE in the SPS production formula rates for Golden Spread and the New Mexico Cooperatives and SPS transmission formula rate, be reduced to 8.61 percent and 9.11 percent , respectively, effective Oct. 20, 2014. In January 2015, the FERC issued an order setting the third complaint for hearing procedures and granting the complainants’ requested refund effective date. SPS subsequently sought rehearing. FERC has not acted on the SPS rehearing request. 2015 Formula Rate Change Filing — In January 2015, SPS filed to revise the production formula rates for Golden Spread, the four New Mexico Cooperatives and WTMPA, effective Feb. 1, 2015. The filing proposed several modifications, including a reduction in wholesale depreciation rates and the use of a 12 CP demand-related cost allocator for all wholesale customers. On March 31, 2015, the FERC accepted this filing, effective July 1, 2015, subject to refund and settlement judge or hearing procedures. 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. In December 2013, SPS received $37.1 million and recognized a pre-tax gain of $13.6 million and regulatory liabilities for retail jurisdictional gain sharing of $7.2 million . The gain is reflected in the consolidated statement of income as a reduction to O&M expenses. In December 2014, Golden Spread submitted a preliminary challenge under the SPS transmission formula rate procedures asserting the gain should be shared with wholesale transmission customers. SPS disputed this claim. In October 2015, the FERC denied rehearing on the matter. |
Commitments and Contingencies
Commitments and Contingencies | 9 Months Ended |
Sep. 30, 2015 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | Commitments and Contingencies Except to the extent noted below and in Note 5 above, the circumstances set forth in Notes 5, 12, 13 and 14 to the consolidated financial statements included in Xcel Energy Inc.’s Annual Report on Form 10-K for the year ended Dec. 31, 2014 and in Notes 5 and 6 to the consolidated financial statements included in Xcel Energy Inc.’s Quarterly Reports on Form 10-Q for the quarterly periods ended March 31, 2015 and June 30, 2015, appropriately represent, in all material respects, the current status of commitments and contingent liabilities, and are incorporated herein by reference. The following include commitments, contingencies and unresolved contingencies that are material to Xcel Energy’s financial position. Purchased Power Agreements (PPAs) Under certain PPAs, NSP-Minnesota, PSCo and SPS purchase power from independent power producing entities for which the utility subsidiaries are required to reimburse natural gas or biomass fuel costs, or to participate in tolling arrangements under which the utility subsidiaries procure the natural gas required to produce the energy that they purchase. These specific PPAs create a variable interest in the associated independent power producing entity. The Xcel Energy utility subsidiaries had approx imate ly 3,698 MW of capacity under long-term PPAs as of Sept. 30, 2015 and Dec. 31, 2014 , with entities that have been determined to be variable interest entities. Xcel Energy has concluded that these entities are not required to be consolidated in its consolidated financial statements because it does not have the power to direct the activities that most significantly impact the entities’ economic performance. These agreements have expiration dates through 2033 . Guarantees and Bond Indemnifications Xcel Energy Inc. and its subsidiaries provide guarantees and bond indemnities under specified agreements or transactions. The guarantees and bond indemnities issued by Xcel Energy Inc. guarantee payment or performance by its subsidiaries. As a result, Xcel Energy Inc.’s exposure under the guarantees and bond indemnities is based upon the net liability of the relevant subsidiary under the specified agreements or transactions. Most of the guarantees and bond indemnities issued by Xcel Energy Inc. and its subsidiaries limit the exposure to a maximum amount stated in the guarantees and bond indemnities. As of Sept. 30, 2015 and Dec. 31, 2014 , Xcel Energy Inc. and its subsidiaries had no assets held as collateral related to their guarantees, bond indemnities and indemnification agreements. The following table presents guarantees and bond indemnities issued and outstanding for Xcel Energy Inc.: (Millions of Dollars) Sept. 30, 2015 Dec. 31, 2014 Guarantees issued and outstanding $ 12.9 $ 13.9 Current exposure under these guarantees 0.1 0.2 Bonds with indemnity protection 42.5 31.4 Other Indemnification Agreements Xcel Energy Inc. and its subsidiaries provide indemnifications through contracts entered into in the normal course of business. These are primarily indemnifications against adverse litigation outcomes in connection with underwriting agreements, as well as breaches of representations and warranties, including corporate existence, transaction authorization and income tax matters with respect to assets sold. Xcel Energy Inc.’s and its subsidiaries’ obligations under these agreements may be limited in terms of duration and amount. The maximum potential amount of future payments under these indemnifications cannot be reasonably estimated as the obligated amounts of these indemnifications often are not explicitly stated. Environmental Contingencies Ashland Manufactured Gas Plant (MGP) Site — NSP-Wisconsin has been named a potentially responsible party (PRP) for contamination at a site in Ashland, Wis. The Ashland/Northern States Power Lakefront Superfund Site (the Ashland site) includes property owned by NSP-Wisconsin, which was a site previously operated by a predecessor company as a MGP facility (the Upper Bluff), and two other properties: an adjacent city lakeshore park area (Kreher Park), on which an unaffiliated third party previously operated a sawmill and where NSP-Wisconsin believes wood treating operations were conducted; and an area of Lake Superior’s Chequamegon Bay adjoining the park (the Sediments). The U.S. Environmental Protection Agency (EPA) issued its Record of Decision (ROD) in 2010, which describes the preferred remedy the EPA has selected for the cleanup of the Ashland site. For the Sediments at the Ashland site, the ROD preferred remedy is a hybrid remedy involving both dry excavation and wet conventional dredging methodologies (the Hybrid Remedy). The ROD also identifies the possibility of a wet conventional dredging only remedy for the Sediments (the Wet Dredge), contingent upon the completion of a successful Wet Dredge pilot study. In 2011, the EPA issued special notice letters identifying several entities, including NSP-Wisconsin, as PRPs, for future remediation at the Ashland site. As a result of settlement negotiations with NSP-Wisconsin, the EPA agreed to segment the Ashland site into separate areas. The first area (Phase I Project Area) includes soil and groundwater in Kreher Park and the Upper Bluff. The second area includes the Sediments. In October 2012, a settlement among the EPA, the Wisconsin Department of Natural Resources, the Bad River and Red Cliff Bands of the Lake Superior Tribe of Chippewa Indians and NSP-Wisconsin was approved by the U.S. District Court for the Western District of Wisconsin. This settlement resolves claims against NSP-Wisconsin for its alleged responsibility for the remediation of the Phase I Project Area. Under the terms of the settlement, NSP-Wisconsin agreed to perform the remediation of the Phase I Project Area, but does not admit any liability with respect to the Ashland site. Fieldwork to address the Phase I Project Area at the Ashland site began at the end of 2012 and continues. Demolition activities occurred at the Ashland site in 2013. Soil, including excavation and treatment, as well as containment wall remedies were completed in early 2015. In fall 2015, the ground water remedy was initiated at the site with the installation of groundwater wells and the start of construction on the groundwater treatment plant. The final design for the Phase I remedy was approved by the EPA in September 2015. The current cost estimate for the cleanup of the Phase I Project Area is approximately $57 million , of which approximately $39 million has already been spent. The settlement also resolves claims by the federal, state and tribal trustees against NSP-Wisconsin for alleged natural resource damages at the Ashland site, including both the Phase I Project Area and the Sediments. Negotiations are ongoing between the EPA and NSP-Wisconsin regarding who will pay for or perform the cleanup of the Sediments and what remedy will be implemented at the site to address the Sediments. It is NSP-Wisconsin’s view that the Hybrid Remedy is not safe or feasible to implement. The EPA’s ROD for the Ashland site includes estimates that the cost of the Hybrid Remedy is between $63 million and $77 million , with a potential deviation in such estimated costs of up to 50 percent higher to 30 percent lower. In November 2013, NSP-Wisconsin submitted a revised Wet Dredge pilot study work plan proposal to the EPA. In May 2014, NSP-Wisconsin entered into a final administrative order on consent (AOC) for the Wet Dredge pilot study with the EPA. In early 2015, NSP-Wisconsin entered into an AOC to construct a breakwater at the site to serve as wave attenuation and containment for a wet dredge pilot study and full scale sediment remedy at the site. Construction of the breakwater is underway with anticipated completion in early 2016. A wet dredge pilot study is anticipated to commence in summer 2016. In August 2012, NSP-Wisconsin also filed litigation against other PRPs for their share of the cleanup costs for the Ashland site. A final settlement has been reached between NSP-Wisconsin, along with the EPA, and two of the PRPs, Wisconsin Central Ltd. and Soo Line Railroad Co. (collectively, the “Railroad PRPs”) resolving claims relating to the Railroad PRPs’ share of the costs of cleanup at the Ashland site. NSP-Wisconsin also entered into a second private party settlement agreement with LE Myers Co. Under the agreements, the Railroad PRPs contributed $10.5 million and LE Myers Co. contributed $5.4 million to the costs of the cleanup at the Ashland site. The agreements for the Railroad PRPs and LE Myers Co. were approved by the U.S. District Court for the Western District of Wisconsin in 2015 and payment has been received. As discussed below, existing PSCW policy requires that any payments received from PRPs be used to reduce the amount of the cleanup costs ultimately recovered from customers. Trial with the remaining PRPs for this matter, County of Ashland and City of Ashland, took place in May 2015. In September 2015, the Court ruled that the County of Ashland is not a liable party and the City of Ashland, although a liable party, is not required to contribute any funds to the cleanup of the site. NSP-Wisconsin filed a notice of appeal with the Seventh Circuit Court of Appeals in October 2015. At Sept. 30, 2015 and Dec. 31, 2014, NSP-Wisconsin had recorded a liability of $95.7 million and $107.6 million , respectively, for the Ashland site based upon potential remediation and design costs together with estimated outside legal and consultant costs; of which $16.6 million and $28.9 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 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 NSP-Wisconsin rate recovery for all remediation costs incurred at the Ashland site, and has authorized recovery of MGP remediation costs by other Wisconsin utilities. Under the established PSCW policy, once deferred MGP remediation costs are determined by the PSCW to be prudent, utilities are allowed to recover those deferred costs in natural gas rates, typically over a four - to six -year amortization period. The PSCW historically has not allowed utilities to recover their carrying costs on unamortized regulatory assets for MGP remediation. The PSCW reviewed the existing MGP cost recovery policy as it applied to the Ashland site in the context of NSP-Wisconsin’s 2013 general rate case. In December 2012, 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 a 2014 rate case decision, the PSCW continued the cost recovery treatment with respect to the 2013 and 2014 cleanup costs for the Phase I Project Area and allowed NSP-Wisconsin to increase its 2014 amortization expense related to the cleanup by an additional $1.1 million to offset the need for a rate decrease for the natural gas utility. Cost recovery will continue at the level set in the 2014 rate case through 2015. In May 2015, NSP-Wisconsin filed its 2016 rate case, in which it requested an increase to the annual recovery for MGP clean-up costs from $4.7 million to $7.6 million . A decision is anticipated in December 2015. Fargo, N.D. MGP Site — In May 2015, in connection with a city water main replacement and street improvement project in Fargo, N.D., underground pipes, tars and impacted soils, which may be related to a former MGP site operated by NSP-Minnesota or a prior company, were discovered. After initial reports and discussions with the City of Fargo and the North Dakota Department of Health, NSP-Minnesota removed the impacted soils and other materials from the project area. NSP-Minnesota is undertaking further investigation of the location of the historic MGP site and nearby properties. At this time, NSP-Minnesota’s investigation of the site is considered preliminary as information is still being gathered. As of Sept. 30, 2015, NSP-Minnesota had recorded a liability of $1.4 million related to further investigation and additional planned activities. Uncertainties include the nature and cost of the additional remediation efforts that may be necessary, the ability to recover costs from insurance carriers and the potential for contributions from entities that may be identified as PRPs. Therefore, the total cost of remediation, NSP-Minnesota’s potential liability and amounts allocable to the North Dakota and Minnesota jurisdictions related to the site cannot currently be reasonably estimated. In July 2015, NSP-Minnesota filed a request with the North Dakota Public Service Commission (NDPSC) for approval to initially defer the portion of investigation and response costs allocable to the North Dakota jurisdiction. Environmental Requirements Water Federal Clean Water Act (CWA) Effluent Limitations Guidelines (ELG) — In September 2015, the EPA issued a final 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. Xcel Energy is currently reviewing the final rule and cannot predict, at this time, whether the costs of compliance with the final rule will have a material impact on the results of operations, financial position or cash flows. Xcel Energy believes that compliance costs would be recoverable through regulatory mechanisms. Federal CWA Waters of the United States Rule — In June 2015, the EPA and the U.S. Army Corps of Engineers published a final rule that significantly expands the types of water bodies regulated under the CWA and broadens the scope of waters subject to federal jurisdiction. The expansion of the term “Waters of the U.S.” will subject more utility projects to federal CWA jurisdiction, thereby potentially delaying the siting of new generation projects, pipelines, transmission lines and distribution lines, as well as increasing project costs and expanding permitting and reporting requirements. The rule went into effect in August 2015. On Oct. 9, 2015, the U.S. Court of Appeals for the Sixth Circuit issued a nationwide stay of the final rule, pending further legal proceedings. Air Green House Gas (GHG) Emission Standard for Existing Sources — In June 2014, the EPA published its proposed rule on GHG emission standards for existing power plants. A final rule was published in October 2015. States must develop implementation plans by September 2016, with the possibility of an extension to September 2018. If a state decides not to submit a plan, the EPA will prepare a federal plan for the state. In addition, the EPA published a proposed model federal plan and will provide a 90 -day public comment period on the federal plan once it has been published in the Federal Register. Among other things, the rule requires that state plans include enforceable measures to ensure emissions from existing power plants in the state achieve the EPA’s state-specific interim (2022-2029) and final (2030 and thereafter) emission performance targets. The plan will likely require additional emission reductions in states in which Xcel Energy operates. Until Xcel Energy has reviewed the final rule and has more information about state implementation plans (SIPs), Xcel Energy cannot predict whether the costs of compliance with the final rule will have a material impact on the results of operations, financial position or cash flows. Xcel Energy believes that compliance costs will be recoverable through regulatory mechanisms. GHG New Source Performance Standard (NSPS) Proposal — In January 2014, the EPA re-proposed a GHG NSPS for newly constructed power plants which would set performance standards (maximum carbon dioxide emission rates) for coal- and natural gas-fired power plants. For coal power plants, the NSPS requires an emissions level equivalent to partial carbon capture and storage (CCS) technology; for natural gas-fired power plants, the NSPS reflects emissions levels from combined cycle technology with no CCS. The NSPS does 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. The final rule was published in October 2015. Xcel Energy does not anticipate the costs of compliance with the final rule will have a material impact on the results of operations, financial position or cash flows. GHG NSPS for Modified and Reconstructed Power Plants — In June 2014, the EPA published a proposed NSPS that would apply to GHG emissions from power plants that are modified or reconstructed. A final rule was published in October 2015. A modification is a change to an existing source that increases the maximum achievable hourly rate of emissions. A reconstruction involves the replacement of components at a unit to the extent that the capital cost of the new components exceeds 50 percent of the capital cost of an entirely new comparable unit. The standards do not require installation of CCS technology. Instead, the standard for coal-fired power plants requires a combination of best operating practices and equipment upgrades. The standards for natural gas-fired power plants require emissions standards based on efficient combined cycle technology. These requirements would only apply if Xcel Energy were to modify or reconstruct an existing power plant in the future in a way that triggers applicability of this rule. Cross-State Air Pollution Rule (CSAPR) — CSAPR addresses long range transport of particulate matter (PM) and ozone by requiring reductions in sulfur dioxide (SO 2 ) and nitrous oxide (NOx) from utilities in the eastern half of the United States using an emissions trading program. For Xcel Energy, the rule applies in Minnesota, Wisconsin and Texas. In August 2012, the D.C. Circuit vacated the CSAPR and remanded it back to the EPA. The D.C. Circuit stated the EPA must continue administering the Clean Air Interstate Rule (CAIR) pending adoption of a valid replacement. In April 2014, the U.S. Supreme Court reversed and remanded the case to the D.C. Circuit. The Supreme Court held that the EPA’s rule design did not violate the Clean Air Act (CAA) and that states had received adequate opportunity to develop their own plans. Because the D.C. Circuit overturned the CSAPR on two over-arching issues, there are many other issues the D.C. Circuit did not rule on that were considered on remand. In July 2015, the D.C. Circuit issued an opinion which found the reduction budgets exceed what is necessary for Texas to reduce its impact on downwind states that do not meet ambient air quality standards. The D.C. Circuit remanded the matter to the EPA to reconsider the emission budgets. While the EPA reconsiders emission budgets, the D.C. Circuit left CSAPR in effect. In October 2014, the D.C. Circuit granted the EPA’s request to begin to implement CSAPR by imposing its 2012 compliance obligations starting in January 2015. While the litigation continues, the EPA is administering the CSAPR in 2015. Multiple changes to the SPS system since 2011 will substantially reduce estimated costs of complying with the CSAPR. These include the addition of 700 MW of wind power, the construction of Jones Units 3 and 4, reduced wholesale load, new PPAs, installation of NOx combustion controls on Tolk Units 1 and 2 and completion of certain transmission projects. As a result, SPS estimates compliance with the CSAPR in 2015 will not have a material impact on the results of operations, financial position or cash flows. NSP-Minnesota can operate within its CSAPR emission allowance allocations. NSP-Wisconsin can operate within its CSAPR emission allowance allocation for SO 2 . NSP-Wisconsin is complying with the CSAPR for NOx in 2015 through operational changes or allowance purchases. CSAPR compliance in 2015 is not having a material impact on the results of operations, financial position or cash flows. Electric Generating Unit (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. In 2014, the U.S. Supreme Court decided to review the D.C. Circuit’s decision that upheld the MATS standard. By April 2015, the MATS compliance deadline, Xcel Energy had met the EGU MATS rule through a combination of emission control projects and controls required by other programs preceding MATS, such as regional haze and state mercury regulations. Xcel Energy also retired two coal units at the Black Dog plant and ceased use of coal at Bay Front Unit 5. In addition, mercury controls were installed in SPS’ Tolk and Harrington plants for a capital cost of $8 million . In June 2015, the U.S. Supreme Court found that the EPA acted unreasonably by not considering the cost to regulate mercury and other hazardous air pollutants. The D.C. Circuit, on remand, will decide whether to leave MATS in effect while the EPA considers such costs in making a new determination. Xcel Energy believes EGU MATS costs will be recoverable through regulatory mechanisms and does not anticipate a material impact on the results of operations, financial position or cash flows. Industrial Boiler (IB) Maximum Achievable Control Technology (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 project to meet the requirements was completed in September 2015 with an estimated cost of approximately $20 million . Regional Haze Rules — The regional haze program is designed to address widespread haze that results from emissions from a multitude of sources. In 2005, the EPA amended the best available retrofit technology (BART) requirements of its regional haze rules, which require the installation and operation of emission controls for industrial facilities emitting air pollutants that reduce visibility in 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 SO 2 , 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 Clean Air Clean Jobs Act (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 Hayden Unit 1 and Hayden Unit 2 will be placed into service in late 2015 and late 2016, respectively, at an estimated combined cost of $82.4 million . PSCo anticipates these costs will be fully recoverable through regulatory mechanisms. In March 2013, WildEarth Guardians petitioned the U.S. Court of Appeals for the 10 th Circuit to review the EPA’s decision approving the Colorado SIP. WildEarth Guardians has challenged the BART determination made for Comanche Units 1 and 2. In comments before the EPA, WildEarth Guardians urged that current emission limitations be made more stringent or that selective catalytic reduction (SCR) be added to the units. In September 2014, the EPA filed a request with the Court to remand the case to the EPA for additional explanation of the EPA’s decision approving the BART determination for Comanche Units 1 and 2. In October 2014, the Court granted the EPA’s request and vacated the current briefing schedule. In May 2015, the EPA published its final rule which re-affirmed the approval of the State of Colorado’s BART determination for Comanche Units 1 and 2. The determination found that the controls currently installed on the units for NOx are BART. In July 2015, WildEarth Guardians filed a petition for review of the EPA’s May 2015 final rule. In September 2015, in response to a motion filed by WildEarth Guardians and the EPA, the 10 th Circuit issued an order dismissing the case. In 2010, two environmental groups petitioned the U.S. Department of the Interior (DOI) to certify that 12 coal-fired boilers and one coal-fired cement kiln in Colorado are contributing to visibility problems in Rocky Mountain National Park. The following PSCo plants are named in the petition: Cherokee, Hayden, Pawnee and Valmont. The groups allege the Colorado BART rule is inadequate to satisfy the CAA mandate of ensuring reasonable further progress towards restoring natural visibility conditions in the park. It is not known when the DOI will rule on the petition. NSP-Minnesota In 2009, the Minnesota Pollution Control Agency (MPCA) approved a SIP (the Minnesota SIP) and submitted it to the EPA for approval. The MPCA’s source-specific BART limits for Sherco Units 1 and 2 require combustion controls for NOx and scrubber upgrades for SO 2 . 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 were installed first and the scrubber upgrades were completed in December 2014, at a cost of $46.9 million . NSP-Minnesota anticipates these costs will be fully recoverable in rates. 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 (Eighth Circuit). NSP-Minnesota and other regulated parties were denied intervention. In June 2013, the Eighth Circuit ordered this case to be held in abeyance until the U.S. Supreme Court decided the CSAPR case. In October 2014, the Eighth Circuit set a briefing schedule that was completed in February 2015. The Eighth Circuit heard arguments in September 2015 and a decision is anticipated in early 2016. If this litigation ultimately results in further EPA proceedings concerning the Minnesota SIP, such proceedings may consider whether SCRs should be required for Sherco Units 1 and 2. SPS Harrington Units 1 and 2 are potentially subject to BART. Texas developed a SIP (the Texas SIP) that finds the CAIR equal to BART for EGUs. As a result, no additional controls beyond CAIR compliance would be required. In May 2012, the EPA deferred its review of the Texas SIP in its final rule allowing states to find that CSAPR compliance meets BART requirements for EGUs. In December 2014, the EPA proposed to approve the BART portion of the Texas SIP, with the exception that the EPA would substitute CSAPR compliance for Texas’ reliance on CAIR. The EPA has indicated that it expects to issue its final rule in December 2015. In May 2014, the EPA issued a request for information under the CAA related to SO 2 control equipment at Tolk Units 1 and 2. In December 2014, the EPA proposed to disapprove the reasonable progress portions of the Texas SIP and instead adopt a Federal Implementation Plan. The EPA proposed to require dry scrubbers on both Tolk units to reduce SO 2 emissions to help achieve reasonable progress goals for Texas and Oklahoma national parks and wilderness areas. As proposed, the dry scrubbers would need to be installed and operating within five years of the EPA’s final action, currently expected in December 2015. Whether dry scrubbers are required is dependent on the EPA’s final decision. If required, they would cost approximately $600 million , with an annual operating cost of approximately $10.4 million . Xcel Energy believes these costs would be recoverable through regulatory mechanisms and therefore does not expect a material impact on results of operations, financial position or cash flows. Reasonably Attributable Visibility Impairment (RAVI) — RAVI is intended to address observable impairment from a specific source such as distinct, identifiable plumes from a source’s stack to a national park. In 2009, the DOI certified that a portion of the visibility impairment in Voyageurs and Isle Royale National Parks is reasonably attributable to emissions from NSP-Minnesota’s Sherco Units 1 and 2. The EPA is required to determine whether there is RAVI-type impairment in these parks and identify the potential source of the impairment. If the EPA finds that Sherco Units 1 and 2 cause or contribute to RAVI in the national parks, the EPA would then evaluate whether the level of controls required by the MPCA is appropriate. The EPA has stated it plans to issue a separate notice on the issue of BART for Sherco Units 1 and 2 under the RAVI program. In December 2012, a lawsuit against the EPA was filed in the U.S. District Court for the District of Minnesota (Minnesota District Court) by the following organizations: National Parks Conservation Association, Minnesota Center for Environmental Advocacy, Friends of the Boundary Waters Wilderness, Voyageurs National Park Association, Fresh Energy and Sierra Club. The lawsuit alleges the EPA has failed to perform a nondiscretionary duty to determine BART for Sherco Units 1 and 2 under the RAVI program. The EPA filed an answer denying the allegations. The District Court denied NSP-Minnesota’s motion to intervene in July 2013. NSP-Minnesota appealed this decision to the Eighth Circuit, which on July 23, 2014, reversed the District Court and found that NSP-Minnesota has standing and a right to intervene. In May 2015, NSP-Minnesota, the EPA and the six environmental advocacy organizations filed a settlement agreement in the Minnesota District Court. The agreement anticipates a federal rulemaking that would impose stricter SO 2 emission limits on Sherco Units 1, 2 and 3, without making a RAVI attribution finding or a RAVI BART determination. The emission limits for Units 1 and 2 reflect the success of a recently completed control project. The Unit 3 emission limits will be met through changes in the operation of the existing scrubber. The Minnesota District Court issued an order staying the litigation for the time needed to complete the actions required by the settlement agreement. The plaintiffs agreed to withdraw their complaint with prejudice when those actions are completed. Plaintiffs also agreed not to request a RAVI certification for Sherco Units 1, 2 and/or 3 in the future. As required by the CAA, the EPA published notice of the proposed settlement in the Federal Register. The EPA reviewed the public comments in July 2015 and notified the Minnesota District Court that the settlement agreement is final. The EPA has seven months to recommend and adopt a rule which will set the agreed-upon SO 2 emissions. In October 2015, the EPA proposed a rule that would set the agreed-upon SO 2 emission limits, which public comments due in Nov |
Borrowings and Other Financing
Borrowings and Other Financing Instruments | 9 Months Ended |
Sep. 30, 2015 | |
Debt Disclosure [Abstract] | |
Borrowings and Other Financing Instruments | Borrowings and Other Financing Instruments Short-Term Borrowings Money Pool — Xcel Energy Inc. and its utility subsidiaries have established a money pool arrangement that allows for short-term investments in and borrowings between the utility subsidiaries. NSP-Wisconsin does not participate in the money pool. Xcel Energy Inc. may make investments in the utility subsidiaries at market-based interest rates; however, the money pool arrangement does not allow the utility subsidiaries to make investments in Xcel Energy Inc. The money pool balances are eliminated in consolidation. Commercial Paper — Xcel Energy Inc. and its utility subsidiaries meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under their credit facilities. Commercial paper outstanding for Xcel Energy was as follows: (Amounts in Millions, Except Interest Rates) Three Months Ended Twelve Months Ended Borrowing limit $ 2,750 $ 2,750 Amount outstanding at period end 64 1,020 Average amount outstanding 272 841 Maximum amount outstanding 478 1,200 Weighted average interest rate, computed on a daily basis 0.46 % 0.33 % Weighted average interest rate at period end 0.38 0.56 Letters of Credit — Xcel Energy Inc. and its subsidiaries use letters of credit, generally with terms of one year , to provide financial guarantees for certain operating obligations. At Sept. 30, 2015 and Dec. 31, 2014 , there were $39 million and $61 million , respectively, of letters of credit outstanding under the credit facilities. The contract amounts of these letters of credit approximate their fair value and are subject to fees. Credit Facilities — In order to use their commercial paper programs to fulfill short-term funding needs, Xcel Energy Inc. and its utility subsidiaries must have revolving credit facilities in place at least equal to the amount of their respective commercial paper borrowing limits and cannot issue commercial paper in an aggregate amount exceeding available capacity under these credit facilities. The lines of credit provide short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings. At Sept. 30, 2015 , Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available: (Millions of Dollars) Credit Facility (a) Drawn (b) Available Xcel Energy Inc. $ 1,000 $ 64 $ 936 PSCo 700 5 695 NSP-Minnesota 500 24 476 SPS 400 10 390 NSP-Wisconsin 150 — 150 Total $ 2,750 $ 103 $ 2,647 (a) These credit facilities expire in October 2019. (b) Includes outstanding commercial paper and letters of credit. All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the respective credit facilities. Xcel Energy Inc. and its subsidiaries had no direct advances on the credit facilities outstanding at Sept. 30, 2015 and Dec. 31, 2014 . Long-Term Borrowings During the nine months ended Sept. 30, 2015, Xcel Energy Inc. and its utility subsidiaries completed the following bond issuances: • In May, PSCo issued $250 million of 2.9 percent first mortgage bonds due May 15, 2025; • In June, Xcel Energy Inc. issued $250 million of 1.2 percent senior notes due June 1, 2017 and $250 million of 3.3 percent senior notes due June 1, 2025; • In June, NSP-Wisconsin issued $100 million of 3.3 percent first mortgage bonds due June 15, 2024; • In August, NSP-Minnesota issued $300 million of 2.2 percent first mortgage bonds due Aug. 15, 2020 and $300 million of 4.0 percent first mortgage bonds due Aug. 15, 2045; and • In September, SPS issued $200 million of 3.3 percent first mortgage bonds due June 15, 2024. |
Fair Value of Financial Assets
Fair Value of Financial Assets and Liabilities | 9 Months Ended |
Sep. 30, 2015 | |
Fair Value Disclosures [Abstract] | |
Fair Value of Financial Assets and Liabilities | Fair Value of Financial Assets and Liabilities Fair Value Measurements The accounting guidance for fair value measurements and disclosures provides a single definition of fair value and requires certain disclosures about assets and liabilities measured at fair value. A hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value is established by this guidance. The three levels in the hierarchy are as follows: Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices. Level 2 — Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reporting date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, or priced with models using highly observable inputs. Level 3 — Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 are those valued with models requiring significant management judgment or estimation. Specific valuation methods include the following: Cash equivalents — The fair values of cash equivalents are generally based on cost plus accrued interest; money market funds are measured using quoted net asset values. Investments in equity securities and other funds — Equity securities are valued using quoted prices in active markets. The fair values for commingled funds, international equity funds, private equity investments and real estate investments are measured using net asset values, which take into consideration the value of underlying fund investments, as well as the other accrued assets and liabilities of a fund, in order to determine a per-share market value. The investments in commingled funds and international equity funds may be redeemed for net asset value with proper notice. Proper notice varies by fund and can range from daily with one or two days notice to annually with 90 days notice. Private equity investments require approval of the fund for any unscheduled redemption, and such redemptions may be approved or denied by the fund at its sole discretion. Unscheduled distributions from real estate investments may be redeemed with proper notice, which is typically quarterly with 45 - 90 days notice; however, withdrawals from real estate investments may be delayed or discounted as a result of fund illiquidity. Based on Xcel Energy’s evaluation of its redemption rights, fair value measurements for private equity and real estate investments have been assigned a Level 3. Investments in debt securities — Fair values for debt securities are determined by a third party pricing service using recent trades and observable spreads from benchmark interest rates for similar securities. Interest rate derivatives — The fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts. Commodity derivatives — The methods used to measure the fair value of commodity derivative forwards and options utilize forward prices and volatilities, as well as pricing adjustments for specific delivery locations, and are generally assigned a Level 2. When contractual settlements extend to periods beyond those readily observable on active exchanges or quoted by brokers, the significance of the use of less observable forecasts of long-term forward prices and volatilities on a valuation is evaluated, and may result in Level 3 classification. Electric commodity derivatives held by NSP-Minnesota include transmission congestion instruments purchased from MISO, PJM Interconnection, LLC, Electric Reliability Council of Texas, SPP and New York Independent System Operator, generally referred to as financial transmission rights (FTRs). Electric commodity derivatives held by SPS include FTRs purchased from SPP. FTRs purchased from a RTO are financial instruments that entitle or obligate the holder to monthly revenues or charges based on transmission congestion across a given transmission path. The value of an FTR is derived from, and designed to offset, the cost of energy congestion, which is caused by overall transmission load and other transmission constraints. In addition to overall transmission load, congestion is also influenced by the operating schedules of power plants and the consumption of electricity pertinent to a given transmission path. Unplanned plant outages, scheduled plant maintenance, changes in the relative costs of fuels used in generation, weather and overall changes in demand for electricity can each impact the operating schedules of the power plants on the transmission grid and the value of an FTR. The valuation process for FTRs utilizes complex iterative modeling to predict the impacts of forecasted changes in these drivers of transmission system congestion on the historical pricing of FTR purchases. If forecasted costs of electric transmission congestion increase or decrease for a given FTR path, the value of that particular FTR instrument will likewise increase or decrease. Given the limited observability of management’s forecasts for several of the inputs to this complex valuation model – including expected plant operating schedules and retail and wholesale demand, fair value measurements for FTRs have been assigned a Level 3. Non-trading monthly FTR settlements are included in the fuel and purchased energy cost recovery mechanisms as applicable in each jurisdiction, and therefore changes in the fair value of the yet to be settled portions of most FTRs are deferred as a regulatory asset or liability. Given this regulatory treatment and the limited magnitude of FTRs relative to the electric utility operations of NSP-Minnesota and SPS, the numerous unobservable quantitative inputs to the complex model used for valuation of FTRs are insignificant to the consolidated financial statements of Xcel Energy. Non-Derivative Instruments Fair Value Measurements The NRC requires NSP-Minnesota to maintain a portfolio of investments to fund the costs of decommissioning its nuclear generating plants. Together with all accumulated earnings or losses, the assets of the nuclear decommissioning fund are legally restricted for the purpose of decommissioning the Monticello and Prairie Island (PI) nuclear generating plants. The fund contains cash equivalents, debt securities, equity securities and other investments – all classified as available-for-sale. NSP-Minnesota plans to reinvest matured securities until decommissioning begins. NSP-Minnesota uses the MPUC approved asset allocation for the escrow and investment targets by asset class for both the escrow and qualified trust. NSP-Minnesota recognizes the costs of funding the decommissioning of its nuclear generating plants over the lives of the plants, assuming rate recovery of all costs. Given the purpose and legal restrictions on the use of nuclear decommissioning fund assets, realized and unrealized gains on fund investments over the life of the fund are deferred as an offset of NSP-Minnesota’s regulatory asset for nuclear decommissioning costs. Consequently, any realized and unrealized gains and losses on securities in the nuclear decommissioning fund, including any other-than-temporary impairments, are deferred as a component of the regulatory asset for nuclear decommissioning. Unrealized gains for the nuclear decommissioning fund were $298.4 million and $312.1 million at Sept. 30, 2015 and Dec. 31, 2014 , respectively, and unrealized losses and amounts recorded as other-than-temporary impairments were $87.3 million and $74.1 million at Sept. 30, 2015 and Dec. 31, 2014 , respectively. The following tables present the cost and fair value of Xcel Energy’s non-derivative instruments with recurring fair value measurements in the nuclear decommissioning fund at Sept. 30, 2015 and Dec. 31, 2014 : Sept. 30, 2015 Fair Value (Thousands of Dollars) Cost Level 1 Level 2 Level 3 Total Nuclear decommissioning fund (a) Cash equivalents $ 33,681 $ 33,681 $ — $ — $ 33,681 Commingled funds 351,676 — 381,230 — 381,230 International equity funds 217,003 — 188,853 — 188,853 Private equity investments 98,133 — — 145,695 145,695 Real estate 49,151 — — 71,976 71,976 Debt securities: Government securities 24,557 — 21,423 — 21,423 U.S. corporate bonds 70,311 — 61,874 — 61,874 International corporate bonds 14,099 — 13,059 — 13,059 Municipal bonds 210,728 — 215,014 — 215,014 Asset-backed securities 2,834 — 2,836 — 2,836 Mortgage-backed securities 11,734 — 12,077 — 12,077 Equity securities: Common stock 386,176 533,431 — — 533,431 Total $ 1,470,083 $ 567,112 $ 896,366 $ 217,671 $ 1,681,149 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $80.3 million of equity investments in unconsolidated subsidiaries and $46.3 million of miscellaneous investments. Dec. 31, 2014 Fair Value (Thousands of Dollars) Cost Level 1 Level 2 Level 3 Total Nuclear decommissioning fund (a) Cash equivalents $ 24,184 $ 24,184 $ — $ — $ 24,184 Commingled funds 470,013 — 465,615 — 465,615 International equity funds 80,454 — 78,721 — 78,721 Private equity investments 73,936 — — 101,237 101,237 Real estate 43,859 — — 64,249 64,249 Debt securities: Government securities 30,674 — 28,808 — 28,808 U.S. corporate bonds 81,463 — 77,562 — 77,562 International corporate bonds 16,950 — 16,341 — 16,341 Municipal bonds 242,282 — 249,201 — 249,201 Asset-backed securities 9,131 — 9,250 — 9,250 Mortgage-backed securities 23,225 — 23,895 — 23,895 Equity securities: Common stock 369,751 564,858 — — 564,858 Total $ 1,465,922 $ 589,042 $ 949,393 $ 165,486 $ 1,703,921 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $83.1 million of equity investments in unconsolidated subsidiaries and $45.6 million of miscellaneous investments. The following tables present the changes in Level 3 nuclear decommissioning fund investments for the three and nine months ended Sept. 30, 2015 and 2014 : (Thousands of Dollars) July 1, 2015 Purchases Settlements Gains Recognized as Regulatory Assets (a) Sept. 30, 2015 Private equity investments $ 133,993 $ 3,066 $ — $ 8,636 $ 145,695 Real estate 70,834 1,501 (1,719 ) 1,360 71,976 Total $ 204,827 $ 4,567 $ (1,719 ) $ 9,996 $ 217,671 (Thousands of Dollars) July 1, 2014 Purchases Settlements Gains Recognized as Regulatory Asset (a) Sept. 30, 2014 Private equity investments $ 81,123 $ 11,125 $ — $ 4,756 $ 97,004 Real estate 65,658 1,530 (5,876 ) 2,661 63,973 Total $ 146,781 $ 12,655 $ (5,876 ) $ 7,417 $ 160,977 (Thousands of Dollars) Jan. 1, 2015 Purchases Settlements Gains Recognized as Regulatory Assets (a) Sept. 30, 2015 Private equity investments $ 101,237 $ 24,197 $ — $ 20,261 $ 145,695 Real estate 64,249 9,633 (4,341 ) 2,435 71,976 Total $ 165,486 $ 33,830 $ (4,341 ) $ 22,696 $ 217,671 (Thousands of Dollars) Jan. 1, 2014 Purchases Settlements Gains Recognized as Regulatory Asset (a) Sept. 30, 2014 Private equity investments $ 62,696 $ 22,078 $ — $ 12,230 $ 97,004 Real estate 57,368 5,386 (5,876 ) 7,095 63,973 Total $ 120,064 $ 27,464 $ (5,876 ) $ 19,325 $ 160,977 (a) Gains are deferred as a component of the regulatory assets for nuclear decommissioning. The following table summarizes the final contractual maturity dates of the debt securities in the nuclear decommissioning fund, by asset class, at Sept. 30, 2015 : Final Contractual Maturity (Thousands of Dollars) Due in 1 Year or Less Due in 1 to 5 Years Due in 5 to 10 Years Due after 10 Years Total Government securities $ — $ — $ — $ 21,423 $ 21,423 U.S. corporate bonds — 15,398 51,317 (4,841 ) 61,874 International corporate bonds — 2,976 9,109 974 13,059 Municipal bonds 1,260 27,500 44,594 141,660 215,014 Asset-backed securities — — 2,836 — 2,836 Mortgage-backed securities — — — 12,077 12,077 Debt securities $ 1,260 $ 45,874 $ 107,856 $ 171,293 $ 326,283 Derivative Instruments Fair Value Measurements Xcel Energy enters into derivative instruments, including forward contracts, futures, swaps and options, for trading purposes and to manage risk in connection with changes in interest rates, utility commodity prices and vehicle fuel prices. Interest Rate Derivatives — Xcel Energy enters into various instruments that effectively fix the interest payments on certain floating rate debt obligations or effectively fix the yield or price on a specified benchmark interest rate for an anticipated debt issuance for a specific period. These derivative instruments are generally designated as cash flow hedges for accounting purposes. At Sept. 30, 2015 , accumulated other comprehensive losses related to interest rate derivatives included $3.7 million of net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings, including forecasted amounts for any unsettled hedges, as applicable. Wholesale and Commodity Trading Risk — Xcel Energy Inc.’s utility subsidiaries conduct various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy and energy-related instruments. Xcel Energy’s risk management policy allows management to conduct these activities within guidelines and limitations as approved by its risk management committee, which is made up of management personnel not directly involved in the activities governed by this policy. Commodity Derivatives — Xcel Energy enters into derivative instruments to manage variability of future cash flows from changes in commodity prices in its electric and natural gas operations, as well as for trading purposes. This could include the purchase or sale of energy or energy-related products, natural gas to generate electric energy, natural gas for resale, FTRs, vehicle fuel and weather derivatives. At Sept. 30, 2015 , Xcel Energy had various vehicle fuel contracts designated as cash flow hedges extending through December 2016. Xcel Energy also enters into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers but are not designated as qualifying hedging transactions. Changes in the fair value of non-trading commodity derivative instruments are recorded in other comprehensive income or deferred as a regulatory asset or liability. The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. Xcel Energy recorded immaterial amounts to income related to the ineffectiveness of cash flow hedges for the three and nine months ended Sept. 30, 2015 and 2014 . At Sept. 30, 2015 , net losses related to commodity derivative cash flow hedges recorded as a component of accumulated other comprehensive losses included $0.1 million of net losses expected to be reclassified into earnings during the next 12 months as the hedged transactions occur. Additionally, Xcel Energy enters into commodity derivative instruments for trading purposes not directly related to commodity price risks associated with serving its electric and natural gas customers. Changes in the fair value of these commodity derivatives are recorded in electric operating revenues, net of amounts credited to customers under margin-sharing mechanisms. The following table details the gross notional amounts of commodity forwards, options and FTRs at Sept. 30, 2015 and Dec. 31, 2014 : (Amounts in Thousands) (a)(b) Sept. 30, 2015 Dec. 31, 2014 Megawatt hours of electricity 76,323 56,361 Million British thermal units of natural gas 13,709 927 Gallons of vehicle fuel 176 282 (a) Amounts are not reflective of net positions in the underlying commodities. (b) Notional amounts for options are included on a gross basis, but are weighted for the probability of exercise. The following tables detail the impact of derivative activity during the three and nine months ended Sept. 30, 2015 and 2014, on accumulated other comprehensive loss, regulatory assets and liabilities, and income: Three Months Ended Sept. 30, 2015 Pre-Tax Fair Value Gains (Losses) Recognized During the Period in: Pre-Tax (Gains) Losses Reclassified into Income During the Period from: Pre-Tax Losses Recognized (Thousands of Dollars) Accumulated Other Regulatory Accumulated Other Regulatory Assets and (Liabilities) Derivatives designated as cash flow hedges Interest rate $ — $ — $ 1,118 (a) $ — $ — Vehicle fuel and other commodity (70 ) — 34 (b) — — Total $ (70 ) $ — $ 1,152 $ — $ — Other derivative instruments Commodity trading $ — $ — $ — $ — $ (3,460 ) (c) Electric commodity — (2,403 ) — 2,860 (d) — Natural gas commodity — (2,978 ) — — (405 ) (e) Total $ — $ (5,381 ) $ — $ 2,860 $ (3,865 ) Nine Months Ended Sept. 30, 2015 Pre-Tax Fair Value Gains (Losses) Recognized During the Period in: Pre-Tax (Gains) Losses Reclassified into Income During the Period from: Pre-Tax Losses Recognized (Thousands of Dollars) Accumulated Other Regulatory Accumulated Other Regulatory Assets and (Liabilities) Derivatives designated as cash flow hedges Interest rate $ — $ — $ 3,013 (a) $ — $ — Vehicle fuel and other commodity (59 ) — 88 (b) — — Total $ (59 ) $ — $ 3,101 $ — $ — Other derivative instruments Commodity trading $ — $ — $ — $ — $ (5,896 ) (c) Electric commodity — (16,611 ) — 16,020 (d) — Natural gas commodity — (3,366 ) — 8,685 (e) (9,455 ) (e) Total $ — $ (19,977 ) $ — $ 24,705 $ (15,351 ) Three Months Ended Sept. 30, 2014 Pre-Tax Fair Value Gains (Losses) Recognized During the Period in: Pre-Tax (Gains) Losses Reclassified into Income During the Period from: Pre-Tax Gains (Losses) Recognized (Thousands of Dollars) Accumulated Other Regulatory Accumulated Other Regulatory Assets and (Liabilities) Derivatives designated as cash flow hedges Interest rate $ — $ — $ 967 (a) $ — $ — Vehicle fuel and other commodity (69 ) — (16 ) (b) — — Total $ (69 ) $ — $ 951 $ — $ — Other derivative instruments Commodity trading $ — $ — $ — $ — $ (1,656 ) (c) Electric commodity — (3,391 ) — 6,629 (d) — Natural gas commodity — (2,455 ) — — (209 ) (d) Total $ — $ (5,846 ) $ — $ 6,629 $ (1,865 ) Nine Months Ended Sept. 30, 2014 Pre-Tax Fair Value Gains (Losses) Recognized During the Period in: Pre-Tax (Gains) Losses Reclassified into Income During the Period from: Pre-Tax Gains (Losses) Recognized (Thousands of Dollars) Accumulated Other Regulatory Accumulated Other Regulatory Derivatives designated as cash flow hedges Interest rate $ — $ — $ 2,869 (a) $ — $ — Vehicle fuel and other commodity (56 ) — (61 ) (b) — — Total $ (56 ) $ — $ 2,808 $ — $ — Other derivative instruments Commodity trading $ — $ — $ — $ — $ 1,266 (c) Electric commodity — (17,240 ) — (18,641 ) (d) — Natural gas commodity — 13,603 — (18,840 ) (e) (5,575 ) (e) Other commodity — — — — 643 (c) Total $ — $ (3,637 ) $ — $ (37,481 ) $ (3,666 ) (a) Amounts are recorded to interest charges. (b) Amounts are recorded to O&M expenses. (c) Amounts are recorded to electric operating revenues. Portions of these gains and losses are subject to sharing with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate. (d) Amounts are recorded to electric fuel and purchased power. These derivative settlement gain and loss amounts are shared with electric customers through fuel and purchased energy cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate. (e) Amounts for the three and nine months ended Sept. 30, 2015 included $0.4 million and $0.5 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. Losses for the nine months ended Sept. 30, 2014 included immaterial settlement losses on derivatives entered to mitigate natural gas price risk for electric generation, recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate. The remaining derivative settlement gains and losses for the three and nine months ended Sept. 30, 2015 and nine months ended 2014 relate to natural gas operations and are recorded to cost of natural gas sold and transported. These gains and losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset or liability, as appropriate. Xcel Energy had no derivative instruments designated as fair value hedges during the three and nine months ended Sept. 30, 2015 and 2014 . Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for these periods. Consideration of Credit Risk and Concentrations — Xcel Energy continuously monitors the creditworthiness of the counterparties to its interest rate derivatives and commodity derivative contracts prior to settlement, and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. Given this assessment, as well as an assessment of the impact of Xcel Energy’s own credit risk when determining the fair value of derivative liabilities, the impact of considering credit risk was immaterial to the fair value of unsettled commodity derivatives presented in the consolidated balance sheets. Xcel Energy Inc. and its subsidiaries employ additional credit risk control mechanisms when appropriate, such as letters of credit, parental guarantees, standardized master netting agreements and termination provisions that allow for offsetting of positive and negative exposures. Credit exposure is monitored and, when necessary, the activity with a specific counterparty is limited until credit enhancement is provided. Xcel Energy’s utility subsidiaries’ most significant concentrations of credit risk with particular entities or industries are contracts with counterparties to their wholesale, trading and non-trading commodity and transmission activities. At Sept. 30, 2015 , three of Xcel Energy’s 10 most significant counterparties for these activities, comprising $24.7 million or 10 percent of this credit exposure, had investment grade credit ratings from Standard & Poor’s Ratings Services, Moody’s Investor Services or Fitch Ratings. Five of the 10 most significant counterparties, comprising $61.1 million or 26 percent of this credit exposure, were not rated by these external agencies, but based on Xcel Energy’s internal analysis, had credit quality consistent with investment grade. The remaining two most significant counterparties, comprising $11.5 million or 5 percent of this credit exposure, had credit quality less than investment grade, based on ratings from external and internal analysis. All 10 of these significant counterparties are RTOs, municipal or cooperative electric entities or other utilities. Credit Related Contingent Features — Contract provisions for derivative instruments that the utility subsidiaries enter, including those recorded to the consolidated balance sheet at fair value, as well as those accounted for as normal purchase-normal sale contracts and therefore not reflected on the balance sheet, may require the posting of collateral or settlement of the contracts for various reasons, including if the applicable utility subsidiary is unable to maintain its credit ratings. If the credit ratings of Xcel Energy Inc.’s utility subsidiaries were downgraded below investment grade, derivative instruments reflected in a $8.9 million gross liability position on the consolidated balance sheet at Sept. 30, 2015 would have required Xcel Energy Inc.’s utility subsidiaries to post collateral or settle applicable outstanding contracts, including other contracts subject to master netting agreements, which would have resulted in payments of $0.1 million . At Dec. 31, 2014, there were no derivative instruments in a liability position that would have required the posting of collateral or settlement of applicable outstanding contracts if the credit ratings of Xcel Energy Inc.’s utility subsidiaries were downgraded below investment grade. Certain derivative instruments are also subject to contract provisions that contain adequate assurance clauses. These provisions allow counterparties to seek performance assurance, including cash collateral, in the event that a given utility subsidiary’s ability to fulfill its contractual obligations is reasonably expected to be impaired. Xcel Energy had no collateral posted related to adequate assurance clauses in derivative contracts as of Sept. 30, 2015 and Dec. 31, 2014 . Recurring Fair Value Measurements — The following table presents for each of the fair value hierarchy levels, Xcel Energy’s derivative assets and liabilities measured at fair value on a recurring basis at Sept. 30, 2015 : Sept. 30, 2015 Fair Value Fair Value Total Counterparty Netting (b) Total (Thousands of Dollars) Level 1 Level 2 Level 3 Current derivative assets Other derivative instruments: Commodity trading $ — $ 9,140 $ 4,307 $ 13,447 $ (5,150 ) $ 8,297 Electric commodity — — 34,715 34,715 (6,361 ) 28,354 Natural gas commodity — 3,062 — 3,062 (1,690 ) 1,372 Total current derivative assets $ — $ 12,202 $ 39,022 $ 51,224 $ (13,201 ) 38,023 PPAs (a) 10,087 Current derivative instruments $ 48,110 Noncurrent derivative assets Other derivative instruments: Commodity trading $ — $ 29,523 $ — $ 29,523 $ (7,411 ) $ 22,112 Total noncurrent derivative assets $ — $ 29,523 $ — $ 29,523 $ (7,411 ) 22,112 PPAs (a) 32,631 Noncurrent derivative instruments $ 54,743 Sept. 30, 2015 Fair Value Fair Value Total Counterparty Netting (b) Total (Thousands of Dollars) Level 1 Level 2 Level 3 Current derivative liabilities Derivatives designated as cash flow hedges: Vehicle fuel and other commodity $ — $ 156 $ — $ 156 $ — $ 156 Other derivative instruments: Commodity trading — 6,461 1,478 7,939 (5,592 ) 2,347 Electric commodity — — 6,361 6,361 (6,361 ) — Natural gas commodity — 2,777 — 2,777 (1,690 ) 1,087 Other commodity — 844 — 844 — 844 Total current derivative liabilities $ — $ 10,238 $ 7,839 $ 18,077 $ (13,643 ) 4,434 PPAs (a) 22,869 Current derivative instruments $ 27,303 Noncurrent derivative liabilities Derivatives designated as cash flow hedges: Vehicle fuel and other commodity $ — $ 36 $ — $ 36 $ — $ 36 Other derivative instruments: Commodity trading — 20,789 — 20,789 (11,097 ) 9,692 Other commodity — 18 — 18 — 18 Total noncurrent derivative liabilities $ — $ 20,843 $ — $ 20,843 $ (11,097 ) 9,746 PPAs (a) 163,842 Noncurrent derivative instruments $ 173,588 (a) In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, Xcel Energy began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, Xcel Energy qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities. (b) Xcel Energy nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Sept. 30, 2015 . At Sept. 30, 2015 , derivative assets and liabilities include no obligations to return cash collateral and the rights to reclaim cash collateral of $4.1 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, 2014 : Dec. 31, 2014 Fair Value Fair Value Total Counterparty Netting (b) Total (Thousands of Dollars) Level 1 Level 2 Level 3 Current derivative assets Other derivative instruments: Commodity trading $ — $ 14,326 $ 4,732 $ 19,058 $ (3,240 ) $ 15,818 Electric commodity — — 62,825 62,825 (11,402 ) 51,423 Natural gas commodity — 381 — 381 (22 ) 359 Total current derivative assets $ — $ 14,707 $ 67,557 $ 82,264 $ (14,664 ) 67,600 PPAs (a) 18,123 Current derivative instruments $ 85,723 Noncurrent derivative assets Other derivative instruments: Commodity trading $ — $ 17,617 $ — $ 17,617 $ (4,151 ) $ 13,466 Total noncurrent derivative assets $ — $ 17,617 $ — $ 17,617 $ (4,151 ) 13,466 PPAs (a) 40,309 Noncurrent derivative instruments $ 53,775 Dec. 31, 2014 Fair Value Fair Value Total Counterparty Netting (b) Total (Thousands of Dollars) Level 1 Level 2 Level 3 Current derivative liabilities Derivatives designated as cash flow hedges: Vehicle fuel and other commodity $ — $ 118 $ — $ 118 $ — $ 118 Other derivative instruments: Commodity trading — 7,974 — 7,974 (7,974 ) — Electric commodity — — 11,402 11,402 (11,402 ) — Natural gas commodity — 548 — 548 (21 ) 527 Total current derivative liabilities $ — $ 8,640 $ 11,402 $ 20,042 $ (19,397 ) 645 PPAs (a) 20,987 Current derivative instruments $ 21,632 Noncurrent derivative liabilities Derivatives designated as cash flow hedges: Vehicle fuel and other commodity $ — $ 102 $ — $ 102 $ — $ 102 Other derivative instruments: Commodity trading — 6,890 — 6,890 (6,033 ) 857 Natural gas commodity — 35 — 35 — 35 Total noncurrent derivative liabilities $ — $ 7,027 $ — $ 7,027 $ (6,033 ) 994 PPAs (a) 182,942 Noncurrent derivative instruments $ 183,936 (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, 2014 . At Dec. 31, 2014 , derivative assets and liabilities include no obligations to return cash collateral and rights to reclaim cash collateral of $6.6 million . The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements. The following table presents the changes in Level 3 commodity derivatives for the three and nine months ended Sept. 30, 2015 and 2014 : Three Months Ended Sept. 30 (Thousands of Dollars) 2015 2014 Balance at July 1 $ 46,826 $ 105,394 Purchases 486 5,588 Settlements (20,216 ) (20,032 ) Transfers out of Level 3 — (1,093 ) Net transactions recorded during the period: Gains recognized in earnings (a) 121 1,480 Gains (losses) recognized as regulatory assets and liabilities 3,966 (17,705 ) Balance at Sept. 30 $ 31,183 $ 73,632 Nine Months Ended Sept. 30 (Thousands of Dollars) 2015 2014 Balance at Jan. 1 $ 56,155 $ 41,660 Purchases 63,724 126,752 Settlements (57,462 ) (107,451 ) Transfers out of Level 3 — (1,093 ) Net transactions recorded during the period: Gains recognized in earnings (a) 1,401 8,917 (Losses) gains recognized as regulatory assets and liabilities (32,635 ) 4,847 Balance at Sept. 30 $ 31,183 $ 73,632 (a) These amounts relate to commodity derivatives held at the end of the period. Xcel Energy recognizes transfers between levels as of the beginning of each period. There were no transfers of amounts between levels for derivative instruments for the three |
Other Income (Expense), Net
Other Income (Expense), Net | 9 Months Ended |
Sep. 30, 2015 | |
Other Income and Expenses [Abstract] | |
Other Income (Expense), Net | Other Income, Net Other income, net consisted of the following: Three Months Ended Sept. 30 Nine Months Ended Sept. 30 (Thousands of Dollars) 2015 2014 2015 2014 Interest income $ 312 $ 1,139 $ 4,939 $ 6,324 Other nonoperating income 625 682 2,387 3,042 Insurance policy income (expense) 689 (417 ) (1,578 ) (4,663 ) Other nonoperating expense — — — (16 ) Other income, net $ 1,626 $ 1,404 $ 5,748 $ 4,687 |
Segment Information
Segment Information | 9 Months Ended |
Sep. 30, 2015 | |
Segment Reporting [Abstract] | |
Segment Information | Segment Information The regulated electric utility operating results of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS, as well as the regulated natural gas utility operating results of NSP-Minnesota, NSP-Wisconsin and PSCo are each separately and regularly reviewed by Xcel Energy’s chief operating decision maker. Xcel Energy evaluates performance by each utility subsidiary based on profit or loss generated from the product or service provided. These segments are managed separately because the revenue streams are dependent upon regulated rate recovery, which is separately determined for each segment. Xcel Energy has the following reportable segments: regulated electric utility, regulated natural gas utility and all other. • Xcel Energy’s regulated electric utility segment generates, transmits and distributes electricity primarily in portions of Minnesota, Wisconsin, Michigan, North Dakota, South Dakota, Colorado, Texas and New Mexico. In addition, this segment includes sales for resale and provides wholesale transmission service to various entities in the United States. Regulated electric utility also includes commodity trading operations. • Xcel Energy’s regulated natural gas utility segment transports, stores and distributes natural gas primarily in portions of Minnesota, Wisconsin, North Dakota, Michigan and Colorado. • Revenues from operating segments not included above are below the necessary quantitative thresholds and are therefore included in the all other category. Those primarily include steam revenue, appliance repair services, nonutility real estate activities, revenues associated with processing solid waste into refuse-derived fuel and investments in rental housing projects that qualify for low-income housing tax credits. Xcel Energy had equity investments in unconsolidated subsidiaries of $80.3 million and $83.1 million as of Sept. 30, 2015 and Dec. 31, 2014 , respectively, included in the regulated natural gas utility segment. Asset and capital expenditure information is not provided for Xcel Energy’s reportable segments because as an integrated electric and natural gas utility, Xcel Energy operates significant assets that are not dedicated to a specific business segment, and reporting assets and capital expenditures by business segment would require arbitrary and potentially misleading allocations which may not necessarily reflect the assets that would be required for the operation of the business segments on a stand-alone basis. To report income from operations for regulated electric and regulated natural gas utility segments, the majority of costs are directly assigned to each segment. However, some costs, such as common depreciation, common O&M expenses and interest expense are allocated based on cost causation allocators. A general allocator is used for certain general and administrative expenses, including office supplies, rent, property insurance and general advertising. (Thousands of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total Three Months Ended Sept. 30, 2015 Operating revenues from external customers $ 2,667,480 $ 216,019 $ 17,813 $ — $ 2,901,312 Intersegment revenues 392 293 — (685 ) — Total revenues $ 2,667,872 $ 216,312 $ 17,813 $ (685 ) $ 2,901,312 Net income (loss) $ 437,978 $ (4,176 ) $ (7,339 ) $ — $ 426,463 (Thousands of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total Three Months Ended Sept. 30, 2014 Operating revenues from external customers $ 2,616,351 $ 236,649 $ 16,807 $ — $ 2,869,807 Intersegment revenues 472 597 — (1,069 ) — Total revenues $ 2,616,823 $ 237,246 $ 16,807 $ (1,069 ) $ 2,869,807 Net income $ 360,656 $ 3,996 $ 3,930 $ — $ 368,582 (Thousands of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total Nine Months Ended Sept. 30, 2015 Operating revenues from external customers (a) $ 7,105,803 $ 1,216,146 $ 56,716 $ — $ 8,378,665 Intersegment revenues 1,142 1,141 — (2,283 ) — Total revenues $ 7,106,945 $ 1,217,287 $ 56,716 $ (2,283 ) $ 8,378,665 Net income (loss) $ 733,954 (a) $ 72,617 $ (31,111 ) $ — $ 775,460 (Thousands of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total Nine Months Ended Sept. 30, 2014 Operating revenues from external customers $ 7,215,699 $ 1,485,464 $ 56,344 $ — $ 8,757,507 Intersegment revenues 1,262 4,967 — (6,229 ) — Total revenues $ 7,216,961 $ 1,490,431 $ 56,344 $ (6,229 ) $ 8,757,507 Net income (loss) $ 731,766 $ 96,629 $ (3,428 ) $ — $ 824,967 (a) Includes a net of tax charge related to the Monticello LCM/EPU project. See Note 5. |
Earnings Per Share
Earnings Per Share | 9 Months Ended |
Sep. 30, 2015 | |
Earnings Per Share [Abstract] | |
Earnings Per Share | Earnings Per Share Basic earnings per share (EPS) was computed by dividing the earnings available to Xcel Energy Inc.’s common shareholders by the weighted average number of common shares outstanding during the period. Diluted EPS was computed by dividing the earnings available to Xcel Energy Inc.’s common shareholders by the diluted weighted average number of common shares outstanding during the period. Diluted EPS reflects the potential dilution that could occur if securities or other agreements to issue common stock (i.e., common stock equivalents) were settled. The weighted average number of potentially dilutive shares outstanding used to calculate Xcel Energy Inc.’s diluted EPS is calculated using the treasury stock method. Common Stock Equivalents — Xcel Energy Inc. currently has common stock equivalents related to certain equity awards in share-based compensation arrangements. Common stock equivalents causing dilutive impact to EPS include commitments to issue common stock related to time based equity compensation awards and time based employer matching contributions to certain 401(k) plan participants. Stock equivalent units granted to Xcel Energy Inc.’s Board of Directors are included in common shares outstanding upon grant date as there is no further service, performance or market condition associated with these awards. Restricted stock, granted to settle amounts due to certain employees under the Xcel Energy Inc. Executive Annual Incentive Award Plan, is included in common shares outstanding when granted. Share-based compensation arrangements for which there is currently no dilutive impact to EPS include the following: • Equity awards subject to a performance condition; included in common shares outstanding when all necessary conditions for settlement have been satisfied by the end of the reporting period. • Liability awards subject to a performance condition; any portions settled in shares are included in common shares outstanding upon settlement. The dilutive impact of common stock equivalents affecting EPS was as follows: Three Months Ended Sept. 30, 2015 Three Months Ended Sept. 30, 2014 (Amounts in thousands, except per share data) Income Shares Per Share Amount Income Shares Per Share Amount Net income $ 426,463 — — $ 368,582 — — Basic EPS: Earnings available to common shareholders 426,463 508,031 $ 0.84 368,582 506,082 $ 0.73 Effect of dilutive securities: Time based equity awards — 396 — — 283 — Diluted EPS: Earnings available to common shareholders $ 426,463 508,427 $ 0.84 $ 368,582 506,365 $ 0.73 Nine Months Ended Sept. 30, 2015 Nine Months Ended Sept. 30, 2014 (Amounts in thousands, except per share data) Income Shares Per Share Amount Income Shares Per Share Amount Net income $ 775,460 — $ 824,967 — — Basic EPS: Earnings available to common shareholders 775,460 507,585 $ 1.53 824,967 502,983 $ 1.64 Effect of dilutive securities: Time based equity awards — 391 — — 230 — Diluted EPS: Earnings available to common shareholders $ 775,460 507,976 $ 1.53 $ 824,967 503,213 $ 1.64 |
Benefit Plans and Other Postret
Benefit Plans and Other Postretirement Benefits | 9 Months Ended |
Sep. 30, 2015 | |
Compensation and Retirement Disclosure [Abstract] | |
Benefit Plans and Other Postretirement Benefits | Benefit Plans and Other Postretirement Benefits Components of Net Periodic Benefit Cost (Credit) Three Months Ended Sept. 30 2015 2014 2015 2014 (Thousands of Dollars) Pension Benefits Postretirement Health Service cost $ 24,828 $ 22,086 $ 529 $ 864 Interest cost 37,131 39,155 6,324 8,507 Expected return on plan assets (53,473 ) (51,801 ) (6,650 ) (8,489 ) Amortization of prior service credit (451 ) (437 ) (2,672 ) (2,672 ) Amortization of net loss 31,288 29,191 1,351 2,935 Net periodic benefit cost (credit) 39,323 38,194 (1,118 ) 1,145 Costs not recognized due to the effects of regulation (7,016 ) (6,605 ) — — Net benefit cost (credit) recognized for financial reporting $ 32,307 $ 31,589 $ (1,118 ) $ 1,145 Nine Months Ended Sept. 30 2015 2014 2015 2014 (Thousands of Dollars) Pension Benefits Postretirement Health Service cost $ 74,484 $ 66,257 $ 1,587 $ 2,592 Interest cost 111,393 117,465 18,972 25,521 Expected return on plan assets (160,418 ) (155,403 ) (19,950 ) (25,466 ) Amortization of prior service credit (1,353 ) (1,310 ) (8,015 ) (8,016 ) Amortization of net loss 93,864 87,572 4,053 8,805 Net periodic benefit cost (credit) 117,970 114,581 (3,353 ) 3,436 Costs not recognized due to the effects of regulation (22,035 ) (20,261 ) — — Net benefit cost (credit) recognized for financial reporting $ 95,935 $ 94,320 $ (3,353 ) $ 3,436 In January 2015, contributions of $90.0 million were made across four of Xcel Energy’s pension plans. Xcel Energy does not expect additional pension contributions during 2015. |
Other Comprehensive Income
Other Comprehensive Income | 9 Months Ended |
Sep. 30, 2015 | |
Stockholders' Equity Note [Abstract] | |
Other Comprehensive Income | Other Comprehensive Income Changes in accumulated other comprehensive (loss) income, net of tax, for the three and nine months ended Sept. 30, 2015 and 2014 were as follows: Three Months Ended Sept. 30, 2015 (Thousands of Dollars) Gains and Losses on Cash Flow Hedges Unrealized Gains and Losses on Marketable Securities Defined Benefit Pension and Postretirement Items Total Accumulated other comprehensive (loss) income at July 1 $ (56,436 ) $ 112 $ (48,862 ) $ (105,186 ) Other comprehensive loss before reclassifications (42 ) (1 ) — (43 ) Losses reclassified from net accumulated other comprehensive loss 706 — 884 1,590 Net current period other comprehensive income (loss) 664 (1 ) 884 1,547 Accumulated other comprehensive (loss) income at Sept. 30 $ (55,772 ) $ 111 $ (47,978 ) $ (103,639 ) Three Months Ended Sept. 30, 2014 (Thousands of Dollars) Gains and Losses on Cash Flow Hedges Unrealized Gains and Losses on Marketable Securities Defined Benefit Pension and Total Accumulated other comprehensive (loss) income at July 1 $ (58,610 ) $ 115 $ (44,871 ) $ (103,366 ) Other comprehensive (loss) income before reclassifications (42 ) 2 — (40 ) Losses reclassified from net accumulated other comprehensive loss 558 — 847 1,405 Net current period other comprehensive income 516 2 847 1,365 Accumulated other comprehensive (loss) income at Sept. 30 $ (58,094 ) $ 117 $ (44,024 ) $ (102,001 ) Nine Months Ended Sept. 30, 2015 (Thousands of Dollars) Gains and Losses on Cash Flow Hedges Unrealized Gains and Losses on Marketable Securities Defined Benefit Pension and Postretirement Items Total Accumulated other comprehensive (loss) income at Jan. 1 $ (57,628 ) $ 110 $ (50,621 ) $ (108,139 ) Other comprehensive (loss) income before reclassifications (35 ) 1 — (34 ) Losses reclassified from net accumulated other comprehensive loss 1,891 — 2,643 4,534 Net current period other comprehensive income 1,856 1 2,643 4,500 Accumulated other comprehensive (loss) income at Sept. 30 $ (55,772 ) $ 111 $ (47,978 ) $ (103,639 ) Nine Months Ended Sept. 30, 2014 (Thousands of Dollars) Gains and Losses on Cash Flow Hedges Unrealized Gains and Losses on Marketable Securities Defined Benefit Pension and Postretirement Items Total Accumulated other comprehensive (loss) income at Jan. 1 $ (59,753 ) $ 77 $ (46,599 ) $ (106,275 ) Other comprehensive (loss) income before reclassifications (34 ) 40 — 6 Losses reclassified from net accumulated other comprehensive loss 1,693 — 2,575 4,268 Net current period other comprehensive income 1,659 40 2,575 4,274 Accumulated other comprehensive (loss) income at Sept. 30 $ (58,094 ) $ 117 $ (44,024 ) $ (102,001 ) Reclassifications from accumulated other comprehensive loss for the three and nine months ended Sept. 30, 2015 and 2014 were as follows: Amounts Reclassified from Accumulated Other Comprehensive Loss (Thousands of Dollars) Three Months Ended Sept. 30, 2015 Three Months Ended Sept. 30, 2014 (Gains) losses on cash flow hedges: Interest rate derivatives $ 1,118 (a) $ 967 (a) Vehicle fuel derivatives 34 (b) (16 ) (b) Total, pre-tax 1,152 951 Tax benefit (446 ) (393 ) Total, net of tax 706 558 Defined benefit pension and postretirement (gains) losses: Amortization of net loss 1,532 (c) 1,500 (c) Prior service credit (89 ) (c) (86 ) (c) Total, pre-tax 1,443 1,414 Tax benefit (559 ) (567 ) Total, net of tax 884 847 Total amounts reclassified, net of tax $ 1,590 $ 1,405 Amounts Reclassified from Accumulated Other Comprehensive Loss (Thousands of Dollars) Nine Months Ended Sept. 30, 2015 Nine Months Ended Sept. 30, 2014 (Gains) losses on cash flow hedges: Interest rate derivatives $ 3,013 (a) $ 2,869 (a) Vehicle fuel derivatives 88 (b) (61 ) (b) Total, pre-tax 3,101 2,808 Tax benefit (1,210 ) (1,115 ) Total, net of tax 1,891 1,693 Defined benefit pension and postretirement (gains) losses: Amortization of net loss 4,600 (c) 4,499 (c) Prior service (credit) cost (268 ) (c) (258 ) (c) Total, pre-tax 4,332 4,241 Tax benefit (1,689 ) (1,666 ) Total, net of tax 2,643 2,575 Total amounts reclassified, net of tax $ 4,534 $ 4,268 (a) Included in interest charges. (b) Included in O&M expenses. (c) Included in the computation of net periodic pension and postretirement benefit costs. See Note 12 for details regarding these benefit plans. |
Selected Balance Sheet Data (Ta
Selected Balance Sheet Data (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Balance Sheet Related Disclosures [Abstract] | |
Accounts Receivable, Net | (Thousands of Dollars) Sept. 30, 2015 Dec. 31, 2014 Accounts receivable, net Accounts receivable $ 793,188 $ 884,225 Less allowance for bad debts (51,958 ) (57,719 ) $ 741,230 $ 826,506 |
Inventories | (Thousands of Dollars) Sept. 30, 2015 Dec. 31, 2014 Inventories Materials and supplies $ 291,301 $ 244,099 Fuel 212,728 183,249 Natural gas 140,934 169,835 $ 644,963 $ 597,183 |
Property, Plant and Equipment, Net | (Thousands of Dollars) Sept. 30, 2015 Dec. 31, 2014 Property, plant and equipment, net Electric plant $ 35,022,960 $ 33,203,139 Natural gas plant 4,818,049 4,643,452 Common and other property 1,615,290 1,611,486 Plant to be retired (a) 42,336 71,534 Construction work in progress 1,679,178 2,005,531 Total property, plant and equipment 43,177,813 41,535,142 Less accumulated depreciation (13,724,333 ) (13,168,418 ) Nuclear fuel 2,414,986 2,347,422 Less accumulated amortization (2,039,857 ) (1,957,230 ) $ 29,828,609 $ 28,756,916 (a) PSCo’s Cherokee Unit 3 was retired in August 2015. In 2017, PSCo expects to both early retire Valmont Unit 5 and convert Cherokee Unit 4 from a coal-fueled generating facility to natural gas, as approved by the Colorado Public Utilities Commission (CPUC). Amounts are presented net of accumulated depreciation. |
Income Taxes (Tables)
Income Taxes (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Income Tax Disclosure [Abstract] | |
Earliest Open Tax Years Subject to Examination by State Taxing Authorities in the Major Operating Jurisdictions | State Audits — Xcel Energy files consolidated state tax returns based on income in its major operating jurisdictions of Colorado, Minnesota, Texas, and Wisconsin, and various other state income-based tax returns. As of Sept. 30, 2015, Xcel Energy’s earliest open tax years that are subject to examination by state taxing authorities in its major operating jurisdictions were as follows: State Year Colorado 2009 Minnesota 2009 Texas 2009 Wisconsin 2011 |
Reconciliation of Unrecognized Tax Benefits | A reconciliation of the amount of unrecognized tax benefit is as follows: (Millions of Dollars) Sept. 30, 2015 Dec. 31, 2014 Unrecognized tax benefit — Permanent tax positions $ 15.8 $ 16.2 Unrecognized tax benefit — Temporary tax positions 60.6 50.3 Total unrecognized tax benefit $ 76.4 $ 66.5 |
Tax Benefits Associated with NOL and Tax Credit Carryforwards | The unrecognized tax benefit amounts were reduced by the tax benefits associated with net operating loss (NOL) and tax credit carryforwards. The amounts of tax benefits associated with NOL and tax credit carryforwards are as follows: (Millions of Dollars) Sept. 30, 2015 Dec. 31, 2014 NOL and tax credit carryforwards $ (39.2 ) $ (28.5 ) |
Rate Matters (Tables)
Rate Matters (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Public Utilities, General Disclosures [Abstract] | |
NSP-Minnesota's 2014 Electric Rate Case [Table Text Block] | The following table outlines the impact of the MPUC’s July decision: (Millions of Dollars) MPUC July Decision 2014 and 2015 step increase - based on MPUC May order $ 166.1 Reconsideration/clarification adjustments: 2015 Monticello EPU used-and-useful adjustment (13.8 ) 2014 property tax final true-up (3.1 ) Other, net 0.2 Total 2014 and 2015 step increase $ 149.4 Impact of interim rate effective March 3, 2015 (3.6 ) Estimated revenue impact $ 145.8 |
SPS' New Mexico 2015 Electric Rate Case [Table Text Block] | The major components of the requested rate increase are summarized below: (Millions of Dollars) Request 2015 base period deficiency $ 19.7 Capital expenditures — post-test year adjustments 12.3 Depreciation, higher rates reflecting changes in depreciable lives, interim retirements and net salvage 3.7 Transmission revenue and expense, including charges paid to SPP for construction of regionally shared transmission projects 2.0 ROE, reflecting an increase from 9.96 percent to 10.25 percent 1.6 Rider revenue adjustments - gross receipts tax 1.3 Other, net 4.8 Requested rate increase $ 45.4 |
Colorado 2015 Multi-Year Gas Rate Case - Base Rate Answer Testimony [Table Text Block] | The following table reflects the current positions of Staff and OCC: (Millions of Dollars) Staff OCC PSCo’s filed 2015 base rate request $ 40.5 $ 40.5 ROE (12.8 ) (13.7 ) Capital structure and cost of debt (12.8 ) (4.8 ) Cherokee pipeline adjustment (11.2 ) 4.8 Move to 2014 HTY (10.5 ) (16.4 ) Operating and maintenance (O&M) expenses (3.5 ) (2.7 ) Other, net (4.4 ) (1.9 ) Total adjustments $ (55.2 ) $ (34.7 ) Recommended (decrease) increase $ (14.7 ) $ 5.8 |
Colorado 2015 Multi-Year Gas Rate Case - PSIA Rider Answer Testimony [Table Text Block] | The Staff’s recommendation for the PSIA rider is as follows: (Millions of Dollars) 2016 2017 PSCo’s filed incremental PSIA request $ 21.7 $ 21.2 Transfer PSIA O&M to base rates (24.1 ) (2.0 ) ROE and capital structure (8.2 ) (3.6 ) Transfer meter replacement program from base rates to PSIA 1.7 1.7 Total $ (8.9 ) $ 17.3 |
Colorado 2015 Multi-Year Gas Rate Case [Table Text Block] | The following table summarizes the request: (Millions of Dollars) 2015 2016 Step 2017 Step Total base rate increase $ 40.5 $ 7.6 $ 18.1 Incremental PSIA rider revenues (0.1 ) 21.7 21.2 Total revenue impact $ 40.4 $ 29.3 $ 39.3 |
Colorado 2015 Multi-Year Gas Rate Case - PSIA Rider [Table Text Block] | PSCo’s rebuttal testimony, compared to its initial filed base rate and rider request are summarized as follows: (Millions of Dollars) 2015 2016 Step 2017 Step PSCo’s filed base rate request $ 40.5 $ 7.6 $ 18.1 Shift O&M expenses between PSIA and base rates — 7.0 6.4 Rebuttal corrections and adjustments — — (7.7 ) Total base rate request $ 40.5 $ 14.6 $ 16.8 Incremental PSIA rider revenues (0.1 ) 14.7 21.7 Total revenue impact from rebuttal $ 40.4 $ 29.3 $ 38.5 |
SPS' Texas 2015 Electric Rate Case [Table Text Block] | The following table reflects the positions of Alliance of Xcel Municipalities (AXM), the Office of Public Utility Counsel (OPUC), the PUCT Staff (Staff), SPS as well as the estimated recommendation of the ALJs: SPS Rebuttal Testimony ALJs’ PFD (a) (Millions of Dollars) AXM OPUC Staff SPS’ revised rate request $ 58.9 $ 58.9 $ 58.9 $ 58.9 $ 42.1 Investment for capital expenditures — post-test year adjustments (11.3 ) (23.8 ) (23.8 ) — (16.7 ) Lower ROE (10.9 ) (13.5 ) (12.1 ) — (6.3 ) Rate base adjustments (largely the removal of the prepaid pension asset) (6.2 ) (6.8 ) — — — O&M expense adjustments (13.7 ) (11.0 ) (7.9 ) (1.6 ) (5.3 ) Depreciation expense (13.3 ) — — — (3.9 ) Property taxes — (1.2 ) (4.4 ) (1.8 ) (3.7 ) Revenue adjustments (2.2 ) (0.2 ) — — — Wholesale load reductions (13.2 ) — (11.1 ) — — Southwest Power Pool (SPP) transmission expansion plan — — — (7.3 ) (4.2 ) Other, net (1.7 ) (0.6 ) (2.2 ) (1.8 ) (0.6 ) Total recommendation $ (13.6 ) $ 1.8 $ (2.6 ) $ 46.4 $ 1.4 Adjustment to move rate case expenses to a separate docket — — — (4.3 ) (0.2 ) Recommendation, excluding rate case expenses $ (13.6 ) $ 1.8 $ (2.6 ) $ 42.1 $ 1.2 (a) The ALJs’ recommendation reflects proposed adjustments to SPS’ rebuttal testimony, as of Oct. 12, 2015, which supports a $42.1 million rate increase. |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Commitments and Contingencies Disclosure [Abstract] | |
Guarantees and Bond Indemnities Issued and Outstanding | The following table presents guarantees and bond indemnities issued and outstanding for Xcel Energy Inc.: (Millions of Dollars) Sept. 30, 2015 Dec. 31, 2014 Guarantees issued and outstanding $ 12.9 $ 13.9 Current exposure under these guarantees 0.1 0.2 Bonds with indemnity protection 42.5 31.4 |
Borrowings and Other Financin28
Borrowings and Other Financing Instruments (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Debt Disclosure [Abstract] | |
Commercial Paper | Commercial paper outstanding for Xcel Energy was as follows: (Amounts in Millions, Except Interest Rates) Three Months Ended Twelve Months Ended Borrowing limit $ 2,750 $ 2,750 Amount outstanding at period end 64 1,020 Average amount outstanding 272 841 Maximum amount outstanding 478 1,200 Weighted average interest rate, computed on a daily basis 0.46 % 0.33 % Weighted average interest rate at period end 0.38 0.56 |
Credit Facilities | At Sept. 30, 2015 , Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available: (Millions of Dollars) Credit Facility (a) Drawn (b) Available Xcel Energy Inc. $ 1,000 $ 64 $ 936 PSCo 700 5 695 NSP-Minnesota 500 24 476 SPS 400 10 390 NSP-Wisconsin 150 — 150 Total $ 2,750 $ 103 $ 2,647 (a) These credit facilities expire in October 2019. (b) Includes outstanding commercial paper and letters of credit. |
Fair Value of Financial Asset29
Fair Value of Financial Assets and Liabilities (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Fair Value Disclosures [Abstract] | |
Cost and Fair Value of Nuclear Decommissioning Fund Investments | The following tables present the cost and fair value of Xcel Energy’s non-derivative instruments with recurring fair value measurements in the nuclear decommissioning fund at Sept. 30, 2015 and Dec. 31, 2014 : Sept. 30, 2015 Fair Value (Thousands of Dollars) Cost Level 1 Level 2 Level 3 Total Nuclear decommissioning fund (a) Cash equivalents $ 33,681 $ 33,681 $ — $ — $ 33,681 Commingled funds 351,676 — 381,230 — 381,230 International equity funds 217,003 — 188,853 — 188,853 Private equity investments 98,133 — — 145,695 145,695 Real estate 49,151 — — 71,976 71,976 Debt securities: Government securities 24,557 — 21,423 — 21,423 U.S. corporate bonds 70,311 — 61,874 — 61,874 International corporate bonds 14,099 — 13,059 — 13,059 Municipal bonds 210,728 — 215,014 — 215,014 Asset-backed securities 2,834 — 2,836 — 2,836 Mortgage-backed securities 11,734 — 12,077 — 12,077 Equity securities: Common stock 386,176 533,431 — — 533,431 Total $ 1,470,083 $ 567,112 $ 896,366 $ 217,671 $ 1,681,149 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $80.3 million of equity investments in unconsolidated subsidiaries and $46.3 million of miscellaneous investments. Dec. 31, 2014 Fair Value (Thousands of Dollars) Cost Level 1 Level 2 Level 3 Total Nuclear decommissioning fund (a) Cash equivalents $ 24,184 $ 24,184 $ — $ — $ 24,184 Commingled funds 470,013 — 465,615 — 465,615 International equity funds 80,454 — 78,721 — 78,721 Private equity investments 73,936 — — 101,237 101,237 Real estate 43,859 — — 64,249 64,249 Debt securities: Government securities 30,674 — 28,808 — 28,808 U.S. corporate bonds 81,463 — 77,562 — 77,562 International corporate bonds 16,950 — 16,341 — 16,341 Municipal bonds 242,282 — 249,201 — 249,201 Asset-backed securities 9,131 — 9,250 — 9,250 Mortgage-backed securities 23,225 — 23,895 — 23,895 Equity securities: Common stock 369,751 564,858 — — 564,858 Total $ 1,465,922 $ 589,042 $ 949,393 $ 165,486 $ 1,703,921 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $83.1 million of equity investments in unconsolidated subsidiaries and $45.6 million of miscellaneous investments. |
Changes in Level 3 Nuclear Decommissioning Fund Investments | The following tables present the changes in Level 3 nuclear decommissioning fund investments for the three and nine months ended Sept. 30, 2015 and 2014 : (Thousands of Dollars) July 1, 2015 Purchases Settlements Gains Recognized as Regulatory Assets (a) Sept. 30, 2015 Private equity investments $ 133,993 $ 3,066 $ — $ 8,636 $ 145,695 Real estate 70,834 1,501 (1,719 ) 1,360 71,976 Total $ 204,827 $ 4,567 $ (1,719 ) $ 9,996 $ 217,671 (Thousands of Dollars) July 1, 2014 Purchases Settlements Gains Recognized as Regulatory Asset (a) Sept. 30, 2014 Private equity investments $ 81,123 $ 11,125 $ — $ 4,756 $ 97,004 Real estate 65,658 1,530 (5,876 ) 2,661 63,973 Total $ 146,781 $ 12,655 $ (5,876 ) $ 7,417 $ 160,977 (Thousands of Dollars) Jan. 1, 2015 Purchases Settlements Gains Recognized as Regulatory Assets (a) Sept. 30, 2015 Private equity investments $ 101,237 $ 24,197 $ — $ 20,261 $ 145,695 Real estate 64,249 9,633 (4,341 ) 2,435 71,976 Total $ 165,486 $ 33,830 $ (4,341 ) $ 22,696 $ 217,671 (Thousands of Dollars) Jan. 1, 2014 Purchases Settlements Gains Recognized as Regulatory Asset (a) Sept. 30, 2014 Private equity investments $ 62,696 $ 22,078 $ — $ 12,230 $ 97,004 Real estate 57,368 5,386 (5,876 ) 7,095 63,973 Total $ 120,064 $ 27,464 $ (5,876 ) $ 19,325 $ 160,977 (a) Gains are deferred as a component of the regulatory assets for nuclear decommissioning. |
Final Contractual Maturity Dates of Debt Securities in the Nuclear Decommissioning Fund by Asset Class | The following table summarizes the final contractual maturity dates of the debt securities in the nuclear decommissioning fund, by asset class, at Sept. 30, 2015 : Final Contractual Maturity (Thousands of Dollars) Due in 1 Year or Less Due in 1 to 5 Years Due in 5 to 10 Years Due after 10 Years Total Government securities $ — $ — $ — $ 21,423 $ 21,423 U.S. corporate bonds — 15,398 51,317 (4,841 ) 61,874 International corporate bonds — 2,976 9,109 974 13,059 Municipal bonds 1,260 27,500 44,594 141,660 215,014 Asset-backed securities — — 2,836 — 2,836 Mortgage-backed securities — — — 12,077 12,077 Debt securities $ 1,260 $ 45,874 $ 107,856 $ 171,293 $ 326,283 |
Gross Notional Amounts of Commodity Forwards, Options, and FTRs | The following table details the gross notional amounts of commodity forwards, options and FTRs at Sept. 30, 2015 and Dec. 31, 2014 : (Amounts in Thousands) (a)(b) Sept. 30, 2015 Dec. 31, 2014 Megawatt hours of electricity 76,323 56,361 Million British thermal units of natural gas 13,709 927 Gallons of vehicle fuel 176 282 (a) Amounts are not reflective of net positions in the underlying commodities. (b) Notional amounts for options are included on a gross basis, but are weighted for the probability of exercise. |
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income | The following tables detail the impact of derivative activity during the three and nine months ended Sept. 30, 2015 and 2014, on accumulated other comprehensive loss, regulatory assets and liabilities, and income: Three Months Ended Sept. 30, 2015 Pre-Tax Fair Value Gains (Losses) Recognized During the Period in: Pre-Tax (Gains) Losses Reclassified into Income During the Period from: Pre-Tax Losses Recognized (Thousands of Dollars) Accumulated Other Regulatory Accumulated Other Regulatory Assets and (Liabilities) Derivatives designated as cash flow hedges Interest rate $ — $ — $ 1,118 (a) $ — $ — Vehicle fuel and other commodity (70 ) — 34 (b) — — Total $ (70 ) $ — $ 1,152 $ — $ — Other derivative instruments Commodity trading $ — $ — $ — $ — $ (3,460 ) (c) Electric commodity — (2,403 ) — 2,860 (d) — Natural gas commodity — (2,978 ) — — (405 ) (e) Total $ — $ (5,381 ) $ — $ 2,860 $ (3,865 ) Nine Months Ended Sept. 30, 2015 Pre-Tax Fair Value Gains (Losses) Recognized During the Period in: Pre-Tax (Gains) Losses Reclassified into Income During the Period from: Pre-Tax Losses Recognized (Thousands of Dollars) Accumulated Other Regulatory Accumulated Other Regulatory Assets and (Liabilities) Derivatives designated as cash flow hedges Interest rate $ — $ — $ 3,013 (a) $ — $ — Vehicle fuel and other commodity (59 ) — 88 (b) — — Total $ (59 ) $ — $ 3,101 $ — $ — Other derivative instruments Commodity trading $ — $ — $ — $ — $ (5,896 ) (c) Electric commodity — (16,611 ) — 16,020 (d) — Natural gas commodity — (3,366 ) — 8,685 (e) (9,455 ) (e) Total $ — $ (19,977 ) $ — $ 24,705 $ (15,351 ) Three Months Ended Sept. 30, 2014 Pre-Tax Fair Value Gains (Losses) Recognized During the Period in: Pre-Tax (Gains) Losses Reclassified into Income During the Period from: Pre-Tax Gains (Losses) Recognized (Thousands of Dollars) Accumulated Other Regulatory Accumulated Other Regulatory Assets and (Liabilities) Derivatives designated as cash flow hedges Interest rate $ — $ — $ 967 (a) $ — $ — Vehicle fuel and other commodity (69 ) — (16 ) (b) — — Total $ (69 ) $ — $ 951 $ — $ — Other derivative instruments Commodity trading $ — $ — $ — $ — $ (1,656 ) (c) Electric commodity — (3,391 ) — 6,629 (d) — Natural gas commodity — (2,455 ) — — (209 ) (d) Total $ — $ (5,846 ) $ — $ 6,629 $ (1,865 ) Nine Months Ended Sept. 30, 2014 Pre-Tax Fair Value Gains (Losses) Recognized During the Period in: Pre-Tax (Gains) Losses Reclassified into Income During the Period from: Pre-Tax Gains (Losses) Recognized (Thousands of Dollars) Accumulated Other Regulatory Accumulated Other Regulatory Derivatives designated as cash flow hedges Interest rate $ — $ — $ 2,869 (a) $ — $ — Vehicle fuel and other commodity (56 ) — (61 ) (b) — — Total $ (56 ) $ — $ 2,808 $ — $ — Other derivative instruments Commodity trading $ — $ — $ — $ — $ 1,266 (c) Electric commodity — (17,240 ) — (18,641 ) (d) — Natural gas commodity — 13,603 — (18,840 ) (e) (5,575 ) (e) Other commodity — — — — 643 (c) Total $ — $ (3,637 ) $ — $ (37,481 ) $ (3,666 ) (a) Amounts are recorded to interest charges. (b) Amounts are recorded to O&M expenses. (c) Amounts are recorded to electric operating revenues. Portions of these gains and losses are subject to sharing with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate. (d) Amounts are recorded to electric fuel and purchased power. These derivative settlement gain and loss amounts are shared with electric customers through fuel and purchased energy cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate. (e) Amounts for the three and nine months ended Sept. 30, 2015 included $0.4 million and $0.5 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. Losses for the nine months ended Sept. 30, 2014 included immaterial settlement losses on derivatives entered to mitigate natural gas price risk for electric generation, recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate. The remaining derivative settlement gains and losses for the three and nine months ended Sept. 30, 2015 and nine months ended 2014 relate to natural gas operations and are recorded to cost of natural gas sold and transported. These gains and losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset or liability, as appropriate. |
Derivative Assets and Liabilities Measured at Fair Value on a Recurring Basis by Hierarchy Level | Recurring Fair Value Measurements — The following table presents for each of the fair value hierarchy levels, Xcel Energy’s derivative assets and liabilities measured at fair value on a recurring basis at Sept. 30, 2015 : Sept. 30, 2015 Fair Value Fair Value Total Counterparty Netting (b) Total (Thousands of Dollars) Level 1 Level 2 Level 3 Current derivative assets Other derivative instruments: Commodity trading $ — $ 9,140 $ 4,307 $ 13,447 $ (5,150 ) $ 8,297 Electric commodity — — 34,715 34,715 (6,361 ) 28,354 Natural gas commodity — 3,062 — 3,062 (1,690 ) 1,372 Total current derivative assets $ — $ 12,202 $ 39,022 $ 51,224 $ (13,201 ) 38,023 PPAs (a) 10,087 Current derivative instruments $ 48,110 Noncurrent derivative assets Other derivative instruments: Commodity trading $ — $ 29,523 $ — $ 29,523 $ (7,411 ) $ 22,112 Total noncurrent derivative assets $ — $ 29,523 $ — $ 29,523 $ (7,411 ) 22,112 PPAs (a) 32,631 Noncurrent derivative instruments $ 54,743 Sept. 30, 2015 Fair Value Fair Value Total Counterparty Netting (b) Total (Thousands of Dollars) Level 1 Level 2 Level 3 Current derivative liabilities Derivatives designated as cash flow hedges: Vehicle fuel and other commodity $ — $ 156 $ — $ 156 $ — $ 156 Other derivative instruments: Commodity trading — 6,461 1,478 7,939 (5,592 ) 2,347 Electric commodity — — 6,361 6,361 (6,361 ) — Natural gas commodity — 2,777 — 2,777 (1,690 ) 1,087 Other commodity — 844 — 844 — 844 Total current derivative liabilities $ — $ 10,238 $ 7,839 $ 18,077 $ (13,643 ) 4,434 PPAs (a) 22,869 Current derivative instruments $ 27,303 Noncurrent derivative liabilities Derivatives designated as cash flow hedges: Vehicle fuel and other commodity $ — $ 36 $ — $ 36 $ — $ 36 Other derivative instruments: Commodity trading — 20,789 — 20,789 (11,097 ) 9,692 Other commodity — 18 — 18 — 18 Total noncurrent derivative liabilities $ — $ 20,843 $ — $ 20,843 $ (11,097 ) 9,746 PPAs (a) 163,842 Noncurrent derivative instruments $ 173,588 (a) In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, Xcel Energy began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, Xcel Energy qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities. (b) Xcel Energy nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Sept. 30, 2015 . At Sept. 30, 2015 , derivative assets and liabilities include no obligations to return cash collateral and the rights to reclaim cash collateral of $4.1 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, 2014 : Dec. 31, 2014 Fair Value Fair Value Total Counterparty Netting (b) Total (Thousands of Dollars) Level 1 Level 2 Level 3 Current derivative assets Other derivative instruments: Commodity trading $ — $ 14,326 $ 4,732 $ 19,058 $ (3,240 ) $ 15,818 Electric commodity — — 62,825 62,825 (11,402 ) 51,423 Natural gas commodity — 381 — 381 (22 ) 359 Total current derivative assets $ — $ 14,707 $ 67,557 $ 82,264 $ (14,664 ) 67,600 PPAs (a) 18,123 Current derivative instruments $ 85,723 Noncurrent derivative assets Other derivative instruments: Commodity trading $ — $ 17,617 $ — $ 17,617 $ (4,151 ) $ 13,466 Total noncurrent derivative assets $ — $ 17,617 $ — $ 17,617 $ (4,151 ) 13,466 PPAs (a) 40,309 Noncurrent derivative instruments $ 53,775 Dec. 31, 2014 Fair Value Fair Value Total Counterparty Netting (b) Total (Thousands of Dollars) Level 1 Level 2 Level 3 Current derivative liabilities Derivatives designated as cash flow hedges: Vehicle fuel and other commodity $ — $ 118 $ — $ 118 $ — $ 118 Other derivative instruments: Commodity trading — 7,974 — 7,974 (7,974 ) — Electric commodity — — 11,402 11,402 (11,402 ) — Natural gas commodity — 548 — 548 (21 ) 527 Total current derivative liabilities $ — $ 8,640 $ 11,402 $ 20,042 $ (19,397 ) 645 PPAs (a) 20,987 Current derivative instruments $ 21,632 Noncurrent derivative liabilities Derivatives designated as cash flow hedges: Vehicle fuel and other commodity $ — $ 102 $ — $ 102 $ — $ 102 Other derivative instruments: Commodity trading — 6,890 — 6,890 (6,033 ) 857 Natural gas commodity — 35 — 35 — 35 Total noncurrent derivative liabilities $ — $ 7,027 $ — $ 7,027 $ (6,033 ) 994 PPAs (a) 182,942 Noncurrent derivative instruments $ 183,936 (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, 2014 . At Dec. 31, 2014 , derivative assets and liabilities include no obligations to return cash collateral and rights to reclaim cash collateral of $6.6 million . The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements. |
Changes in Level 3 Commodity Derivatives | The following table presents the changes in Level 3 commodity derivatives for the three and nine months ended Sept. 30, 2015 and 2014 : Three Months Ended Sept. 30 (Thousands of Dollars) 2015 2014 Balance at July 1 $ 46,826 $ 105,394 Purchases 486 5,588 Settlements (20,216 ) (20,032 ) Transfers out of Level 3 — (1,093 ) Net transactions recorded during the period: Gains recognized in earnings (a) 121 1,480 Gains (losses) recognized as regulatory assets and liabilities 3,966 (17,705 ) Balance at Sept. 30 $ 31,183 $ 73,632 Nine Months Ended Sept. 30 (Thousands of Dollars) 2015 2014 Balance at Jan. 1 $ 56,155 $ 41,660 Purchases 63,724 126,752 Settlements (57,462 ) (107,451 ) Transfers out of Level 3 — (1,093 ) Net transactions recorded during the period: Gains recognized in earnings (a) 1,401 8,917 (Losses) gains recognized as regulatory assets and liabilities (32,635 ) 4,847 Balance at Sept. 30 $ 31,183 $ 73,632 (a) These amounts relate to commodity derivatives held at the end of the period. |
Carrying Amount and Fair Value of Long-term Debt | As of Sept. 30, 2015 and Dec. 31, 2014 , other financial instruments for which the carrying amount did not equal fair value were as follows: Sept. 30, 2015 Dec. 31, 2014 (Thousands of Dollars) Carrying Amount Fair Value Carrying Amount Fair Value Long-term debt, including current portion $ 13,148,225 $ 14,304,149 $ 11,757,360 $ 13,360,236 |
Other Income (Expense), Net (Ta
Other Income (Expense), Net (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Other Income and Expenses [Abstract] | |
Other Income (Expense), Net | Other income, net consisted of the following: Three Months Ended Sept. 30 Nine Months Ended Sept. 30 (Thousands of Dollars) 2015 2014 2015 2014 Interest income $ 312 $ 1,139 $ 4,939 $ 6,324 Other nonoperating income 625 682 2,387 3,042 Insurance policy income (expense) 689 (417 ) (1,578 ) (4,663 ) Other nonoperating expense — — — (16 ) Other income, net $ 1,626 $ 1,404 $ 5,748 $ 4,687 |
Segment Information (Tables)
Segment Information (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Segment Reporting [Abstract] | |
Results by Reportable Segment | (Thousands of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total Three Months Ended Sept. 30, 2015 Operating revenues from external customers $ 2,667,480 $ 216,019 $ 17,813 $ — $ 2,901,312 Intersegment revenues 392 293 — (685 ) — Total revenues $ 2,667,872 $ 216,312 $ 17,813 $ (685 ) $ 2,901,312 Net income (loss) $ 437,978 $ (4,176 ) $ (7,339 ) $ — $ 426,463 (Thousands of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total Three Months Ended Sept. 30, 2014 Operating revenues from external customers $ 2,616,351 $ 236,649 $ 16,807 $ — $ 2,869,807 Intersegment revenues 472 597 — (1,069 ) — Total revenues $ 2,616,823 $ 237,246 $ 16,807 $ (1,069 ) $ 2,869,807 Net income $ 360,656 $ 3,996 $ 3,930 $ — $ 368,582 (Thousands of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total Nine Months Ended Sept. 30, 2015 Operating revenues from external customers (a) $ 7,105,803 $ 1,216,146 $ 56,716 $ — $ 8,378,665 Intersegment revenues 1,142 1,141 — (2,283 ) — Total revenues $ 7,106,945 $ 1,217,287 $ 56,716 $ (2,283 ) $ 8,378,665 Net income (loss) $ 733,954 (a) $ 72,617 $ (31,111 ) $ — $ 775,460 (Thousands of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total Nine Months Ended Sept. 30, 2014 Operating revenues from external customers $ 7,215,699 $ 1,485,464 $ 56,344 $ — $ 8,757,507 Intersegment revenues 1,262 4,967 — (6,229 ) — Total revenues $ 7,216,961 $ 1,490,431 $ 56,344 $ (6,229 ) $ 8,757,507 Net income (loss) $ 731,766 $ 96,629 $ (3,428 ) $ — $ 824,967 (a) Includes a net of tax charge related to the Monticello LCM/EPU project. See Note 5. |
Earnings Per Share (Tables)
Earnings Per Share (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Earnings Per Share [Abstract] | |
Dilutive Impact of Common Stock Equivalents | The dilutive impact of common stock equivalents affecting EPS was as follows: Three Months Ended Sept. 30, 2015 Three Months Ended Sept. 30, 2014 (Amounts in thousands, except per share data) Income Shares Per Share Amount Income Shares Per Share Amount Net income $ 426,463 — — $ 368,582 — — Basic EPS: Earnings available to common shareholders 426,463 508,031 $ 0.84 368,582 506,082 $ 0.73 Effect of dilutive securities: Time based equity awards — 396 — — 283 — Diluted EPS: Earnings available to common shareholders $ 426,463 508,427 $ 0.84 $ 368,582 506,365 $ 0.73 Nine Months Ended Sept. 30, 2015 Nine Months Ended Sept. 30, 2014 (Amounts in thousands, except per share data) Income Shares Per Share Amount Income Shares Per Share Amount Net income $ 775,460 — $ 824,967 — — Basic EPS: Earnings available to common shareholders 775,460 507,585 $ 1.53 824,967 502,983 $ 1.64 Effect of dilutive securities: Time based equity awards — 391 — — 230 — Diluted EPS: Earnings available to common shareholders $ 775,460 507,976 $ 1.53 $ 824,967 503,213 $ 1.64 |
Benefit Plans and Other Postr33
Benefit Plans and Other Postretirement Benefits (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Compensation and Retirement Disclosure [Abstract] | |
Components of Net Periodic Benefit Cost (Credit) | Components of Net Periodic Benefit Cost (Credit) Three Months Ended Sept. 30 2015 2014 2015 2014 (Thousands of Dollars) Pension Benefits Postretirement Health Service cost $ 24,828 $ 22,086 $ 529 $ 864 Interest cost 37,131 39,155 6,324 8,507 Expected return on plan assets (53,473 ) (51,801 ) (6,650 ) (8,489 ) Amortization of prior service credit (451 ) (437 ) (2,672 ) (2,672 ) Amortization of net loss 31,288 29,191 1,351 2,935 Net periodic benefit cost (credit) 39,323 38,194 (1,118 ) 1,145 Costs not recognized due to the effects of regulation (7,016 ) (6,605 ) — — Net benefit cost (credit) recognized for financial reporting $ 32,307 $ 31,589 $ (1,118 ) $ 1,145 Nine Months Ended Sept. 30 2015 2014 2015 2014 (Thousands of Dollars) Pension Benefits Postretirement Health Service cost $ 74,484 $ 66,257 $ 1,587 $ 2,592 Interest cost 111,393 117,465 18,972 25,521 Expected return on plan assets (160,418 ) (155,403 ) (19,950 ) (25,466 ) Amortization of prior service credit (1,353 ) (1,310 ) (8,015 ) (8,016 ) Amortization of net loss 93,864 87,572 4,053 8,805 Net periodic benefit cost (credit) 117,970 114,581 (3,353 ) 3,436 Costs not recognized due to the effects of regulation (22,035 ) (20,261 ) — — Net benefit cost (credit) recognized for financial reporting $ 95,935 $ 94,320 $ (3,353 ) $ 3,436 |
Other Comprehensive Income (Tab
Other Comprehensive Income (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Stockholders' Equity Note [Abstract] | |
Changes in Accumulated Other Comprehensive Income (Loss), Net of Tax | Changes in accumulated other comprehensive (loss) income, net of tax, for the three and nine months ended Sept. 30, 2015 and 2014 were as follows: Three Months Ended Sept. 30, 2015 (Thousands of Dollars) Gains and Losses on Cash Flow Hedges Unrealized Gains and Losses on Marketable Securities Defined Benefit Pension and Postretirement Items Total Accumulated other comprehensive (loss) income at July 1 $ (56,436 ) $ 112 $ (48,862 ) $ (105,186 ) Other comprehensive loss before reclassifications (42 ) (1 ) — (43 ) Losses reclassified from net accumulated other comprehensive loss 706 — 884 1,590 Net current period other comprehensive income (loss) 664 (1 ) 884 1,547 Accumulated other comprehensive (loss) income at Sept. 30 $ (55,772 ) $ 111 $ (47,978 ) $ (103,639 ) Three Months Ended Sept. 30, 2014 (Thousands of Dollars) Gains and Losses on Cash Flow Hedges Unrealized Gains and Losses on Marketable Securities Defined Benefit Pension and Total Accumulated other comprehensive (loss) income at July 1 $ (58,610 ) $ 115 $ (44,871 ) $ (103,366 ) Other comprehensive (loss) income before reclassifications (42 ) 2 — (40 ) Losses reclassified from net accumulated other comprehensive loss 558 — 847 1,405 Net current period other comprehensive income 516 2 847 1,365 Accumulated other comprehensive (loss) income at Sept. 30 $ (58,094 ) $ 117 $ (44,024 ) $ (102,001 ) Nine Months Ended Sept. 30, 2015 (Thousands of Dollars) Gains and Losses on Cash Flow Hedges Unrealized Gains and Losses on Marketable Securities Defined Benefit Pension and Postretirement Items Total Accumulated other comprehensive (loss) income at Jan. 1 $ (57,628 ) $ 110 $ (50,621 ) $ (108,139 ) Other comprehensive (loss) income before reclassifications (35 ) 1 — (34 ) Losses reclassified from net accumulated other comprehensive loss 1,891 — 2,643 4,534 Net current period other comprehensive income 1,856 1 2,643 4,500 Accumulated other comprehensive (loss) income at Sept. 30 $ (55,772 ) $ 111 $ (47,978 ) $ (103,639 ) Nine Months Ended Sept. 30, 2014 (Thousands of Dollars) Gains and Losses on Cash Flow Hedges Unrealized Gains and Losses on Marketable Securities Defined Benefit Pension and Postretirement Items Total Accumulated other comprehensive (loss) income at Jan. 1 $ (59,753 ) $ 77 $ (46,599 ) $ (106,275 ) Other comprehensive (loss) income before reclassifications (34 ) 40 — 6 Losses reclassified from net accumulated other comprehensive loss 1,693 — 2,575 4,268 Net current period other comprehensive income 1,659 40 2,575 4,274 Accumulated other comprehensive (loss) income at Sept. 30 $ (58,094 ) $ 117 $ (44,024 ) $ (102,001 ) |
Reclassifications out of Accumulated Other Comprehensive Loss | Reclassifications from accumulated other comprehensive loss for the three and nine months ended Sept. 30, 2015 and 2014 were as follows: Amounts Reclassified from Accumulated Other Comprehensive Loss (Thousands of Dollars) Three Months Ended Sept. 30, 2015 Three Months Ended Sept. 30, 2014 (Gains) losses on cash flow hedges: Interest rate derivatives $ 1,118 (a) $ 967 (a) Vehicle fuel derivatives 34 (b) (16 ) (b) Total, pre-tax 1,152 951 Tax benefit (446 ) (393 ) Total, net of tax 706 558 Defined benefit pension and postretirement (gains) losses: Amortization of net loss 1,532 (c) 1,500 (c) Prior service credit (89 ) (c) (86 ) (c) Total, pre-tax 1,443 1,414 Tax benefit (559 ) (567 ) Total, net of tax 884 847 Total amounts reclassified, net of tax $ 1,590 $ 1,405 Amounts Reclassified from Accumulated Other Comprehensive Loss (Thousands of Dollars) Nine Months Ended Sept. 30, 2015 Nine Months Ended Sept. 30, 2014 (Gains) losses on cash flow hedges: Interest rate derivatives $ 3,013 (a) $ 2,869 (a) Vehicle fuel derivatives 88 (b) (61 ) (b) Total, pre-tax 3,101 2,808 Tax benefit (1,210 ) (1,115 ) Total, net of tax 1,891 1,693 Defined benefit pension and postretirement (gains) losses: Amortization of net loss 4,600 (c) 4,499 (c) Prior service (credit) cost (268 ) (c) (258 ) (c) Total, pre-tax 4,332 4,241 Tax benefit (1,689 ) (1,666 ) Total, net of tax 2,643 2,575 Total amounts reclassified, net of tax $ 4,534 $ 4,268 (a) Included in interest charges. (b) Included in O&M expenses. (c) Included in the computation of net periodic pension and postretirement benefit costs. See Note 12 for details regarding these benefit plans. |
Balance Sheet Data, Accounts Re
Balance Sheet Data, Accounts Receivable (Details) - USD ($) $ in Thousands | Sep. 30, 2015 | Dec. 31, 2014 |
Accounts receivable, net | ||
Accounts receivable | $ 793,188 | $ 884,225 |
Less allowance for bad debts | (51,958) | (57,719) |
Accounts receivable, net | $ 741,230 | $ 826,506 |
Balance Sheet Related Disclosur
Balance Sheet Related Disclosures, Inventories (Details) - USD ($) $ in Thousands | Sep. 30, 2015 | Dec. 31, 2014 |
Public Utilities, Inventory [Line Items] | ||
Inventories | $ 644,963 | $ 597,183 |
Materials and supplies | ||
Public Utilities, Inventory [Line Items] | ||
Inventories | 291,301 | 244,099 |
Fuel | ||
Public Utilities, Inventory [Line Items] | ||
Inventories | 212,728 | 183,249 |
Natural gas | ||
Public Utilities, Inventory [Line Items] | ||
Inventories | $ 140,934 | $ 169,835 |
Balance Sheet Related Disclos37
Balance Sheet Related Disclosures, Property, Plant and Equipment (Details) - USD ($) $ in Thousands | Sep. 30, 2015 | Dec. 31, 2014 | |
Public Utility, Property, Plant and Equipment [Line Items] | |||
Property, plant and equipment, gross | $ 43,177,813 | $ 41,535,142 | |
Less accumulated depreciation | (13,724,333) | (13,168,418) | |
Property, plant and equipment, net | 29,828,609 | 28,756,916 | |
Electric plant | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Property, plant and equipment, gross | 35,022,960 | 33,203,139 | |
Natural gas plant | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Property, plant and equipment, gross | 4,818,049 | 4,643,452 | |
Common and other property | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Property, plant and equipment, gross | 1,615,290 | 1,611,486 | |
Plant to be retired | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Property, plant and equipment, gross | [1] | 42,336 | 71,534 |
Construction work in progress | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Property, plant and equipment, gross | 1,679,178 | 2,005,531 | |
Nuclear fuel | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Property, plant and equipment, gross | 2,414,986 | 2,347,422 | |
Less accumulated depreciation | $ (2,039,857) | $ (1,957,230) | |
[1] | PSCo’s Cherokee Unit 3 was retired in August 2015. In 2017, PSCo expects to both early retire Valmont Unit 5 and convert Cherokee Unit 4 from a coal-fueled generating facility to natural gas, as approved by the Colorado Public Utilities Commission (CPUC). Amounts are presented net of accumulated depreciation. |
Income Taxes (Details)
Income Taxes (Details) - USD ($) | 3 Months Ended | 9 Months Ended | |
Sep. 30, 2012 | Sep. 30, 2015 | Dec. 31, 2014 | |
Unrecognized Tax Benefits [Abstract] | |||
Unrecognized tax benefit — Permanent tax positions | $ 15,800,000 | $ 16,200,000 | |
Unrecognized tax benefit — Temporary tax positions | 60,600,000 | 50,300,000 | |
Total unrecognized tax benefit | 76,400,000 | 66,500,000 | |
NOL and tax credit carryforwards | (39,200,000) | (28,500,000) | |
Upper bound of decrease in unrecognized tax benefit that is reasonably possible | 10,000,000 | ||
Amounts accrued for penalties related to unrecognized tax benefits | $ 0 | $ 0 | |
Internal Revenue Service (IRS) | |||
Tax Audits [Abstract] | |||
Year(s) under examination | 2010 and 2011 | 2012 and 2013 | |
Year of carryback claim under examination | 2,009 | ||
Potential Tax Adjustments | $ 13,000,000 | ||
Colorado | |||
Tax Audits [Abstract] | |||
Earliest year subject to examination | 2,009 | ||
Minnesota | |||
Tax Audits [Abstract] | |||
Earliest year subject to examination | 2,009 | ||
Texas | |||
Tax Audits [Abstract] | |||
Earliest year subject to examination | 2,009 | ||
Wisconsin | |||
Tax Audits [Abstract] | |||
Earliest year subject to examination | 2,011 |
Rate Matters, NSP-Minnesota (De
Rate Matters, NSP-Minnesota (Details) $ in Thousands | Oct. 20, 2015 | Jan. 06, 2015 | Oct. 31, 2015USD ($) | Sep. 30, 2015 | Jul. 31, 2015USD ($) | May. 31, 2015USD ($) | Mar. 31, 2015USD ($) | Feb. 28, 2015 | Dec. 31, 2013USD ($) | Nov. 30, 2013USD ($) | Sep. 30, 2015USD ($) | Mar. 31, 2015USD ($) | Sep. 30, 2014USD ($) | Sep. 30, 2015USD ($)MW | Sep. 30, 2014USD ($) | Dec. 31, 2014USD ($) | Dec. 31, 2013USD ($) | Dec. 31, 2008USD ($) |
Rate Matters [Abstract] | ||||||||||||||||||
Loss on Monticello LCM/EPU project | $ 0 | $ 0 | $ 129,463 | $ 0 | ||||||||||||||
NSP-Minnesota | MPUC Proceeding - Minnesota Electric Rate Case 2014 | ||||||||||||||||||
Rate Matters [Abstract] | ||||||||||||||||||
Public Utilities, Number Of Years Rate Case Is Applicable For | 2 years | |||||||||||||||||
Public Utilities, Requested Return on Equity, Percentage | 10.25% | |||||||||||||||||
Public Utilities, Requested Equity Capital Structure, Percentage | 52.50% | |||||||||||||||||
NSP-Minnesota | MPUC Proceeding - Minnesota Electric Rate Case 2014, Rates 2014 [Member] | ||||||||||||||||||
Rate Matters [Abstract] | ||||||||||||||||||
Public Utilities, Requested Rate Base, Amount | $ 6,670,000 | |||||||||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 193,000 | |||||||||||||||||
Public Utilities, Requested Rate Increase (Decrease), Percentage | 6.90% | |||||||||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount | $ 115,300 | |||||||||||||||||
NSP-Minnesota | MPUC Proceeding - Minnesota Electric Rate Case 2014, Rates 2015 [Member] | ||||||||||||||||||
Rate Matters [Abstract] | ||||||||||||||||||
Public Utilities, Requested Rate Base, Amount | $ 412,000 | |||||||||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 98,000 | |||||||||||||||||
Public Utilities, Requested Rate Increase (Decrease), Percentage | 3.50% | |||||||||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount | 106,000 | |||||||||||||||||
Public Utilities, Amount Of Public Utility's Amended Unadjusted Cumulative Multi-year Rate Increase | $ 221,300 | |||||||||||||||||
NSP-Minnesota | MPUC Proceeding - Nuclear Project Prudency Investigation | ||||||||||||||||||
Rate Matters [Abstract] | ||||||||||||||||||
Nuclear Project Expenditures, Amount | $ 665,000 | |||||||||||||||||
Total Capitalized Nuclear Project Costs | $ 748,000 | |||||||||||||||||
Initial Estimated Nuclear Project Expenditures | $ 320,000 | |||||||||||||||||
Loss on Monticello LCM/EPU project | $ 129,000 | |||||||||||||||||
NSP-Minnesota | FERC Proceeding, MISO ROE Complaint [Member] | ||||||||||||||||||
Rate Matters [Abstract] | ||||||||||||||||||
Public Utilities, Base Return On Equity Charged To Customers Through Transmission Formula Rates | 12.38% | |||||||||||||||||
Public Utilities, ROE Applicable To Transmission Formula Rates In The Regional Transmission Operator's Region, Recommended By Third Parties | 8.67% | 9.15% | ||||||||||||||||
Public Utilities, Maximum Equity Capital Structure Percentage Allowed Per The Complaint | 50.00% | |||||||||||||||||
Public Utilities, ROE Applicable To Transmission Formula Rates In The Regional Transmission Operator's Region, Lower Bound, Percentage | 8.72% | 8.67% | ||||||||||||||||
Public Utilities, ROE Applicable To Transmission Formula Rates In The Regional Transmission Operator's Region, Upper Bound, Percentage | 9.13% | 9.54% | ||||||||||||||||
NSP-Minnesota | Minnesota Public Utilities Commission [Member] | MPUC Proceeding - Minnesota Electric Rate Case 2014 | ||||||||||||||||||
Rate Matters [Abstract] | ||||||||||||||||||
Public Utilities, Approved Rate Increase (Decrease), Amount | $ 149,400 | $ 166,100 | ||||||||||||||||
Public Utilities, Approved Rate Increase (Decrease), Percentage | 5.30% | 5.90% | ||||||||||||||||
Public Utilities; Approved Decrease Related To Disallowance Of Project Costs | $ 18,000 | |||||||||||||||||
Public Utilities, Number Of Years Of Decoupling Pilot | 3 years | |||||||||||||||||
Public Utilities, Percent Cap On Revenue For Decoupling Pilot | 3.00% | |||||||||||||||||
Public Utilities, Approved Decrease Related To Used-and-useful Date Of Project | $ (13,800) | |||||||||||||||||
Estimated Revenue Impact | 145,800 | |||||||||||||||||
NSP-Minnesota | Minnesota Public Utilities Commission [Member] | MPUC Proceeding - Minnesota Electric Rate Case 2014, Rates 2014 [Member] | ||||||||||||||||||
Rate Matters [Abstract] | ||||||||||||||||||
Public Utilities, Interim Rate Increase (Decrease), Amount | $ 127,000 | |||||||||||||||||
Public Utilities, Approved Rate Increase (Decrease), Amount | $ 58,900 | |||||||||||||||||
Public Utilities, Approved Decrease Related To Property Taxes | (3,100) | |||||||||||||||||
NSP-Minnesota | Minnesota Public Utilities Commission [Member] | MPUC Proceeding - Minnesota Electric Rate Case 2014, Rates 2015 [Member] | ||||||||||||||||||
Rate Matters [Abstract] | ||||||||||||||||||
Public Utilities, Approved Rate Increase (Decrease), Amount | $ 125,200 | |||||||||||||||||
Public Utilities, Approved Increase Related To Other, Net | 200 | |||||||||||||||||
Public Utilities, Decrease Related To Interim Rates Effective Date | $ (3,600) | |||||||||||||||||
NSP-Minnesota | Minnesota Public Utilities Commission [Member] | MPUC Proceeding - Nuclear Project Prudency Investigation | ||||||||||||||||||
Rate Matters [Abstract] | ||||||||||||||||||
Public Utilities, Amount Of Recoverable Investment, With Return | $ 415,000 | |||||||||||||||||
Public Utilities, Amount Of Recoverable Investment, Without A Return | $ 333,000 | |||||||||||||||||
Public Utilities, Percentage Of Investment Considered Used And Useful | 50.00% | |||||||||||||||||
NSP-Minnesota | Federal Energy Regulatory Commission (FERC) | FERC Proceeding, MISO ROE Complaint [Member] | ||||||||||||||||||
Rate Matters [Abstract] | ||||||||||||||||||
Public Utilities, Number Of Steps Required For Newly Adopted ROE Discounted Cash Flow Methodology | 2 | |||||||||||||||||
Public Utilities, ROE Basis Point Adder Requested By Third Parties | 50 | |||||||||||||||||
NSP-Minnesota | FERC Staff [Member] | FERC Proceeding, MISO ROE Complaint [Member] | ||||||||||||||||||
Rate Matters [Abstract] | ||||||||||||||||||
Public Utilities, ROE Applicable To Transmission Formula Rates In The Regional Transmission Operator's Region, Recommended By Third Parties | 8.68% | |||||||||||||||||
NSP-Minnesota | MISO TOs [Member] | FERC Proceeding, MISO ROE Complaint [Member] | ||||||||||||||||||
Rate Matters [Abstract] | ||||||||||||||||||
Public Utilities, ROE Applicable To Transmission Formula Rates In The Regional Transmission Operator's Region, Lower Bound, Percentage | 10.80% | |||||||||||||||||
Minimum | NSP-Minnesota | MPUC Proceeding - Nuclear Project Prudency Investigation | ||||||||||||||||||
Rate Matters [Abstract] | ||||||||||||||||||
Facility Generating Capacity, In MW | MW | 600 | |||||||||||||||||
Minimum | NSP-Minnesota | FERC Proceeding, MISO ROE Complaint [Member] | ||||||||||||||||||
Rate Matters [Abstract] | ||||||||||||||||||
Public Utilities, Decrease In Transmission Revenue, Net Of Expense, Due To New ROE Methodology | $ 7,000 | |||||||||||||||||
Maximum | NSP-Minnesota | MPUC Proceeding - Nuclear Project Prudency Investigation | ||||||||||||||||||
Rate Matters [Abstract] | ||||||||||||||||||
Facility Generating Capacity, In MW | MW | 671 | |||||||||||||||||
Maximum | NSP-Minnesota | FERC Proceeding, MISO ROE Complaint [Member] | ||||||||||||||||||
Rate Matters [Abstract] | ||||||||||||||||||
Public Utilities, Decrease In Transmission Revenue, Net Of Expense, Due To New ROE Methodology | $ 9,000 | |||||||||||||||||
Subsequent Event | NSP-Minnesota | MPUC Proceeding - Transmission Cost Recovery Rider Filing 2016 [Member] | ||||||||||||||||||
Rate Matters [Abstract] | ||||||||||||||||||
Public Utilities, Requested Rider Revenue, Amount | $ 19,200 | |||||||||||||||||
Subsequent Event | NSP-Minnesota | MPUC Proceeding - Transmission Cost Recovery Rider Filing 2016 - With Additional Transmission Investment [Member] | ||||||||||||||||||
Rate Matters [Abstract] | ||||||||||||||||||
Public Utilities, Requested Rider Revenue, Amount | 78,300 | |||||||||||||||||
Public Utilities, Additional Transmission Investment, Amount | $ 59,100 | |||||||||||||||||
Public Utilities, Additional Transmission Investment, Number Of Projects | 2 | |||||||||||||||||
Subsequent Event | NSP-Minnesota | SDPUC Proceeding - Infrastructure Rider Filing 2016 [Member] | ||||||||||||||||||
Rate Matters [Abstract] | ||||||||||||||||||
Public Utilities, Requested Rider Revenue, Amount | $ 10,300 | |||||||||||||||||
Subsequent Event | NSP-Minnesota | MISO TOs [Member] | FERC Proceeding, MISO ROE Complaint [Member] | ||||||||||||||||||
Rate Matters [Abstract] | ||||||||||||||||||
Public Utilities, ROE Applicable To Transmission Formula Rates In The Regional Transmission Operator's Region, Lower Bound, Percentage | 10.75% |
Rate Matters Rate Matters - NSP
Rate Matters Rate Matters - NSP-Wisconsin (Details) - NSP-Wisconsin - USD ($) $ in Millions | Oct. 01, 2015 | May. 31, 2015 |
PSCW Proceeding - Electric and Gas Rate Case 2016 - Electric Rates 2016 [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 27.4 | |
Public Utilities, Requested Rate Increase (Decrease), Percentage | 3.90% | |
Public Utilities, Requested Rate Base, Amount | $ 1,200 | |
PSCW Proceeding - Electric and Gas Rate Case 2016 - Gas Rates 2016 [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 5.9 | |
Public Utilities, Requested Rate Increase (Decrease), Percentage | 5.00% | |
Public Utilities, Requested Rate Base, Amount | $ 111.2 | |
PSCW Proceeding - Electric and Gas Rate Case 2016 [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Public Utilities, Requested Return on Equity, Percentage | 10.20% | |
Public Utilities, Requested Equity Capital Structure, Percentage | 52.50% | |
Subsequent Event | PSCW Proceeding - Electric and Gas Rate Case 2016 - Electric Rates 2016 [Member] | Public Service Commission of Wisconsin (PSCW) [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Public Utilities, Recommended Rate Increase (Decrease), Amount | $ 10.4 | |
Public Utilities, Recommended Rate Increase, Percentage | 1.50% | |
Subsequent Event | PSCW Proceeding - Electric and Gas Rate Case 2016 - Gas Rates 2016 [Member] | Public Service Commission of Wisconsin (PSCW) [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Public Utilities, Recommended Rate Increase (Decrease), Amount | $ 3 | |
Public Utilities, Recommended Rate Increase, Percentage | 2.50% | |
Subsequent Event | PSCW Proceeding - Electric and Gas Rate Case 2016 [Member] | Public Service Commission of Wisconsin (PSCW) [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Public Utilities, Recommended Return on Equity, Percentage | 10.00% | |
Public Utilities, Recommended Equity Capital Structure, Percentage | 52.50% | |
Subsequent Event | PSCW Proceeding - Electric and Gas Rate Case 2016 [Member] | Citizens Utility Board [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Public Utilities, Recommended Return on Equity, Percentage | 8.75% |
Rate Matters, PSCo (Details)
Rate Matters, PSCo (Details) - PSCo $ in Millions | 1 Months Ended | 9 Months Ended | 12 Months Ended | |||
Jul. 31, 2015USD ($) | Jun. 30, 2015USD ($) | Mar. 31, 2015USD ($) | Feb. 28, 2015 | Sep. 30, 2015USD ($)GWh | Dec. 31, 2014GWh | |
CPUC Proceeding - Colorado 2015 Multi-Year Gas Rate Case | ||||||
Rate Matters [Abstract] | ||||||
Public Utilities, Requested Equity Capital Structure, Percentage | 56.00% | |||||
CPUC Proceeding - Colorado 2015 Multi-Year Gas Rate Case, Gas Rates 2015 | ||||||
Rate Matters [Abstract] | ||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 40.5 | |||||
Public Utilities, Requested Rate Increase (Decrease), Percentage | 3.50% | |||||
Public Utilities, Requested Return on Equity, Percentage | 10.10% | |||||
Public Utilities, Requested Rate Base, Amount | $ 1,260 | |||||
Public Utilities, Total Revenue Impact | 40.4 | |||||
Public Utilities, Increase In Request By Shift In O&M Expenses Between Rider And Base Rates | $ 0 | |||||
Public Utilities, Decrease In Request by Corrections And Adjustments Based On Rebuttal Testimony | 0 | |||||
Public Utilities, Increase To Base Rate Request From Rebuttal Testimony | 40.5 | |||||
Public Utilities, Total Revenue Impact From Rebuttal Testimony | 40.4 | |||||
CPUC Proceeding - Colorado 2015 Multi-Year Gas Rate Case, Gas Rates 2016 [Member] | ||||||
Rate Matters [Abstract] | ||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 7.6 | |||||
Public Utilities, Requested Rate Increase (Decrease), Percentage | 0.70% | |||||
Public Utilities, Requested Return on Equity, Percentage | 10.10% | |||||
Public Utilities, Requested Rate Base, Amount | $ 1,310 | |||||
Public Utilities, Total Revenue Impact | 29.3 | |||||
Public Utilities, Increase In Request By Shift In O&M Expenses Between Rider And Base Rates | 7 | |||||
Public Utilities, Decrease In Request by Corrections And Adjustments Based On Rebuttal Testimony | 0 | |||||
Public Utilities, Increase To Base Rate Request From Rebuttal Testimony | 14.6 | |||||
Public Utilities, Total Revenue Impact From Rebuttal Testimony | 29.3 | |||||
CPUC Proceeding - Colorado 2015 Multi-Year Gas Rate Case, Gas Rates 2017 [Member] | ||||||
Rate Matters [Abstract] | ||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 18.1 | |||||
Public Utilities, Requested Rate Increase (Decrease), Percentage | 1.50% | |||||
Public Utilities, Requested Return on Equity, Percentage | 10.30% | |||||
Public Utilities, Requested Rate Base, Amount | $ 1,360 | |||||
Public Utilities, Total Revenue Impact | 39.3 | |||||
Public Utilities, Increase In Request By Shift In O&M Expenses Between Rider And Base Rates | 6.4 | |||||
Public Utilities, Decrease In Request by Corrections And Adjustments Based On Rebuttal Testimony | (7.7) | |||||
Public Utilities, Increase To Base Rate Request From Rebuttal Testimony | 16.8 | |||||
Public Utilities, Total Revenue Impact From Rebuttal Testimony | 38.5 | |||||
CPUC Proceeding - Colorado 2015 Multi-Year Gas Rate Case, Gas Rates PSIA Rider 2015 [Member] | ||||||
Rate Matters [Abstract] | ||||||
Public Utilities, Revenue Impact Of Requested Rider | (0.1) | |||||
Public Utilities, Increase (Decrease) To Rider Revenues Request Related To Rebuttal Testimony | (0.1) | |||||
Public Utilities, Revenue Projection Of Requested Rider | 67 | |||||
CPUC Proceeding - Colorado 2015 Multi-Year Gas Rate Case, Gas Rates PSIA Rider 2016 [Member] | ||||||
Rate Matters [Abstract] | ||||||
Public Utilities, Revenue Impact Of Requested Rider | 21.7 | |||||
Public Utilities, Increase (Decrease) To Rider Revenues Request Related To Rebuttal Testimony | 14.7 | |||||
Public Utilities, Revenue Projection Of Requested Rider | 81.7 | |||||
CPUC Proceeding - Colorado 2015 Multi-Year Gas Rate Case, Gas Rates PSIA Rider 2017 [Member] | ||||||
Rate Matters [Abstract] | ||||||
Public Utilities, Revenue Impact Of Requested Rider | 21.2 | |||||
Public Utilities, Increase (Decrease) To Rider Revenues Request Related To Rebuttal Testimony | 21.7 | |||||
Public Utilities, Revenue Projection Of Requested Rider | 103.4 | |||||
CPUC Proceeding - Annual Electric Earnings Test | ||||||
Rate Matters [Abstract] | ||||||
Public Utilities, Return On Equity Threshold For Earnings Sharing For 2015 Through 2017 | 9.83% | |||||
Demand Side Management Cost Adjustment, 2015 [Member] | ||||||
Rate Matters [Abstract] | ||||||
Public Utilities, Approved Electric Demand Side Management Budget | 81.6 | |||||
Public Utilities, Approved Gas Demand Side Management Budget | 13.1 | |||||
Demand Side Management Cost Adjustment [Member] | ||||||
Rate Matters [Abstract] | ||||||
Public Utilities, Incentive Award Upon Achieving Savings Goal | $ 5 | |||||
Public Utilities, Percentage Of Net Economic Benefits On Which Incentive Is Earned | 5.00% | |||||
Public Utilities, Maximum Annual Incentive | $ 30 | |||||
Demand Side Management Cost Adjustment, 2016 [Member] | ||||||
Rate Matters [Abstract] | ||||||
Public Utilities, Approved Electric Demand Side Management Budget | 78.7 | |||||
Public Utilities, Approved Gas Demand Side Management Budget | $ 13.6 | |||||
Colorado Public Utilities Commission Staff (CPUC) | CPUC Proceeding - Colorado 2015 Multi-Year Gas Rate Case, Gas Rates 2015 | ||||||
Rate Matters [Abstract] | ||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | 40.5 | |||||
Public Utilities, Decrease To Requested Return On Equity | $ (12.8) | |||||
Public Utilities, Decrease To Cost Of Debt And Capital Structure | (12.8) | |||||
Public Utilities, Increase (Decrease) Related to Pipeline Adjustment | (11.2) | |||||
Public Utilities, Decrease In Request To Move To Historical Test Year | (10.5) | |||||
Public Utilities, Decrease To O&M Expenses | (3.5) | |||||
Public Utilities, Decrease Related To Other, Net | (4.4) | |||||
Public Utilities, Total Decrease Adjustment Related to Requested Rate Increase | (55.2) | |||||
Public Utilities, Recommended Rate Increase (Decrease), Amount | (14.7) | |||||
Colorado Public Utilities Commission Staff (CPUC) | CPUC Proceeding - Colorado 2015 Multi-Year Gas Rate Case, Gas Rates PSIA Rider 2016 [Member] | ||||||
Rate Matters [Abstract] | ||||||
Public Utilities, Revenue Impact Of Requested Rider | 21.7 | |||||
Public Utilities, Decrease In Request By Transfer Of Operating And Maintenance Expense To Base Rates | (24.1) | |||||
Public Utilities, Decrease To Return On Equity And Capital Structure | (8.2) | |||||
Public Utilities, Increase In Request By Transfer Meter Replacement Program From Base Rates To Rider | 1.7 | |||||
Public Utilities, Recommended Rider Increase (Decrease) | (8.9) | |||||
Colorado Public Utilities Commission Staff (CPUC) | CPUC Proceeding - Colorado 2015 Multi-Year Gas Rate Case, Gas Rates PSIA Rider 2017 [Member] | ||||||
Rate Matters [Abstract] | ||||||
Public Utilities, Revenue Impact Of Requested Rider | 21.2 | |||||
Public Utilities, Decrease In Request By Transfer Of Operating And Maintenance Expense To Base Rates | (2) | |||||
Public Utilities, Decrease To Return On Equity And Capital Structure | (3.6) | |||||
Public Utilities, Increase In Request By Transfer Meter Replacement Program From Base Rates To Rider | 1.7 | |||||
Public Utilities, Recommended Rider Increase (Decrease) | 17.3 | |||||
Colorado Public Utilities Commission Staff (CPUC) | Demand Side Management Cost Adjustment 2014 [Member] | ||||||
Rate Matters [Abstract] | ||||||
Public Utilities, Maximum Savings Goal (In GWh) | GWh | 384 | |||||
Colorado Public Utilities Commission Staff (CPUC) | Demand Side Management Cost Adjustment, 2015 [Member] | ||||||
Rate Matters [Abstract] | ||||||
Public Utilities, Maximum Savings Goal (In GWh) | GWh | 400 | |||||
Colorado Public Utilities Commission Staff (CPUC) | Demand Side Management Cost Adjustment, 2015 through 2020 [Member] | ||||||
Rate Matters [Abstract] | ||||||
Public Utilities, Maximum Savings Goal (In GWh) | GWh | 400 | |||||
Public Utilities, Annual Earnings Limit | $ 84.3 | |||||
Office of Consumer Counsel [Member] | CPUC Proceeding - Colorado 2015 Multi-Year Gas Rate Case, Gas Rates 2015 | ||||||
Rate Matters [Abstract] | ||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 40.5 | |||||
Public Utilities, Decrease To Requested Return On Equity | (13.7) | |||||
Public Utilities, Decrease To Cost Of Debt And Capital Structure | (4.8) | |||||
Public Utilities, Increase (Decrease) Related to Pipeline Adjustment | 4.8 | |||||
Public Utilities, Decrease In Request To Move To Historical Test Year | (16.4) | |||||
Public Utilities, Decrease To O&M Expenses | (2.7) | |||||
Public Utilities, Decrease Related To Other, Net | (1.9) | |||||
Public Utilities, Total Decrease Adjustment Related to Requested Rate Increase | (34.7) | |||||
Public Utilities, Recommended Rate Increase (Decrease), Amount | $ 5.8 |
Rate Matters, SPS (Details)
Rate Matters, SPS (Details) $ in Thousands | Oct. 29, 2015USD ($) | Oct. 28, 2015USD ($) | Oct. 12, 2015USD ($) | Oct. 31, 2015USD ($) | Aug. 31, 2015USD ($) | Jun. 30, 2015USD ($) | May. 31, 2015USD ($) | Mar. 31, 2015USD ($) | Jan. 31, 2015 | Dec. 31, 2014USD ($) | Oct. 31, 2014 | Dec. 31, 2013USD ($) | Aug. 31, 2013Factor | Jul. 31, 2013 | Mar. 31, 2013 | Apr. 30, 2012 | Sep. 30, 2015USD ($) | ||
Public Utilities, General Disclosures [Line Items] | |||||||||||||||||||
Other Liabilities, Current | $ 475,119 | $ 561,579 | |||||||||||||||||
SPS | Global Settlement Agreement [Member] | |||||||||||||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||||||||||||
Number Of Customers For Which A Public Utility Proposes To Revise Formula Rates | 4 | ||||||||||||||||||
Public Utilities, Disclosure Of Regulatory Matters Pending | 9 | ||||||||||||||||||
Public Utilities, Number Of Coincident Peaks Used As Demand Allocator, Revised | 3 | ||||||||||||||||||
Public Utilities, Base Return On Equity Charged To Customers Through Transmission Formula Rates, Percentage | 10.50% | ||||||||||||||||||
Public Utilities, Incremental ROE Basis Point Increase | 50 | ||||||||||||||||||
Public Utilities, Base Return On Equity Charged To Customers Through Production Formula Rates, Percentage | 10.00% | ||||||||||||||||||
Number Of Coincident Peaks Utilized As Demand Allocator | 12 | ||||||||||||||||||
Number Of Coincident Peaks Used As Demand Allocator, Original | 12 | ||||||||||||||||||
Number of Days Until Settlement Agreement Effective After Approval | 30 days | ||||||||||||||||||
SPS | Federal Energy Regulatory Commission (FERC) Orders [Member] | |||||||||||||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||||||||||||
Number Of Customers For Which A Public Utility Proposes To Revise Formula Rates | 4 | ||||||||||||||||||
Number Of Coincident Peaks Used As Demand Allocator, Original | 12 | ||||||||||||||||||
Number Of Components Included In Regulatory Proceeding | Factor | 2 | ||||||||||||||||||
Current Year Pre-tax Earnings Impact Of Regulatory Proceedings | $ 1,900 | ||||||||||||||||||
SPS | Wholesale Electric Rate Complaint [Member] | |||||||||||||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||||||||||||
Public Utilities, Base Return On Equity Charged To Customers Through Transmission Formula Rates, Percentage | 11.27% | ||||||||||||||||||
Public Utilities, Base Return On Equity Charged To Customers Through Production Formula Rates, Percentage | 10.25% | ||||||||||||||||||
Public Utilities, Base Return On Equity Requested Charged To Customers Through Production Formula Rates, Percentage | 8.61% | 9.15% | 9.15% | ||||||||||||||||
Public Utilities, Base Return On Equity Requested By Customers To Be Charged Through Transmission Formula Rates, Percentage | 9.11% | 9.65% | 9.65% | ||||||||||||||||
SPS | Texas 2015 Electric Rate Case | |||||||||||||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 42,100 | [1] | $ 64,800 | ||||||||||||||||
Public Utilities, Requested Rate Increase (Decrease), Percentage | 4.40% | 6.70% | |||||||||||||||||
Public Utilities, Requested Return on Equity, Percentage | 10.25% | ||||||||||||||||||
Public Utilities, Requested Rate Base, Amount | $ 1,600,000 | ||||||||||||||||||
Public Utilities, Requested Equity Capital Structure, Percentage | 53.97% | ||||||||||||||||||
Public Utilities, Revised Requested Rate Increase | $ 58,900 | ||||||||||||||||||
Public Utilities, Additional Capital Investment | $ 392,000 | ||||||||||||||||||
Public Utilities, Post Test Year Decrease Adjustments | $ 0 | ||||||||||||||||||
Public Utilities, Decrease To Requested Return On Equity | 0 | ||||||||||||||||||
Public Utilities, Decrease To Rate Base | 0 | ||||||||||||||||||
Public Utilities, Decrease To O&M Expenses | (1,600) | ||||||||||||||||||
Public Utilities, Decrease To Depreciation Expense | 0 | ||||||||||||||||||
Public Utilities, Decrease To Property Taxes | (1,800) | ||||||||||||||||||
Public Utilities, Decrease To Revenue Adjustments | 0 | ||||||||||||||||||
Public Utilities, Decrease To Wholesale Load Reductions | 0 | ||||||||||||||||||
Public Utilities, Decrease To Transmission Expansion Plan | (7,300) | ||||||||||||||||||
Public Utilities, Decrease Related To Other, Net | (1,800) | ||||||||||||||||||
Public Utilities, Requested Rate Increase (Including Case Expenses), Amount | 46,400 | ||||||||||||||||||
Public Utilities, Decrease Adjustment To Move Rate Case Expenses To Separate Docket | $ (4,300) | ||||||||||||||||||
SPS | Golden Spread [Member] | Global Settlement Agreement [Member] | |||||||||||||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||||||||||||
Public Utilities, Regulatory Settlement To Be Paid | $ 44,900 | ||||||||||||||||||
SPS | Public Service Company of New Mexico [Member] | Global Settlement Agreement [Member] | |||||||||||||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||||||||||||
Public Utilities, Regulatory Settlement To Be Paid | $ 4,200 | ||||||||||||||||||
SPS | Alliance of Xcel Municipalities [Member] | Texas 2015 Electric Rate Case | |||||||||||||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||||||||||||
Public Utilities, Revised Requested Rate Increase | 58,900 | ||||||||||||||||||
Public Utilities, Recommended Rate Increase (Decrease), Amount | $ (13,600) | ||||||||||||||||||
Public Utilities, Post Test Year Decrease Adjustments | (11,300) | ||||||||||||||||||
Public Utilities, Decrease To Requested Return On Equity | (10,900) | ||||||||||||||||||
Public Utilities, Decrease To Rate Base | (6,200) | ||||||||||||||||||
Public Utilities, Decrease To O&M Expenses | (13,700) | ||||||||||||||||||
Public Utilities, Decrease To Depreciation Expense | (13,300) | ||||||||||||||||||
Public Utilities, Decrease To Property Taxes | 0 | ||||||||||||||||||
Public Utilities, Decrease To Revenue Adjustments | (2,200) | ||||||||||||||||||
Public Utilities, Decrease To Wholesale Load Reductions | (13,200) | ||||||||||||||||||
Public Utilities, Decrease To Transmission Expansion Plan | 0 | ||||||||||||||||||
Public Utilities, Decrease Related To Other, Net | (1,700) | ||||||||||||||||||
Public Utilities, Recommended Rate Increase (Decrease) (Including Case Expenses) | (13,600) | ||||||||||||||||||
Public Utilities, Decrease Adjustment To Move Rate Case Expenses To Separate Docket | 0 | ||||||||||||||||||
SPS | Office of Public Utility Counsel [Member] | Texas 2015 Electric Rate Case | |||||||||||||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||||||||||||
Public Utilities, Revised Requested Rate Increase | 58,900 | ||||||||||||||||||
Public Utilities, Recommended Rate Increase (Decrease), Amount | 1,800 | ||||||||||||||||||
Public Utilities, Post Test Year Decrease Adjustments | (23,800) | ||||||||||||||||||
Public Utilities, Decrease To Requested Return On Equity | (13,500) | ||||||||||||||||||
Public Utilities, Decrease To Rate Base | (6,800) | ||||||||||||||||||
Public Utilities, Decrease To O&M Expenses | (11,000) | ||||||||||||||||||
Public Utilities, Decrease To Depreciation Expense | 0 | ||||||||||||||||||
Public Utilities, Decrease To Property Taxes | (1,200) | ||||||||||||||||||
Public Utilities, Decrease To Revenue Adjustments | (200) | ||||||||||||||||||
Public Utilities, Decrease To Wholesale Load Reductions | 0 | ||||||||||||||||||
Public Utilities, Decrease To Transmission Expansion Plan | 0 | ||||||||||||||||||
Public Utilities, Decrease Related To Other, Net | (600) | ||||||||||||||||||
Public Utilities, Recommended Rate Increase (Decrease) (Including Case Expenses) | 1,800 | ||||||||||||||||||
Public Utilities, Decrease Adjustment To Move Rate Case Expenses To Separate Docket | 0 | ||||||||||||||||||
SPS | Public Utility Commission of Texas Staff [Member] | Texas 2015 Electric Rate Case | |||||||||||||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||||||||||||
Public Utilities, Revised Requested Rate Increase | $ 58,900 | ||||||||||||||||||
Public Utilities, Recommended Rate Increase (Decrease), Amount | (2,600) | ||||||||||||||||||
Public Utilities, Post Test Year Decrease Adjustments | (23,800) | ||||||||||||||||||
Public Utilities, Decrease To Requested Return On Equity | (12,100) | ||||||||||||||||||
Public Utilities, Decrease To Rate Base | 0 | ||||||||||||||||||
Public Utilities, Decrease To O&M Expenses | (7,900) | ||||||||||||||||||
Public Utilities, Decrease To Depreciation Expense | 0 | ||||||||||||||||||
Public Utilities, Decrease To Property Taxes | (4,400) | ||||||||||||||||||
Public Utilities, Decrease To Revenue Adjustments | 0 | ||||||||||||||||||
Public Utilities, Decrease To Wholesale Load Reductions | (11,100) | ||||||||||||||||||
Public Utilities, Decrease To Transmission Expansion Plan | 0 | ||||||||||||||||||
Public Utilities, Decrease Related To Other, Net | (2,200) | ||||||||||||||||||
Public Utilities, Recommended Rate Increase (Decrease) (Including Case Expenses) | (2,600) | ||||||||||||||||||
Public Utilities, Decrease Adjustment To Move Rate Case Expenses To Separate Docket | $ 0 | ||||||||||||||||||
SPS | Federal Energy Regulatory Commission (FERC) | Federal Energy Regulatory Commission (FERC) Orders [Member] | |||||||||||||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||||||||||||
Public Utilities, Number Of Coincident Peaks Used As Demand Allocator, Revised | 3 | ||||||||||||||||||
Number Of Coincident Peaks Used As Demand Allocator, Original | 12 | ||||||||||||||||||
Other Liabilities, Current | $ 50,400 | ||||||||||||||||||
Subsequent Event | SPS | Global Settlement Agreement [Member] | |||||||||||||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||||||||||||
Public Utilities, Estimated Net Gain Expected To Be Recognized | $ 7,900 | ||||||||||||||||||
Subsequent Event | SPS | New Mexico 2015 Electric Rate Case [Member] | |||||||||||||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 45,400 | ||||||||||||||||||
Public Utilities, Requested Return on Equity, Percentage | 10.25% | ||||||||||||||||||
Public Utilities, Requested Rate Base, Amount | $ 734,000 | ||||||||||||||||||
Public Utilities, Requested Equity Capital Structure, Percentage | 53.97% | ||||||||||||||||||
Public Utilities, Net Requested Increase Base Rates, Amount | $ 24,300 | ||||||||||||||||||
Public Utilities, Decrease In Base Fuel Revenues | 21,100 | ||||||||||||||||||
Public Utilities, Base Period Deficiency | 19,700 | ||||||||||||||||||
Public Utilities, Post Test Year Adjustment Related To Capital Expenditures | 12,300 | ||||||||||||||||||
Public Utilities, Depreciation Expense | 3,700 | ||||||||||||||||||
Public Utilities, SPP Transmission Expansion Plan | $ 2,000 | ||||||||||||||||||
Public Utilities, Approved Return on Equity, Percentage | 9.96% | ||||||||||||||||||
Public Utilities, ROE | $ 1,600 | ||||||||||||||||||
Public Utilities, Rider Costs To Be Recovered Through Base Rates, Amount | 1,300 | ||||||||||||||||||
Public Utilities, Other Net | $ 4,800 | ||||||||||||||||||
Subsequent Event | SPS | Administrative Law Judge [Member] | Texas 2015 Electric Rate Case | |||||||||||||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||||||||||||
Public Utilities, Recommended Rate Increase (Decrease), Amount | [1] | $ 1,200 | |||||||||||||||||
Public Utilities, Recommended Return on Equity, Percentage | 9.70% | ||||||||||||||||||
Public Utilities, Recommended Equity Capital Structure, Percentage | 53.97% | ||||||||||||||||||
Public Utilities, Post Test Year Decrease Adjustments | [1] | $ (16,700) | |||||||||||||||||
Public Utilities, Decrease To Requested Return On Equity | [1] | (6,300) | |||||||||||||||||
Public Utilities, Decrease To Rate Base | [1] | 0 | |||||||||||||||||
Public Utilities, Decrease To O&M Expenses | [1] | (5,300) | |||||||||||||||||
Public Utilities, Decrease To Depreciation Expense | [1] | (3,900) | |||||||||||||||||
Public Utilities, Decrease To Property Taxes | [1] | (3,700) | |||||||||||||||||
Public Utilities, Decrease To Revenue Adjustments | [1] | 0 | |||||||||||||||||
Public Utilities, Decrease To Wholesale Load Reductions | [1] | 0 | |||||||||||||||||
Public Utilities, Decrease To Transmission Expansion Plan | [1] | (4,200) | |||||||||||||||||
Public Utilities, Decrease Related To Other, Net | [1] | (600) | |||||||||||||||||
Public Utilities, Recommended Rate Increase (Decrease) (Including Case Expenses) | [1] | 1,400 | |||||||||||||||||
Public Utilities, Decrease Adjustment To Move Rate Case Expenses To Separate Docket | [1] | $ (200) | |||||||||||||||||
Public Utilities, Revised Recommended Rate Increase (Decrease), Amount | $ 14,400 | ||||||||||||||||||
Certain Texas Transmission Assets [Member] | SPS | Federal Energy Regulatory Commission (FERC) | |||||||||||||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||||||||||||
Current Year Pre-tax Earnings Impact Of Regulatory Proceedings | $ 13,600 | ||||||||||||||||||
Public Utilities, Number Of Substations Included In Purchase And Sale Agreement | 2 | ||||||||||||||||||
Proceeds From Sale Of Other Property, Plant, And Equipment | 37,100 | ||||||||||||||||||
Public Utilities, Regulatory Liabilities Recognized For Jurisdictional Gain Sharing | $ 7,200 | ||||||||||||||||||
[1] | The ALJs’ recommendation reflects proposed adjustments to SPS’ rebuttal testimony, as of Oct. 12, 2015, which supports a $42.1 million rate increase. |
Commitments and Contingencies,
Commitments and Contingencies, Purchased Power Agreements (Details) - Independent Power Producing Entities - MW | 9 Months Ended | 12 Months Ended |
Sep. 30, 2015 | Dec. 31, 2014 | |
Purchased Power Agreements [Abstract] | ||
Generating capacity under long term purchased power agreements | 3,698 | 3,698 |
Purchase Power Agreement Duration, Maximum (year) | 2,033 | 2,033 |
Commitments and Contingencies44
Commitments and Contingencies, Guarantees and Indemnifications (Details) - USD ($) | Sep. 30, 2015 | Dec. 31, 2014 |
Guarantees [Abstract] | ||
Assets held as collateral | $ 0 | $ 0 |
Payment or Performance Guarantee | ||
Guarantees [Abstract] | ||
Guarantees issued and outstanding | 12,900,000 | 13,900,000 |
Current exposure under these guarantees | 100,000 | 200,000 |
Payment or Performance Guarantee | Surety Bonds | ||
Guarantees [Abstract] | ||
Guarantees issued and outstanding | $ 42,500,000 | $ 31,400,000 |
Commitments and Contingencies45
Commitments and Contingencies, Environmental Contingencies - Site Contingencies (Details) $ in Millions | 1 Months Ended | 9 Months Ended | |
May. 31, 2015USD ($) | Sep. 30, 2015USD ($)SiteParties | Dec. 31, 2014USD ($) | |
NSP-Wisconsin | Ashland MGP Site | |||
Site Contingency [Line Items] | |||
Accrual for Environmental Loss Contingencies, Gross | $ 95.7 | $ 107.6 | |
Ashland Manufactured Gas Plant (MGP) Site [Abstract] | |||
Number of properties not owned included in superfund site | Site | 2 | ||
Number of PRPs that have reached a settlement in principle | Parties | 2 | ||
Liability for estimated cost of remediating sites, current | $ 16.6 | $ 28.9 | |
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 | ||
Public Utilities, Annual recovery collected through base rates | $ 4.7 | ||
NSP-Wisconsin | Ashland MGP Site - Phase I Project Area | |||
Site Contingency [Line Items] | |||
Accrual for Environmental Loss Contingencies, Gross | $ 57 | ||
Ashland Manufactured Gas Plant (MGP) Site [Abstract] | |||
Estimated amount spent on cleanup | $ 39 | ||
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 | ||
NSP-Wisconsin | Ashland MGP Site - Sediments | |||
Ashland Manufactured Gas Plant (MGP) Site [Abstract] | |||
Estimated cost of remediating site, low end of range | 63 | ||
Estimated cost of remediating site, high end of range | $ 77 | ||
Potential percent of increase to the high end of the range of estimated site remediation costs (in hundredths) | 50.00% | ||
Potential percent of decrease to the low end of the range of estimated site remediation costs (in hundredths) | 30.00% | ||
NSP-Minnesota | Fargo MGP Site [Member] | |||
Site Contingency [Line Items] | |||
Accrual for Environmental Loss Contingencies, Gross | $ 1.4 | ||
Railroad PRPs [Member] | NSP-Wisconsin | Ashland MGP Site | |||
Ashland Manufactured Gas Plant (MGP) Site [Abstract] | |||
Site Contingency, Recovery from Third Party of Environmental Remediation Cost | 10.5 | ||
LE Myers Co. [Member] | NSP-Wisconsin | Ashland MGP Site | |||
Ashland Manufactured Gas Plant (MGP) Site [Abstract] | |||
Site Contingency, Recovery from Third Party of Environmental Remediation Cost | $ 5.4 | ||
PSCW Proceeding - Electric and Gas Rate Case 2016 - Gas Rates 2016 [Member] | NSP-Wisconsin | Ashland MGP Site | |||
Ashland Manufactured Gas Plant (MGP) Site [Abstract] | |||
Public Utilities, Requested annual recovery collected through base rates | $ 7.6 |
Commitments and Contingencies46
Commitments and Contingencies, Environmental Contingencies - Unrecorded Unconditional Purchase Obligation (Details) $ in Millions | 1 Months Ended | 9 Months Ended | |||||||||
Oct. 31, 2015 | Sep. 30, 2015USD ($)MW | Jul. 31, 2015 | Dec. 31, 2014USD ($) | Apr. 30, 2012MW | Sep. 30, 2015USD ($)MW | Oct. 30, 2015Period | May. 31, 2015Parties | Apr. 30, 2015USD ($) | Apr. 30, 2014Issue | Dec. 31, 2010KilnBoilerGroup | |
Cross-State Air Pollution Rule | |||||||||||
Environmental Requirements [Abstract] | |||||||||||
Number of issues on which the D.C. Circuit overturned the CSAPR | Issue | 2 | ||||||||||
Electric Generating Unit Mercury and Air Toxics Standards Rule | |||||||||||
Environmental Requirements [Abstract] | |||||||||||
Generating capacity (in MW) | MW | 25 | ||||||||||
Implementation of the National Ambient Air Quality Standard for Sulfur Dioxide | |||||||||||
Environmental Requirements [Abstract] | |||||||||||
Number of phases under a consent decree which the EPA is requiring states to evaluate areas for attainment | 3 | ||||||||||
Number of months in which the state would have to submit an implementation plan for the respective nonattainment areas | 18 months | ||||||||||
Number of years for the state to achieve the designated attainment standard | 5 years | ||||||||||
PSCo | Regional Haze Rules | |||||||||||
Environmental Requirements [Abstract] | |||||||||||
Number of environmental groups who petitioned the U.S. Department of the Interior | Group | 2 | ||||||||||
Number of coal-fired boilers | Boiler | 12 | ||||||||||
Number of coal-fired cement kilns | Kiln | 1 | ||||||||||
NSP-Minnesota | Electric Generating Unit Mercury and Air Toxics Standards Rule | |||||||||||
Environmental Requirements [Abstract] | |||||||||||
Number of plants retired to comply with regulation | 2 | ||||||||||
NSP-Minnesota | Regional Haze Rules | |||||||||||
Environmental Requirements [Abstract] | |||||||||||
Amount spent on installation of emission controls | $ 46.9 | ||||||||||
NSP-Minnesota | Reasonably Attributable Visibility Impairment | |||||||||||
Environmental Requirements [Abstract] | |||||||||||
Number of environmental advocacy organizations who filed a settlement agreement | Parties | 6 | ||||||||||
Number of months the EPA has to recommend and adopt a rule which will set the agreed-upon sulfur dioxide emissions | 7 months | ||||||||||
SPS | Cross-State Air Pollution Rule | |||||||||||
Environmental Requirements [Abstract] | |||||||||||
Generating capacity (in MW) | MW | 700 | 700 | |||||||||
SPS | Electric Generating Unit Mercury and Air Toxics Standards Rule | |||||||||||
Environmental Requirements [Abstract] | |||||||||||
Cost of capital incurred for installed mercury controls | $ 8 | ||||||||||
SPS | Regional Haze Rules | |||||||||||
Environmental Requirements [Abstract] | |||||||||||
Number of years to comply with proposed regulation | 5 years | ||||||||||
SPS | Implementation of the National Ambient Air Quality Standard for Sulfur Dioxide | |||||||||||
Environmental Requirements [Abstract] | |||||||||||
Number of units which sulfur dioxide controls could be required | 1 | ||||||||||
NSP-Wisconsin | Industrial Boiler Maximum Achievable Control Technology Rules | |||||||||||
Environmental Requirements [Abstract] | |||||||||||
Estimated cost to comply with regulation | $ 20 | ||||||||||
Subsequent Event | Green House Gas Emission Standard for Existing Sources | |||||||||||
Environmental Requirements [Abstract] | |||||||||||
Duration period for public comment (in days) | 90 days | ||||||||||
Percentage of a comparable new plant's capital cost which would have to be exceeded to consider a project as a reconstruction under the proposed GHG NSPS for Modified and Reconstructed Power Plants | 50.00% | ||||||||||
Subsequent Event | National Ambient Air Quality Standards for Ozone | |||||||||||
Environmental Requirements [Abstract] | |||||||||||
Number of hours measured for standard | Period | 8 | ||||||||||
Current level of air quality concentrations (in parts per billion) | 75 | ||||||||||
Proposed level of air quality concentrations (in parts per billion) | 70 | ||||||||||
Subsequent Event | SPS | National Ambient Air Quality Standards for Ozone | |||||||||||
Environmental Requirements [Abstract] | |||||||||||
Proposed level of air quality concentrations (in parts per billion) | 70 | ||||||||||
Capital Addition Purchase Commitments | PSCo | Regional Haze Rules | |||||||||||
Environmental Requirements [Abstract] | |||||||||||
Liability for estimated cost to comply with regulation | 82.4 | $ 82.4 | |||||||||
Capital Addition Purchase Commitments | SPS | Regional Haze Rules | |||||||||||
Environmental Requirements [Abstract] | |||||||||||
Liability for estimated cost to comply with regulation | 600 | 600 | |||||||||
Estimated annual operating cost to comply with proposed regulation | $ 10.4 | $ 10.4 | |||||||||
Minimum | Electric Generating Unit Mercury and Air Toxics Standards Rule | |||||||||||
Environmental Requirements [Abstract] | |||||||||||
Number of years before affected facilities must demonstrate compliance | 3 years | ||||||||||
Maximum | Electric Generating Unit Mercury and Air Toxics Standards Rule | |||||||||||
Environmental Requirements [Abstract] | |||||||||||
Number of years before affected facilities must demonstrate compliance | 4 years |
Commitments and Contingencies47
Commitments and Contingencies, Legal Contingencies (Details) | 1 Months Ended | 3 Months Ended | 9 Months Ended | 12 Months Ended | 13 Months Ended | 84 Months Ended | |||||||
Oct. 31, 2015USD ($) | May. 31, 2015USD ($) | Dec. 31, 2014USD ($) | Jul. 31, 2011USD ($) | Sep. 30, 2007USD ($) | Sep. 30, 2015USD ($) | Sep. 30, 2014USD ($) | Sep. 30, 2015USD ($)Factor | Sep. 30, 2014USD ($) | Dec. 31, 2011 | Dec. 31, 2009 | Jun. 30, 2001USD ($) | Dec. 31, 2009 | |
Legal Contingencies [Abstract] | |||||||||||||
Sales to the City of Seattle | $ 2,901,312,000 | $ 2,869,807,000 | $ 8,378,665,000 | $ 8,757,507,000 | |||||||||
Gas Trading Litigation | |||||||||||||
Legal Contingencies [Abstract] | |||||||||||||
Loss Contingency, Number of Plaintiffs | 7 | 13 | |||||||||||
Loss Contingency, Claims Settled, Number | 5 | ||||||||||||
Loss Contingency, Claims Dismissed, Number | 6 | 1 | |||||||||||
PSCo | Pacific Northwest FERC Refund Proceeding | |||||||||||||
Legal Contingencies [Abstract] | |||||||||||||
Minimum amount of damages claimed by plaintiff | 34,000,000 | 34,000,000 | |||||||||||
Sales to the City of Seattle | $ 50,000,000 | ||||||||||||
Estimated City of Seattle's claim for refunds not including interest | 28,000,000 | $ 28,000,000 | |||||||||||
Number of factors considered in assessment | Factor | 2 | ||||||||||||
Accrual for legal contingency | 0 | $ 0 | |||||||||||
NSP-Minnesota | Fibrominn Fuel Handling Dispute | |||||||||||||
Legal Contingencies [Abstract] | |||||||||||||
Minimum amount of damages claimed by plaintiff | 20,000,000 | 20,000,000 | |||||||||||
Accrual for legal contingency | $ 0 | 0 | |||||||||||
NSP-Minnesota | Nuclear Waste Disposal Litigation | |||||||||||||
Legal Contingencies [Abstract] | |||||||||||||
Damages awarded | $ 116,500,000 | ||||||||||||
Cash payment received under settlement agreement | $ 32,800,000 | $ 100,000,000 | 214,700,000 | ||||||||||
Litigation Settlement, Amount of Claim | $ 13,200,000 | $ 13,100,000 | |||||||||||
NSP-Wisconsin | Gas Trading Litigation | |||||||||||||
Legal Contingencies [Abstract] | |||||||||||||
Loss Contingency, Number of Plaintiffs | 2 | ||||||||||||
Subsequent Event | Limited Partnership Investment | |||||||||||||
Legal Contingencies [Abstract] | |||||||||||||
Length Of Commitment (In Years) | 5 years | ||||||||||||
Maximum | Subsequent Event | Limited Partnership Investment | |||||||||||||
Legal Contingencies [Abstract] | |||||||||||||
Maximum Committed Future Investment | $ 50,000,000 |
Borrowings and Other Financin48
Borrowings and Other Financing Instruments, Commercial Paper (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended |
Sep. 30, 2015 | Dec. 31, 2014 | |
Short-term Debt [Line Items] | ||
Amount outstanding at period end | $ 64,000 | $ 1,019,500 |
Commercial Paper | ||
Short-term Debt [Line Items] | ||
Borrowing limit | 2,750,000 | 2,750,000 |
Amount outstanding at period end | 64,000 | 1,020,000 |
Average amount outstanding | 272,000 | 841,000 |
Maximum amount outstanding | $ 478,000 | $ 1,200,000 |
Weighted average interest rate, computed on a daily basis (percentage) | 0.46% | 0.33% |
Weighted average interest rate at period end (percentage) | 0.38% | 0.56% |
Borrowings and Other Financin49
Borrowings and Other Financing Instruments, Letters of Credit (Details) - USD ($) $ in Thousands | 9 Months Ended | |
Sep. 30, 2015 | Dec. 31, 2014 | |
Line of Credit Facility [Line Items] | ||
Amount outstanding at period end | $ 64,000 | $ 1,019,500 |
Letter of Credit | ||
Line of Credit Facility [Line Items] | ||
Amount outstanding at period end | $ 39,000 | $ 61,000 |
Letter of Credit | Letter of Credit | ||
Line of Credit Facility [Line Items] | ||
Term of letters of credit (in years) | 1 year |
Borrowings and Other Financin50
Borrowings and Other Financing Instruments, Credit Facilities (Details) - Credit Facilities $ in Millions | Sep. 30, 2015USD ($) | |
Line of Credit Facility [Line Items] | ||
Credit Facility | $ 2,750 | [1] |
Drawn | 103 | [2] |
Available | 2,647 | |
Direct advances on the credit facility outstanding | 0 | |
Xcel Energy Inc. | ||
Line of Credit Facility [Line Items] | ||
Credit Facility | 1,000 | [1] |
Drawn | 64 | [2] |
Available | 936 | |
PSCo | ||
Line of Credit Facility [Line Items] | ||
Credit Facility | 700 | [1] |
Drawn | 5 | [2] |
Available | 695 | |
NSP-Minnesota | ||
Line of Credit Facility [Line Items] | ||
Credit Facility | 500 | [1] |
Drawn | 24 | [2] |
Available | 476 | |
SPS | ||
Line of Credit Facility [Line Items] | ||
Credit Facility | 400 | [1] |
Drawn | 10 | [2] |
Available | 390 | |
NSP-Wisconsin | ||
Line of Credit Facility [Line Items] | ||
Credit Facility | 150 | [1] |
Drawn | 0 | [2] |
Available | $ 150 | |
[1] | These credit facilities expire in October 2019. | |
[2] | Includes outstanding commercial paper and letters of credit. |
Borrowings and Other Financin51
Borrowings and Other Financing Instruments Borrowings and Other Financing Instruments, Long-Term Borrowings (Details) - Bonds [Member] - USD ($) $ in Millions | Sep. 30, 2015 | Aug. 31, 2015 | Jun. 30, 2015 | May. 31, 2015 |
PSCo | Series Due May 15, 2025 [Member] | ||||
Debt Instrument [Line Items] | ||||
Debt Instrument, Face Amount | $ 250 | |||
Debt Instrument, Interest Rate, Stated Percentage | 2.90% | |||
Xcel Energy Inc. | Series Due June 1, 2017 [Member] | ||||
Debt Instrument [Line Items] | ||||
Debt Instrument, Face Amount | $ 250 | |||
Debt Instrument, Interest Rate, Stated Percentage | 1.20% | |||
Xcel Energy Inc. | Series Due June 1, 2025 [Member] | ||||
Debt Instrument [Line Items] | ||||
Debt Instrument, Face Amount | $ 250 | |||
Debt Instrument, Interest Rate, Stated Percentage | 3.30% | |||
NSP-Wisconsin | Series Due June 15, 2024 [Member] | ||||
Debt Instrument [Line Items] | ||||
Debt Instrument, Face Amount | $ 100 | |||
Debt Instrument, Interest Rate, Stated Percentage | 3.30% | |||
NSP-Minnesota | Series Due Aug. 15, 2020 [Member] | ||||
Debt Instrument [Line Items] | ||||
Debt Instrument, Face Amount | $ 300 | |||
Debt Instrument, Interest Rate, Stated Percentage | 2.20% | |||
NSP-Minnesota | Series Due Aug. 15, 2045 [Member] | ||||
Debt Instrument [Line Items] | ||||
Debt Instrument, Face Amount | $ 300 | |||
Debt Instrument, Interest Rate, Stated Percentage | 4.00% | |||
SPS | Series Due June 15, 2024 [Member] | ||||
Debt Instrument [Line Items] | ||||
Debt Instrument, Face Amount | $ 200 | |||
Debt Instrument, Interest Rate, Stated Percentage | 3.30% |
Fair Value of Financial Asset52
Fair Value of Financial Assets and Liabilities (Details) | 9 Months Ended |
Sep. 30, 2015 | |
Minimum | Commingled and international equity funds | |
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items] | |
Notice period for investment redemption (in days) | 1 day |
Minimum | Real Estate Funds | |
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items] | |
Notice period for investment redemption (in days) | 45 days |
Maximum | Commingled and international equity funds | |
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items] | |
Notice period for investment redemption (in days) | 90 days |
Maximum | Real Estate Funds | |
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items] | |
Notice period for investment redemption (in days) | 90 days |
Fair Value of Financial Asset53
Fair Value of Financial Assets and Liabilities, Cost and Fair Value of Nuclear Decommissioning Fund (Details) - USD ($) $ in Thousands | Sep. 30, 2015 | Dec. 31, 2014 | ||
Available-for-sale Securities [Abstract] | ||||
Unrealized gains for the nuclear decommissioning fund | $ 298,400 | $ 312,100 | ||
Unrealized losses and other than temporary impairments for the nuclear decommissioning fund | 87,300 | 74,100 | ||
Investments [Abstract] | ||||
Equity investments in unconsolidated subsidiaries | 80,300 | 83,100 | ||
Miscellaneous investments | 46,300 | 45,600 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Cash Equivalents | 33,681 | 24,184 | ||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities | 1,470,083 | 1,465,922 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Commingled funds | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities | 351,676 | 470,013 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | International equity funds | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities | 217,003 | 80,454 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Private equity investments | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities | 98,133 | 73,936 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Real estate | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities | 49,151 | 43,859 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Government securities | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 24,557 | 30,674 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | U.S. corporate bonds | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 70,311 | 81,463 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | International corporate bonds | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 14,099 | 16,950 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Municipal bonds | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 210,728 | 242,282 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Asset-backed securities | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 2,834 | 9,131 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Mortgage-backed securities | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 11,734 | 23,225 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Common stock | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Equity Securities | 386,176 | 369,751 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Cash Equivalents | 33,681 | 24,184 | ||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities | 1,681,149 | [1] | 1,703,921 | [2] |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Commingled funds | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities | 381,230 | 465,615 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | International equity funds | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities | 188,853 | 78,721 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Private equity investments | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities | 145,695 | 101,237 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Real estate | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities | 71,976 | 64,249 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Government securities | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 21,423 | 28,808 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | U.S. corporate bonds | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 61,874 | 77,562 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | International corporate bonds | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 13,059 | 16,341 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Municipal bonds | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 215,014 | 249,201 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Asset-backed securities | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 2,836 | 9,250 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Mortgage-backed securities | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 12,077 | 23,895 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Common stock | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Equity Securities | 533,431 | 564,858 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Cash Equivalents | 33,681 | 24,184 | ||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities | 567,112 | 589,042 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Commingled funds | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities | 0 | 0 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | International equity funds | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities | 0 | 0 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Private equity investments | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities | 0 | 0 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Real estate | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities | 0 | 0 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Government securities | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 0 | 0 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | U.S. corporate bonds | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 0 | 0 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | International corporate bonds | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 0 | 0 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Municipal bonds | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 0 | 0 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Asset-backed securities | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 0 | 0 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Mortgage-backed securities | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 0 | 0 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Common stock | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Equity Securities | 533,431 | 564,858 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Cash Equivalents | 0 | 0 | ||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities | 896,366 | 949,393 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Commingled funds | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities | 381,230 | 465,615 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | International equity funds | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities | 188,853 | 78,721 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Private equity investments | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities | 0 | 0 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Real estate | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities | 0 | 0 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Government securities | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 21,423 | 28,808 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | U.S. corporate bonds | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 61,874 | 77,562 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | International corporate bonds | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 13,059 | 16,341 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Municipal bonds | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 215,014 | 249,201 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Asset-backed securities | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 2,836 | 9,250 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Mortgage-backed securities | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 12,077 | 23,895 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Common stock | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Equity Securities | 0 | 0 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Cash Equivalents | 0 | 0 | ||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities | 217,671 | 165,486 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Commingled funds | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities | 0 | 0 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | International equity funds | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities | 0 | 0 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Private equity investments | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities | 145,695 | 101,237 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Real estate | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities | 71,976 | 64,249 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Government securities | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 0 | 0 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | U.S. corporate bonds | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 0 | 0 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | International corporate bonds | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 0 | 0 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Municipal bonds | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 0 | 0 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Asset-backed securities | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 0 | 0 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Mortgage-backed securities | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Debt Securities | 0 | 0 | ||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Common stock | ||||
Available-for-sale Securities [Abstract] | ||||
Available-for-sale Securities, Equity Securities | $ 0 | $ 0 | ||
[1] | Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $80.3 million of equity investments in unconsolidated subsidiaries and $46.3 million of miscellaneous investments. | |||
[2] | Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $83.1 million of equity investments in unconsolidated subsidiaries and $45.6 million of miscellaneous investments. |
Fair Value of Financial Asset54
Fair Value of Financial Assets and Liabilities, Changes in Level 3 Nuclear Decommissioning Fund (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | ||
Changes in Level 3 Nuclear Decommissioning Fund Assets [Roll Forward] | |||||
Balance at beginning of period | $ 204,827 | $ 146,781 | $ 165,486 | $ 120,064 | |
Purchases | 4,567 | 12,655 | 33,830 | 27,464 | |
Settlements | (1,719) | (5,876) | (4,341) | (5,876) | |
Gains recognized as regulatory assets | [1] | 9,996 | 7,417 | 22,696 | 19,325 |
Balance at end of period | 217,671 | 160,977 | 217,671 | 160,977 | |
Private equity investments | |||||
Changes in Level 3 Nuclear Decommissioning Fund Assets [Roll Forward] | |||||
Balance at beginning of period | 133,993 | 81,123 | 101,237 | 62,696 | |
Purchases | 3,066 | 11,125 | 24,197 | 22,078 | |
Settlements | 0 | 0 | 0 | 0 | |
Gains recognized as regulatory assets | [1] | 8,636 | 4,756 | 20,261 | 12,230 |
Balance at end of period | 145,695 | 97,004 | 145,695 | 97,004 | |
Real estate | |||||
Changes in Level 3 Nuclear Decommissioning Fund Assets [Roll Forward] | |||||
Balance at beginning of period | 70,834 | 65,658 | 64,249 | 57,368 | |
Purchases | 1,501 | 1,530 | 9,633 | 5,386 | |
Settlements | (1,719) | (5,876) | (4,341) | (5,876) | |
Gains recognized as regulatory assets | [1] | 1,360 | 2,661 | 2,435 | 7,095 |
Balance at end of period | $ 71,976 | $ 63,973 | $ 71,976 | $ 63,973 | |
[1] | Gains are deferred as a component of the regulatory assets for nuclear decommissioning. |
Fair Value of Financial Asset55
Fair Value of Financial Assets and Liabilities, Final Contractual Maturity Dates of Debt Securities in Nuclear Decommissioning Fund (Details) $ in Thousands | Sep. 30, 2015USD ($) |
Final Contractual Maturity [Abstract] | |
Due in 1 Year or Less | $ 1,260 |
Due in 1 to 5 Years | 45,874 |
Due in 5 to 10 Years | 107,856 |
Due after 10 Years | 171,293 |
Total | 326,283 |
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 | 21,423 |
Total | 21,423 |
U.S. corporate bonds | |
Final Contractual Maturity [Abstract] | |
Due in 1 Year or Less | 0 |
Due in 1 to 5 Years | 15,398 |
Due in 5 to 10 Years | 51,317 |
Due after 10 Years | (4,841) |
Total | 61,874 |
International corporate bonds | |
Final Contractual Maturity [Abstract] | |
Due in 1 Year or Less | 0 |
Due in 1 to 5 Years | 2,976 |
Due in 5 to 10 Years | 9,109 |
Due after 10 Years | 974 |
Total | 13,059 |
Municipal bonds | |
Final Contractual Maturity [Abstract] | |
Due in 1 Year or Less | 1,260 |
Due in 1 to 5 Years | 27,500 |
Due in 5 to 10 Years | 44,594 |
Due after 10 Years | 141,660 |
Total | 215,014 |
Asset-backed securities | |
Final Contractual Maturity [Abstract] | |
Due in 1 Year or Less | 0 |
Due in 1 to 5 Years | 0 |
Due in 5 to 10 Years | 2,836 |
Due after 10 Years | 0 |
Total | 2,836 |
Mortgage-backed securities | |
Final Contractual Maturity [Abstract] | |
Due in 1 Year or Less | 0 |
Due in 1 to 5 Years | 0 |
Due in 5 to 10 Years | 0 |
Due after 10 Years | 12,077 |
Total | $ 12,077 |
Fair Value of Financial Asset56
Fair Value of Financial Assets and Liabilities, Derivative Instruments (Details) gal in Thousands, MWh in Thousands, MMBTU in Thousands, $ in Millions | Sep. 30, 2015USD ($)MMBTUMWhgalCounterparty | Dec. 31, 2014MMBTUMWhgal | |
Commodity Derivatives [Abstract] | |||
Amount of accumulated other comprehensive gains (losses) related to commodity derivatives expected to be reclassified into earnings within the next twelve months | $ (0.1) | ||
Credit Concentration Risk | |||
Consideration of Credit Risk and Concentrations [Abstract] | |||
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure | Counterparty | 10 | ||
Credit Concentration Risk | External Credit Rating, Investment Grade [Member] | |||
Consideration of Credit Risk and Concentrations [Abstract] | |||
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure | Counterparty | 3 | ||
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties | $ 24.7 | ||
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths) | 10.00% | ||
Credit Concentration Risk | No Investment Grade Ratings from External Credit Rating Agencies | |||
Consideration of Credit Risk and Concentrations [Abstract] | |||
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure | Counterparty | 5 | ||
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties | $ 61.1 | ||
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths) | 26.00% | ||
Credit Concentration Risk | Credit Quality Less Than Investment Grade [Member] | |||
Consideration of Credit Risk and Concentrations [Abstract] | |||
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure | Counterparty | 2 | ||
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties | $ 11.5 | ||
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths) | 5.00% | ||
Interest Rate Swap | |||
Interest Rate Derivatives [Abstract] | |||
Amount of accumulated other comprehensive gains (losses) related to interest rate derivatives expected to be reclassified into earnings within the next twelve months | $ (3.7) | ||
Electric Commodity (in megawatt hours) | |||
Gross Notional Amounts of Commodity Forwards, Options and FTRs [Abstract] | |||
Derivative, Nonmonetary Notional amount | MWh | [1],[2] | 76,323 | 56,361 |
Natural Gas Commodity (in million British thermal units) | |||
Gross Notional Amounts of Commodity Forwards, Options and FTRs [Abstract] | |||
Derivative, Nonmonetary Notional amount | MMBTU | [1],[2] | 13,709 | 927 |
Vehicle Fuel Commodity (in gallons) | |||
Gross Notional Amounts of Commodity Forwards, Options and FTRs [Abstract] | |||
Derivative, Nonmonetary Notional amount | gal | [1],[2] | 176 | 282 |
[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 Asset57
Fair Value of Financial Assets and Liabilities, Impact of Derivative Activity (Details) - USD ($) | 3 Months Ended | 9 Months Ended | |||||||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | ||||||
Financial Impact of Qualifying Fair Value Hedges on Earnings [Abstract] | |||||||||
Derivative instruments designated as fair value hedges | $ 0 | $ 0 | $ 0 | $ 0 | |||||
Recognized gains (losses) from fair value hedges or related hedged transactions | 0 | 0 | 0 | 0 | |||||
Designated as Hedging Instrument | Cash Flow Hedges | |||||||||
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract] | |||||||||
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss | (70,000) | (69,000) | (59,000) | (56,000) | |||||
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities | 0 | 0 | 0 | 0 | |||||
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss | 1,152,000 | 951,000 | 3,101,000 | 2,808,000 | |||||
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities) | 0 | 0 | 0 | 0 | |||||
Pre-tax gains (losses) recognized during the period in income | 0 | 0 | 0 | 0 | |||||
Designated as Hedging Instrument | Cash Flow Hedges | Interest Rate | |||||||||
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract] | |||||||||
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss | 0 | 0 | 0 | 0 | |||||
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities | 0 | 0 | 0 | 0 | |||||
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss | [1] | 1,118,000 | 967,000 | 3,013,000 | 2,869,000 | ||||
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities) | 0 | 0 | 0 | 0 | |||||
Pre-tax gains (losses) recognized during the period in income | 0 | 0 | 0 | 0 | |||||
Designated as Hedging Instrument | Cash Flow Hedges | Vehicle Fuel And Other Commodity | |||||||||
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract] | |||||||||
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss | (70,000) | (69,000) | (59,000) | (56,000) | |||||
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities | 0 | 0 | 0 | 0 | |||||
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss | [2] | 34,000 | (16,000) | 88,000 | (61,000) | ||||
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities) | 0 | 0 | 0 | 0 | |||||
Pre-tax gains (losses) recognized during the period in income | 0 | 0 | 0 | 0 | |||||
Other Derivative Instruments | |||||||||
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract] | |||||||||
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss | 0 | 0 | 0 | 0 | |||||
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities | (5,381,000) | (5,846,000) | (19,977,000) | (3,637,000) | |||||
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss | 0 | 0 | 0 | 0 | |||||
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities) | 2,860,000 | 6,629,000 | 24,705,000 | (37,481,000) | |||||
Pre-tax gains (losses) recognized during the period in income | (3,865,000) | (1,865,000) | (15,351,000) | (3,666,000) | |||||
Other Derivative Instruments | Commodity Trading | |||||||||
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract] | |||||||||
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss | 0 | 0 | 0 | 0 | |||||
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities | 0 | 0 | 0 | 0 | |||||
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss | 0 | 0 | 0 | 0 | |||||
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities) | 0 | 0 | 0 | 0 | |||||
Pre-tax gains (losses) recognized during the period in income | [3] | (3,460,000) | (1,656,000) | (5,896,000) | 1,266,000 | ||||
Other Derivative Instruments | Electric Commodity | |||||||||
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract] | |||||||||
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss | 0 | 0 | 0 | 0 | |||||
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities | (2,403,000) | (3,391,000) | (16,611,000) | (17,240,000) | |||||
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss | 0 | 0 | 0 | 0 | |||||
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities) | [4] | 2,860,000 | 6,629,000 | 16,020,000 | (18,641,000) | ||||
Pre-tax gains (losses) recognized during the period in income | 0 | 0 | 0 | 0 | |||||
Other Derivative Instruments | Natural Gas Commodity | |||||||||
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract] | |||||||||
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss | 0 | 0 | 0 | 0 | |||||
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities | (2,978,000) | (2,455,000) | (3,366,000) | 13,603,000 | |||||
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss | 0 | 0 | 0 | 0 | |||||
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities) | 0 | 0 | 8,685,000 | [5] | (18,840,000) | [5] | |||
Pre-tax gains (losses) recognized during the period in income | (405,000) | [5] | $ (209,000) | [4] | (9,455,000) | [5] | (5,575,000) | [5] | |
Other Derivative Instruments | Other Commodity | |||||||||
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract] | |||||||||
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss | 0 | ||||||||
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities | 0 | ||||||||
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss | 0 | ||||||||
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities) | 0 | ||||||||
Pre-tax gains (losses) recognized during the period in income | [3] | $ 643,000 | |||||||
Other Derivative Instruments | 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) | $ 400,000 | $ 500,000 | |||||||
[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 gain and loss amounts are shared with electric customers through fuel and purchased energy cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate. | ||||||||
[5] | Amounts for the three and nine months ended Sept. 30, 2015 included $0.4 million and $0.5 million, respectively, of settlement losses on derivatives entered to mitigate natural gas price risk for electric generation, recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate. Losses for the nine months ended Sept. 30, 2014 included immaterial settlement losses on derivatives entered to mitigate natural gas price risk for electric generation, recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate. The remaining derivative settlement gains and losses for the three and nine months ended Sept. 30, 2015 and nine months ended 2014 relate to natural gas operations and are recorded to cost of natural gas sold and transported. These gains and losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset or liability, as appropriate. |
Fair Value of Financial Asset58
Fair Value of Financial Assets and Liabilities, Credit Related Contingent Features (Details) - USD ($) | Sep. 30, 2015 | Dec. 31, 2014 |
Fair Value Disclosures [Abstract] | ||
Derivative instruments in a gross liability position | $ 8.9 | $ 0 |
Assets Needed for Immediate Settlement, Aggregate Fair Value | 0.1 | |
Collateral posted on derivative instruments | 0 | 0 |
Collateral posted related to adequate assurance clauses in derivative contracts | $ 0 | $ 0 |
Fair Value of Financial Asset59
Fair Value of Financial Assets and Liabilities, Derivative Assets and Liabilities at Fair Value (Details) - USD ($) $ in Thousands | Sep. 30, 2015 | Dec. 31, 2014 | |||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Collateral, Obligation to Return Cash, Offset | $ 0 | $ 0 | |||
Derivative Liability, Collateral, Right to Reclaim Cash, Offset | 4,100 | 6,600 | |||
Other Current Assets | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 48,110 | 85,723 | |||
Other Noncurrent Assets | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 54,743 | 53,775 | |||
Other Current Liabilities | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 27,303 | 21,632 | |||
Other Noncurrent Liabilities | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 173,588 | 183,936 | |||
Fair Value Total | Other Current Assets | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 82,264 | ||||
Fair Value Total | Other Current Assets | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 19,058 | ||||
Fair Value Total | Other Current Assets | Other Derivative Instruments | Electric Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 62,825 | ||||
Fair Value Total | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 381 | ||||
Fair Value Total | Other Noncurrent Assets | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 17,617 | ||||
Fair Value Total | Other Current Liabilities | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 118 | ||||
Fair Value Total | Other Current Liabilities | Other Derivative Instruments | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 20,042 | ||||
Fair Value Total | Other Current Liabilities | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 7,974 | ||||
Fair Value Total | Other Current Liabilities | Other Derivative Instruments | Electric Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 11,402 | ||||
Fair Value Total | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 548 | ||||
Fair Value Total | Other Noncurrent Liabilities | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 102 | ||||
Fair Value Total | Other Noncurrent Liabilities | Other Derivative Instruments | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 7,027 | ||||
Fair Value Total | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 6,890 | ||||
Fair Value Total | Other Noncurrent Liabilities | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 35 | ||||
Fair Value Measured on a Recurring Basis | Other Current Assets | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 38,023 | 67,600 | |||
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 8,297 | 15,818 | |||
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Electric Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 28,354 | 51,423 | |||
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 1,372 | 359 | |||
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 22,112 | 13,466 | |||
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 22,112 | 13,466 | |||
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 156 | 118 | |||
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 4,434 | 645 | |||
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 2,347 | 0 | |||
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Electric Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 0 | 0 | |||
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 1,087 | 527 | |||
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Other Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 844 | ||||
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 36 | 102 | |||
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Other Derivative Instruments | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 9,746 | 994 | |||
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 9,692 | 857 | |||
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 35 | ||||
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Other Derivative Instruments | Other Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 18 | ||||
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets | Other Derivative Instruments | Electric Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Assets | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Assets | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 0 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities | Other Derivative Instruments | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 0 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 0 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities | Other Derivative Instruments | Electric Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 0 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 0 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities | Other Derivative Instruments | Other Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 0 | ||||
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Liabilities | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 0 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Liabilities | Other Derivative Instruments | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 0 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 0 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Liabilities | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 0 | ||||
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Liabilities | Other Derivative Instruments | Other Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 0 | ||||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 12,202 | 14,707 | |||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 9,140 | 14,326 | |||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets | Other Derivative Instruments | Electric Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 3,062 | 381 | |||
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Assets | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 29,523 | 17,617 | |||
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Assets | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 29,523 | 17,617 | |||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 156 | 118 | |||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities | Other Derivative Instruments | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 10,238 | 8,640 | |||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 6,461 | 7,974 | |||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities | Other Derivative Instruments | Electric Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 0 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 2,777 | 548 | |||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities | Other Derivative Instruments | Other Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 844 | ||||
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Liabilities | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 36 | 102 | |||
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Liabilities | Other Derivative Instruments | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 20,843 | 7,027 | |||
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 20,789 | 6,890 | |||
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Liabilities | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 35 | ||||
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Liabilities | Other Derivative Instruments | Other Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 18 | ||||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 39,022 | 67,557 | |||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 4,307 | 4,732 | |||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets | Other Derivative Instruments | Electric Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 34,715 | 62,825 | |||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Assets | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Assets | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 0 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities | Other Derivative Instruments | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 7,839 | 11,402 | |||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 1,478 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities | Other Derivative Instruments | Electric Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 6,361 | 11,402 | |||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 0 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities | Other Derivative Instruments | Other Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 0 | ||||
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Liabilities | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 0 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Liabilities | Other Derivative Instruments | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 0 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 0 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Liabilities | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 0 | ||||
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Liabilities | Other Derivative Instruments | Other Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 0 | ||||
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Assets | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 51,224 | ||||
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Assets | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 13,447 | ||||
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Assets | Other Derivative Instruments | Electric Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 34,715 | ||||
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 3,062 | ||||
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Noncurrent Assets | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 29,523 | 17,617 | |||
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Noncurrent Assets | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 29,523 | ||||
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Liabilities | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 156 | ||||
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Liabilities | Other Derivative Instruments | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 18,077 | ||||
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Liabilities | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 7,939 | ||||
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Liabilities | Other Derivative Instruments | Electric Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 6,361 | ||||
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 2,777 | ||||
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Liabilities | Other Derivative Instruments | Other Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 844 | ||||
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Noncurrent Liabilities | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 36 | ||||
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Noncurrent Liabilities | Other Derivative Instruments | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 20,843 | ||||
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 20,789 | ||||
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Noncurrent Liabilities | Other Derivative Instruments | Other Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 18 | ||||
Fair Value Measured on a Recurring Basis | Netting | Other Current Assets | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | (13,201) | [1] | (14,664) | [2] | |
Fair Value Measured on a Recurring Basis | Netting | Other Current Assets | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | (5,150) | [1] | (3,240) | [2] | |
Fair Value Measured on a Recurring Basis | Netting | Other Current Assets | Other Derivative Instruments | Electric Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | (6,361) | [1] | (11,402) | [2] | |
Fair Value Measured on a Recurring Basis | Netting | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | (1,690) | [1] | (22) | [2] | |
Fair Value Measured on a Recurring Basis | Netting | Other Noncurrent Assets | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | (7,411) | [1] | (4,151) | [2] | |
Fair Value Measured on a Recurring Basis | Netting | Other Noncurrent Assets | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | (7,411) | [1] | (4,151) | [2] | |
Fair Value Measured on a Recurring Basis | Netting | Other Current Liabilities | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 0 | [1] | 0 | [2] | |
Fair Value Measured on a Recurring Basis | Netting | Other Current Liabilities | Other Derivative Instruments | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | (13,643) | [1] | (19,397) | [2] | |
Fair Value Measured on a Recurring Basis | Netting | Other Current Liabilities | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | (5,592) | [1] | (7,974) | [2] | |
Fair Value Measured on a Recurring Basis | Netting | Other Current Liabilities | Other Derivative Instruments | Electric Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | (6,361) | [1] | (11,402) | [2] | |
Fair Value Measured on a Recurring Basis | Netting | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | (1,690) | [1] | (21) | [2] | |
Fair Value Measured on a Recurring Basis | Netting | Other Current Liabilities | Other Derivative Instruments | Other Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | [1] | 0 | |||
Fair Value Measured on a Recurring Basis | Netting | Other Noncurrent Liabilities | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 0 | [1] | 0 | [2] | |
Fair Value Measured on a Recurring Basis | Netting | Other Noncurrent Liabilities | Other Derivative Instruments | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | (11,097) | [1] | (6,033) | [2] | |
Fair Value Measured on a Recurring Basis | Netting | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | (11,097) | [1] | (6,033) | [2] | |
Fair Value Measured on a Recurring Basis | Netting | Other Noncurrent Liabilities | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | [2] | 0 | |||
Fair Value Measured on a Recurring Basis | Netting | Other Noncurrent Liabilities | Other Derivative Instruments | Other Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | [1] | 0 | |||
Fair Value, Measurements, Nonrecurring | Other Current Assets | Purchased Power Agreements | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 10,087 | [3] | 18,123 | [4] | |
Fair Value, Measurements, Nonrecurring | Other Noncurrent Assets | Purchased Power Agreements | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 32,631 | [3] | 40,309 | [4] | |
Fair Value, Measurements, Nonrecurring | Other Current Liabilities | Purchased Power Agreements | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 22,869 | [3] | 20,987 | [4] | |
Fair Value, Measurements, Nonrecurring | Other Noncurrent Liabilities | Purchased Power Agreements | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | $ 163,842 | [3] | $ 182,942 | [4] | |
[1] | Xcel Energy nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Sept. 30, 2015. At Sept. 30, 2015, derivative assets and liabilities include no obligations to return cash collateral and the rights to reclaim cash collateral of $4.1 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, 2014. At Dec. 31, 2014, derivative assets and liabilities include no obligations to return cash collateral and rights to reclaim cash collateral of $6.6 million. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements. | ||||
[3] | In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, Xcel Energy began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, Xcel Energy qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities. | ||||
[4] | In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, Xcel Energy began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, Xcel Energy qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities. |
Fair Value of Financial Asset60
Fair Value of Financial Assets and Liabilities, Changes in Level 3 Commodity Derivatives (Details) - Commodity Contract - USD ($) | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | ||
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward] | |||||
Balance at beginning of period | $ 46,826,000 | $ 105,394,000 | $ 56,155,000 | $ 41,660,000 | |
Purchases | 486,000 | 5,588,000 | 63,724,000 | 126,752,000 | |
Settlements | (20,216,000) | (20,032,000) | (57,462,000) | (107,451,000) | |
Transfers out of Level 3 | 0 | (1,093,000) | 0 | (1,093,000) | |
Gains recognized in earnings | [1] | 121,000 | 1,480,000 | 1,401,000 | 8,917,000 |
(Losses) gains recognized as regulatory assets and liabilities | 3,966,000 | (17,705,000) | (32,635,000) | 4,847,000 | |
Balance at end of period | 31,183,000 | 73,632,000 | 31,183,000 | 73,632,000 | |
Transfers into Level 3 | $ 0 | $ 0 | $ 0 | $ 0 | |
[1] | These amounts relate to commodity derivatives held at the end of the period. |
Fair Value of Financial Asset61
Fair Value of Financial Assets and Liabilities, Fair Value of Long-Term Debt (Details) - USD ($) $ in Thousands | Sep. 30, 2015 | Dec. 31, 2014 |
Carrying Amount | ||
Financial Liabilities, Balance Sheet Groupings [Abstract] | ||
Long-term Debt, Including Current Portion | $ 13,148,225 | $ 11,757,360 |
Fair Value | ||
Financial Liabilities, Balance Sheet Groupings [Abstract] | ||
Long-term Debt, Including Current Portion | $ 14,304,149 | $ 13,360,236 |
Other Income (Expense), Net (De
Other Income (Expense), Net (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | |
Other Income and Expenses [Abstract] | ||||
Interest income | $ 312 | $ 1,139 | $ 4,939 | $ 6,324 |
Other nonoperating income | 625 | 682 | 2,387 | 3,042 |
Insurance policy income (expense) | 689 | (417) | (1,578) | (4,663) |
Other Nonoperating Expense | 0 | 0 | 0 | (16) |
Other income, net | $ 1,626 | $ 1,404 | $ 5,748 | $ 4,687 |
Segment Information (Details)
Segment Information (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | Dec. 31, 2014 | ||
Segment Reporting Information [Line Items] | ||||||
Equity investments in unconsolidated subsidiaries | $ 80,300 | $ 80,300 | $ 83,100 | |||
Operating revenues | 2,901,312 | $ 2,869,807 | 8,378,665 | $ 8,757,507 | ||
Net income (loss) | 426,463 | 368,582 | 775,460 | 824,967 | ||
Regulated Electric | ||||||
Segment Reporting Information [Line Items] | ||||||
Operating revenues | 2,667,872 | 2,616,823 | 7,106,945 | 7,216,961 | ||
Net income (loss) | 437,978 | 360,656 | 733,954 | [1] | 731,766 | |
Regulated Natural Gas | ||||||
Segment Reporting Information [Line Items] | ||||||
Equity investments in unconsolidated subsidiaries | 80,300 | 80,300 | $ 83,100 | |||
Operating revenues | 216,312 | 237,246 | 1,217,287 | 1,490,431 | ||
Net income (loss) | (4,176) | 3,996 | 72,617 | 96,629 | ||
All Other | ||||||
Segment Reporting Information [Line Items] | ||||||
Operating revenues | 17,813 | 16,807 | 56,716 | 56,344 | ||
Net income (loss) | (7,339) | 3,930 | (31,111) | (3,428) | ||
Operating Segments | ||||||
Segment Reporting Information [Line Items] | ||||||
Operating revenues | 2,901,312 | 2,869,807 | 8,378,665 | 8,757,507 | ||
Operating Segments | Regulated Electric | ||||||
Segment Reporting Information [Line Items] | ||||||
Operating revenues | 2,667,480 | 2,616,351 | 7,105,803 | 7,215,699 | ||
Operating Segments | Regulated Natural Gas | ||||||
Segment Reporting Information [Line Items] | ||||||
Operating revenues | 216,019 | 236,649 | 1,216,146 | 1,485,464 | ||
Operating Segments | All Other | ||||||
Segment Reporting Information [Line Items] | ||||||
Operating revenues | 17,813 | 16,807 | 56,716 | 56,344 | ||
Intersegment Eliminations | ||||||
Segment Reporting Information [Line Items] | ||||||
Operating revenues | (685) | (1,069) | (2,283) | (6,229) | ||
Net income (loss) | 0 | 0 | 0 | 0 | ||
Intersegment Eliminations | Regulated Electric | ||||||
Segment Reporting Information [Line Items] | ||||||
Operating revenues | 392 | 472 | 1,142 | 1,262 | ||
Intersegment Eliminations | Regulated Natural Gas | ||||||
Segment Reporting Information [Line Items] | ||||||
Operating revenues | 293 | 597 | 1,141 | 4,967 | ||
Intersegment Eliminations | All Other | ||||||
Segment Reporting Information [Line Items] | ||||||
Operating revenues | $ 0 | $ 0 | $ 0 | $ 0 | ||
[1] | Includes a net of tax charge related to the Monticello LCM/EPU project. See Note 5. |
Earnings Per Share (Details)
Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | |
Dilutive Impact of Common Stock Equivalents on Earnings per Share (Abstract] | ||||
Net income | $ 426,463 | $ 368,582 | $ 775,460 | $ 824,967 |
Basic earnings per share [Abstract] | ||||
Earnings available to common shareholders | $ 426,463 | $ 368,582 | $ 775,460 | $ 824,967 |
Weighted average common shares outstanding - basic (in shares) | 508,031 | 506,082 | 507,585 | 502,983 |
Earnings available to common shareholders - basic (in dollars per share) | $ 0.84 | $ 0.73 | $ 1.53 | $ 1.64 |
Effect of dilutive securities [Abstract] | ||||
Time based equity awards | 396 | 283 | 391 | 230 |
Diluted earnings per share [Abstract] | ||||
Earnings available to common shareholders | $ 426,463 | $ 368,582 | $ 775,460 | $ 824,967 |
Weighted average common shares outstanding - diluted (in shares) | 508,427 | 506,365 | 507,976 | 503,213 |
Earnings available to common shareholders - diluted (in dollars per share) | $ 0.84 | $ 0.73 | $ 1.53 | $ 1.64 |
Benefit Plans and Other Postr65
Benefit Plans and Other Postretirement Benefits (Details) $ in Thousands | 1 Months Ended | 3 Months Ended | 9 Months Ended | ||
Jan. 31, 2015USD ($)Plan | Sep. 30, 2015USD ($) | Sep. 30, 2014USD ($) | Sep. 30, 2015USD ($) | Sep. 30, 2014USD ($) | |
Pension Benefits | |||||
Components of Net Periodic Benefit Cost [Abstract] | |||||
Service cost | $ 24,828 | $ 22,086 | $ 74,484 | $ 66,257 | |
Interest cost | 37,131 | 39,155 | 111,393 | 117,465 | |
Expected return on plan assets | (53,473) | (51,801) | (160,418) | (155,403) | |
Amortization of prior service cost (credit) | (451) | (437) | (1,353) | (1,310) | |
Amortization of net loss | 31,288 | 29,191 | 93,864 | 87,572 | |
Net periodic benefit cost (credit) | 39,323 | 38,194 | 117,970 | 114,581 | |
Costs not recognized due to the effects of regulation | (7,016) | (6,605) | (22,035) | (20,261) | |
Net benefit cost (credit) recognized for financial reporting | 32,307 | 31,589 | 95,935 | 94,320 | |
Total contributions to Xcel Energy's pension plans during the period | $ 90,000 | ||||
Number of pension plans to which contributions were made | Plan | 4 | ||||
Postretirement Health Care Benefits | |||||
Components of Net Periodic Benefit Cost [Abstract] | |||||
Service cost | 529 | 864 | 1,587 | 2,592 | |
Interest cost | 6,324 | 8,507 | 18,972 | 25,521 | |
Expected return on plan assets | (6,650) | (8,489) | (19,950) | (25,466) | |
Amortization of prior service cost (credit) | (2,672) | (2,672) | (8,015) | (8,016) | |
Amortization of net loss | 1,351 | 2,935 | 4,053 | 8,805 | |
Net periodic benefit cost (credit) | (1,118) | 1,145 | (3,353) | 3,436 | |
Costs not recognized due to the effects of regulation | 0 | 0 | 0 | 0 | |
Net benefit cost (credit) recognized for financial reporting | $ (1,118) | $ 1,145 | $ (3,353) | $ 3,436 |
Other Comprehensive Income (Det
Other Comprehensive Income (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | ||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||||
Accumulated other comprehensive income (loss) at beginning of period | $ (105,186) | $ (103,366) | $ (108,139) | $ (106,275) | |
Other comprehensive income (loss) before reclassifications | (43) | (40) | (34) | 6 | |
(Gains) losses reclassified from net accumulated other comprehensive loss | 1,590 | 1,405 | 4,534 | 4,268 | |
Net current period other comprehensive income (loss) | 1,547 | 1,365 | 4,500 | 4,274 | |
Accumulated other comprehensive income (loss) at end of period | (103,639) | (102,001) | (103,639) | (102,001) | |
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||||
Operating and maintenance expenses | 565,984 | 568,391 | 1,746,093 | 1,714,138 | |
Total, pre-tax | (665,492) | (564,551) | (1,207,950) | (1,260,965) | |
Tax benefit | 239,029 | 195,969 | 432,490 | 435,998 | |
Amounts Reclassified from Accumulated Other Comprehensive Loss | |||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||||
Total, net of tax | 1,590 | 1,405 | 4,534 | 4,268 | |
Gains and Losses on Cash Flow Hedges | |||||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||||
Accumulated other comprehensive income (loss) at beginning of period | (56,436) | (58,610) | (57,628) | (59,753) | |
Other comprehensive income (loss) before reclassifications | (42) | (42) | (35) | (34) | |
(Gains) losses reclassified from net accumulated other comprehensive loss | 706 | 558 | 1,891 | 1,693 | |
Net current period other comprehensive income (loss) | 664 | 516 | 1,856 | 1,659 | |
Accumulated other comprehensive income (loss) at end of period | (55,772) | (58,094) | (55,772) | (58,094) | |
Gains and Losses on Cash Flow Hedges | Amounts Reclassified from Accumulated Other Comprehensive Loss | |||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||||
Total, pre-tax | 1,152 | 951 | 3,101 | 2,808 | |
Tax benefit | (446) | (393) | (1,210) | (1,115) | |
Total, net of tax | 706 | 558 | 1,891 | 1,693 | |
Gains and Losses on Cash Flow Hedges | Interest Rate Derivatives | Amounts Reclassified from Accumulated Other Comprehensive Loss | |||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||||
Interest charges | [1] | 1,118 | 967 | 3,013 | 2,869 |
Gains and Losses on Cash Flow Hedges | Vehicle Fuel Derivatives | Amounts Reclassified from Accumulated Other Comprehensive Loss | |||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||||
Operating and maintenance expenses | [2] | 34 | (16) | 88 | (61) |
Unrealized Gains and Losses on Marketable Securities | |||||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||||
Accumulated other comprehensive income (loss) at beginning of period | 112 | 115 | 110 | 77 | |
Other comprehensive income (loss) before reclassifications | (1) | 2 | 1 | 40 | |
(Gains) losses reclassified from net accumulated other comprehensive loss | 0 | 0 | 0 | 0 | |
Net current period other comprehensive income (loss) | (1) | 2 | 1 | 40 | |
Accumulated other comprehensive income (loss) at end of period | 111 | 117 | 111 | 117 | |
Defined Benefit Pension and Postretirement Items | |||||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||||
Accumulated other comprehensive income (loss) at beginning of period | (48,862) | (44,871) | (50,621) | (46,599) | |
Other comprehensive income (loss) before reclassifications | 0 | 0 | 0 | 0 | |
(Gains) losses reclassified from net accumulated other comprehensive loss | 884 | 847 | 2,643 | 2,575 | |
Net current period other comprehensive income (loss) | 884 | 847 | 2,643 | 2,575 | |
Accumulated other comprehensive income (loss) at end of period | (47,978) | (44,024) | (47,978) | (44,024) | |
Defined Benefit Pension and Postretirement Items | Amounts Reclassified from Accumulated Other Comprehensive Loss | |||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||||
Amortization of net loss | [3] | 1,532 | 1,500 | 4,600 | 4,499 |
Prior service (credit) cost | [3] | (89) | (86) | (268) | (258) |
Total, pre-tax | 1,443 | 1,414 | 4,332 | 4,241 | |
Tax benefit | (559) | (567) | (1,689) | (1,666) | |
Total, net of tax | $ 884 | $ 847 | $ 2,643 | $ 2,575 | |
[1] | Included in interest charges. | ||||
[2] | Included in O&M expenses. | ||||
[3] | Included in the computation of net periodic pension and postretirement benefit costs. See Note 12 for details regarding these benefit plans. |