Document and Entity Information
Document and Entity Information - shares | 6 Months Ended | |
Jun. 30, 2018 | Jul. 23, 2018 | |
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 | 509,087,107 | |
Document Fiscal Year Focus | 2,018 | |
Document Fiscal Period Focus | Q2 | |
Document Type | 10-Q | |
Amendment Flag | false | |
Document Period End Date | Jun. 30, 2018 |
CONSOLIDATED STATEMENTS OF INCO
CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) - USD ($) $ in Thousands, shares in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | |
Operating revenues | ||||
Electric | $ 2,348,000 | $ 2,338,000 | $ 4,617,000 | $ 4,637,000 |
Natural gas | 292,000 | 290,000 | 954,000 | 915,000 |
Other | 18,000 | 17,000 | 38,000 | 39,000 |
Total operating revenues | 2,658,000 | 2,645,000 | 5,609,000 | 5,591,000 |
Operating expenses | ||||
Electric fuel and purchased power | 935,000 | 919,000 | 1,867,000 | 1,844,000 |
Cost of natural gas sold and transported | 104,000 | 114,000 | 479,000 | 479,000 |
Cost of sales — other | 8,000 | 8,000 | 17,000 | 17,000 |
Operating and maintenance expenses | 578,000 | 572,000 | 1,135,000 | 1,152,000 |
Conservation and demand side management expenses | 69,000 | 65,000 | 139,000 | 132,000 |
Depreciation and amortization | 377,000 | 366,000 | 760,000 | 731,000 |
Taxes (other than income taxes) | 137,000 | 135,000 | 282,000 | 277,000 |
Total operating expenses | 2,208,000 | 2,179,000 | 4,679,000 | 4,632,000 |
Operating income | 450,000 | 466,000 | 930,000 | 959,000 |
Other expense, net | (2,000) | (4,000) | (1,000) | (4,000) |
Equity earnings of unconsolidated subsidiaries | 9,000 | 7,000 | 16,000 | 15,000 |
Allowance for funds used during construction — equity | 26,000 | 16,000 | 49,000 | 31,000 |
Interest charges and financing costs | ||||
Interest charges — includes other financing costs of $6, $6, $12 and $12, respectively | 175,000 | 164,000 | 346,000 | 330,000 |
Allowance for funds used during construction — debt | (11,000) | (8,000) | (22,000) | (15,000) |
Total interest charges and financing costs | 164,000 | 156,000 | 324,000 | 315,000 |
Income before income taxes | 319,000 | 329,000 | 670,000 | 686,000 |
Income taxes | 54,000 | 102,000 | 114,000 | 219,000 |
Net income | $ 265,000 | $ 227,000 | $ 556,000 | $ 467,000 |
Weighted average common shares outstanding: | ||||
Basic (in shares) | 509.6 | 509 | 509.3 | 508.4 |
Diluted (in shares) | 510 | 509.1 | 509.7 | 509 |
Earnings per average common share: | ||||
Basic (in dollars per share) | $ 0.52 | $ 0.45 | $ 1.09 | $ 0.92 |
Diluted (in dollars per share) | 0.52 | 0.45 | 1.09 | 0.92 |
Cash dividends declared per common share (in dollars per share) | $ 0.38 | $ 0.36 | $ 0.76 | $ 0.72 |
CONSOLIDATED STATEMENTS OF INC3
CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) (Parenthetical) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | |
Interest charges and financing costs | ||||
Other financing costs | $ 6 | $ 6 | $ 12 | $ 12 |
CONSOLIDATED STATEMENTS OF COMP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | |
Comprehensive income: | ||||
Net income | $ 265,000 | $ 227,000 | $ 556,000 | $ 467,000 |
Pension and retiree medical benefits: | ||||
Amortization of losses included in net periodic benefit cost, net of tax of $1, $1, $1 and $1, respectively | 1,000 | 1,000 | 2,000 | 2,000 |
Derivative instruments: | ||||
Reclassification of losses to net income, net of tax of $0, $1, $0 and $1, respectively | 1,000 | 1,000 | 1,000 | 1,000 |
Other comprehensive income | 2,000 | 2,000 | 3,000 | 3,000 |
Comprehensive income | $ 267,000 | $ 229,000 | $ 559,000 | $ 470,000 |
CONSOLIDATED STATEMENTS OF COM5
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) (Parenthetical) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | |
Pension and retiree medical benefits: | ||||
Amortization of losses included in net periodic benefit cost, tax | $ 1 | $ 1 | $ 1 | $ 1 |
Derivative instruments: | ||||
Reclassification of losses to net income, tax | $ 0 | $ 1 | $ 0 | $ 1 |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) - USD ($) $ in Thousands | 6 Months Ended | |
Jun. 30, 2018 | Jun. 30, 2017 | |
Operating activities | ||
Net income | $ 556,000 | $ 467,000 |
Adjustments to reconcile net income to cash provided by operating activities: | ||
Depreciation and amortization | 769,000 | 739,000 |
Nuclear fuel amortization | 62,000 | 57,000 |
Deferred income taxes | 110,000 | 309,000 |
Allowance for equity funds used during construction | (49,000) | (31,000) |
Equity earnings of unconsolidated subsidiaries | (16,000) | (15,000) |
Dividends from unconsolidated subsidiaries | 18,000 | 24,000 |
Share-based compensation expense | 10,000 | 32,000 |
Other, net | (6,000) | (4,000) |
Changes in operating assets and liabilities: | ||
Accounts receivable | (11,000) | 17,000 |
Accrued unbilled revenues | 115,000 | 121,000 |
Inventories | 101,000 | 65,000 |
Other current assets | 39,000 | (84,000) |
Accounts payable | (1,000) | (52,000) |
Net regulatory assets and liabilities | 143,000 | 1,000 |
Other current liabilities | (247,000) | (190,000) |
Pension and other employee benefit obligations | (142,000) | (140,000) |
Change in other noncurrent assets | 10,000 | (7,000) |
Change in other noncurrent liabilities | (24,000) | (17,000) |
Net cash provided by operating activities | 1,437,000 | 1,292,000 |
Investing activities | ||
Utility capital/construction expenditures | (1,903,000) | (1,474,000) |
Allowance for equity funds used during construction | 49,000 | 31,000 |
Purchases of investment securities | (367,000) | (368,000) |
Proceeds from the sale of investment securities | 357,000 | 350,000 |
Other, net | (1,000) | (13,000) |
Net cash used in investing activities | (1,865,000) | (1,474,000) |
Financing activities | ||
(Repayments of) proceeds from short-term borrowings, net | (132,000) | 392,000 |
Proceeds from issuances of long-term debt | 1,186,000 | 394,000 |
Repayments of long-term debt, including reacquisition premiums | (1,000) | (250,000) |
Dividends paid | (359,000) | (355,000) |
Other, net | (17,000) | (22,000) |
Net cash provided by financing activities | 677,000 | 159,000 |
Net change in cash and cash equivalents | 249,000 | (23,000) |
Cash and cash equivalents at beginning of period | 83,000 | 84,000 |
Cash and cash equivalents at end of period | 332,000 | 61,000 |
Supplemental disclosure of cash flow information: | ||
Cash paid for interest (net of amounts capitalized) | (313,000) | (301,000) |
Cash paid for income taxes, net | (3,000) | (4,000) |
Supplemental disclosure of non-cash investing and financing transactions: | ||
Property, plant and equipment additions in accounts payable | 262,000 | 233,000 |
Issuance of common stock for equity awards | $ 35,000 | $ 19,000 |
CONSOLIDATED BALANCE SHEETS (UN
CONSOLIDATED BALANCE SHEETS (UNAUDITED) - USD ($) $ in Millions | Jun. 30, 2018 | Dec. 31, 2017 |
Current assets | ||
Cash and cash equivalents | $ 332 | $ 83 |
Accounts receivable, net | 808 | 797 |
Accrued unbilled revenues | 648 | 764 |
Inventories | 511 | 610 |
Regulatory assets | 440 | 424 |
Derivative instruments | 75 | 44 |
Prepaid taxes | 78 | 68 |
Prepayments and other | 164 | 183 |
Total current assets | 3,056 | 2,973 |
Property, plant and equipment, net | 35,289 | 34,329 |
Other assets | ||
Nuclear decommissioning fund and other investments | 2,398 | 2,397 |
Regulatory assets | 3,177 | 3,005 |
Derivative instruments | 47 | 48 |
Other | 273 | 278 |
Total other assets | 5,895 | 5,728 |
Total assets | 44,240 | 43,030 |
Current liabilities | ||
Current portion of long-term debt | 856 | 457 |
Short-term debt | 682 | 814 |
Accounts payable | 1,092 | 1,243 |
Regulatory liabilities | 395 | 239 |
Taxes accrued | 316 | 448 |
Accrued interest | 176 | 174 |
Dividends payable | 193 | 183 |
Derivative instruments | 27 | 29 |
Other | 441 | 501 |
Total current liabilities | 4,178 | 4,088 |
Deferred credits and other liabilities | ||
Deferred income taxes | 3,973 | 3,845 |
Deferred investment tax credits | 56 | 58 |
Regulatory liabilities | 5,113 | 5,083 |
Asset retirement obligations | 2,534 | 2,475 |
Derivative instruments | 113 | 126 |
Customer advances | 202 | 193 |
Pension and employee benefit obligations | 884 | 1,042 |
Other | 226 | 145 |
Total deferred credits and other liabilities | 13,101 | 12,967 |
Commitments and contingencies | ||
Capitalization | ||
Long-term debt | 15,311 | 14,520 |
Common stock — 1,000,000,000 shares authorized of $2.50 par value; 508,898,420 and 507,762,881 shares outstanding at June 30, 2018 and Dec. 31, 2017, respectively | 1,272 | 1,269 |
Additional paid in capital | 5,920 | 5,898 |
Retained earnings | 4,580 | 4,413 |
Accumulated other comprehensive loss | (122) | (125) |
Total common stockholders’ equity | 11,650 | 11,455 |
Total liabilities and equity | $ 44,240 | $ 43,030 |
CONSOLIDATED BALANCE SHEETS (U8
CONSOLIDATED BALANCE SHEETS (UNAUDITED) (Parenthetical) - $ / shares | Jun. 30, 2018 | Dec. 31, 2017 |
Capitalization, Long-term Debt and Equity | ||
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) | 508,898,420 | 507,762,881 |
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, 2016 | $ 11,021,000 | $ 1,268,000 | $ 5,881,000 | $ 3,982,000 | $ (110,000) |
Balance (in shares) at Dec. 31, 2016 | 507,223,000 | ||||
Increase (Decrease) in Stockholders' Equity | |||||
Net income | 467,000 | 467,000 | |||
Other comprehensive income | 3,000 | 3,000 | |||
Dividends declared on common stock | (368,000) | (368,000) | |||
Issuances of common stock (in shares) | 611,000 | ||||
Issuances of common stock | 5,000 | $ 1,000 | 4,000 | ||
Purchase of common stock (in shares) | (71,000) | ||||
Repurchases of common stock | (3,000) | $ 0 | (3,000) | ||
Share-based compensation | (2,000) | 0 | (2,000) | ||
Ending balance at Jun. 30, 2017 | 11,123,000 | $ 1,269,000 | 5,882,000 | 4,079,000 | (107,000) |
Balance (in shares) at Jun. 30, 2017 | 507,763,000 | ||||
Beginning balance at Mar. 31, 2017 | 11,069,000 | $ 1,269,000 | 5,873,000 | 4,036,000 | (109,000) |
Balance (in shares) at Mar. 31, 2017 | 507,763,000 | ||||
Increase (Decrease) in Stockholders' Equity | |||||
Net income | 227,000 | 227,000 | |||
Other comprehensive income | 2,000 | 2,000 | |||
Dividends declared on common stock | (184,000) | (184,000) | |||
Share-based compensation | 9,000 | 9,000 | 0 | ||
Ending balance at Jun. 30, 2017 | 11,123,000 | $ 1,269,000 | 5,882,000 | 4,079,000 | (107,000) |
Balance (in shares) at Jun. 30, 2017 | 507,763,000 | ||||
Beginning balance at Dec. 31, 2017 | $ 11,455,000 | $ 1,269,000 | 5,898,000 | 4,413,000 | (125,000) |
Balance (in shares) at Dec. 31, 2017 | 507,762,881 | 507,763,000 | |||
Increase (Decrease) in Stockholders' Equity | |||||
Net income | $ 556,000 | 556,000 | |||
Other comprehensive income | 3,000 | 3,000 | |||
Dividends declared on common stock | (389,000) | (389,000) | |||
Issuances of common stock (in shares) | 1,157,000 | ||||
Issuances of common stock | 27,000 | $ 3,000 | 24,000 | ||
Purchase of common stock (in shares) | (22,000) | ||||
Repurchases of common stock | (1,000) | $ 0 | (1,000) | ||
Share-based compensation | (1,000) | (1,000) | 0 | ||
Ending balance at Jun. 30, 2018 | $ 11,650,000 | $ 1,272,000 | 5,920,000 | 4,580,000 | (122,000) |
Balance (in shares) at Jun. 30, 2018 | 508,898,420 | 508,898,000 | |||
Beginning balance at Mar. 31, 2018 | $ 11,561,000 | $ 1,272,000 | 5,903,000 | 4,510,000 | (124,000) |
Balance (in shares) at Mar. 31, 2018 | 508,662,000 | ||||
Increase (Decrease) in Stockholders' Equity | |||||
Net income | 265,000 | 265,000 | |||
Other comprehensive income | 2,000 | 2,000 | |||
Dividends declared on common stock | (195,000) | (195,000) | |||
Issuances of common stock (in shares) | 236,000 | ||||
Issuances of common stock | 10,000 | $ 0 | 10,000 | ||
Share-based compensation | 7,000 | 7,000 | 0 | ||
Ending balance at Jun. 30, 2018 | $ 11,650,000 | $ 1,272,000 | $ 5,920,000 | $ 4,580,000 | $ (122,000) |
Balance (in shares) at Jun. 30, 2018 | 508,898,420 | 508,898,000 |
Management's Opinion
Management's Opinion | 6 Months Ended |
Jun. 30, 2018 | |
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 June 30, 2018 and Dec. 31, 2017 ; the results of its operations, including the components of net income and comprehensive income, and changes in stockholders’ equity for the three and six months ended June 30, 2018 and 2017 ; and its cash flows for the six months ended June 30, 2018 and 2017 . All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after June 30, 2018 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, 2017 balance sheet information has been derived from the audited 2017 consolidated financial statements included in the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, 2017 . 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, 2017 , filed with the SEC on Feb. 23, 2018. 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 | 6 Months Ended |
Jun. 30, 2018 | |
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, 2017 , appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference. |
Accounting Pronouncements
Accounting Pronouncements | 6 Months Ended |
Jun. 30, 2018 | |
New Accounting Pronouncements and Changes in Accounting Principles [Abstract] | |
Accounting Pronouncements | Accounting Pronouncements Recently Issued Leases — I n February 2016, the Financial Accounting Standards Board (FASB) issued Leases, Topic 842 (Accounting Standards Update (ASU) No. 2016-02) , which for lessees requires balance sheet recognition of right-of-use assets and lease liabilities for most leases. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2018. Xcel Energy has not yet fully determined the impacts of implementation. However, adoption is expected to occur on Jan. 1, 2019 utilizing the practical expedients provided by the standard and proposed in Targeted Improvements, Topic 842 ( Proposed ASU 2018-200 ). On Jan. 1, 2019 agreements considered leases for the use of office space, equipment and natural gas storage assets, as well as certain purchased power agreements (PPAs) for fossil-fueled generating facilities are expected to be recognized on the consolidated balance sheet. Recently Adopted Revenue Recognition — In May 2014, the FASB issued Revenue from Contracts with Customers, Topic 606 (ASU No. 2014-09) , which provides a new framework for the recognition of revenue. Xcel Energy implemented the guidance on a modified retrospective basis on Jan. 1, 2018. Results for reporting periods beginning after Dec. 31, 2017 are presented in accordance with Topic 606, while prior period results have not been adjusted and continue to be reported in accordance with prior accounting guidance. Other than increased disclosures regarding revenues related to contracts with customers, the implementation did not have a significant impact on Xcel Energy’s consolidated financial statements. For related disclosures, see Note 14 to the consolidated financial statements. Classification and Measurement of Financial Instruments — In January 2016, the FASB issued Recognition and Measurement of Financial Assets and Financial Liabilities, Subtopic 825-10 (ASU No. 2016-01) , which eliminated the available-for-sale classification for marketable equity securities and also replaced the cost method of accounting for non-marketable equity securities with a model for recognizing impairments and observable price changes. Under the new standard, other than when the consolidation or equity method of accounting is utilized, changes in the fair value of equity securities are recognized in earnings. Xcel Energy implemented the guidance on Jan. 1, 2018. As a result of application of accounting principles for rate regulated entities, changes in the fair value of the securities in the nuclear decommissioning fund, historically classified as available-for-sale, continue to be deferred to a regulatory asset, and the overall adoption impacts were not material. Presentation of Net Periodic Benefit Cost — I n March 2017, the FASB issued Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, Topic 715 (ASU No. 2017-07) , which establishes that only the service cost element of pension cost may be presented as a component of operating income in the income statement. Also under the guidance, only the service cost component of pension cost is eligible for capitalization. As a result of the application of accounting principles for rate regulated entities, a similar amount of pension cost, including non-service components, will be recognized consistent with the historical ratemaking treatment, and the impacts of adoption will be limited to changes in classification of non-service costs in the consolidated statement of income. Xcel Energy implemented the new guidance on Jan. 1, 2018, and as a result, $12 million of pension costs were retrospectively reclassified from operating and maintenance expenses to other income, net on the consolidated income statement for the six months ended June 30, 2017. Under a practical expedient permitted by the standard, Xcel Energy used benefit cost amounts disclosed for prior periods as the basis for retrospective application. |
Selected Balance Sheet Data
Selected Balance Sheet Data | 6 Months Ended |
Jun. 30, 2018 | |
Balance Sheet Related Disclosures [Abstract] | |
Selected Balance Sheet Data | Selected Balance Sheet Data (Millions of Dollars) June 30, 2018 Dec. 31, 2017 Accounts receivable, net Accounts receivable $ 856 $ 849 Less allowance for bad debts (48 ) (52 ) $ 808 $ 797 (Millions of Dollars) June 30, 2018 Dec. 31, 2017 Inventories Materials and supplies $ 312 $ 311 Fuel 147 186 Natural gas 52 113 $ 511 $ 610 (Millions of Dollars) June 30, 2018 Dec. 31, 2017 Property, plant and equipment, net Electric plant $ 39,745 $ 39,016 Natural gas plant 5,955 5,800 Common and other property 2,045 2,013 Plant to be retired (a) 10 11 Construction work in progress 2,658 2,087 Total property, plant and equipment 50,413 48,927 Less accumulated depreciation (15,479 ) (15,000 ) Nuclear fuel 2,712 2,697 Less accumulated amortization (2,357 ) (2,295 ) $ 35,289 $ 34,329 (a) In the third quarter of 2017, PSCo early retired Valmont Unit 5 and converted Cherokee Unit 4 from a coal-fueled generating facility to natural gas. PSCo also expects Craig Unit 1 to be early retired in approximately 2025. Amounts are presented net of accumulated depreciation. |
Income Taxes
Income Taxes | 6 Months Ended |
Jun. 30, 2018 | |
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, 2017 appropriately represents, in all material respects, the current status of other income tax matters, and is incorporated herein by reference. Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense. The following reconciles such differences: Three Months Ended June 30 Six Months Ended June 30 2018 2017 2018 2017 Federal statutory rate 21.0 % 35.0 % 21.0 % 35.0 % State tax, net of federal tax effect 5.1 4.1 5.0 4.1 Increase (decreases) in tax from: Wind production tax credits (PTCs) (5.4 ) (4.5 ) (5.8 ) (4.2 ) Regulatory differences - ARAM (a) (5.4 ) (0.1 ) (5.6 ) (0.1 ) Regulatory differences - ARAM deferral (b) 4.0 — 4.8 — Regulatory differences - other utility plant items (1.0 ) (0.9 ) (1.0 ) (0.7 ) Other, net (1.4 ) (2.6 ) (1.4 ) (2.2 ) Effective income tax rate 16.9 % 31.0 % 17.0 % 31.9 % (a) The average rate assumption method (ARAM); a method to flow back excess deferred taxes to customers. (b) The ARAM deferral may decrease during the year, which would result in a reduction to tax expense with a corresponding reduction to revenue, as we receive further direction from our regulatory commissions regarding the return of excess deferred taxes to our customers resulting from the Tax Cuts and Jobs Act (TCJA). Federal Audits — Xcel Energy files a consolidated federal income tax return. The statute of limitations applicable to Xcel Energy’s federal income tax returns expire as follows: Tax Year(s) Expiration 2009 - 2011 December 2018 2012 - 2014 October 2019 2015 September 2019 2016 September 2020 In 2012, the Internal Revenue Service (IRS) commenced an examination of tax years 2010 and 2011 , including the 2009 carryback claim. The IRS proposed an adjustment to the federal tax loss carryback claims and in 2015, the IRS forwarded the issue to the Office of Appeals (Appeals). In 2017, Xcel Energy and Appeals reached an agreement and the benefit related to the agreed upon portions was recognized. In the second quarter of 2018, the Joint Committee on Taxation completed its review and took no exception to the agreement. As a result, the remaining unrecognized tax benefit was released and recorded as a payable to the IRS. In the third quarter of 2015, the IRS commenced an examination of tax years 2012 and 2013 . In the third quarter of 2017, the IRS concluded the audit of tax years 2012 and 2013 and proposed an adjustment that would impact Xcel Energy’s net operating loss (NOL) and effective tax rate (ETR). After evaluating the proposed adjustment, Xcel Energy filed a protest with the IRS. As of June 30, 2018, the case has been forwarded to Appeals and Xcel Energy has recognized its best estimate of income tax expense that will result from a final resolution of this issue; however, the outcome and timing of a resolution is unknown. 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 June 30, 2018, 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 2012 • In 2016, Minnesota began an audit of years 2010 through 2014 . As of June 30, 2018, Minnesota had not proposed any material adjustments; • In 2016, Wisconsin began an audit of years 2012 and 2013 . As of June 30, 2018, the Company is evaluating the state’s proposed audit adjustments. No material accruals are expected; and • As of June 30, 2018, there were no other state income tax audits in progress. Unrecognized Benefits — The unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the annual ETR. In addition, the unrecognized tax benefit balance includes temporary tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. A change in the period of deductibility would not affect the ETR but would accelerate the payment of cash to the taxing authority to an earlier period. A reconciliation of the amount of unrecognized tax benefit is as follows: (Millions of Dollars) June 30, 2018 Dec. 31, 2017 Unrecognized tax benefit — Permanent tax positions $ 21 $ 20 Unrecognized tax benefit — Temporary tax positions 13 19 Total unrecognized tax benefit $ 34 $ 39 The unrecognized tax benefit amounts were reduced by the tax benefits associated with NOL and tax credit carryforwards. The amounts of tax benefits associated with NOL and tax credit carryforwards are as follows: (Millions of Dollars) June 30, 2018 Dec. 31, 2017 NOL and tax credit carryforwards $ (33 ) $ (31 ) 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 progresses and audit resumes, the Minnesota and Wisconsin audits progress, and other state audits resume. As the IRS Appeals and Minnesota and Wisconsin audits progress and the IRS audit resumes, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $29 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 June 30, 2018 and Dec. 31, 2017 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of June 30, 2018 or Dec. 31, 2017. |
Rate Matters
Rate Matters | 6 Months Ended |
Jun. 30, 2018 | |
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, 2017 and in Note 5 to the consolidated financial statements to Xcel Energy Inc.’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2018, appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference. Tax Reform — Regulatory Proceedings The specific impacts of the TCJA on customer rates are subject to regulatory approval. Each of the states in Xcel Energy’s service areas have opened dockets to address the impacts of the TCJA. NSP-Minnesota — In April 2018, NSP-Minnesota updated the estimated impact of the TCJA, which reflected an overall reduction in 2018 revenue requirements of approximately $136 million for electric and $7 million for natural gas, and made recommendations regarding the sharing of those benefits with ratepayers. The proposed electric options included: customer refunds and rider impacts of $68 million , deferral of $44 million to allow for a rate case stay-out for 2020, acceleration of depreciation for the King coal plant of $22 million and low income program funding of $2 million . The proposed natural gas options included customer refunds and rider impacts of $3 million , with the remaining TCJA benefits deferred to mitigate increased costs in the next natural gas rate case. In June 2018, the Minnesota Department of Commerce (DOC) recommended to implement refunds for the current tax impacts (approximately $90 million ), and incorporate the deferred tax impacts (approximately $53 million ) in NSP-Minnesota’s next electric and gas rate cases. A decision from the Minnesota Public Utilities Commission (MPUC) is expected in 2018. NSP-Minnesota — North and South Dakota — In February 2018, NSP-Minnesota proposed using the reduced revenue requirements from the TCJA to defer planned future rate filings in North Dakota and South Dakota. In July 2018, the South Dakota Public Utilities Commission (SDPUC) approved a settlement which proposed a one-time customer refund of $11 million for the 2018 impact of the TCJA and a two -year rate case moratorium. NSP-Wisconsin — In May 2018, the Public Service Commission of Wisconsin (PSCW) issued its final order which requires customer refunds of $27 million and defers approximately $5 million until NSP-Wisconsin’s next rate case proceeding. NSP-Wisconsin — Michigan — In May 2018, the Michigan Public Service Commission (MPSC) approved electric and natural gas tax reform settlement agreements. Most of the electric TCJA benefits were included in NSP-Wisconsin’s recently approved Michigan 2018 electric base rate case. Natural gas TCJA benefits are to be returned to customers commencing in July 2018. PSCo — Colorado Natural Gas — In February 2018, the administrative law judge (ALJ) approved PSCo and the Colorado Public Utilities Commission (CPUC) Staff’s TCJA settlement agreement, which includes a $20 million reduction to provisional rates effective March 1, 2018. A final true-up would provide customers the full net benefit of the TCJA retroactive to January 2018. PSCo — Colorado Electric — In April 2018, PSCo, the CPUC Staff and the Office of Consumer Counsel (OCC) filed a TCJA settlement agreement that recommended a customer refund of $42 million in 2018, with the remainder of $59 million be used to accelerate the amortization of an existing prepaid pension asset. In June 2018, the CPUC approved the customer refund of $42 million , effective June 1, 2018. The CPUC set the decision regarding the remainder of the $59 million for hearing before an ALJ. Revisions to the TCJA settlement will be addressed in a future electric rate case. SPS — Texas — In June 2018, SPS, the Public Utility Commission of Texas (PUCT) Staff and various intervenors reached a settlement in the Texas electric rate case which included the impacts of the TCJA. The settlement reflects no change in customer rates or refunds, and SPS’ actual capital structure, which SPS has informed the parties it intends to be a 57 percent equity ratio to offset the negative impacts on its credit metrics and potentially its credit ratings. SPS — New Mexico — In February 2018, SPS indicated that the TCJA would reduce revenue requirements by approximately $11 million and recommended increasing its equity ratio to 58 percent to offset the negative impact of the TCJA on its credit metrics and potentially its credit ratings. The impact of the TCJA is expected to be addressed as part of SPS’ pending New Mexico electric rate case. Other Regulatory Proceedings NSP-Minnesota Recently Concluded Regulatory Proceedings — MPUC and the North Dakota Public Service Commission (NDPSC) PPA Terminations and Amendments — In June 2018, NSP-Minnesota executed the terminations of the Benson and Laurentian PPAs, and purchased the Benson biomass facility. As a result, a $103 million regulatory asset was recognized for the costs of the Benson transaction, including payments to Benson of $93 million , as well as other transaction costs and future estimated facility removal costs. For Laurentian, a regulatory asset of $109 million was recognized for annual termination payments over six years. The regulatory approvals provide for recovery of the Benson regulatory asset over approximately 10 years, and for recovery of the Laurentian termination payments as they occur, through fuel and purchased energy recovery mechanisms. PSCo Pending Regulatory Proceedings — CPUC Colorado 2017 Multi-Year Electric Rate Case — In October 2017, PSCo filed a multi-year request with the CPUC seeking to increase electric rates approximately $245 million over four years . The request was based on forecast test years (FTY), a 10.0 percent return on equity (ROE) and an equity ratio of 55.25 percent . Interim rates, subject to refund and interest, were to be effective on June 1, 2018. Revenue Request (Millions of Dollars) 2018 2019 2020 2021 Total Revenue request $ 74 $ 75 $ 60 $ 36 $ 245 Clean Air Clean Jobs Act (CACJA) rider conversion to base rates 90 — — — 90 Transmission Cost Adjustment (TCA) rider conversion to base rates 43 — — — 43 Total $ 207 $ 75 $ 60 $ 36 $ 378 Expected year-end rate base (billions of dollars) $ 6.8 $ 7.1 $ 7.3 $ 7.4 In March 2018, PSCo, CPUC Staff and OCC reached a settlement and filed a motion with the CPUC requesting changes to the procedural schedule and scope of the electric case, which included delaying the implementation of provisional rates from June 2018 to January 2019 and requiring PSCo to file updated test year information for 2019 through 2021 which included the impacts of TCJA. In April 2018, the CPUC denied the motion on procedural grounds and dismissed the electric rate case. Colorado 2017 Multi-Year Natural Gas Rate Case — In June 2017, PSCo filed a multi-year request with the CPUC seeking to increase retail natural gas rates approximately $139 million over three years . The request, detailed below, was based on FTYs, a 10.0 percent ROE and an equity ratio of 55.25 percent . Revenue Request (Millions of Dollars) 2018 2019 2020 Total Revenue request $ 63 $ 33 $ 43 $ 139 Pipeline System Integrity Adjustment (PSIA) rider conversion to base rates (a) — 94 — 94 Total $ 63 $ 127 $ 43 $ 233 Expected year-end rate base (billions of dollars) (b) $ 1.5 $ 2.3 $ 2.4 (a) The roll-in of PSIA rider revenue into base rates will not have an impact on customer bills or revenue as these costs are already being recovered through the rider. The recovery of incremental PSIA related investments in 2019 and 2020 are included in the base rate request. (b) The additional rate base in 2019 predominantly reflects the roll-in of capital associated with the PSIA rider. In February 2018, the ALJ approved a TCJA settlement agreement between PSCo and the CPUC Staff, which reduced provisional rates by $20 million , based on a preliminary TCJA estimate of $29 million . The settlement remains subject to CPUC approval. The impact of the TCJA will be trued-up later in 2018. Annualized provisional rates of approximately $43 million were effective March 1, 2018. In May 2018, the ALJ issued an interim recommended decision which would result in a 2018 overall rate increase of approximately $46 million , prior to the impact of the TCJA. The estimated rate increase reflects a 2016 HTY with a 13 -month average rate base of $1.6 billion , a ROE of 9.35 percent and an equity ratio of 54.2 percent . On July 12, 2018, the CPUC deliberated and approved several of the ALJ’s recommendations including application of a 2016 HTY, with a 13 -month average rate base, and an ROE of 9.35 percent . The CPUC adjusted the equity ratio to 54.6 percent and provided no return on the prepaid pension and retiree medical asset. With these adjustments the total rate increase, prior to TCJA impacts, would be $47 million . The estimated impact of the CPUC’s decision is presented below: (Millions of Dollars) Estimated Impact of the CPUC’s Decision Filed 2018 revenue request based on a FTY $ 63 Impact of the change in test year 5 PSCo’s deficiency based on a 2016 HTY - year-end rate base 68 Adjustments: ROE at 9.35 percent (9 ) Equity ratio of 54.6 percent (2 ) Change in amortization period for certain regulatory assets, including a debt return (6 ) Loss of return on prepaid pension and retiree medical (4 ) Change from 2016 year-end to average rate base (5 ) Other, net 5 Total adjustments (21 ) Total rate increase, prior to the TCJA impacts $ 47 The CPUC is expected to issue its order on the natural gas rate case in the third quarter of 2018. The CPUC is expected to issue a final decision with the impacts of the TCJA later in 2018. Provisional rates, subject to refund, were implemented on Jan. 1, 2018. A current liability which represents PSCo’s best estimate of a refund obligation associated with provisional rates was recorded as of June 30, 2018. PSIA Rider In June 2018, PSCo filed for an extension to the PSIA rider through 2020. PSCo requested an expedited decision by Nov. 15, 2018. PSCo also requested authorization to roll-in recovery of costs in the current PSIA rider into base rates effective Jan. 1, 2019, if the CPUC rejects the proposed PSIA extension or fails to rule on the request by the end of 2018. Additionally, PSCo reduced PSIA revenues by approximately $8 million for 2018 for the impact of the TCJA, effective May 1, 2018. PSIA revenues are subject to the CPUC approved PSIA rider true-up process. SPS Pending Regulatory Proceedings — PUCT Texas 2017 Electric Rate Case — In 2017, SPS filed a $54 million , or 5.8 percent , retail electric, non-fuel base rate increase case in Texas with each of its Texas municipalities and the PUCT. The request was based on a HTY ended June 30, 2017, a requested ROE of 10.25 percent , an electric rate base of approximately $1.9 billion and an equity ratio of 53.97 percent . The request also reflects the acceleration of depreciation lives for the two generating units at the Tolk Generating Station from 2042 and 2045 to 2032. In May 2018, SPS filed rebuttal testimony and revised its request to an overall increase in the annual base rate revenue of approximately $32 million , or 5.9 percent , net of the TCJA (approximately $32 million after adjusting for a 58 percent equity ratio) and other adjustments. This request would be equivalent to approximately $17 million after adjusting for the Transmission Cost Recovery Factor (TCRF) rider. In June 2018, SPS, the PUCT Staff and various intervenors reached a settlement, which results in no overall change to SPS’ revenues after adjusting for the impact of the TCJA and the lower costs of long-term debt. The following are key terms: • The ability to use an equity ratio that reflects SPS' actual capital structure, which SPS has informed the parties it intends to be 57 percent to mitigate the impact of TCJA on credit metrics; • A 9.5 percent ROE for the calculation of allowance for funds used during construction (AFUDC); • TCRF rider will remain in effect; • SPS will accelerate depreciation rates for the Tolk Generating Station Units 1 and 2 by 50 percent of the original request; and • SPS agrees that it will file its next base rate case no later than Dec. 31, 2019. A reconciliation of the settlement is as follows: (Millions of Dollars) Original base rate request $ 69 Base rate revenue to be recovered through TCRF (15 ) Net revenue request 54 Adjustment for TCJA and other items (37 ) Requested incremental revenue 17 Unspecified settlement adjustments (13 ) Accelerated depreciation (Tolk plant) (4 ) SPS' net revenue change $ — Under the terms of the settlement, the final rates would not change from the current rates. However, SPS would be permitted to surcharge customers for unrecovered TCRF charges that were not billed during the period of Jan. 23, 2018 through June 10, 2018. A PUCT decision is expected in the third quarter of 2018. Appeal of the Texas 2015 Electric Rate Case Decision — In 2014, SPS had requested an overall retail electric revenue rate increase of $42 million . In 2015, the PUCT approved an overall rate decrease of approximately $4 million , net of rate case expenses. In April 2016, SPS filed an appeal with the Texas State District Court (District Court) challenging the PUCT’s order. In 2017, the District Court denied SPS’ appeal, and SPS appealed the District Court’s decision to the state Court of Appeals for the 7th Circuit. In 2018, the Court of Appeals upheld the District Court’s decision on the PUCT’s order, rejecting SPS’ appeal. As part of the settlement of the 2017 Texas rate case, SPS has agreed to end its appeal. Pending Regulatory Proceeding — (New Mexico Public Regulation Commission) NMPRC New Mexico 2017 Electric Rate Case — In October 2017, SPS filed an electric rate case with the NMPRC seeking an increase in base rates of approximately $43 million . The request was based on a HTY ended June 30, 2017, a ROE of 10.25 percent , an equity ratio of 53.97 percent , a 35 percent federal income tax rate and a rate base of approximately $885 million , including rate base additions through Nov. 30, 2017. In May 2018, SPS reduced its request to $27 million , net of the TCJA (approximately $11 million ) and other adjustments, based on a requested ROE of 10.25 percent and an equity ratio of 58.0 percent . In June 2018, the New Mexico Hearing Examiner issued a recommended decision proposing an increase of $12 million , based on a ROE of 9.4 percent and an equity ratio of 53.97 percent . She also denied SPS' requests to shorten depreciation lives related to Tolk Units 1 and 2 and Cunningham Unit 1. The Hearing Examiner rejected intervenor proposals to refund the impacts of the TCJA back to Jan. 1, 2018. The following table summarizes certain parties’ proposed modifications to SPS’ request, SPS’ revised request, and the Hearing Examiner’s recommendation: (Millions of Dollars) NMPRC Staff Testimony NMAG Testimony SPS Rebuttal Testimony Hearing Examiner's Recommendation SPS request $ 43 $ 43 $ 43 $ 43 Reduction to request for the impact of the TCJA (11 ) (11 ) (11 ) (11 ) SPS request, including the impact of the TCJA 32 32 32 32 ROE (4 ) (6 ) — (5 ) Capital structure (7 ) (3 ) — (3 ) Depreciation lives (Tolk and Cunningham plants) (3 ) (3 ) — (3 ) Disallow rate case expenses (2 ) (3 ) (1 ) — Regional transmission revenue and expense (adjustment for the impact of the TCJA): Impact of the TCJA — (3 ) — (1 ) Aligning costs with transmission plant in rate base — — — (1 ) Post test year plant (updated to actual) (1 ) (2 ) (3 ) — Excess generation adjustment — (1 ) — (1 ) Other, net (4 ) (4 ) (1 ) (6 ) Recommended rate increase $ 11 $ 7 $ 27 $ 12 ROE 9.0 % 9.21 % 10.25 % 9.4 % Equity ratio 52.0 % 53.97 % 58.0 % 53.97 % SPS anticipates a decision and implementation of final rates in the third quarter of 2018. Appeal of the New Mexico 2016 Electric Rate Case Dismissal — In November 2016, SPS filed an electric rate case with the NMPRC seeking an increase in base rates of approximately $41 million , representing a total revenue increase of approximately 10.9 percent . The rate filing was based on a requested ROE of 10.1 percent , an equity ratio of 53.97 percent , an electric rate base of approximately $832 million and a future test year ending June 30, 2018. In 2017, the NMPRC dismissed SPS’ rate case. SPS filed a notice of appeal in the New Mexico Supreme Court. A decision is not expected until the second half of 2019. Pending Regulatory Proceeding — Federal Energy Regulatory Commission (FERC) Midcontinent Independent System Operator, Inc. (MISO) Return on Equity (ROE) Complaints — In November 2013, a group of customers filed a complaint at the FERC against 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 , and the removal of ROE adders (including those for Regional Transmission Organization (RTO) membership), effective Nov. 12, 2013. In September 2016, the FERC approved an ALJ recommendation that MISO TOs be granted a 10.32 percent base ROE using the methodology adopted by FERC in June 2014 (Opinion 531). This ROE would be applicable for the 15 -month refund period from Nov. 12, 2013 to Feb. 11, 2015, and prospectively from the date of the FERC order. The total prospective ROE would be 10.82 percent , including a 50 basis point adder for RTO membership. The requests are pending FERC action. In February 2015, a second complaint seeking to reduce the MISO ROE from 12.38 percent to 8.67 percent prior to any RTO adder was filed, resulting in a second period of potential refunds from Feb. 12, 2015 to May 11, 2016. In June 2016, an ALJ recommended a base ROE of 9.7 percent , applying the FERC Opinion 531 methodology. FERC action is pending. In April 2017, the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit) vacated and remanded Opinion 531. It is unclear how the D.C. Circuit’s opinion to vacate and remand Opinion 531 will affect the September 2016 FERC order or the timing and outcome of the second ROE complaint. NSP-Minnesota has recognized a current refund liability consistent with the best estimate of the final ROE. Southwest Power Pool, Inc. (SPP) Open Access Transmission Tariff (OATT) Upgrade Costs — Under the SPP OATT, costs of participant funded, or “sponsored,” transmission upgrades may be recovered from other SPP customers whose transmission service depends on capacity enabled by the upgrade. The SPP OATT has allowed SPP to charge for these upgrades since 2008, but SPP had not been charging its customers for these upgrades. In 2016, the FERC granted SPP’s request to recover the charges not billed since 2008. SPP subsequently billed SPS approximately $13 million for these charges. SPP is also billing SPS ongoing charges of approximately $0.5 million per month. In November 2017, the FERC denied an SPS request for rehearing. In January 2018, SPS appealed the FERC request to the D.C. Circuit Court of Appeals. SPS has filed to recover the SPP charges as part of the appeal. The appeal is currently pending. In October 2017, SPS filed a complaint against SPP regarding the amounts billed asserting that SPP has assessed upgrade charges to SPS in violation of the SPP OATT. In March 2018, the FERC denied SPS’ complaint. SPS sought rehearing in April 2018, and the FERC approved the rehearing request for further consideration on May 7, 2018. If SPS’ complaint results in additional charges or refunds, SPS will seek to recover or refund the differential in future rate proceedings. |
Commitments and Contingencies
Commitments and Contingencies | 6 Months Ended |
Jun. 30, 2018 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | Commitments and Contingencies Except to the extent noted below and in Note 5 of the consolidated financial statements, the circumstances set forth in Notes 12, 13 and 14 to the consolidated financial statements included in Xcel Energy Inc.’s Annual Report on Form 10-K for the year ended Dec. 31, 2017 and in Notes 5 and 6 to Xcel Energy Inc.’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2018, 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. PPAs NSP-Minnesota, PSCo and SPS purchase power from independent power producing entities for which the utility subsidiaries are required to reimburse natural gas or biomass fuel costs, or to participate in tolling arrangements under which the utility subsidiaries procure the natural gas required to produce the energy that they purchase. These specific PPAs create a variable interest in the associated independent power producing entity. The Xcel Energy utility subsidiaries had approximately 3,470 Megawatts (MW) of capacity under long-term PPAs as of June 30, 2018 and 3,537 MW as of Dec. 31, 2017, 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 various expiration dates through 2041 . 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. Xcel Energy Inc.’s exposure is based upon the net liability under the specified agreements or transactions. Most of the guarantees and bond indemnities issued by Xcel Energy Inc. and its subsidiaries have a stated maximum guarantee or indemnity amount. As of June 30, 2018 and Dec. 31, 2017, 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: (Millions of Dollars) June 30, 2018 Dec. 31, 2017 Guarantees issued and outstanding $ 18.4 $ 18.8 Current exposure under these guarantees — — Bonds with indemnity protection $ 51.8 53.1 Other Indemnification Agreements Xcel Energy Inc. and its subsidiaries provide indemnifications through various contracts. 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 future payments under these indemnifications cannot be reasonably estimated as the dollar amounts are often not explicitly stated. Environmental Contingencies Ashland Manufactured Gas Plant (MGP) Site — NSP-Wisconsin was named a potentially responsible party (PRP) for contamination at a site in Ashland, Wis. The Ashland/Northern States Power Lakefront Superfund Site (the Site) includes NSP-Wisconsin property, previously operated as a MGP facility (the Upper Bluff), an adjacent city lakeshore park area (Kreher Park) (collectively the Phase I Area); and a sediment area of Lake Superior’s Chequamegon Bay (Phase II Area). NSP-Wisconsin initiated a wet dredge remedy of the Phase II area in 2017. NSP-Wisconsin anticipates completion of Phase II activities in 2018 with final site restoration activities in early 2019. Groundwater treatment activities at the Site will continue for many years. The current cost estimate for the remediation of the entire site is approximately $175 million , of which approximately $146 million has been spent. As of June 30, 2018 and Dec. 31, 2017 , NSP-Wisconsin recorded a total liability of $29 million and $30 million , respectively, for the entire site. NSP-Wisconsin has deferred the unrecovered portion of the estimated Site remediation costs as a regulatory asset. The PSCW has authorized NSP-Wisconsin rate recovery for all remediation costs incurred at the Site. In 2012, the PSCW agreed to allow NSP-Wisconsin to pre-collect certain costs, to amortize costs over a ten -year period and to apply a three percent carrying cost to the unamortized regulatory asset. In December 2017, the PSCW approved an NSP-Wisconsin natural gas rate case, which included recovery of additional expenses associated with remediating the Site. The annual recovery of MGP clean-up costs increased from $12 million in 2017 to $18 million in 2018. Fargo, N.D. MGP Site — In May 2015, underground pipes, tars and impacted soils were discovered in a right-of-way in Fargo, N.D. that appeared to be associated with a former MGP operated by NSP-Minnesota or prior companies. NSP-Minnesota removed impacted soils and other materials and commenced an investigation of the historic MGP and adjacent properties (the Fargo MGP Site). The North Dakota Department of Health approved NSP-Minnesota’s proposed cleanup plan in January 2017, which involves targeted source removal of impacted soils and historic MGP infrastructure. Remediation activities commenced in June 2018. NSP-Minnesota has also initiated insurance recovery litigation in North Dakota. The U.S. District Court for the District of North Dakota has set a trial date for Spring of 2020. NSP-Minnesota recorded an estimated liability of $10 million as of June 30, 2018 and $16 million as of Dec. 31, 2017 , for the Fargo MGP Site. The current cost estimate for the remediation of the site is approximately $22 million , of which approximately $12 million has been spent. NSP-Minnesota has deferred Fargo MGP Site costs allocable to the North Dakota jurisdiction, or approximately 88 percent of all remediation costs, as approved by the NDPSC. In December 2017, NSP-Minnesota filed a request with the MPUC to defer post-2017 MGP remediation expenditures allocable to the Minnesota jurisdiction, including the Fargo MGP Site. In March 2018, the DOC recommended that the MPUC deny NSP-Minnesota’s deferral request. A MPUC decision is expected in the third quarter of 2018. Other MGP, Landfill or Disposal Sites — Xcel Energy is currently involved in investigating and/or remediating several MGP, landfill or other disposal sites. Xcel Energy has identified eleven sites across its service territories in addition to the Ashland MGP Site and the Fargo MGP Site, where contamination is present and where investigation and/or remediation activities are currently underway. Other parties may have responsibility for some portion of the investigation and/or remediation activities. Xcel Energy anticipates that these investigation or remediation activities will continue through at least 2018. Xcel Energy accrued $5 million as of June 30, 2018 and $4 million as of Dec. 31, 2017 for all of these sites. There may be insurance recovery and/or recovery from other PRPs that will offset any costs incurred. Xcel Energy anticipates that any amounts spent will be fully recovered from customers. Environmental Requirements Air Revisions to the National Ambient Air Quality Standard (NAAQS) for Ozone - In 2015, the EPA revised the NAAQS for ozone by lowering the eight -hour standard from 75 parts per billion (ppb) to 70 ppb. Xcel Energy meets the 2015 ozone standard in all areas where its generating units operate, except for the Denver Metropolitan Area. PSCo’s retirement of its coal fired plants in the Denver non-attainment area helped Colorado’s plan to mitigate non-attainment. In June 2018, the EPA designated the parts of the Denver Metropolitan Area that currently do not attain the 2008 ozone standards as also not attaining the more stringent 2015 ozone standard. Colorado will continue to consider further reductions that are available in the non-attainment area as it develops plans to meet the ozone standards. The gas plants that operate in PSCo’s non-attainment area may be required to improve or add controls, implement further work practices and/or implement enhanced emissions monitoring as part of future Colorado state plans. Legal Contingencies Xcel Energy is involved in various litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or is a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Management maintains accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss. For current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Xcel Energy’s financial statements. Unless otherwise required by GAAP, legal fees are expensed as incurred. Employment, Tort and Commercial Litigation Gas Trading Litigation — e prime, inc. (e prime) is a wholly owned subsidiary of Xcel Energy. e prime was in the business of natural gas trading and marketing but has not engaged in natural gas trading or marketing activities since 2003. Thirteen lawsuits were commenced against e prime and Xcel Energy (and NSP-Wisconsin, in two instances) between 2003 and 2009 alleging fraud and anticompetitive activities in conspiring to restrain the trade of natural gas and manipulate natural gas prices. e prime, Xcel Energy Inc. and its other affiliates were sued along with several other gas marketing companies. These cases were all consolidated in the U.S. District Court in Nevada. Six of the cases remain active, which includes a multi-district litigation (MDL) matter consisting of a Colorado class (Breckenridge), a Wisconsin class (Arandell Corp.), a Missouri class, a Kansas class, and two other cases identified as “Sinclair Oil” and “Farmland.” In March 2017, summary judgment was granted by the MDL judge in favor of Xcel Energy and e prime in the Sinclair Oil and Farmland cases. In November 2017, the U.S. District Court in Nevada granted summary judgment against two plaintiffs in the Arandell Corp. case in favor of Xcel Energy and NSP-Wisconsin, leaving only three individual plaintiffs remaining in the litigation. In addition, the plaintiffs’ motions for class certification and remand back to originating courts in these cases were denied in March 2017. Plaintiffs appealed the summary judgment motions granted in the Farmland and Sinclair Oil cases and the denial of class certification and remand to the U.S. Court of Appeals for the Ninth Circuit (Ninth Circuit). In March 2018, the Ninth Circuit reversed and remanded the summary judgment in the Farmland case. The Farmland defendants subsequently filed a request for further review by the Ninth Circuit, which was denied. Taking into account the decision in the Farmland case, the Sinclair plaintiffs have requested the Ninth Circuit to reverse the grant of summary judgment without hearing. Oral arguments were presented to the Ninth Circuit in July 2018 regarding this issue and the denial of class certification and it is uncertain when a decision will be issued. Xcel Energy, NSP-Wisconsin and e prime have concluded that a loss is remote. Line Extension Disputes — In December 2015, Development Recovery Company (DRC) filed a lawsuit in the Denver District Court, stating PSCo failed to award proper allowances and refunds for line extensions to new developments pursuant to the terms of electric and gas service agreements entered into by PSCo and various developers. The dispute involved claims by over fifty developers. In February 2018, the Colorado Supreme Court denied DRC’s petition to appeal the Denver District Court’s dismissal of the lawsuit, effectively terminating this litigation. However, in January 2018, DRC filed a new lawsuit in Boulder County District Court, asserting a single claim that PSCo was required to file its line extension agreements with the CPUC but failed to do so. This claim is substantially similar to the arguments previously raised by DRC. PSCo filed a motion to dismiss this claim, which was granted in May 2018. DRC subsequently filed an appeal to the Colorado Court of Appeals. It is uncertain when a decision will be rendered regarding this appeal. PSCo has concluded that a loss is remote with respect to this matter as the service agreements were developed to implement CPUC approved tariffs and PSCo has complied with the tariff provisions. Also, if a loss were sustained, PSCo believes it would be allowed to recover these costs through traditional regulatory mechanisms. The amount or range in dispute is presently unknown and no accrual has been recorded for this matter. |
Borrowings and Other Financing
Borrowings and Other Financing Instruments | 6 Months Ended |
Jun. 30, 2018 | |
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. Short-Term Debt — 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 and term loan agreements. Commercial paper and term loan borrowings outstanding for Xcel Energy were as follows: (Amounts in Millions, Except Interest Rates) Three Months Ended Year Ended Borrowing limit $ 3,000 $ 3,250 Amount outstanding at period end 682 814 Average amount outstanding 1,028 644 Maximum amount outstanding 1,349 1,247 Weighted average interest rate, computed on a daily basis 2.42 % 1.35 % Weighted average interest rate at period end 2.47 1.90 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 June 30, 2018 and Dec. 31, 2017 , there were $42 million and $30 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. As of June 30, 2018 , 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. $ 1,250 $ 520 $ 730 PSCo 700 4 696 NSP-Minnesota 500 36 464 SPS 400 134 266 NSP-Wisconsin 150 30 120 Total $ 3,000 $ 724 $ 2,276 (a) These credit facilities expire in June 2021 , with the exception of Xcel Energy Inc.’s 364 -day term loan agreement entered into in December 2017. (b) Includes outstanding commercial paper, term loan borrowings and letters of credit. In addition, Xcel Energy Inc. entered into a $500 million 364 -day term loan in December 2017. As of June 30, 2018, $250 million of borrowings remain outstanding with no additional borrowing capacity. All credit facility bank borrowings, outstanding letters of credit, term loan borrowings 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 as of June 30, 2018 and Dec. 31, 2017 . Long-Term Borrowings During the three months ended June 30, 2018, Xcel Energy Inc. and its utility subsidiaries issued the following: • PSCo issued $350 million of 3.70 percent first mortgage green bonds due June 15, 2028 and $350 million of 4.10 percent first mortgage green bonds due June 15, 2048 ; and • Xcel Energy Inc. issued $500 million of 4.00 percent senior notes due June 15, 2028 . |
Fair Value of Financial Assets
Fair Value of Financial Assets and Liabilities | 6 Months Ended |
Jun. 30, 2018 | |
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 value (NAV). Investments in equity securities and other funds — Equity securities are valued using quoted prices in active markets. The fair values for commingled funds are measured using NAVs, which take into consideration the value of underlying fund investments, as well as the other accrued assets and liabilities of a fund, in order to determine a per-share market value. The investments in commingled funds may be redeemed for NAV 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. 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 classification. 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 and SPS include transmission congestion instruments, generally referred to as financial transmission rights (FTRs). 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 transmission congestion. 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 the cleared prices for each FTR for the most recent auction. 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 transparency in the auction process, fair value measurements for FTRs have been assigned a Level 3. Non-trading monthly FTR settlements are included in 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, the limited transparency associated with the valuation of FTRs are insignificant to the consolidated financial statements of Xcel Energy. Non-Derivative Instruments Fair Value Measurements Nuclear Decommissioning Fund The Nuclear Regulatory Commission (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 decommissioning the Monticello and Prairie Island (PI) nuclear generating plants. The fund contains cash equivalents, debt securities, equity securities and other investments. NSP-Minnesota plans to reinvest matured securities until decommissioning begins. NSP-Minnesota uses the asset class target allocations approved by the MPUC for the 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 impairments, are deferred as a component of the regulatory asset for nuclear decommissioning. Unrealized gains for the nuclear decommissioning fund were $547 million and $560 million as of June 30, 2018 and Dec. 31, 2017 , respectively, and unrealized losses and amounts recorded as other-than-temporary impairments were $23 million and $7 million as of June 30, 2018 and Dec. 31, 2017 , 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 as of June 30, 2018 and Dec. 31, 2017 : June 30, 2018 Fair Value (Millions of Dollars) Cost Level 1 Level 2 Level 3 Investments Measured at NAV (b) Total Nuclear decommissioning fund (a) Cash equivalents $ 31 $ 31 $ — $ — $ — $ 31 Commingled funds: Non U.S. equities 262 199 — — 90 289 Emerging market debt funds 158 — — — 158 158 Private equity investments 151 — — — 220 220 Real estate 128 — — — 197 197 Debt securities: Government securities 76 — 75 — — 75 U.S. corporate bonds 330 — 323 — — 323 Non U.S. corporate bonds 58 — 56 — — 56 Equity securities: U.S. equities 269 568 — — — 568 Non U.S. equities 157 227 — — — 227 Total $ 1,620 $ 1,025 $ 454 $ — $ 665 $ 2,144 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $138 million of equity investments in unconsolidated subsidiaries and $115 million of rabbi trust assets and miscellaneous investments. (b) Due to limited availability of published pricing and a lack of immediate redeemability, certain fund investments measured at NAV are not required to be categorized within the fair value hierarchy. Dec. 31, 2017 Fair Value (Millions of Dollars) Cost Level 1 Level 2 Level 3 Investments Measured at NAV (b) Total Nuclear decommissioning fund (a) Cash equivalents $ 29 $ 29 $ — $ — $ — $ 29 Commingled funds: Non U.S. equities 264 217 — — 90 307 Emerging market debt funds 156 — — — 166 166 Private equity investments 141 — — — 198 198 Real estate 131 — — — 202 202 Other commingled funds 9 6 — — 3 9 Debt securities: Government securities 68 — 69 — — 69 U.S. corporate bonds 320 — 322 — — 322 Non U.S. corporate bonds 50 — 50 — — 50 Equity securities: U.S. equities 271 557 — — — 557 Non U.S. equities 152 234 — — — 234 Total $ 1,591 $ 1,043 $ 441 $ — $ 659 $ 2,143 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $140 million of equity investments in unconsolidated subsidiaries and $114 million of rabbi trust assets and miscellaneous investments. (b) Due to limited availability of published pricing and a lack of immediate redeemability, certain fund investments measured at NAV are not required to be categorized within the fair value hierarchy. For the three and six months ended June 30, 2018 and 2017 there were no Level 3 nuclear decommissioning fund investments and no transfers of amounts between levels. The following table summarizes the final contractual maturity dates of the debt securities in the nuclear decommissioning fund, by asset class, as of June 30, 2018 : Final Contractual Maturity (Millions 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 $ — $ 4 $ 2 $ 69 $ 75 U.S. corporate bonds 5 90 172 56 323 Non U.S. corporate bonds 2 20 30 4 56 Debt securities $ 7 $ 114 $ 204 $ 129 $ 454 Rabbi Trusts In 2016, Xcel Energy established rabbi trusts to provide partial funding for future distributions of its supplemental executive retirement plan and deferred compensation plan. The following tables present the cost and fair value of the assets held in rabbi trusts as of June 30, 2018 and Dec. 31, 2017 : June 30, 2018 Fair Value (Millions of Dollars) Cost Level 1 Level 2 Level 3 Total Rabbi Trusts (a) Cash equivalents $ 11 $ 11 $ — $ — $ 11 Mutual funds 37 51 — — 51 Total $ 48 $ 62 $ — $ — $ 62 Dec. 31, 2017 Fair Value (Millions of Dollars) Cost Level 1 Level 2 Level 3 Total Rabbi Trusts (a) Cash equivalents $ 12 $ 12 $ — $ — $ 12 Mutual funds 47 50 — — 50 Total $ 59 $ 62 $ — $ — $ 62 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet. 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. As of June 30, 2018 , accumulated other comprehensive losses related to interest rate derivatives included $3 million of net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings, including forecasted amounts for unsettled hedges, as applicable. 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, energy-related instruments and natural gas-related instruments, including derivatives. 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. As of June 30, 2018 , Xcel Energy had various vehicle fuel contracts designated as cash flow hedges extending through December 2018. Xcel Energy enters into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers, but may not be 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 six months ended June 30, 2018 and 2017. As of June 30, 2018 , net gains related to commodity derivative cash flow hedges recorded as a component of accumulated other comprehensive losses included immaterial net gains expected to be reclassified into earnings during the next 12 months as the hedged transactions occur. Additionally, Xcel Energy enters into commodity derivative instruments for trading purposes not directly related to commodity price risks associated with serving its electric and natural gas customers. Changes in the fair value of these commodity derivatives are recorded in electric operating revenues, net of amounts credited to customers under margin-sharing mechanisms. The following table details the gross notional amounts of commodity forwards, options and FTRs as of June 30, 2018 and Dec. 31, 2017 : (Amounts in Millions) (a)(b) June 30, 2018 Dec. 31, 2017 Megawatt hours of electricity 108 68 Million British thermal units of natural gas 26 37 (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 six months ended June 30, 2018 and 2017 on accumulated other comprehensive loss, regulatory assets and liabilities, and income: Three Months Ended June 30, 2018 Pre-Tax Fair Value Gains Recognized During the Period in: Pre-Tax (Gains) Losses Reclassified into Income During the Period from: Pre-Tax Gains Recognized (Millions of Dollars) Accumulated Other Regulatory Accumulated Other Regulatory Assets and (Liabilities) Derivatives designated as cash flow hedges Interest rate $ — $ — $ 1 (a) $ — $ — Total $ — $ — $ 1 $ — $ — Other derivative instruments Commodity trading $ — $ — $ — $ — $ 2 (b) Electric commodity — 37 — (3 ) (c) — Total $ — $ 37 $ — $ (3 ) $ 2 Six Months Ended June 30, 2018 Pre-Tax Fair Value Gains Recognized During the Period in: Pre-Tax Losses Reclassified into Income During the Period from: Pre-Tax Gains (Losses) Recognized (Millions of Dollars) Accumulated Other Regulatory Accumulated Other Regulatory Assets and (Liabilities) Derivatives designated as cash flow hedges Interest rate $ — $ — $ 1 (a) $ — $ — Total $ — $ — $ 1 $ — $ — Other derivative instruments Commodity trading $ — $ — $ — $ — $ 10 (b) Electric commodity — 8 — — — Natural gas commodity — — — 2 (d) (2 ) (d) Total $ — $ 8 $ — $ 2 $ 8 Three Months Ended June 30, 2017 Pre-Tax Fair Value Losses Recognized During the Period in: Pre-Tax (Gains) Losses Reclassified into Income During the Period from: Pre-Tax Gains Recognized (Millions of Dollars) Accumulated Other Regulatory Accumulated Other Regulatory Assets and (Liabilities) Derivatives designated as cash flow hedges Interest rate $ — $ — $ 2 (a) $ — $ — Total $ — $ — $ 2 $ — $ — Other derivative instruments Commodity trading $ — $ — $ — $ — $ 6 (b) Electric commodity — (1 ) — (2 ) (c) — Natural gas commodity — (2 ) — — — Total $ — $ (3 ) $ — $ (2 ) $ 6 Six Months Ended June 30, 2017 Pre-Tax Fair Value Losses Recognized During the Period in: Pre-Tax (Gains) Losses Reclassified into Income During the Period from: Pre-Tax Gains (Losses) Recognized (Millions of Dollars) Accumulated Other Regulatory Accumulated Other Regulatory Derivatives designated as cash flow hedges Interest rate $ — $ — $ 2 (a) $ — $ — Total $ — $ — $ 2 $ — $ — Other derivative instruments Commodity trading $ — $ — $ — $ — $ 7 (b) Electric commodity — — — (6 ) (c) — Natural gas commodity — (8 ) — 1 (d) (4 ) (d) Total $ — $ (8 ) $ — $ (5 ) $ 3 (a) Amounts are recorded to interest charges. (b) 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. (c) Amounts are recorded to electric fuel and purchased power. These derivative settlement gains and losses are shared with electric customers through fuel and purchased energy cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate. (d) Certain derivatives are utilized to mitigate natural gas price risk for electric generation and are recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate. Amounts for the three and six months ended June 30, 2018 included no settlement gains or losses and $1 million of settlement losses, respectively. Amounts for the three and six months ended June 30, 2017 included no settlement gains or losses and $1 million of settlement gains, respectively. The remaining derivative settlement gains and losses for the three and six months ended June 30, 2018 and 2017 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 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 six months ended June 30, 2018 and 2017 . 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 credit risk was immaterial to the fair value of unsettled commodity derivatives presented in the consolidated balance sheets. Xcel Energy Inc. and its subsidiaries employ additional credit risk control mechanisms when appropriate, such as letters of credit, parental guarantees, standardized master netting agreements and termination provisions that allow for offsetting of positive and negative exposures. Credit exposure is monitored and, when necessary, the activity with a specific counterparty is limited until credit enhancement is provided. Xcel Energy’s utility subsidiaries’ most significant concentrations of credit risk with particular entities or industries are contracts with counterparties to their wholesale, trading and non-trading commodity activities. As of June 30, 2018 , four of Xcel Energy’s 10 most significant counterparties for these activities, comprising $56 million or 29 percent of this credit exposure, had investment grade credit ratings from Standard & Poor’s, Moody’s or Fitch Ratings. Five of the 10 most significant counterparties, comprising $40 million or 21 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 one remaining significant counterparty, comprising $5 million or 3 percent of this credit exposure, had credit quality less than investment grade based on ratings from external analysis. Nine of these significant counterparties are municipal or cooperative electric entities or other utilities. Credit Related Contingent Features — Contract provisions for derivative instruments that the utility subsidiaries enter, including 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’s credit ratings are downgraded below its investment grade credit rating by any of the major credit rating agencies or for cross-default contractual provisions that could result in the settlement of such contracts if there was a failure under other financing arrangements related to payment terms or other covenants. As of June 30, 2018 and Dec. 31, 2017, there were no derivative instruments in a material liability position with such underlying contract provisions. 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 June 30, 2018 and Dec. 31, 2017 . 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 as of June 30, 2018 : June 30, 2018 Fair Value Fair Value Total Counterparty Netting (b) Total (Millions of Dollars) Level 1 Level 2 Level 3 Current derivative assets Other derivative instruments: Commodity trading $ 1 $ 27 $ 2 $ 30 $ (18 ) $ 12 Electric commodity — — 59 59 (1 ) 58 Natural gas commodity — 1 — 1 — 1 Total current derivative assets $ 1 $ 28 $ 61 $ 90 $ (19 ) 71 PPAs (a) 4 Current derivative instruments $ 75 Noncurrent derivative assets Other derivative instruments: Commodity trading $ — $ 35 $ 6 $ 41 $ (12 ) $ 29 Total noncurrent derivative assets $ — $ 35 $ 6 $ 41 $ (12 ) 29 PPAs (a) 18 Noncurrent derivative instruments $ 47 June 30, 2018 Fair Value Fair Value Total Counterparty Netting (b) Total (Millions of Dollars) Level 1 Level 2 Level 3 Current derivative liabilities Other derivative instruments: Commodity trading $ 1 $ 24 $ 2 $ 27 $ (22 ) $ 5 Electric commodity — — 1 1 (1 ) — Total current derivative liabilities $ 1 $ 24 $ 3 $ 28 $ (23 ) 5 PPAs (a) 22 Current derivative instruments $ 27 Noncurrent derivative liabilities Other derivative instruments: Commodity trading $ — $ 27 $ — $ 27 $ (15 ) $ 12 Total noncurrent derivative liabilities $ — $ 27 $ — $ 27 $ (15 ) 12 PPAs (a) 101 Noncurrent derivative instruments $ 113 (a) 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 is being 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 June 30, 2018 . At June 30, 2018 , derivative assets and liabilities include no obligations to return cash collateral and the rights to reclaim cash collateral of $8 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 as of Dec. 31, 2017 : Dec. 31, 2017 Fair Value Fair Value Total Counterparty Netting (b) Total (Millions of Dollars) Level 1 Level 2 Level 3 Current derivative assets Other derivative instruments: Commodity trading $ 2 $ 22 $ — $ 24 $ (15 ) $ 9 Electric commodity — — 32 32 (2 ) 30 Total current derivative assets $ 2 $ 22 $ 32 $ 56 $ (17 ) 39 PPAs (a) 5 Current derivative instruments $ 44 Noncurrent derivative assets Other derivative instruments: Commodity trading $ — $ 31 $ 5 $ 36 $ (7 ) $ 29 Total noncurrent derivative assets $ — $ 31 $ 5 $ 36 $ (7 ) 29 PPAs (a) 19 Noncurrent derivative instruments $ 48 Dec. 31, 2017 Fair Value Fair Value Total Counterparty Netting (b) Total (Millions of Dollars) Level 1 Level 2 Level 3 Current derivative liabilities Other derivative instruments: Commodity trading $ 2 $ 18 $ — $ 20 $ (15 ) $ 5 Electric commodity — — 2 2 (2 ) — Natural gas commodity — 1 — 1 — 1 Total current derivative liabilities $ 2 $ 19 $ 2 $ 23 $ (17 ) 6 PPAs (a) 23 Current derivative instruments $ 29 Noncurrent derivative liabilities Other derivative instruments: Commodity trading $ — $ 24 $ — $ 24 $ (10 ) $ 14 Total noncurrent derivative liabilities $ — $ 24 $ — $ 24 $ (10 ) 14 PPAs (a) 112 Noncurrent derivative instruments $ 126 (a) 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 is being 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, 2017 . At Dec. 31, 2017 , derivative assets and liabilities include no obligations to return cash collateral and rights to reclaim cash collateral of $3 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 six months ended June 30, 2018 and 2017: Three Months Ended June 30 (Millions of Dollars) 2018 2017 Balance at April 1 $ 19 $ 6 Purchases 45 76 Settlements (20 ) (22 ) Net transactions recorded during the period: (Losses) gains recognized in earnings (a) (2 ) 6 Net gains recognized as regulatory assets and liabilities 22 3 Balance at June 30 $ 64 $ 69 Six Months Ended June 30 (Thousands of Dollars) 2018 2017 Balance at Jan. 1 $ 35 $ 17 Purchases 46 80 Settlements (32 ) (42 ) Net transactions recorded during the period: Gains recognized in earnings (a) — 5 Net gains recognized as regulatory assets and liabilities 15 9 Balance at June 30 $ 64 $ 69 (a) These amounts relate to commodity derivatives held at the end of the period. Xcel Energy recognizes transfers between levels as of the beginning of each period. There were no transfers of amounts between levels for derivative instruments for the three and six months ended June 30, 2018 and 2017. Fair Value of Long-Term Debt As of June 30, 2018 and Dec. 31, 2017 , other financial instruments for which the carrying amount did not equal fair value were as follows: June 30, 2018 Dec. 31, 2017 (Millions of Dollars) Carrying Amount Fair Value Carrying Amount Fair Value Long-term debt, including current portion $ 16,167 $ 16,750 $ 14,977 $ 16,531 The fair value of Xcel Energy’s long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities. The fair value estimates are based on information available to management as of June 30, 2018 and Dec. 31, 2017 , and given the observability of the inputs to these estimates, the fair values presented for long-term debt have been assigned a Level 2. |
Other Income, Net
Other Income, Net | 6 Months Ended |
Jun. 30, 2018 | |
Other Income and Expenses [Abstract] | |
Other Income, Net | Other Expense, Net Other expense, net consisted of the following: Three Months Ended June 30 Six Months Ended June 30 (Millions of Dollars) 2018 2017 2018 2017 Interest income $ 3 $ 2 $ 7 $ 6 Other nonoperating income 1 2 2 5 Insurance policy expense (2 ) (1 ) (1 ) (2 ) Benefits non-service costs (4 ) (7 ) (9 ) (13 ) Other expense, net $ (2 ) $ (4 ) $ (1 ) $ (4 ) |
Segment Information
Segment Information | 6 Months Ended |
Jun. 30, 2018 | |
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 $138 million and $140 million as of June 30, 2018 and Dec. 31, 2017 , 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 operating and maintenance (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. (Millions of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total Three Months Ended June 30, 2018 Operating revenues from external customers $ 2,348 $ 292 $ 18 $ — $ 2,658 Intersegment revenues — — — — — Total revenues $ 2,348 $ 292 $ 18 $ — $ 2,658 Net income (loss) $ 264 $ 27 $ (26 ) $ — $ 265 (Millions of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total Three Months Ended June 30, 2017 Operating revenues from external customers $ 2,338 $ 290 $ 17 $ — $ 2,645 Intersegment revenues 1 — — (1 ) — Total revenues $ 2,339 $ 290 $ 17 $ (1 ) $ 2,645 Net income (loss) $ 227 $ 13 $ (13 ) $ — $ 227 (Millions of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total Six Months Ended June 30, 2018 Operating revenues from external customers $ 4,617 $ 954 $ 38 $ — $ 5,609 Intersegment revenues 1 1 — (2 ) — Total revenues $ 4,618 $ 955 $ 38 $ (2 ) $ 5,609 Net income (loss) $ 483 $ 121 $ (48 ) $ — $ 556 (Millions of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total Six Months Ended June 30, 2017 Operating revenues from external customers $ 4,637 $ 915 $ 39 $ — $ 5,591 Intersegment revenues 1 1 — (2 ) — Total revenues $ 4,638 $ 916 $ 39 $ (2 ) $ 5,591 Net income (loss) $ 422 $ 76 $ (31 ) $ — $ 467 |
Earnings Per Share
Earnings Per Share | 6 Months Ended |
Jun. 30, 2018 | |
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 a dilutive impact to EPS include commitments to issue common stock related to time based equity compensation awards. 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 June 30, 2018 Three Months Ended June 30, 2017 (Amounts in millions, except per share data) Income Shares Per Share Income Shares Per Share Net income $ 265 — — $ 227 — — Basic EPS: Earnings available to common shareholders 265 509.6 $ 0.52 227 508.5 $ 0.45 Effect of dilutive securities: Equity awards — 0.4 — — 0.6 — Diluted EPS: Earnings available to common shareholders $ 265 510.0 $ 0.52 $ 227 509.1 $ 0.45 Six Months Ended June 30, 2018 Six Months Ended June 30, 2017 (Amounts in millions, except per share data) Income Shares Per Share Income Shares Per Share Net income $ 556 — — $ 467 — — Basic EPS: Earnings available to common shareholders 556 509.3 $ 1.09 467 508.4 $ 0.92 Effect of dilutive securities: Equity awards — 0.4 — — 0.6 — Diluted EPS: Earnings available to common shareholders $ 556 509.7 $ 1.09 $ 467 509.0 $ 0.92 |
Benefit Plans and Other Postret
Benefit Plans and Other Postretirement Benefits | 6 Months Ended |
Jun. 30, 2018 | |
Retirement Benefits [Abstract] | |
Benefit Plans and Other Postretirement Benefits | Benefit Plans and Other Postretirement Benefits Components of Net Periodic Benefit Cost (Credit) Three Months Ended June 30 2018 2017 2018 2017 (Millions of Dollars) Pension Benefits Postretirement Health Service cost $ 24 $ 24 $ 1 $ 1 Interest cost (a) 33 36 5 6 Expected return on plan assets (a) (52 ) (52 ) (6 ) (6 ) Amortization of prior service credit (a) (1 ) — (3 ) (3 ) Amortization of net loss (a) 27 26 2 1 Net periodic benefit cost (credit) 31 34 (1 ) (1 ) Costs not recognized due to the effects of regulation (1 ) (4 ) — — Net benefit cost (credit) recognized for financial reporting $ 30 $ 30 $ (1 ) $ (1 ) Six Months Ended June 30 2018 2017 2018 2017 (Millions of Dollars) Pension Benefits Postretirement Health Service cost $ 47 $ 48 $ 1 $ 2 Interest cost (a) 67 72 11 12 Expected return on plan assets (a) (104 ) (104 ) (13 ) (12 ) Amortization of prior service credit (a) (2 ) (1 ) (5 ) (5 ) Amortization of net loss (a) 55 53 3 2 Net periodic benefit cost (credit) 63 68 (3 ) (1 ) Costs not recognized due to the effects of regulation (2 ) (8 ) — — Net benefit cost (credit) recognized for financial reporting $ 61 $ 60 $ (3 ) $ (1 ) (a) The components of net periodic cost other than the service cost component are included in the line item “other expense, net” in the income statement or capitalized on the balance sheet as a regulatory asset. In January 2018, contributions of $150 million were made across four of Xcel Energy’s pension plans. Xcel Energy does not expect additional pension contributions during 2018. |
Other Comprehensive Income
Other Comprehensive Income | 6 Months Ended |
Jun. 30, 2018 | |
Stockholders' Equity Note [Abstract] | |
Other Comprehensive Income | Other Comprehensive Loss Changes in accumulated other comprehensive loss, net of tax, for the three and six months ended June 30, 2018 and 2017 were as follows: Three Months Ended June 30, 2018 (Millions of Dollars) Gains and Losses on Cash Flow Hedges Defined Benefit Pension and Postretirement Items Total Accumulated other comprehensive loss at April 1 $ (58 ) $ (66 ) $ (124 ) Losses reclassified from net accumulated other comprehensive loss 1 1 2 Net current period other comprehensive income 1 1 2 Accumulated other comprehensive loss at June 30 $ (57 ) $ (65 ) $ (122 ) Three Months Ended June 30, 2017 (Millions of Dollars) Gains and Losses on Cash Flow Hedges Defined Benefit Pension and Postretirement Items Total Accumulated other comprehensive loss at April 1 $ (51 ) $ (58 ) $ (109 ) Losses reclassified from net accumulated other comprehensive loss 1 1 2 Net current period other comprehensive income 1 1 2 Accumulated other comprehensive loss at June 30 $ (50 ) $ (57 ) $ (107 ) Six Months Ended June 30, 2018 (Millions of Dollars) Gains and Losses on Cash Flow Hedges Defined Benefit Pension and Postretirement Items Total Accumulated other comprehensive loss at Jan. 1 $ (58 ) $ (67 ) $ (125 ) Losses reclassified from net accumulated other comprehensive loss 1 2 3 Net current period other comprehensive income 1 2 3 Accumulated other comprehensive loss at June 30 $ (57 ) $ (65 ) $ (122 ) Six Months Ended June 30, 2017 (Millions of Dollars) Gains and Losses on Cash Flow Hedges Defined Benefit Pension and Postretirement Items Total Accumulated other comprehensive loss at Jan. 1 $ (51 ) $ (59 ) $ (110 ) Losses reclassified from net accumulated other comprehensive loss 1 2 3 Net current period other comprehensive income 1 2 3 Accumulated other comprehensive loss at June 30 $ (50 ) $ (57 ) $ (107 ) Reclassifications from accumulated other comprehensive loss for the three and six months ended June 30, 2018 and 2017 were as follows: Amounts Reclassified from Accumulated Loss (Millions of Dollars) Three Months Ended June 30, 2018 Three Months Ended June 30, 2017 Losses on cash flow hedges: Interest rate derivatives $ 1 (a) $ 2 (a) Total, pre-tax 1 2 Tax benefit — (1 ) Total, net of tax 1 1 Defined benefit pension and postretirement losses: Amortization of net loss 2 (b) 2 (b) Total, pre-tax 2 2 Tax benefit (1 ) (1 ) Total, net of tax 1 1 Total amounts reclassified, net of tax $ 2 $ 2 Amounts Reclassified from Accumulated Other Comprehensive Loss (Millions of Dollars) Six Months Ended June 30, 2018 Six Months Ended June 30, 2017 Losses on cash flow hedges: Interest rate derivatives $ 1 (a) $ 2 (a) Total, pre-tax 1 2 Tax benefit — (1 ) Total, net of tax 1 1 Defined benefit pension and postretirement losses: Amortization of net loss 3 (b) 3 (b) Total, pre-tax 3 3 Tax benefit (1 ) (1 ) Total, net of tax 2 2 Total amounts reclassified, net of tax $ 3 $ 3 (a) Included in interest charges (b) Included in the computation of net periodic pension and postretirement benefit costs. See Note 12 to the consolidated financial statements for details regarding these benefit plans. |
Revenues
Revenues | 6 Months Ended |
Jun. 30, 2018 | |
Revenue from Contract with Customer [Abstract] | |
Revenues | Revenues Xcel Energy principally generates revenue from the generation, transmission, distribution and sale of electricity and the transportation, distribution and sale of natural gas to wholesale and retail customers. Performance obligations related to the sale of energy are satisfied as energy is delivered to customers. Xcel Energy recognizes revenue in an amount that corresponds directly to the price of the energy delivered to the customer. The measurement of energy sales to customers is generally based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated, and the corresponding unbilled revenue is recognized. Contract terms are generally short-term in nature, and as such Xcel Energy does not recognize a separate financing component of its collections from customers. Xcel Energy presents its revenues net of any excise or other fiduciary-type taxes or fees. NSP-Minnesota participates in MISO, and SPS participates in SPP. Xcel Energy’s utility subsidiaries recognize sales to both native load and other end use customers on a gross basis in electric revenues and cost of sales. Revenues and charges for short term wholesale sales of excess energy transacted through RTOs are also recorded on a gross basis. Other revenues and charges related to participating and transacting in RTOs are recorded on a net basis in cost of sales. Xcel Energy Inc.’s utility subsidiaries have various rate-adjustment mechanisms in place that provide for the recovery of natural gas, electric fuel and purchased energy costs. These cost-adjustment tariffs may increase or decrease the level of revenue collected from customers and are revised periodically for differences between the total amount collected under the clauses and the costs incurred. When applicable, under governing regulatory commission rate orders, fuel cost over-recoveries (the excess of fuel revenue billed to customers over fuel costs incurred) are deferred as regulatory liabilities and under-recoveries (the excess of fuel costs incurred over fuel revenues billed to customers) are deferred as regulatory assets. Certain rate rider mechanisms qualify as alternative revenue programs under GAAP. These mechanisms arise from costs imposed upon the utility by action of a regulator or legislative body related to an environmental, public safety or other mandate. When certain criteria are met (including collection within 24 months), revenue is recognized equal to the revenue requirement, which may include return on rate base items and incentives. The mechanisms are revised periodically for differences between the total amount collected and the revenue recognized, which may increase or decrease the level of revenue collected from customers. Alternative revenue is recorded on a gross basis and is disclosed separate from revenue from contracts with customers in the period earned. In the following tables, revenue is classified by the type of goods/services rendered and market/customer type. The tables also reconcile revenue to the reportable segments. Three Months Ended June 30, 2018 (Millions of Dollars) Electric Natural Gas All Other Total Major revenue types Revenue from contracts with customers: Residential $ 678 $ 157 $ 9 $ 844 Commercial and industrial (C&I) 1,206 82 5 1,293 Other 33 — 2 35 Total retail 1,917 239 16 2,172 Wholesale 194 — — 194 Transmission 132 — — 132 Other 24 23 — 47 Total revenue from contracts with customers 2,267 262 16 2,545 Alternative revenue and other 81 30 2 113 Total revenues $ 2,348 $ 292 $ 18 $ 2,658 Three Months Ended June 30, 2017 (Millions of Dollars) Electric Natural Gas All Other Total Major revenue types Revenue from contracts with customers: Residential $ 654 $ 163 $ 9 $ 826 C&I 1,243 85 4 1,332 Other 33 — 1 34 Total retail 1,930 248 14 2,192 Wholesale 172 — — 172 Transmission 126 — — 126 Other 27 23 — 50 Total revenue from contracts with customers 2,255 271 14 2,540 Alternative revenue and other 83 19 3 105 Total revenues $ 2,338 $ 290 $ 17 $ 2,645 Six Months Ended June 30, 2018 (Millions of Dollars) Electric Natural Gas All Other Total Major revenue types Revenue from contracts with customers: Residential $ 1,365 $ 547 $ 18 $ 1,930 C&I 2,318 289 12 2,619 Other 66 — 4 70 Total retail 3,749 836 34 4,619 Wholesale 382 — — 382 Transmission 255 — — 255 Other 63 51 — 114 Total revenue from contracts with customers 4,449 887 34 5,370 Alternative revenue and other 168 67 4 239 Total revenues $ 4,617 $ 954 $ 38 $ 5,609 Six Months Ended June 30, 2017 (Millions of Dollars) Electric Natural Gas All Other Total Major revenue types Revenue from contracts with customers: Residential $ 1,339 $ 537 $ 17 $ 1,893 C&I 2,391 280 13 2,684 Other 65 — 3 68 Total retail 3,795 817 33 4,645 Wholesale 353 — — 353 Transmission 247 — — 247 Other 52 47 — 99 Total revenue from contracts with customers 4,447 864 33 5,344 Alternative revenue and other 190 51 6 247 Total revenues $ 4,637 $ 915 $ 39 $ 5,591 |
Selected Balance Sheet Data (Ta
Selected Balance Sheet Data (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Balance Sheet Related Disclosures [Abstract] | |
Accounts Receivable, Net | (Millions of Dollars) June 30, 2018 Dec. 31, 2017 Accounts receivable, net Accounts receivable $ 856 $ 849 Less allowance for bad debts (48 ) (52 ) $ 808 $ 797 |
Inventories | (Millions of Dollars) June 30, 2018 Dec. 31, 2017 Inventories Materials and supplies $ 312 $ 311 Fuel 147 186 Natural gas 52 113 $ 511 $ 610 |
Property, Plant and Equipment, Net | (Millions of Dollars) June 30, 2018 Dec. 31, 2017 Property, plant and equipment, net Electric plant $ 39,745 $ 39,016 Natural gas plant 5,955 5,800 Common and other property 2,045 2,013 Plant to be retired (a) 10 11 Construction work in progress 2,658 2,087 Total property, plant and equipment 50,413 48,927 Less accumulated depreciation (15,479 ) (15,000 ) Nuclear fuel 2,712 2,697 Less accumulated amortization (2,357 ) (2,295 ) $ 35,289 $ 34,329 (a) In the third quarter of 2017, PSCo early retired Valmont Unit 5 and converted Cherokee Unit 4 from a coal-fueled generating facility to natural gas. PSCo also expects Craig Unit 1 to be early retired in approximately 2025. Amounts are presented net of accumulated depreciation. |
Income Taxes (Tables)
Income Taxes (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Income Tax Disclosure [Abstract] | |
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block] | Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense. The following reconciles such differences: Three Months Ended June 30 Six Months Ended June 30 2018 2017 2018 2017 Federal statutory rate 21.0 % 35.0 % 21.0 % 35.0 % State tax, net of federal tax effect 5.1 4.1 5.0 4.1 Increase (decreases) in tax from: Wind production tax credits (PTCs) (5.4 ) (4.5 ) (5.8 ) (4.2 ) Regulatory differences - ARAM (a) (5.4 ) (0.1 ) (5.6 ) (0.1 ) Regulatory differences - ARAM deferral (b) 4.0 — 4.8 — Regulatory differences - other utility plant items (1.0 ) (0.9 ) (1.0 ) (0.7 ) Other, net (1.4 ) (2.6 ) (1.4 ) (2.2 ) Effective income tax rate 16.9 % 31.0 % 17.0 % 31.9 % (a) The average rate assumption method (ARAM); a method to flow back excess deferred taxes to customers. (b) The ARAM deferral may decrease during the year, which would result in a reduction to tax expense with a corresponding reduction to revenue, as we receive further direction from our regulatory commissions regarding the return of excess deferred taxes to our customers resulting from the Tax Cuts and Jobs Act (TCJA). |
Summary of Statute of Limitations Applicable to Open Tax Years [Table Text Block] | Xcel Energy files a consolidated federal income tax return. The statute of limitations applicable to Xcel Energy’s federal income tax returns expire as follows: Tax Year(s) Expiration 2009 - 2011 December 2018 2012 - 2014 October 2019 2015 September 2019 2016 September 2020 |
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 June 30, 2018, 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 2012 |
Reconciliation of Unrecognized Tax Benefits | A reconciliation of the amount of unrecognized tax benefit is as follows: (Millions of Dollars) June 30, 2018 Dec. 31, 2017 Unrecognized tax benefit — Permanent tax positions $ 21 $ 20 Unrecognized tax benefit — Temporary tax positions 13 19 Total unrecognized tax benefit $ 34 $ 39 |
Tax Benefits Associated with NOL and Tax Credit Carryforwards | The unrecognized tax benefit amounts were reduced by the tax benefits associated with NOL and tax credit carryforwards. The amounts of tax benefits associated with NOL and tax credit carryforwards are as follows: (Millions of Dollars) June 30, 2018 Dec. 31, 2017 NOL and tax credit carryforwards $ (33 ) $ (31 ) |
Interest Payable related to Unrecognized Tax Benefits [Table Text Block] | 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 June 30, 2018 and Dec. 31, 2017 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of June 30, 2018 or Dec. 31, 2017. |
Rate Matters (Tables)
Rate Matters (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Public Utilities, General Disclosures [Abstract] | |
Colorado 2017 Multi-Year Electric Rate Case | Revenue Request (Millions of Dollars) 2018 2019 2020 2021 Total Revenue request $ 74 $ 75 $ 60 $ 36 $ 245 Clean Air Clean Jobs Act (CACJA) rider conversion to base rates 90 — — — 90 Transmission Cost Adjustment (TCA) rider conversion to base rates 43 — — — 43 Total $ 207 $ 75 $ 60 $ 36 $ 378 Expected year-end rate base (billions of dollars) $ 6.8 $ 7.1 $ 7.3 $ 7.4 |
Colorado 2017 Multi-Year Gas Rate Case | The request, detailed below, was based on FTYs, a 10.0 percent ROE and an equity ratio of 55.25 percent . Revenue Request (Millions of Dollars) 2018 2019 2020 Total Revenue request $ 63 $ 33 $ 43 $ 139 Pipeline System Integrity Adjustment (PSIA) rider conversion to base rates (a) — 94 — 94 Total $ 63 $ 127 $ 43 $ 233 Expected year-end rate base (billions of dollars) (b) $ 1.5 $ 2.3 $ 2.4 (a) The roll-in of PSIA rider revenue into base rates will not have an impact on customer bills or revenue as these costs are already being recovered through the rider. The recovery of incremental PSIA related investments in 2019 and 2020 are included in the base rate request. (b) The additional rate base in 2019 predominantly reflects the roll-in of capital associated with the PSIA rider. |
Colorado 2017 Multi-Year Gas Rate Case - CPUC Decision | The estimated impact of the CPUC’s decision is presented below: (Millions of Dollars) Estimated Impact of the CPUC’s Decision Filed 2018 revenue request based on a FTY $ 63 Impact of the change in test year 5 PSCo’s deficiency based on a 2016 HTY - year-end rate base 68 Adjustments: ROE at 9.35 percent (9 ) Equity ratio of 54.6 percent (2 ) Change in amortization period for certain regulatory assets, including a debt return (6 ) Loss of return on prepaid pension and retiree medical (4 ) Change from 2016 year-end to average rate base (5 ) Other, net 5 Total adjustments (21 ) Total rate increase, prior to the TCJA impacts $ 47 |
Texas 2017 Electric Rate Case - Settlement Reconciliation | A reconciliation of the settlement is as follows: (Millions of Dollars) Original base rate request $ 69 Base rate revenue to be recovered through TCRF (15 ) Net revenue request 54 Adjustment for TCJA and other items (37 ) Requested incremental revenue 17 Unspecified settlement adjustments (13 ) Accelerated depreciation (Tolk plant) (4 ) SPS' net revenue change $ — |
New Mexico 2017 Electric Rate Case | The following table summarizes certain parties’ proposed modifications to SPS’ request, SPS’ revised request, and the Hearing Examiner’s recommendation: (Millions of Dollars) NMPRC Staff Testimony NMAG Testimony SPS Rebuttal Testimony Hearing Examiner's Recommendation SPS request $ 43 $ 43 $ 43 $ 43 Reduction to request for the impact of the TCJA (11 ) (11 ) (11 ) (11 ) SPS request, including the impact of the TCJA 32 32 32 32 ROE (4 ) (6 ) — (5 ) Capital structure (7 ) (3 ) — (3 ) Depreciation lives (Tolk and Cunningham plants) (3 ) (3 ) — (3 ) Disallow rate case expenses (2 ) (3 ) (1 ) — Regional transmission revenue and expense (adjustment for the impact of the TCJA): Impact of the TCJA — (3 ) — (1 ) Aligning costs with transmission plant in rate base — — — (1 ) Post test year plant (updated to actual) (1 ) (2 ) (3 ) — Excess generation adjustment — (1 ) — (1 ) Other, net (4 ) (4 ) (1 ) (6 ) Recommended rate increase $ 11 $ 7 $ 27 $ 12 ROE 9.0 % 9.21 % 10.25 % 9.4 % Equity ratio 52.0 % 53.97 % 58.0 % 53.97 % |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
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: (Millions of Dollars) June 30, 2018 Dec. 31, 2017 Guarantees issued and outstanding $ 18.4 $ 18.8 Current exposure under these guarantees — — Bonds with indemnity protection $ 51.8 53.1 |
Borrowings and Other Financin29
Borrowings and Other Financing Instruments (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Debt Disclosure [Abstract] | |
Commercial Paper | Commercial paper and term loan borrowings outstanding for Xcel Energy were as follows: (Amounts in Millions, Except Interest Rates) Three Months Ended Year Ended Borrowing limit $ 3,000 $ 3,250 Amount outstanding at period end 682 814 Average amount outstanding 1,028 644 Maximum amount outstanding 1,349 1,247 Weighted average interest rate, computed on a daily basis 2.42 % 1.35 % Weighted average interest rate at period end 2.47 1.90 |
Credit Facilities | As of June 30, 2018 , 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. $ 1,250 $ 520 $ 730 PSCo 700 4 696 NSP-Minnesota 500 36 464 SPS 400 134 266 NSP-Wisconsin 150 30 120 Total $ 3,000 $ 724 $ 2,276 (a) These credit facilities expire in June 2021 , with the exception of Xcel Energy Inc.’s 364 -day term loan agreement entered into in December 2017. (b) Includes outstanding commercial paper, term loan borrowings and letters of credit. |
Fair Value of Financial Asset30
Fair Value of Financial Assets and Liabilities (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
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 as of June 30, 2018 and Dec. 31, 2017 : June 30, 2018 Fair Value (Millions of Dollars) Cost Level 1 Level 2 Level 3 Investments Measured at NAV (b) Total Nuclear decommissioning fund (a) Cash equivalents $ 31 $ 31 $ — $ — $ — $ 31 Commingled funds: Non U.S. equities 262 199 — — 90 289 Emerging market debt funds 158 — — — 158 158 Private equity investments 151 — — — 220 220 Real estate 128 — — — 197 197 Debt securities: Government securities 76 — 75 — — 75 U.S. corporate bonds 330 — 323 — — 323 Non U.S. corporate bonds 58 — 56 — — 56 Equity securities: U.S. equities 269 568 — — — 568 Non U.S. equities 157 227 — — — 227 Total $ 1,620 $ 1,025 $ 454 $ — $ 665 $ 2,144 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $138 million of equity investments in unconsolidated subsidiaries and $115 million of rabbi trust assets and miscellaneous investments. (b) Due to limited availability of published pricing and a lack of immediate redeemability, certain fund investments measured at NAV are not required to be categorized within the fair value hierarchy. Dec. 31, 2017 Fair Value (Millions of Dollars) Cost Level 1 Level 2 Level 3 Investments Measured at NAV (b) Total Nuclear decommissioning fund (a) Cash equivalents $ 29 $ 29 $ — $ — $ — $ 29 Commingled funds: Non U.S. equities 264 217 — — 90 307 Emerging market debt funds 156 — — — 166 166 Private equity investments 141 — — — 198 198 Real estate 131 — — — 202 202 Other commingled funds 9 6 — — 3 9 Debt securities: Government securities 68 — 69 — — 69 U.S. corporate bonds 320 — 322 — — 322 Non U.S. corporate bonds 50 — 50 — — 50 Equity securities: U.S. equities 271 557 — — — 557 Non U.S. equities 152 234 — — — 234 Total $ 1,591 $ 1,043 $ 441 $ — $ 659 $ 2,143 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $140 million of equity investments in unconsolidated subsidiaries and $114 million of rabbi trust assets and miscellaneous investments. (b) Due to limited availability of published pricing and a lack of immediate redeemability, certain fund investments measured at NAV are not required to be categorized within the fair value hierarchy. |
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, as of June 30, 2018 : Final Contractual Maturity (Millions 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 $ — $ 4 $ 2 $ 69 $ 75 U.S. corporate bonds 5 90 172 56 323 Non U.S. corporate bonds 2 20 30 4 56 Debt securities $ 7 $ 114 $ 204 $ 129 $ 454 |
Rabbi Trust Securities Amortized Cost and Fair Value Measured on Recurrring Basis [Table Text Block] | In 2016, Xcel Energy established rabbi trusts to provide partial funding for future distributions of its supplemental executive retirement plan and deferred compensation plan. The following tables present the cost and fair value of the assets held in rabbi trusts as of June 30, 2018 and Dec. 31, 2017 : June 30, 2018 Fair Value (Millions of Dollars) Cost Level 1 Level 2 Level 3 Total Rabbi Trusts (a) Cash equivalents $ 11 $ 11 $ — $ — $ 11 Mutual funds 37 51 — — 51 Total $ 48 $ 62 $ — $ — $ 62 Dec. 31, 2017 Fair Value (Millions of Dollars) Cost Level 1 Level 2 Level 3 Total Rabbi Trusts (a) Cash equivalents $ 12 $ 12 $ — $ — $ 12 Mutual funds 47 50 — — 50 Total $ 59 $ 62 $ — $ — $ 62 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet. |
Gross Notional Amounts of Commodity Forwards, Options, and FTRs | The following table details the gross notional amounts of commodity forwards, options and FTRs as of June 30, 2018 and Dec. 31, 2017 : (Amounts in Millions) (a)(b) June 30, 2018 Dec. 31, 2017 Megawatt hours of electricity 108 68 Million British thermal units of natural gas 26 37 (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 six months ended June 30, 2018 and 2017 on accumulated other comprehensive loss, regulatory assets and liabilities, and income: Three Months Ended June 30, 2018 Pre-Tax Fair Value Gains Recognized During the Period in: Pre-Tax (Gains) Losses Reclassified into Income During the Period from: Pre-Tax Gains Recognized (Millions of Dollars) Accumulated Other Regulatory Accumulated Other Regulatory Assets and (Liabilities) Derivatives designated as cash flow hedges Interest rate $ — $ — $ 1 (a) $ — $ — Total $ — $ — $ 1 $ — $ — Other derivative instruments Commodity trading $ — $ — $ — $ — $ 2 (b) Electric commodity — 37 — (3 ) (c) — Total $ — $ 37 $ — $ (3 ) $ 2 Six Months Ended June 30, 2018 Pre-Tax Fair Value Gains Recognized During the Period in: Pre-Tax Losses Reclassified into Income During the Period from: Pre-Tax Gains (Losses) Recognized (Millions of Dollars) Accumulated Other Regulatory Accumulated Other Regulatory Assets and (Liabilities) Derivatives designated as cash flow hedges Interest rate $ — $ — $ 1 (a) $ — $ — Total $ — $ — $ 1 $ — $ — Other derivative instruments Commodity trading $ — $ — $ — $ — $ 10 (b) Electric commodity — 8 — — — Natural gas commodity — — — 2 (d) (2 ) (d) Total $ — $ 8 $ — $ 2 $ 8 Three Months Ended June 30, 2017 Pre-Tax Fair Value Losses Recognized During the Period in: Pre-Tax (Gains) Losses Reclassified into Income During the Period from: Pre-Tax Gains Recognized (Millions of Dollars) Accumulated Other Regulatory Accumulated Other Regulatory Assets and (Liabilities) Derivatives designated as cash flow hedges Interest rate $ — $ — $ 2 (a) $ — $ — Total $ — $ — $ 2 $ — $ — Other derivative instruments Commodity trading $ — $ — $ — $ — $ 6 (b) Electric commodity — (1 ) — (2 ) (c) — Natural gas commodity — (2 ) — — — Total $ — $ (3 ) $ — $ (2 ) $ 6 Six Months Ended June 30, 2017 Pre-Tax Fair Value Losses Recognized During the Period in: Pre-Tax (Gains) Losses Reclassified into Income During the Period from: Pre-Tax Gains (Losses) Recognized (Millions of Dollars) Accumulated Other Regulatory Accumulated Other Regulatory Derivatives designated as cash flow hedges Interest rate $ — $ — $ 2 (a) $ — $ — Total $ — $ — $ 2 $ — $ — Other derivative instruments Commodity trading $ — $ — $ — $ — $ 7 (b) Electric commodity — — — (6 ) (c) — Natural gas commodity — (8 ) — 1 (d) (4 ) (d) Total $ — $ (8 ) $ — $ (5 ) $ 3 (a) Amounts are recorded to interest charges. (b) 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. (c) Amounts are recorded to electric fuel and purchased power. These derivative settlement gains and losses are shared with electric customers through fuel and purchased energy cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate. (d) Certain derivatives are utilized to mitigate natural gas price risk for electric generation and are recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate. Amounts for the three and six months ended June 30, 2018 included no settlement gains or losses and $1 million of settlement losses, respectively. Amounts for the three and six months ended June 30, 2017 included no settlement gains or losses and $1 million of settlement gains, respectively. The remaining derivative settlement gains and losses for the three and six months ended June 30, 2018 and 2017 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 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 | 2017 . 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 as of June 30, 2018 : June 30, 2018 Fair Value Fair Value Total Counterparty Netting (b) Total (Millions of Dollars) Level 1 Level 2 Level 3 Current derivative assets Other derivative instruments: Commodity trading $ 1 $ 27 $ 2 $ 30 $ (18 ) $ 12 Electric commodity — — 59 59 (1 ) 58 Natural gas commodity — 1 — 1 — 1 Total current derivative assets $ 1 $ 28 $ 61 $ 90 $ (19 ) 71 PPAs (a) 4 Current derivative instruments $ 75 Noncurrent derivative assets Other derivative instruments: Commodity trading $ — $ 35 $ 6 $ 41 $ (12 ) $ 29 Total noncurrent derivative assets $ — $ 35 $ 6 $ 41 $ (12 ) 29 PPAs (a) 18 Noncurrent derivative instruments $ 47 June 30, 2018 Fair Value Fair Value Total Counterparty Netting (b) Total (Millions of Dollars) Level 1 Level 2 Level 3 Current derivative liabilities Other derivative instruments: Commodity trading $ 1 $ 24 $ 2 $ 27 $ (22 ) $ 5 Electric commodity — — 1 1 (1 ) — Total current derivative liabilities $ 1 $ 24 $ 3 $ 28 $ (23 ) 5 PPAs (a) 22 Current derivative instruments $ 27 Noncurrent derivative liabilities Other derivative instruments: Commodity trading $ — $ 27 $ — $ 27 $ (15 ) $ 12 Total noncurrent derivative liabilities $ — $ 27 $ — $ 27 $ (15 ) 12 PPAs (a) 101 Noncurrent derivative instruments $ 113 (a) 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 is being 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 June 30, 2018 . At June 30, 2018 , derivative assets and liabilities include no obligations to return cash collateral and the rights to reclaim cash collateral of $8 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 as of Dec. 31, 2017 : Dec. 31, 2017 Fair Value Fair Value Total Counterparty Netting (b) Total (Millions of Dollars) Level 1 Level 2 Level 3 Current derivative assets Other derivative instruments: Commodity trading $ 2 $ 22 $ — $ 24 $ (15 ) $ 9 Electric commodity — — 32 32 (2 ) 30 Total current derivative assets $ 2 $ 22 $ 32 $ 56 $ (17 ) 39 PPAs (a) 5 Current derivative instruments $ 44 Noncurrent derivative assets Other derivative instruments: Commodity trading $ — $ 31 $ 5 $ 36 $ (7 ) $ 29 Total noncurrent derivative assets $ — $ 31 $ 5 $ 36 $ (7 ) 29 PPAs (a) 19 Noncurrent derivative instruments $ 48 Dec. 31, 2017 Fair Value Fair Value Total Counterparty Netting (b) Total (Millions of Dollars) Level 1 Level 2 Level 3 Current derivative liabilities Other derivative instruments: Commodity trading $ 2 $ 18 $ — $ 20 $ (15 ) $ 5 Electric commodity — — 2 2 (2 ) — Natural gas commodity — 1 — 1 — 1 Total current derivative liabilities $ 2 $ 19 $ 2 $ 23 $ (17 ) 6 PPAs (a) 23 Current derivative instruments $ 29 Noncurrent derivative liabilities Other derivative instruments: Commodity trading $ — $ 24 $ — $ 24 $ (10 ) $ 14 Total noncurrent derivative liabilities $ — $ 24 $ — $ 24 $ (10 ) 14 PPAs (a) 112 Noncurrent derivative instruments $ 126 (a) 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 is being 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, 2017 . At Dec. 31, 2017 , derivative assets and liabilities include no obligations to return cash collateral and rights to reclaim cash collateral of $3 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 | ments. The following table presents the changes in Level 3 commodity derivatives for the three and six months ended June 30, 2018 and 2017: Three Months Ended June 30 (Millions of Dollars) 2018 2017 Balance at April 1 $ 19 $ 6 Purchases 45 76 Settlements (20 ) (22 ) Net transactions recorded during the period: (Losses) gains recognized in earnings (a) (2 ) 6 Net gains recognized as regulatory assets and liabilities 22 3 Balance at June 30 $ 64 $ 69 Six Months Ended June 30 (Thousands of Dollars) 2018 2017 Balance at Jan. 1 $ 35 $ 17 Purchases 46 80 Settlements (32 ) (42 ) Net transactions recorded during the period: Gains recognized in earnings (a) — 5 Net gains recognized as regulatory assets and liabilities 15 9 Balance at June 30 $ 64 $ 69 (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 June 30, 2018 and Dec. 31, 2017 , other financial instruments for which the carrying amount did not equal fair value were as follows: June 30, 2018 Dec. 31, 2017 (Millions of Dollars) Carrying Amount Fair Value Carrying Amount Fair Value Long-term debt, including current portion $ 16,167 $ 16,750 $ 14,977 $ 16,531 |
Other Income, Net (Tables)
Other Income, Net (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Other Income and Expenses [Abstract] | |
Other Income, Net | Other expense, net consisted of the following: Three Months Ended June 30 Six Months Ended June 30 (Millions of Dollars) 2018 2017 2018 2017 Interest income $ 3 $ 2 $ 7 $ 6 Other nonoperating income 1 2 2 5 Insurance policy expense (2 ) (1 ) (1 ) (2 ) Benefits non-service costs (4 ) (7 ) (9 ) (13 ) Other expense, net $ (2 ) $ (4 ) $ (1 ) $ (4 ) |
Segment Information (Tables)
Segment Information (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Segment Reporting [Abstract] | |
Results from Operations by Reportable Segment | (Millions of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total Three Months Ended June 30, 2018 Operating revenues from external customers $ 2,348 $ 292 $ 18 $ — $ 2,658 Intersegment revenues — — — — — Total revenues $ 2,348 $ 292 $ 18 $ — $ 2,658 Net income (loss) $ 264 $ 27 $ (26 ) $ — $ 265 (Millions of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total Three Months Ended June 30, 2017 Operating revenues from external customers $ 2,338 $ 290 $ 17 $ — $ 2,645 Intersegment revenues 1 — — (1 ) — Total revenues $ 2,339 $ 290 $ 17 $ (1 ) $ 2,645 Net income (loss) $ 227 $ 13 $ (13 ) $ — $ 227 (Millions of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total Six Months Ended June 30, 2018 Operating revenues from external customers $ 4,617 $ 954 $ 38 $ — $ 5,609 Intersegment revenues 1 1 — (2 ) — Total revenues $ 4,618 $ 955 $ 38 $ (2 ) $ 5,609 Net income (loss) $ 483 $ 121 $ (48 ) $ — $ 556 (Millions of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total Six Months Ended June 30, 2017 Operating revenues from external customers $ 4,637 $ 915 $ 39 $ — $ 5,591 Intersegment revenues 1 1 — (2 ) — Total revenues $ 4,638 $ 916 $ 39 $ (2 ) $ 5,591 Net income (loss) $ 422 $ 76 $ (31 ) $ — $ 467 |
Earnings Per Share (Tables)
Earnings Per Share (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
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 June 30, 2018 Three Months Ended June 30, 2017 (Amounts in millions, except per share data) Income Shares Per Share Income Shares Per Share Net income $ 265 — — $ 227 — — Basic EPS: Earnings available to common shareholders 265 509.6 $ 0.52 227 508.5 $ 0.45 Effect of dilutive securities: Equity awards — 0.4 — — 0.6 — Diluted EPS: Earnings available to common shareholders $ 265 510.0 $ 0.52 $ 227 509.1 $ 0.45 Six Months Ended June 30, 2018 Six Months Ended June 30, 2017 (Amounts in millions, except per share data) Income Shares Per Share Income Shares Per Share Net income $ 556 — — $ 467 — — Basic EPS: Earnings available to common shareholders 556 509.3 $ 1.09 467 508.4 $ 0.92 Effect of dilutive securities: Equity awards — 0.4 — — 0.6 — Diluted EPS: Earnings available to common shareholders $ 556 509.7 $ 1.09 $ 467 509.0 $ 0.92 |
Benefit Plans and Other Postr34
Benefit Plans and Other Postretirement Benefits (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Retirement Benefits [Abstract] | |
Components of Net Periodic Benefit Cost (Credit) | Components of Net Periodic Benefit Cost (Credit) Three Months Ended June 30 2018 2017 2018 2017 (Millions of Dollars) Pension Benefits Postretirement Health Service cost $ 24 $ 24 $ 1 $ 1 Interest cost (a) 33 36 5 6 Expected return on plan assets (a) (52 ) (52 ) (6 ) (6 ) Amortization of prior service credit (a) (1 ) — (3 ) (3 ) Amortization of net loss (a) 27 26 2 1 Net periodic benefit cost (credit) 31 34 (1 ) (1 ) Costs not recognized due to the effects of regulation (1 ) (4 ) — — Net benefit cost (credit) recognized for financial reporting $ 30 $ 30 $ (1 ) $ (1 ) Six Months Ended June 30 2018 2017 2018 2017 (Millions of Dollars) Pension Benefits Postretirement Health Service cost $ 47 $ 48 $ 1 $ 2 Interest cost (a) 67 72 11 12 Expected return on plan assets (a) (104 ) (104 ) (13 ) (12 ) Amortization of prior service credit (a) (2 ) (1 ) (5 ) (5 ) Amortization of net loss (a) 55 53 3 2 Net periodic benefit cost (credit) 63 68 (3 ) (1 ) Costs not recognized due to the effects of regulation (2 ) (8 ) — — Net benefit cost (credit) recognized for financial reporting $ 61 $ 60 $ (3 ) $ (1 ) (a) The components of net periodic cost other than the service cost component are included in the line item “other expense, net” in the income statement or capitalized on the balance sheet as a regulatory asset. |
Other Comprehensive Income (Tab
Other Comprehensive Income (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Stockholders' Equity Note [Abstract] | |
Changes in Accumulated Other Comprehensive Income (Loss), Net of Tax | Changes in accumulated other comprehensive loss, net of tax, for the three and six months ended June 30, 2018 and 2017 were as follows: Three Months Ended June 30, 2018 (Millions of Dollars) Gains and Losses on Cash Flow Hedges Defined Benefit Pension and Postretirement Items Total Accumulated other comprehensive loss at April 1 $ (58 ) $ (66 ) $ (124 ) Losses reclassified from net accumulated other comprehensive loss 1 1 2 Net current period other comprehensive income 1 1 2 Accumulated other comprehensive loss at June 30 $ (57 ) $ (65 ) $ (122 ) Three Months Ended June 30, 2017 (Millions of Dollars) Gains and Losses on Cash Flow Hedges Defined Benefit Pension and Postretirement Items Total Accumulated other comprehensive loss at April 1 $ (51 ) $ (58 ) $ (109 ) Losses reclassified from net accumulated other comprehensive loss 1 1 2 Net current period other comprehensive income 1 1 2 Accumulated other comprehensive loss at June 30 $ (50 ) $ (57 ) $ (107 ) Six Months Ended June 30, 2018 (Millions of Dollars) Gains and Losses on Cash Flow Hedges Defined Benefit Pension and Postretirement Items Total Accumulated other comprehensive loss at Jan. 1 $ (58 ) $ (67 ) $ (125 ) Losses reclassified from net accumulated other comprehensive loss 1 2 3 Net current period other comprehensive income 1 2 3 Accumulated other comprehensive loss at June 30 $ (57 ) $ (65 ) $ (122 ) Six Months Ended June 30, 2017 (Millions of Dollars) Gains and Losses on Cash Flow Hedges Defined Benefit Pension and Postretirement Items Total Accumulated other comprehensive loss at Jan. 1 $ (51 ) $ (59 ) $ (110 ) Losses reclassified from net accumulated other comprehensive loss 1 2 3 Net current period other comprehensive income 1 2 3 Accumulated other comprehensive loss at June 30 $ (50 ) $ (57 ) $ (107 ) |
Reclassifications out of Accumulated Other Comprehensive Loss | Reclassifications from accumulated other comprehensive loss for the three and six months ended June 30, 2018 and 2017 were as follows: Amounts Reclassified from Accumulated Loss (Millions of Dollars) Three Months Ended June 30, 2018 Three Months Ended June 30, 2017 Losses on cash flow hedges: Interest rate derivatives $ 1 (a) $ 2 (a) Total, pre-tax 1 2 Tax benefit — (1 ) Total, net of tax 1 1 Defined benefit pension and postretirement losses: Amortization of net loss 2 (b) 2 (b) Total, pre-tax 2 2 Tax benefit (1 ) (1 ) Total, net of tax 1 1 Total amounts reclassified, net of tax $ 2 $ 2 Amounts Reclassified from Accumulated Other Comprehensive Loss (Millions of Dollars) Six Months Ended June 30, 2018 Six Months Ended June 30, 2017 Losses on cash flow hedges: Interest rate derivatives $ 1 (a) $ 2 (a) Total, pre-tax 1 2 Tax benefit — (1 ) Total, net of tax 1 1 Defined benefit pension and postretirement losses: Amortization of net loss 3 (b) 3 (b) Total, pre-tax 3 3 Tax benefit (1 ) (1 ) Total, net of tax 2 2 Total amounts reclassified, net of tax $ 3 $ 3 (a) Included in interest charges (b) Included in the computation of net periodic pension and postretirement benefit costs. See Note 12 to the consolidated financial statements for details regarding these benefit plans. |
Revenues (Tables)
Revenues (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Revenue from Contract with Customer [Abstract] | |
Disaggregation of Revenue | In the following tables, revenue is classified by the type of goods/services rendered and market/customer type. The tables also reconcile revenue to the reportable segments. Three Months Ended June 30, 2018 (Millions of Dollars) Electric Natural Gas All Other Total Major revenue types Revenue from contracts with customers: Residential $ 678 $ 157 $ 9 $ 844 Commercial and industrial (C&I) 1,206 82 5 1,293 Other 33 — 2 35 Total retail 1,917 239 16 2,172 Wholesale 194 — — 194 Transmission 132 — — 132 Other 24 23 — 47 Total revenue from contracts with customers 2,267 262 16 2,545 Alternative revenue and other 81 30 2 113 Total revenues $ 2,348 $ 292 $ 18 $ 2,658 Three Months Ended June 30, 2017 (Millions of Dollars) Electric Natural Gas All Other Total Major revenue types Revenue from contracts with customers: Residential $ 654 $ 163 $ 9 $ 826 C&I 1,243 85 4 1,332 Other 33 — 1 34 Total retail 1,930 248 14 2,192 Wholesale 172 — — 172 Transmission 126 — — 126 Other 27 23 — 50 Total revenue from contracts with customers 2,255 271 14 2,540 Alternative revenue and other 83 19 3 105 Total revenues $ 2,338 $ 290 $ 17 $ 2,645 Six Months Ended June 30, 2018 (Millions of Dollars) Electric Natural Gas All Other Total Major revenue types Revenue from contracts with customers: Residential $ 1,365 $ 547 $ 18 $ 1,930 C&I 2,318 289 12 2,619 Other 66 — 4 70 Total retail 3,749 836 34 4,619 Wholesale 382 — — 382 Transmission 255 — — 255 Other 63 51 — 114 Total revenue from contracts with customers 4,449 887 34 5,370 Alternative revenue and other 168 67 4 239 Total revenues $ 4,617 $ 954 $ 38 $ 5,609 Six Months Ended June 30, 2017 (Millions of Dollars) Electric Natural Gas All Other Total Major revenue types Revenue from contracts with customers: Residential $ 1,339 $ 537 $ 17 $ 1,893 C&I 2,391 280 13 2,684 Other 65 — 3 68 Total retail 3,795 817 33 4,645 Wholesale 353 — — 353 Transmission 247 — — 247 Other 52 47 — 99 Total revenue from contracts with customers 4,447 864 33 5,344 Alternative revenue and other 190 51 6 247 Total revenues $ 4,637 $ 915 $ 39 $ 5,591 |
Accounting Pronouncements (Deta
Accounting Pronouncements (Details) - Accounting Standards Update 2017-07 $ in Millions | 6 Months Ended |
Jun. 30, 2017USD ($) | |
Operating and Maintenance Expense | |
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |
Net benefit cost (credit) recognized for financial reporting | $ (12) |
Other Income | |
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |
Net benefit cost (credit) recognized for financial reporting | $ 12 |
Balance Sheet Data, Accounts Re
Balance Sheet Data, Accounts Receivable (Details) - USD ($) $ in Millions | Jun. 30, 2018 | Dec. 31, 2017 |
Accounts receivable, net | ||
Accounts receivable | $ 856 | $ 849 |
Less allowance for bad debts | (48) | (52) |
Accounts receivable, net | $ 808 | $ 797 |
Balance Sheet Related Disclosur
Balance Sheet Related Disclosures, Inventories (Details) - USD ($) $ in Millions | Jun. 30, 2018 | Dec. 31, 2017 |
Public Utilities, Inventory [Line Items] | ||
Inventories | $ 511 | $ 610 |
Materials and supplies | ||
Public Utilities, Inventory [Line Items] | ||
Inventories | 312 | 311 |
Fuel | ||
Public Utilities, Inventory [Line Items] | ||
Inventories | 147 | 186 |
Natural gas | ||
Public Utilities, Inventory [Line Items] | ||
Inventories | $ 52 | $ 113 |
Balance Sheet Related Disclos40
Balance Sheet Related Disclosures, Property, Plant and Equipment (Details) - USD ($) $ in Millions | Jun. 30, 2018 | Dec. 31, 2017 | |
Public Utility, Property, Plant and Equipment [Line Items] | |||
Property, plant and equipment, gross | $ 50,413 | $ 48,927 | |
Less accumulated depreciation | (15,479) | (15,000) | |
Property, plant and equipment, net | 35,289 | 34,329 | |
Electric plant | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Property, plant and equipment, gross | 39,745 | 39,016 | |
Natural gas plant | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Property, plant and equipment, gross | 5,955 | 5,800 | |
Common and other property | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Property, plant and equipment, gross | 2,045 | 2,013 | |
Plant to be retired | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Property, plant and equipment, gross | [1] | 10 | 11 |
Construction work in progress | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Property, plant and equipment, gross | 2,658 | 2,087 | |
Nuclear fuel | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Property, plant and equipment, gross | 2,712 | 2,697 | |
Less accumulated depreciation | $ (2,357) | $ (2,295) | |
[1] | In the third quarter of 2017, PSCo early retired Valmont Unit 5 and converted Cherokee Unit 4 from a coal-fueled generating facility to natural gas. PSCo also expects Craig Unit 1 to be early retired in approximately 2025. Amounts are presented net of accumulated depreciation. |
Income Taxes (Details)
Income Taxes (Details) - USD ($) | 3 Months Ended | 6 Months Ended | 12 Months Ended | |||||
Jun. 30, 2018 | Jun. 30, 2017 | Sep. 30, 2015 | Jun. 30, 2018 | Jun. 30, 2017 | Dec. 31, 2016 | Dec. 31, 2012 | Dec. 31, 2017 | |
Tax Audits [Abstract] | ||||||||
Unrecognized Tax Benefits, Income Tax Penalties Accrued | $ 0 | $ 0 | $ 0 | |||||
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent | 21.00% | 35.00% | 21.00% | 35.00% | ||||
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Percent | 5.10% | 4.10% | 5.00% | 4.10% | ||||
Effective Income Tax Rate Reconciliation, Tax Credit, Percent | (5.40%) | (4.50%) | (5.80%) | (4.20%) | ||||
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Percent | (5.40%) | (0.10%) | (5.60%) | (0.10%) | ||||
Effective Income Tax Rate Reconciliation, Tax Cuts and Jobs Act of 2017, Change in Tax Rate, Percent | 4.00% | 0.00% | 4.80% | 0.00% | ||||
Effective Income Tax Rate Reconciliation, Other Regulatory Items, Percent | (1.00%) | (0.90%) | (1.00%) | (0.70%) | ||||
Effective Income Tax Rate Reconciliation, Other Adjustments, Percent | (1.40%) | (2.60%) | (1.40%) | (2.20%) | ||||
Effective Income Tax Rate Reconciliation, Percent | 16.90% | 31.00% | 17.00% | 31.90% | ||||
Unrecognized Tax Benefits [Abstract] | ||||||||
Unrecognized tax benefit — Permanent tax positions | $ 21,000,000 | $ 21,000,000 | 20,000,000 | |||||
Unrecognized tax benefit — Temporary tax positions | 13,000,000 | 13,000,000 | 19,000,000 | |||||
Total unrecognized tax benefit | 34,000,000 | 34,000,000 | 39,000,000 | |||||
NOL and tax credit carryforwards | (33,000,000) | (33,000,000) | $ (31,000,000) | |||||
Upper bound of decrease in unrecognized tax benefit that is reasonably possible | $ 29,000,000 | $ 29,000,000 | ||||||
Internal Revenue Service (IRS) | ||||||||
Tax Audits [Abstract] | ||||||||
Year(s) under examination | 2012 and 2013 | 2010 and 2011 | ||||||
Year of carryback claim under examination | 2,009 | |||||||
Colorado | ||||||||
Tax Audits [Abstract] | ||||||||
Earliest year subject to examination | 2,009 | |||||||
Minnesota | ||||||||
Tax Audits [Abstract] | ||||||||
Year(s) under examination | 2010 through 2014 | |||||||
Earliest year subject to examination | 2,009 | |||||||
Texas | ||||||||
Tax Audits [Abstract] | ||||||||
Earliest year subject to examination | 2,009 | |||||||
Wisconsin | ||||||||
Tax Audits [Abstract] | ||||||||
Year(s) under examination | 2012 and 2013 | |||||||
Earliest year subject to examination | 2,012 |
Rate Matters, NSP-Minnesota (De
Rate Matters, NSP-Minnesota (Details) - USD ($) $ in Millions | 1 Months Ended | 6 Months Ended | ||||||
Jul. 31, 2018 | Jun. 30, 2018 | Apr. 30, 2018 | Sep. 30, 2016 | Jun. 30, 2016 | Feb. 28, 2015 | Nov. 30, 2013 | Jun. 30, 2018 | |
Benson purchase power agreement termination [Member] | ||||||||
Rate Matters [Abstract] | ||||||||
Regulatory Asset, Amortization Period | 10 years | |||||||
Laurentian purchase power agreement termination [Member] | ||||||||
Rate Matters [Abstract] | ||||||||
Regulatory Asset, Amortization Period | 6 years | |||||||
NSP-Minnesota | ||||||||
Rate Matters [Abstract] | ||||||||
Public Utilities, Purchase Power Agreement Termination Payments | $ 93 | $ 93 | ||||||
NSP-Minnesota | FERC Proceeding, MISO ROE Complaint | ||||||||
Rate Matters [Abstract] | ||||||||
Public Utilities, Base Return On Equity Charged To Customers Through Transmission Formula Rates | 12.38% | 12.38% | ||||||
Public Utilities, ROE Applicable To Transmission Formula Rates In The MISO Region, Recommended By Third Parties | 8.67% | 9.15% | ||||||
NSP-Minnesota | Benson purchase power agreement termination [Member] | ||||||||
Rate Matters [Abstract] | ||||||||
Regulatory Assets | 103 | 103 | ||||||
NSP-Minnesota | Laurentian purchase power agreement termination [Member] | ||||||||
Rate Matters [Abstract] | ||||||||
Regulatory Assets | 109 | $ 109 | ||||||
NSP-Minnesota | Minnesota Public Utilities Commission | MPUC Proceeding - Tax Cuts and Jobs Act of 2017 [Member] | ||||||||
Rate Matters [Abstract] | ||||||||
Tax Cuts and Jobs Act of 2017, Estimated 2018 Electric Rate Reduction | $ 136 | |||||||
Tax Cuts and Jobs Act of 2017, Estimated 2018 Natural Gas Rate Reduction | 7 | |||||||
Tax Cuts and Jobs Act of 2017, Proposed 2018 Electric Refund of TCJA Benefits | 68 | |||||||
Tax Cuts and Jobs Act of 2017, Proposed Electric Deferral of TCJA Benefits | 44 | |||||||
Tax Cuts and Jobs Act of 2017, Proposed Amount of Accelerated Depreciation | 22 | |||||||
Tax Cuts and Jobs Act of 2017, Proposed Low Income Program Funding from TCJA Benefits | 2 | |||||||
Tax Cuts and Jobs Act of 2017, Proposed 2018 Natural Gas Refund of TCJA Benefits | $ 3 | |||||||
NSP-Minnesota | Federal Energy Regulatory Commission (FERC) | FERC Proceeding, MISO ROE Complaint | ||||||||
Rate Matters [Abstract] | ||||||||
Public Utilities, ROE Applicable To Transmission Formula Rates In The MISO Region, Approved | 10.32% | |||||||
Public Utilities, Length of Refund Period, In Months | 15 months | |||||||
Public Utilities, ROE Applicable To Transmission Formula Rates In The MISO Region, with RTO Adder, Approved | 10.82% | |||||||
Public Utilities, ROE Basis Point Adder, Approved | 50 | |||||||
NSP-Minnesota | Administrative Law Judge | FERC Proceeding, MISO ROE Complaint | ||||||||
Rate Matters [Abstract] | ||||||||
Public Utilities, ROE Applicable To Transmission Formula Rates In The MISO Region, Recommended By Third Parties | 9.70% | |||||||
NSP-Minnesota | Minnesota Department of Commerce [Member] | MPUC Proceeding - Tax Cuts and Jobs Act of 2017 [Member] | ||||||||
Rate Matters [Abstract] | ||||||||
Tax Cuts and Jobs Act of 2017, Proposed 2018 Total Refund of TCJA Benefits | 90 | |||||||
Tax Cuts and Jobs Act of 2017, Proposed Total Deferral of TCJA Benefits | $ 53 | |||||||
Subsequent Event | NSP-Minnesota | South Dakota Public Utilities Commission [Member] | SDPUC Proceeding - Tax Cuts and Jobs Act of 2017 [Member] | ||||||||
Rate Matters [Abstract] | ||||||||
Tax Cuts and Jobs Act of 2017, Approved Refund of 2018 TCJA Benefits | $ 11 | |||||||
Public Utilities, Length of Stay-out Provision, In Years | 2 years |
Rate Matters Rate Matters, NSP-
Rate Matters Rate Matters, NSP-Wisconsin (Details) - NSP-Wisconsin - Public Service Commission of Wisconsin (PSCW) [Member] - PSCW Proceeding - Tax Cuts and Jobs Act of 2017 [Member] $ in Millions | 1 Months Ended |
May 31, 2018USD ($) | |
Public Utilities, General Disclosures [Line Items] | |
Tax Cuts and Jobs Act of 2017, Approved Refund of 2018 TCJA Benefits | $ 27 |
Tax Cuts and Jobs Act of 2017, Approved Deferral of 2018 TCJA Benefits | $ 5 |
Rate Matters Rate Matters - PSC
Rate Matters Rate Matters - PSCo (Details) - PSCo - USD ($) $ in Millions | Jul. 12, 2018 | May 01, 2018 | Mar. 01, 2018 | Jun. 30, 2018 | May 31, 2018 | Apr. 30, 2018 | Feb. 28, 2018 | Oct. 31, 2017 | Jun. 30, 2017 | |
Colorado Public Utilities Commission [Member] | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Public Utilities, Amount Rider Income Reduced for Tax Cuts and Jobs Act | $ 8 | |||||||||
CPUC Proceeding - Tax Cuts and Jobs Act of 2017 | Colorado Public Utilities Commission [Member] | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Tax Cuts and Jobs Act of 2017, 2018 Electric Refund of TCJA Benefits Under Settlement | $ 42 | |||||||||
Tax Cuts and Jobs Act of 2017, Amount of Accelerated Prepaid Pension Asset Amortization Under Settlement | $ 59 | |||||||||
Tax Cuts and Jobs Act of 2017, 2018 Electric Refund of TCJA Benefits Approved By Commission | $ 42 | |||||||||
Tax Cuts and Jobs Act of 2017, Amount of Accelerated Prepaid Pension Asset Amortization Under Settlement Set For Hearing | $ 59 | |||||||||
CPUC Proceeding - 2017 Multi-Year Electric Rate Case | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Public Utilities, Approximate Rate Increase (Decrease), Amount | $ 245 | |||||||||
Public Utilities, Number of Years Which Rates are Requested to Increase | 4 years | |||||||||
Public Utilities, Requested Return on Equity, Percentage | 10.00% | |||||||||
Public Utilities, Requested Equity Capital Structure, Percentage | 55.25% | |||||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 245 | |||||||||
Public Utilities, Rate Impact | 378 | |||||||||
CPUC Proceeding - 2017 Multi-Year Electric Rate Case, Electric Rates 2018 [Member] | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | 74 | |||||||||
Public Utilities, Rate Impact | 207 | |||||||||
Public Utilities, Expected Year-End Rate Base | 6,800 | |||||||||
CPUC Proceeding - 2017 Multi-Year Gas Rate Case | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Annualized Provisional Rates | $ 43 | |||||||||
Public Utilities, Number of Years Which Rates are Requested to Increase | 3 years | |||||||||
Public Utilities, Requested Return on Equity, Percentage | 10.00% | |||||||||
Public Utilities, Requested Equity Capital Structure, Percentage | 55.25% | |||||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 139 | |||||||||
Public Utilities, Rate Impact | 233 | |||||||||
CPUC Proceeding - 2017 Multi-Year Gas Rate Case | Administrative Law Judge | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Public Utilities, Reduction of Provisional Rates | $ 20 | |||||||||
Public Utilities, Preliminary Estimate for Reduction of Provisional Rates | $ 29 | |||||||||
Public Utilities, Recommended Length of Average Rate Base | 13 months | |||||||||
Public Utilities, Recommended Rate Base | $ 1,600 | |||||||||
Public Utilities, Recommended ROE, Percentage | 9.35% | |||||||||
Public Utilities, Recommended Equity Capital Structure, Percentage | 54.20% | |||||||||
Public Utilities, Total Recommended Rate Increase (Decrease) | $ 46 | |||||||||
CPUC Proceeding - 2017 Multi-Year Electric Rate Case, Electric Rates 2019 | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | 75 | |||||||||
Public Utilities, Rate Impact | 75 | |||||||||
Public Utilities, Expected Year-End Rate Base | 7,100 | |||||||||
CPUC Proceeding - 2017 Multi-Year Electric Rate Case, Electric Rates 2020 | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | 60 | |||||||||
Public Utilities, Rate Impact | 60 | |||||||||
Public Utilities, Expected Year-End Rate Base | 7,300 | |||||||||
CPUC Proceeding - 2017 Multi-Year Electric Rate Case, Electric Rates 2021 | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | 36 | |||||||||
Public Utilities, Rate Impact | 36 | |||||||||
Public Utilities, Expected Year-End Rate Base | 7,400 | |||||||||
CPUC Proceeding - 2017 Multi-Year Gas Rate Case, Gas Rates 2018 | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | 63 | |||||||||
Public Utilities, Rate Impact | 63 | |||||||||
Public Utilities, Expected Year-End Rate Base | [1] | 1,500 | ||||||||
CPUC Proceeding - 2017 Multi-Year Gas Rate Case, Gas Rates 2019 | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | 33 | |||||||||
Public Utilities, Rate Impact | 127 | |||||||||
Public Utilities, Expected Year-End Rate Base | [1] | 2,300 | ||||||||
CPUC Proceeding - 2017 Multi-Year Gas Rate Case, Gas Rates 2020 | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | 43 | |||||||||
Public Utilities, Rate Impact | 43 | |||||||||
Public Utilities, Expected Year-End Rate Base | [1] | 2,400 | ||||||||
Subsequent Event | CPUC Proceeding - 2017 Multi-Year Gas Rate Case | Colorado Public Utilities Commission [Member] | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Public Utilities, Approved Length of Average Rate Base | 13 months | |||||||||
Public Utilities, Approved Return on Equity, Percentage | 9.35% | |||||||||
Public Utilities, Approved Equity Capital Structure, Percentage | 54.60% | |||||||||
Public Utilities, Approved Rate Increase (Decrease), Amount | $ 47 | |||||||||
Subsequent Event | CPUC Proceeding - 2017 Multi-Year Gas Rate Case, Gas Rates 2018 | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Public Utilities, Impact of Change in Test Year | 5 | |||||||||
Public Utilities, Revised requested rate increase | 68 | |||||||||
Subsequent Event | CPUC Proceeding - 2017 Multi-Year Gas Rate Case, Gas Rates 2018 | Colorado Public Utilities Commission [Member] | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Public Utilities, Increase (Decrease) of Recommended ROE | (9) | |||||||||
Public Utilities, Increase (Decrease) of Recommended Capital Structure | (2) | |||||||||
Public Utilities, Increase (Decrease) of Recommended Change in Amortization Period | (6) | |||||||||
Public Utilities, Increase (Decrease) of Recommended Prepaid pension and Retiree Medical Assets | (4) | |||||||||
Public Utilities, Increase (Decrease) of Recommended Change to Average Rate Base | (5) | |||||||||
Public Utilities, Increase (Decrease) Other, net | 5 | |||||||||
Public Utilities, Total Recommended Adjustments | (21) | |||||||||
Public Utilities, Total Recommended Rate Increase, Before Impact of the Tax Cuts and Jobs Act | $ 47 | |||||||||
Clean Air Clean Jobs Act (CACJA) Recovery Rider | CPUC Proceeding - 2017 Multi-Year Electric Rate Case | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Public Utilities, Rider Conversion to Base Rates | 90 | |||||||||
Clean Air Clean Jobs Act (CACJA) Recovery Rider | CPUC Proceeding - 2017 Multi-Year Electric Rate Case, Electric Rates 2018 [Member] | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Public Utilities, Rider Conversion to Base Rates | 90 | |||||||||
Clean Air Clean Jobs Act (CACJA) Recovery Rider | CPUC Proceeding - 2017 Multi-Year Electric Rate Case, Electric Rates 2019 | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Public Utilities, Rider Conversion to Base Rates | 0 | |||||||||
Clean Air Clean Jobs Act (CACJA) Recovery Rider | CPUC Proceeding - 2017 Multi-Year Electric Rate Case, Electric Rates 2020 | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Public Utilities, Rider Conversion to Base Rates | 0 | |||||||||
Clean Air Clean Jobs Act (CACJA) Recovery Rider | CPUC Proceeding - 2017 Multi-Year Electric Rate Case, Electric Rates 2021 | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Public Utilities, Rider Conversion to Base Rates | 0 | |||||||||
Transmission Cost Adjustment (TCA) Rider | CPUC Proceeding - 2017 Multi-Year Electric Rate Case | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Public Utilities, Rider Conversion to Base Rates | 43 | |||||||||
Transmission Cost Adjustment (TCA) Rider | CPUC Proceeding - 2017 Multi-Year Electric Rate Case, Electric Rates 2018 [Member] | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Public Utilities, Rider Conversion to Base Rates | 43 | |||||||||
Transmission Cost Adjustment (TCA) Rider | CPUC Proceeding - 2017 Multi-Year Electric Rate Case, Electric Rates 2019 | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Public Utilities, Rider Conversion to Base Rates | 0 | |||||||||
Transmission Cost Adjustment (TCA) Rider | CPUC Proceeding - 2017 Multi-Year Electric Rate Case, Electric Rates 2020 | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Public Utilities, Rider Conversion to Base Rates | 0 | |||||||||
Transmission Cost Adjustment (TCA) Rider | CPUC Proceeding - 2017 Multi-Year Electric Rate Case, Electric Rates 2021 | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Public Utilities, Rider Conversion to Base Rates | $ 0 | |||||||||
Pipeline System Integrity Adjustment (PSIA) Rider | CPUC Proceeding - 2017 Multi-Year Gas Rate Case | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Public Utilities, Rider Conversion to Base Rates | [2] | 94 | ||||||||
Pipeline System Integrity Adjustment (PSIA) Rider | CPUC Proceeding - 2017 Multi-Year Gas Rate Case, Gas Rates 2018 | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Public Utilities, Rider Conversion to Base Rates | [2] | 0 | ||||||||
Pipeline System Integrity Adjustment (PSIA) Rider | CPUC Proceeding - 2017 Multi-Year Gas Rate Case, Gas Rates 2019 | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Public Utilities, Rider Conversion to Base Rates | [2] | 94 | ||||||||
Pipeline System Integrity Adjustment (PSIA) Rider | CPUC Proceeding - 2017 Multi-Year Gas Rate Case, Gas Rates 2020 | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Public Utilities, Rider Conversion to Base Rates | [2] | $ 0 | ||||||||
[1] | The additional rate base in 2019 predominantly reflects the roll-in of capital associated with the PSIA rider. | |||||||||
[2] | The roll-in of PSIA rider revenue into base rates will not have an impact on customer bills or revenue as these costs are already being recovered through the rider. The recovery of incremental PSIA related investments in 2019 and 2020 are included in the base rate request. |
Rate Matters, SPS (Details)
Rate Matters, SPS (Details) - USD ($) $ in Millions | 1 Months Ended | 6 Months Ended | 12 Months Ended | |||||||
Jun. 30, 2018 | May 31, 2018 | Feb. 28, 2018 | Oct. 31, 2017 | Nov. 30, 2016 | Jun. 30, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
NMPRC Staff [Member] | New Mexico 2017 Electric Rate Case [Member] | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Public Utilities, Increase (Decrease) from Post Test Year Plant Adjustment | $ (1) | |||||||||
Public Utilities, Recommended ROE, Percentage | 9.00% | |||||||||
Public Utilities, Recommended Equity Capital Structure, Percentage | 52.00% | |||||||||
Public Utilities, Increase (Decrease) of Recommended ROE | $ (4) | |||||||||
Public Utilities, Increase (Decrease) of Recommended Capital Structure and Cost of Debt | (7) | |||||||||
Public Utilities, Increase (Decrease) from Recommended Accelerated Depreciation for Tolk Plant | (3) | |||||||||
Public Utilities, Increase (Decrease) Rate Case Expense Disallowance | (2) | |||||||||
Public Utilities, Increase (Decrease) from Regional Transmission Revenue TCJA Adjustment | 0 | |||||||||
Public Utilities, Increase (Decrease) from Regional Transmission Revenue TCJA Adjustment Aligning Costs With Plant In Rate Base | 0 | |||||||||
Public Utilities, Increase (Decrease) Other, net | (4) | |||||||||
Public Utilities, Total Recommended Rate Increase (Decrease) | 11 | |||||||||
Excess generation adjustment | 0 | |||||||||
New Mexico Attorney General (NMAG) [Member] | New Mexico 2017 Electric Rate Case [Member] | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Public Utilities, Increase (Decrease) from Post Test Year Plant Adjustment | $ (2) | |||||||||
Public Utilities, Recommended ROE, Percentage | 9.21% | |||||||||
Public Utilities, Recommended Equity Capital Structure, Percentage | 53.97% | |||||||||
Public Utilities, Increase (Decrease) of Recommended ROE | $ (6) | |||||||||
Public Utilities, Increase (Decrease) of Recommended Capital Structure and Cost of Debt | (3) | |||||||||
Public Utilities, Increase (Decrease) from Recommended Accelerated Depreciation for Tolk Plant | (3) | |||||||||
Public Utilities, Increase (Decrease) Rate Case Expense Disallowance | (3) | |||||||||
Public Utilities, Increase (Decrease) from Regional Transmission Revenue TCJA Adjustment | (3) | |||||||||
Public Utilities, Increase (Decrease) from Regional Transmission Revenue TCJA Adjustment Aligning Costs With Plant In Rate Base | 0 | |||||||||
Public Utilities, Increase (Decrease) Other, net | (4) | |||||||||
Public Utilities, Total Recommended Rate Increase (Decrease) | 7 | |||||||||
Excess generation adjustment | (1) | |||||||||
Hearing Examiner [Member] | New Mexico 2017 Electric Rate Case [Member] | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Public Utilities, Increase (Decrease) from Post Test Year Plant Adjustment | $ 0 | |||||||||
Public Utilities, Recommended ROE, Percentage | 9.40% | |||||||||
Public Utilities, Recommended Equity Capital Structure, Percentage | 53.97% | |||||||||
Public Utilities, Increase (Decrease) of Recommended ROE | $ (5) | |||||||||
Public Utilities, Increase (Decrease) of Recommended Capital Structure and Cost of Debt | (3) | |||||||||
Public Utilities, Increase (Decrease) from Recommended Accelerated Depreciation for Tolk Plant | (3) | |||||||||
Public Utilities, Increase (Decrease) Rate Case Expense Disallowance | 0 | |||||||||
Public Utilities, Increase (Decrease) from Regional Transmission Revenue TCJA Adjustment | (1) | |||||||||
Public Utilities, Increase (Decrease) from Regional Transmission Revenue TCJA Adjustment Aligning Costs With Plant In Rate Base | (1) | |||||||||
Public Utilities, Increase (Decrease) Other, net | (6) | |||||||||
Public Utilities, Total Recommended Rate Increase (Decrease) | 12 | |||||||||
Excess generation adjustment | $ (1) | |||||||||
SPS | PUCT Proceeding - Texas 2017 Electric Rate Case | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Public Utilities, Revised Requested Rate Increase, Percentage | 5.90% | |||||||||
Public Utilities, Revised Incremental Revenue Request | $ 69 | |||||||||
Public Utilities, Revised requested rate increase | $ 32 | |||||||||
Public Utilities, Intended Equity Capital Structure, Percentage | 57.00% | |||||||||
Public Utilities, Requested Rate Increase (Decrease), Percentage | 5.80% | |||||||||
Public Utilities, Requested Return on Equity, Percentage | 10.25% | |||||||||
Public Utilities, Requested Rate Base, Amount | $ 1,900 | |||||||||
Public Utilities, Requested Equity Capital Structure, Percentage | 53.97% | |||||||||
Public Utilities, Revised requested rate increase after TCRF rider adjustment | 17 | |||||||||
Public Utilities, Revised Requested Rate Increase | $ 54 | |||||||||
Public Utilities, Revised requested rate increase after equity ratio adjustment | $ 32 | |||||||||
Public Utilities, Revised Requested Capital Structure, Percentage | 58.00% | |||||||||
SPS | PUCT Proceeding - Appeal of the Texas 2015 Electric Rate Case Decision | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Public Utilities, Revised Requested Rate Increase | $ 42 | |||||||||
SPS | NMPRC Proceeding - New Mexico 2016 Electric Rate Case | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Public Utilities, Requested Rate Increase (Decrease), Percentage | 10.90% | |||||||||
Public Utilities, Requested Return on Equity, Percentage | 10.10% | |||||||||
Public Utilities, Requested Rate Base, Amount | $ 832 | |||||||||
Public Utilities, Requested Equity Capital Structure, Percentage | 53.97% | 53.97% | ||||||||
Public Utiilities, Federal Income Tax Rate Used in Rate Request | 35.00% | |||||||||
Public Utilities, Revised Requested Rate Increase | $ 41 | |||||||||
SPS | New Mexico 2017 Electric Rate Case [Member] | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Tax Cuts and Jobs Act of 2017, Estimated Electric Rate Reduction | $ 11 | $ 11 | $ 11 | |||||||
Public Utilities, Revised Requested Equity Capital Structure, Percentage | 58.00% | |||||||||
Public Utilities, Increase (Decrease) from Post Test Year Plant Adjustment | $ (3) | |||||||||
Public Utilities, Requested Return on Equity, Percentage | 10.25% | 10.25% | ||||||||
Public Utilities, Requested Rate Base, Amount | $ 885 | |||||||||
Public Utilities, Requested Equity Capital Structure, Percentage | 58.00% | |||||||||
Public Utilities, Revised Requested Rate Increase | 43 | |||||||||
Public Utilities, Requested Rate Increase (Decrease) Including TCJA Impact, Amount | $ 27 | $ 32 | ||||||||
Public Utilities, Increase (Decrease) of Recommended ROE | 0 | |||||||||
Public Utilities, Increase (Decrease) of Recommended Capital Structure and Cost of Debt | 0 | |||||||||
Public Utilities, Increase (Decrease) from Recommended Accelerated Depreciation for Tolk Plant | 0 | |||||||||
Public Utilities, Increase (Decrease) Rate Case Expense Disallowance | (1) | |||||||||
Public Utilities, Increase (Decrease) from Regional Transmission Revenue TCJA Adjustment | 0 | |||||||||
Public Utilities, Increase (Decrease) from Regional Transmission Revenue TCJA Adjustment Aligning Costs With Plant In Rate Base | 0 | |||||||||
Public Utilities, Increase (Decrease) Other, net | (1) | |||||||||
Public Utilities, Total Recommended Rate Increase (Decrease) | 27 | |||||||||
Excess generation adjustment | $ 0 | |||||||||
SPS | Public Utility Commission of Texas (PUCT) | PUCT Proceeding - Appeal of the Texas 2015 Electric Rate Case Decision | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Public Utilities, Approved Rate Decrease, Net of Rate Case Expenses | $ 4 | |||||||||
SPS | Settlement Group [Member] | PUCT Proceeding - Texas 2017 Electric Rate Case | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Public Utilities, Revised Incremental Revenue Request | $ 17 | |||||||||
Public Utilities, Requested Return on Equity, Percentage to Calculate AFUDC | 9.50% | |||||||||
Public Utilities, Decrease in Requested Accelerated Depreciation for Tolk Plant, Percent | 50.00% | |||||||||
Public Utilities, Rate Increase Under the Settlement | $ 0 | |||||||||
Public Utilities, Increase (Decrease) from Recommended Accelerated Depreciation for Tolk Plant | (4) | |||||||||
Public Utilities, Increase (Decrease) Related to Tax Cuts and Jobs Act and Other Items | (37) | |||||||||
Public Utilities, Increase (Decrease) Related to Unspecified Settlement Adjustments | $ (13) | |||||||||
SPS | Southwest Power Pool (SPP) | SPP Open Access Transmission Tariff Upgrade Costs | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Public Utilities, Billed Charges For Transmission Service Upgrades | $ 13 | |||||||||
Public Utilities, Monthly Billed Charges For Transmission Service Upgrades | $ 0.5 | |||||||||
Transmission Cost Recovery Factory (TCRF) Rider | SPS | PUCT Proceeding - Texas 2017 Electric Rate Case | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Public Utilities, Rider Conversion to Base Rates | $ (15) |
Commitments and Contingencies,
Commitments and Contingencies, Purchased Power Agreements (Details) - Independent Power Producing Entities - MW | 6 Months Ended | |
Jun. 30, 2018 | Dec. 31, 2017 | |
Variable Interest Entity [Line Items] | ||
Generating capacity under long term purchased power agreements (in MW) | 3,470 | 3,537 |
Purchase Power Agreement Expiration (Year) | 2,041 |
Commitments and Contingencies47
Commitments and Contingencies, Guarantees and Indemnifications (Details) | Jun. 30, 2018USD ($) | Dec. 31, 2017USD ($) |
Guarantees [Abstract] | ||
Assets held as collateral | $ 0 | $ 0 |
Payment or Performance Guarantee | ||
Guarantees [Abstract] | ||
Guarantees issued and outstanding | 18,400,000 | 18,800,000 |
Current exposure under these guarantees | 0 | 0 |
Payment or Performance Guarantee | Surety Bonds | ||
Guarantees [Abstract] | ||
Guarantees issued and outstanding | 51,800,000 | 53,100,000 |
Other MGP Sites [Member] | ||
Guarantees [Abstract] | ||
Accrual for Environmental Loss Contingencies, Gross | $ 5,000,000 | $ 4,000,000 |
Number of identified MGP sites under current investigation and/or remediation in addition to those separately disclosed | 11 |
Commitments and Contingencies48
Commitments and Contingencies, Environmental Contingencies - Site Contingencies (Details) $ in Millions | 6 Months Ended | 12 Months Ended |
Jun. 30, 2018USD ($) | Dec. 31, 2017USD ($) | |
Other MGP Sites [Member] | ||
Manufactured Gas Plant (MGP) Site [Abstract] | ||
Accrual for Environmental Loss Contingencies, Gross | $ 5 | $ 4 |
Number of identified MGP sites under current investigation and/or remediation in addition to those separately disclosed | 11 | |
NSP-Wisconsin | Ashland MGP Site | ||
Manufactured Gas Plant (MGP) Site [Abstract] | ||
Accrual for Environmental Loss Contingencies, Gross | $ 29 | 30 |
Current Cost Estimate for Site Remediation | 175 | |
Estimated amount spent on cleanup | $ 146 | |
Approved amortization period for recovery of remediation costs in natural gas rates (in years) | 10 | |
Carrying cost percentage to be applied to unamortized regulatory asset | 3.00% | |
NSP-Minnesota | Fargo MGP Site | ||
Manufactured Gas Plant (MGP) Site [Abstract] | ||
Accrual for Environmental Loss Contingencies, Gross | $ 10 | 16 |
Current Cost Estimate for Site Remediation | 22 | |
Estimated amount spent on cleanup | $ 12 | |
Percentage of Response Costs Allocable to the Minnesota Jurisdiction | 88.00% | |
PSCW Proceeding - Gas Rate Case 2017 - Gas Rates 2017 | NSP-Wisconsin | Ashland MGP Site | ||
Manufactured Gas Plant (MGP) Site [Abstract] | ||
Public Utilities, Requested annual recovery collected through base rates | $ 12 | |
PSCW Proceeding - Gas Rate Case 2017 - Gas Rates 2018 [Member] | NSP-Wisconsin | Ashland MGP Site | ||
Manufactured Gas Plant (MGP) Site [Abstract] | ||
Public Utilities, Requested annual recovery collected through base rates | $ 18 |
Commitments and Contingencies49
Commitments and Contingencies, Environmental Contingencies - Unrecorded Unconditional Purchase Obligation (Details) - National Ambient Air Quality Standards for Ozone [Member] | Dec. 31, 2015Period |
Environmental Requirements [Abstract] | |
Number of hours measured for standard | 8 |
Revised Level of Air Quality Concentrations (in parts per billion) | 70 |
Former Level of Air Quality Concentrations (in parts per billion) | 75 |
Commitments and Contingencies50
Commitments and Contingencies, Legal Contingencies (Details) | 1 Months Ended | ||
Dec. 31, 2015 | Jun. 30, 2018 | Dec. 31, 2009 | |
Gas Trading Litigation | |||
Legal Contingencies [Abstract] | |||
Loss Contingency, Pending Claims, Number | 6 | 13 | |
Loss Contingency, Subset of Cases within Multi-District Litigation, Number | 2 | ||
NSP-Wisconsin | Gas Trading Litigation | |||
Legal Contingencies [Abstract] | |||
Loss Contingency, Pending Claims, Number | 2 | ||
Minimum | PSCo | Line Extension Disputes | |||
Legal Contingencies [Abstract] | |||
Loss Contingency, Number of Plaintiffs | 50 |
Borrowings and Other Financin51
Borrowings and Other Financing Instruments, Commercial Paper (Details) - USD ($) | 3 Months Ended | 12 Months Ended |
Jun. 30, 2018 | Dec. 31, 2017 | |
Short-term Debt [Line Items] | ||
Amount outstanding at period end | $ 682,000,000 | $ 814,000,000 |
Commercial Paper | ||
Short-term Debt [Line Items] | ||
Borrowing limit | 3,000,000,000 | 3,250,000,000 |
Amount outstanding at period end | 682,000,000 | 814,000,000 |
Average amount outstanding | 1,028,000,000 | 644,000,000 |
Maximum amount outstanding | $ 1,349,000,000 | $ 1,247,000,000 |
Weighted average interest rate, computed on a daily basis (percentage) | 2.42% | 1.35% |
Weighted average interest rate at period end (percentage) | 2.47% | 1.90% |
Borrowings and Other Financin52
Borrowings and Other Financing Instruments, Letters of Credit (Details) - USD ($) $ in Millions | 6 Months Ended | |
Jun. 30, 2018 | Dec. 31, 2017 | |
Line of Credit Facility [Line Items] | ||
Amount outstanding at period end | $ 682 | $ 814 |
Letter of Credit | ||
Line of Credit Facility [Line Items] | ||
Amount outstanding at period end | $ 42 | $ 30 |
Letter of Credit | Letter of Credit | ||
Line of Credit Facility [Line Items] | ||
Term of letters of credit (in years) | 1 year |
Borrowings and Other Financin53
Borrowings and Other Financing Instruments, Credit Facilities (Details) - USD ($) | 6 Months Ended | 12 Months Ended | |
Jun. 30, 2018 | Dec. 31, 2017 | ||
Credit Facilities | |||
Line of Credit Facility [Line Items] | |||
Credit Facility | [1] | $ 3,000,000,000 | |
Drawn | [2] | 724,000,000 | |
Line of Credit Facility, Remaining Borrowing Capacity | 2,276,000,000 | ||
Direct advances on the credit facility outstanding | 0 | $ 0 | |
Xcel Energy Inc. | Credit Facilities | |||
Line of Credit Facility [Line Items] | |||
Credit Facility | [1] | 1,250,000,000 | |
Drawn | [2] | 520,000,000 | |
Line of Credit Facility, Remaining Borrowing Capacity | $ 730,000,000 | ||
Maturity Date | Jun. 30, 2021 | ||
Xcel Energy Inc. | 364-Day Term Loan [Member] | |||
Line of Credit Facility [Line Items] | |||
Credit Facility | $ 500,000,000 | ||
Term of letters of credit (in years) | 364 days | 364 days | |
Line of Credit Facility, Remaining Borrowing Capacity | $ 0 | ||
PSCo | Credit Facilities | |||
Line of Credit Facility [Line Items] | |||
Credit Facility | [1] | 700,000,000 | |
Drawn | [2] | 4,000,000 | |
Line of Credit Facility, Remaining Borrowing Capacity | $ 696,000,000 | ||
Maturity Date | Jun. 30, 2021 | ||
NSP-Minnesota | Credit Facilities | |||
Line of Credit Facility [Line Items] | |||
Credit Facility | [1] | $ 500,000,000 | |
Drawn | [2] | 36,000,000 | |
Line of Credit Facility, Remaining Borrowing Capacity | $ 464,000,000 | ||
Maturity Date | Jun. 30, 2021 | ||
SPS | Credit Facilities | |||
Line of Credit Facility [Line Items] | |||
Credit Facility | [1] | $ 400,000,000 | |
Drawn | [2] | 134,000,000 | |
Line of Credit Facility, Remaining Borrowing Capacity | $ 266,000,000 | ||
Maturity Date | Jun. 30, 2021 | ||
NSP-Wisconsin | Credit Facilities | |||
Line of Credit Facility [Line Items] | |||
Credit Facility | [1] | $ 150,000,000 | |
Drawn | [2] | 30,000,000 | |
Line of Credit Facility, Remaining Borrowing Capacity | $ 120,000,000 | ||
Maturity Date | Jun. 30, 2021 | ||
[1] | These credit facilities expire in June 2021, with the exception of Xcel Energy Inc.’s 364-day term loan agreement entered into in December 2017. | ||
[2] | Includes outstanding commercial paper, term loan borrowings and letters of credit. |
Borrowings and Other Financin54
Borrowings and Other Financing Instruments Borrowings and Other Financing Instruments, Long-Term Borrowings and Other Financing Instruments (Details) - USD ($) | 6 Months Ended | 12 Months Ended |
Jun. 30, 2018 | Dec. 31, 2017 | |
PSCo | Bonds [Member] | Series Due June 15, 2028 [Member] | ||
Debt Instrument [Line Items] | ||
Debt Instrument, Face Amount | $ 350,000,000 | |
Debt Instrument, Interest Rate, Stated Percentage | 3.70% | |
Maturity Date | Jun. 15, 2028 | |
PSCo | Bonds [Member] | Series Due June 15, 2048 [Member] | ||
Debt Instrument [Line Items] | ||
Debt Instrument, Face Amount | $ 350,000,000 | |
Debt Instrument, Interest Rate, Stated Percentage | 4.10% | |
Maturity Date | Jun. 15, 2048 | |
Xcel Energy Inc. [Member] | Bonds [Member] | Series Due June 15, 2028 [Member] | ||
Debt Instrument [Line Items] | ||
Debt Instrument, Face Amount | $ 500,000,000 | |
Debt Instrument, Interest Rate, Stated Percentage | 4.00% | |
Maturity Date | Jun. 15, 2028 | |
364-Day Term Loan [Member] | Xcel Energy Inc. | ||
Debt Instrument [Line Items] | ||
Line of Credit Facility, Remaining Borrowing Capacity | $ 0 | |
Term of letters of credit (in years) | 364 days | 364 days |
Line of Credit Facility, Fair Value of Amount Outstanding | $ 250,000,000 | |
Line of Credit Facility, Maximum Borrowing Capacity | $ 500,000,000 |
Fair Value of Financial Asset55
Fair Value of Financial Assets and Liabilities (Details) | 6 Months Ended |
Jun. 30, 2018 | |
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 Asset56
Fair Value of Financial Assets and Liabilities, Cost and Fair Value of Nuclear Decommissioning Fund (Details) - USD ($) $ in Millions | 6 Months Ended | 12 Months Ended | |||
Jun. 30, 2018 | Dec. 31, 2017 | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Unrealized Gain on Securities | $ 547 | $ 560 | |||
Unrealized Loss on Securities | 23 | 7 | |||
Investments [Abstract] | |||||
Equity investments in unconsolidated subsidiaries | 138 | 140 | |||
Miscellaneous investments | 115 | 114 | |||
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 | 31 | [1] | 29 | [2] | |
Investments [Abstract] | |||||
Equity Securities | 1,620 | [1] | 1,591 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Non U.S. equities | |||||
Investments [Abstract] | |||||
Equity Securities | 262 | [1] | 264 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Emerging market debt funds | |||||
Investments [Abstract] | |||||
Equity Securities | 158 | [1] | 156 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Private equity investments | |||||
Investments [Abstract] | |||||
Equity Securities | 151 | [1] | 141 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Real estate | |||||
Investments [Abstract] | |||||
Equity Securities | 128 | [1] | 131 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Other commingled funds | |||||
Investments [Abstract] | |||||
Equity Securities | [2] | 9 | |||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Government securities | |||||
Investments [Abstract] | |||||
Available-for-sale Securities, Debt Securities | 76 | [1] | 68 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | U.S. corporate bonds | |||||
Investments [Abstract] | |||||
Available-for-sale Securities, Debt Securities | 330 | [1] | 320 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Non U.S. corporate bonds | |||||
Investments [Abstract] | |||||
Available-for-sale Securities, Debt Securities | 58 | [1] | 50 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | U.S. equities | |||||
Investments [Abstract] | |||||
Equity Securities | 269 | [1] | 271 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Non U.S. equities | |||||
Investments [Abstract] | |||||
Equity Securities | 157 | [1] | 152 | [2] | |
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 | 31 | [1] | 29 | [2] | |
Alternative Investment, Fair Value Disclosure | 665 | [1],[3] | 659 | [2],[4] | |
Investments [Abstract] | |||||
Equity Securities | 2,144 | [1] | 2,143 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Cash equivalents | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Alternative Investment, Fair Value Disclosure | 0 | [1],[3] | 0 | [2],[4] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Non U.S. equities | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Alternative Investment, Fair Value Disclosure | 90 | [1],[3] | 90 | [2],[4] | |
Investments [Abstract] | |||||
Equity Securities | 289 | [1] | 307 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Emerging market debt funds | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Alternative Investment, Fair Value Disclosure | 158 | [1],[3] | 166 | [2],[4] | |
Investments [Abstract] | |||||
Equity Securities | 158 | [1] | 166 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Private equity investments | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Alternative Investment, Fair Value Disclosure | 220 | [1],[3] | 198 | [2],[4] | |
Investments [Abstract] | |||||
Equity Securities | 220 | [1] | 198 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Real estate | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Alternative Investment, Fair Value Disclosure | 197 | [1],[3] | 202 | [2],[4] | |
Investments [Abstract] | |||||
Equity Securities | 197 | [1] | 202 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Other commingled funds | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Alternative Investment, Fair Value Disclosure | [2],[4] | 3 | |||
Investments [Abstract] | |||||
Equity Securities | [2] | 9 | |||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Government securities | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Alternative Investment, Fair Value Disclosure | 0 | [1],[3] | 0 | [2],[4] | |
Investments [Abstract] | |||||
Available-for-sale Securities, Debt Securities | 75 | [1] | 69 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | U.S. corporate bonds | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Alternative Investment, Fair Value Disclosure | 0 | [1],[3] | 0 | [2],[4] | |
Investments [Abstract] | |||||
Available-for-sale Securities, Debt Securities | 323 | [1] | 322 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Non U.S. corporate bonds | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Alternative Investment, Fair Value Disclosure | 0 | [1],[3] | 0 | [2],[4] | |
Investments [Abstract] | |||||
Available-for-sale Securities, Debt Securities | 56 | [1] | 50 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | U.S. equities | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Alternative Investment, Fair Value Disclosure | 0 | [1],[3] | 0 | [2],[4] | |
Investments [Abstract] | |||||
Equity Securities | 568 | [1] | 557 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Non U.S. equities | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Alternative Investment, Fair Value Disclosure | 0 | [1],[3] | 0 | [2],[4] | |
Investments [Abstract] | |||||
Equity Securities | 227 | [1] | 234 | [2] | |
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 | 31 | [1] | 29 | [2] | |
Investments [Abstract] | |||||
Equity Securities | 1,025 | [1] | 1,043 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Non U.S. equities | |||||
Investments [Abstract] | |||||
Equity Securities | 199 | [1] | 217 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Emerging market debt funds | |||||
Investments [Abstract] | |||||
Equity Securities | 0 | [1] | 0 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Private equity investments | |||||
Investments [Abstract] | |||||
Equity Securities | 0 | [1] | 0 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Real estate | |||||
Investments [Abstract] | |||||
Equity Securities | 0 | [1] | 0 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Other commingled funds | |||||
Investments [Abstract] | |||||
Equity Securities | [2] | 6 | |||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Government securities | |||||
Investments [Abstract] | |||||
Available-for-sale Securities, Debt Securities | 0 | [1] | 0 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | U.S. corporate bonds | |||||
Investments [Abstract] | |||||
Available-for-sale Securities, Debt Securities | 0 | [1] | 0 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Non U.S. corporate bonds | |||||
Investments [Abstract] | |||||
Available-for-sale Securities, Debt Securities | 0 | [1] | 0 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | U.S. equities | |||||
Investments [Abstract] | |||||
Equity Securities | 568 | [1] | 557 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Non U.S. equities | |||||
Investments [Abstract] | |||||
Equity Securities | 227 | [1] | 234 | [2] | |
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 | [1] | 0 | [2] | |
Investments [Abstract] | |||||
Equity Securities | 454 | [1] | 441 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Non U.S. equities | |||||
Investments [Abstract] | |||||
Equity Securities | 0 | [1] | 0 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Emerging market debt funds | |||||
Investments [Abstract] | |||||
Equity Securities | 0 | [1] | 0 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Private equity investments | |||||
Investments [Abstract] | |||||
Equity Securities | 0 | [1] | 0 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Real estate | |||||
Investments [Abstract] | |||||
Equity Securities | 0 | [1] | 0 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Other commingled funds | |||||
Investments [Abstract] | |||||
Equity Securities | [2] | 0 | |||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Government securities | |||||
Investments [Abstract] | |||||
Available-for-sale Securities, Debt Securities | 75 | [1] | 69 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | U.S. corporate bonds | |||||
Investments [Abstract] | |||||
Available-for-sale Securities, Debt Securities | 323 | [1] | 322 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Non U.S. corporate bonds | |||||
Investments [Abstract] | |||||
Available-for-sale Securities, Debt Securities | 56 | [1] | 50 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | U.S. equities | |||||
Investments [Abstract] | |||||
Equity Securities | 0 | [1] | 0 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Non U.S. equities | |||||
Investments [Abstract] | |||||
Equity Securities | 0 | [1] | 0 | [2] | |
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 | [1] | 0 | [2] | |
Investments [Abstract] | |||||
Equity Securities | 0 | [1] | 0 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Non U.S. equities | |||||
Investments [Abstract] | |||||
Equity Securities | 0 | [1] | 0 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Emerging market debt funds | |||||
Investments [Abstract] | |||||
Equity Securities | 0 | [1] | 0 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Private equity investments | |||||
Investments [Abstract] | |||||
Equity Securities | 0 | [1] | 0 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Real estate | |||||
Investments [Abstract] | |||||
Equity Securities | 0 | [1] | 0 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Other commingled funds | |||||
Investments [Abstract] | |||||
Equity Securities | [2] | 0 | |||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Government securities | |||||
Investments [Abstract] | |||||
Available-for-sale Securities, Debt Securities | 0 | [1] | 0 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | U.S. corporate bonds | |||||
Investments [Abstract] | |||||
Available-for-sale Securities, Debt Securities | 0 | [1] | 0 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Non U.S. corporate bonds | |||||
Investments [Abstract] | |||||
Available-for-sale Securities, Debt Securities | 0 | [1] | 0 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | U.S. equities | |||||
Investments [Abstract] | |||||
Equity Securities | 0 | [1] | 0 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Non U.S. equities | |||||
Investments [Abstract] | |||||
Equity Securities | $ 0 | [1] | $ 0 | [2] | |
[1] | Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $138 million of equity investments in unconsolidated subsidiaries and $115 million of rabbi trust assets and miscellaneous investments. | ||||
[2] | Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $140 million of equity investments in unconsolidated subsidiaries and $114 million of rabbi trust assets and miscellaneous investments. | ||||
[3] | Due to limited availability of published pricing and a lack of immediate redeemability, certain fund investments measured at NAV are not required to be categorized within the fair value hierarchy. | ||||
[4] | Due to limited availability of published pricing and a lack of immediate redeemability, certain fund investments measured at NAV are not required to be categorized within the fair value hierarchy. |
Fair Value of Financial Asset57
Fair Value of Financial Assets and Liabilities, Final Contractual Maturity Dates of Debt Securities in Nuclear Decommissioning Fund (Details) $ in Millions | Jun. 30, 2018USD ($) |
Final Contractual Maturity [Abstract] | |
Due in 1 Year or Less | $ 7 |
Due in 1 to 5 Years | 114 |
Due in 5 to 10 Years | 204 |
Due after 10 Years | 129 |
Total | 454 |
Government securities | |
Final Contractual Maturity [Abstract] | |
Due in 1 Year or Less | 0 |
Due in 1 to 5 Years | 4 |
Due in 5 to 10 Years | 2 |
Due after 10 Years | 69 |
Total | 75 |
U.S. corporate bonds | |
Final Contractual Maturity [Abstract] | |
Due in 1 Year or Less | 5 |
Due in 1 to 5 Years | 90 |
Due in 5 to 10 Years | 172 |
Due after 10 Years | 56 |
Total | 323 |
Non U.S. corporate bonds | |
Final Contractual Maturity [Abstract] | |
Due in 1 Year or Less | 2 |
Due in 1 to 5 Years | 20 |
Due in 5 to 10 Years | 30 |
Due after 10 Years | 4 |
Total | $ 56 |
Fair Value of Financial Asset58
Fair Value of Financial Assets and Liabilities Fair Value of Financial Assets and Liabilities, Cost and Fair Value of Rabbi Trust (Details) - Fair Value, Measured on a Recurring Basis - USD ($) $ in Millions | Jun. 30, 2018 | Dec. 31, 2017 | |
Cost | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Trading Securities | [1] | $ 48 | $ 59 |
Cost | Rabbi Trust [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Cash Equivalents | [1] | 11 | 12 |
Cost | Mutual Funds [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Trading Securities | [1] | 37 | 47 |
Fair Value | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Trading Securities | [1] | 62 | 62 |
Fair Value | Level 1 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Trading Securities | [1] | 62 | 62 |
Fair Value | Level 2 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Trading Securities | [1] | 0 | 0 |
Fair Value | Level 3 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Trading Securities | [1] | 0 | 0 |
Fair Value | Rabbi Trust [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Cash Equivalents | [1] | 11 | 12 |
Fair Value | Rabbi Trust [Member] | Level 1 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Cash Equivalents | [1] | 11 | 12 |
Fair Value | Rabbi Trust [Member] | Level 2 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Cash Equivalents | [1] | 0 | 0 |
Fair Value | Rabbi Trust [Member] | Level 3 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Cash Equivalents | [1] | 0 | 0 |
Fair Value | Mutual Funds [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Trading Securities | [1] | 51 | 50 |
Fair Value | Mutual Funds [Member] | Level 1 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Trading Securities | [1] | 51 | 50 |
Fair Value | Mutual Funds [Member] | Level 2 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Trading Securities | [1] | 0 | 0 |
Fair Value | Mutual Funds [Member] | Level 3 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Trading Securities | [1] | $ 0 | $ 0 |
[1] | Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet. |
Fair Value of Financial Asset59
Fair Value of Financial Assets and Liabilities, Derivative Instruments (Details) MWh in Millions, MMBTU in Millions, $ in Millions | Jun. 30, 2018USD ($)MMBTUMWhCounterparty | Dec. 31, 2017MMBTUMWh | |
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 | Municipal or Cooperative Entities or Other Utilities [Member] | |||
Consideration of Credit Risk and Concentrations [Abstract] | |||
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure | 9 | ||
Credit Concentration Risk | No Investment Grade Ratings from External Credit Rating Agencies [Member] | |||
Consideration of Credit Risk and Concentrations [Abstract] | |||
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure | Counterparty | 5 | ||
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties | $ 40 | ||
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths) | 21.00% | ||
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 | 4 | ||
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties | $ 56 | ||
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths) | 29.00% | ||
Credit Concentration Risk | External Credit Rating, Non Investment Grade [Member] | |||
Consideration of Credit Risk and Concentrations [Abstract] | |||
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure | 1 | ||
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties | $ 5 | ||
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths) | 3.00% | ||
Interest rate derivatives | |||
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) | ||
Electric Commodity (in megawatt hours) | |||
Gross Notional Amounts of Commodity Forwards, Options and FTRs [Abstract] | |||
Derivative, Nonmonetary Notional amount | MWh | [1],[2] | 108 | 68 |
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] | 26 | 37 |
[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 Asset60
Fair Value of Financial Assets and Liabilities, Impact of Derivative Activity (Details) - USD ($) | 3 Months Ended | 6 Months Ended | |||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | ||
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 | 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 | 1,000,000 | 2,000,000 | 1,000,000 | 2,000,000 | |
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] | 1,000,000 | 2,000,000 | 1,000,000 | 2,000,000 |
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 | 37,000,000 | (3,000,000) | 8,000,000 | (8,000,000) | |
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) | (3,000,000) | (2,000,000) | 2,000,000 | (5,000,000) | |
Pre-tax gains (losses) recognized during the period in income | 2,000,000 | 6,000,000 | 8,000,000 | 3,000,000 | |
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 | [2] | 2,000,000 | 6,000,000 | 10,000,000 | 7,000,000 |
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 | 37,000,000 | (1,000,000) | 8,000,000 | 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) | [3] | (3,000,000) | (2,000,000) | 0 | (6,000,000) |
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 | ||
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities | (2,000,000) | 0 | (8,000,000) | ||
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss | 0 | 0 | 0 | ||
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities) | 0 | 2,000,000 | 1,000,000 | ||
Pre-tax gains (losses) recognized during the period in income | 0 | (2,000,000) | (4,000,000) | ||
Other Derivative Instruments | Natural Gas Commodity for Electric Generation | |||||
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 regulatory (assets) and liabilities | $ 0 | $ 0 | $ (1,000,000) | $ 1,000,000 | |
[1] | Amounts are recorded to interest charges. | ||||
[2] | Amounts are recorded to electric fuel and purchased power. These derivative settlement gains and losses are shared with electric customers through fuel and purchased energy cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate. | ||||
[3] | Certain derivatives are utilized to mitigate natural gas price risk for electric generation and are recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate. Amounts for the three and six months ended June 30, 2018 included no settlement gains or losses and $1 million of settlement losses, respectively. Amounts for the three and six months ended June 30, 2017 included no settlement gains or losses and $1 million of settlement gains, respectively. The remaining derivative settlement gains and losses for the three and six months ended June 30, 2018 and 2017 relate to natural gas operations and are recorded to cost of natural gas sold and transported. These gains and losses are subject to cost-recovery and reclassified out of income to a regulatory asset or liability, as appropriate. |
Fair Value of Financial Asset61
Fair Value of Financial Assets and Liabilities, Credit Related Contingent Features (Details) - USD ($) | Jun. 30, 2018 | Dec. 31, 2017 |
Fair Value Disclosures [Abstract] | ||
Derivative instruments in a gross liability position | $ 0 | $ 0 |
Collateral posted on derivative instruments | 0 | 0 |
Collateral posted related to adequate assurance clauses in derivative contracts | $ 0 | $ 0 |
Fair Value of Financial Asset62
Fair Value of Financial Assets and Liabilities, Derivative Assets and Liabilities at Fair Value (Details) - USD ($) $ in Millions | Jun. 30, 2018 | Dec. 31, 2017 | |||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Collateral, Obligation to Return Cash, Offset | $ 0 | $ 0 | |||
Derivative Liability, Collateral, Right to Reclaim Cash, Offset | 8 | 3 | |||
Other Current Assets | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 75 | 44 | |||
Other Noncurrent Assets | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 47 | 48 | |||
Other Current Liabilities | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 27 | 29 | |||
Other Noncurrent Liabilities | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 113 | 126 | |||
Fair Value Measured on a Recurring Basis | Other Current Assets | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 71 | 39 | |||
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset | (19) | [1] | (17) | [2] | |
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 | 12 | 9 | |||
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset | (18) | [1] | (15) | [2] | |
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 | 58 | 30 | |||
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset | (1) | [1] | (2) | [2] | |
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 | ||||
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset | [1] | 0 | |||
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 29 | 29 | |||
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset | (12) | [1] | (7) | [2] | |
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 | 29 | 29 | |||
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset | (12) | [1] | (7) | [2] | |
Fair Value Measured on a Recurring Basis | Other Current Liabilities | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 5 | 6 | |||
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset | (23) | [1] | (17) | [2] | |
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 | 5 | 5 | |||
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset | (22) | [1] | (15) | [2] | |
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 | |||
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset | (1) | [1] | (2) | [2] | |
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 | ||||
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset | [2] | 0 | |||
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 12 | 14 | |||
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset | (15) | [1] | (10) | [2] | |
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 | 12 | 14 | |||
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset | (15) | [1] | (10) | [2] | |
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 1 | 2 | |||
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 | 1 | 2 | |||
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 | ||||
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 | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 1 | 2 | |||
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 | 1 | 2 | |||
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 | ||||
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Liabilities | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 0 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Liabilities | 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 2 | Other Current Assets | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 28 | 22 | |||
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 | 27 | 22 | |||
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 | 1 | ||||
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Assets | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 35 | 31 | |||
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 | 35 | 31 | |||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 24 | 19 | |||
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 | 24 | 18 | |||
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 | 1 | ||||
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Liabilities | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 27 | 24 | |||
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 | 27 | 24 | |||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 61 | 32 | |||
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 | 2 | 0 | |||
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 | 59 | 32 | |||
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 | ||||
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Assets | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 6 | 5 | |||
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 | 6 | 5 | |||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 3 | 2 | |||
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 | 2 | 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 | 1 | 2 | |||
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 | ||||
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Liabilities | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 0 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 0 | 0 | |||
Fair Value, Measurements, Nonrecurring | Other Current Assets | Purchased Power Agreements | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 4 | [3] | 5 | [4] | |
Fair Value, Measurements, Nonrecurring | Other Noncurrent Assets | Purchased Power Agreements | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 18 | [3] | 19 | [4] | |
Fair Value, Measurements, Nonrecurring | Other Current Liabilities | Purchased Power Agreements | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 22 | [3] | 23 | [4] | |
Fair Value, Measurements, Nonrecurring | Other Noncurrent Liabilities | Purchased Power Agreements | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 101 | [3] | 112 | [4] | |
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Assets | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 90 | 56 | |||
Estimate of Fair Value Measurement [Member] | 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 | 30 | 24 | |||
Estimate of Fair Value Measurement [Member] | 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 | 59 | 32 | |||
Estimate of Fair Value Measurement [Member] | 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 | ||||
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 41 | 36 | |||
Estimate of Fair Value Measurement [Member] | 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 | 41 | 36 | |||
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Liabilities | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 28 | 23 | |||
Estimate of Fair Value Measurement [Member] | 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 | 27 | 20 | |||
Estimate of Fair Value Measurement [Member] | 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 | 1 | 2 | |||
Estimate of Fair Value Measurement [Member] | 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 | ||||
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 27 | 24 | |||
Estimate of Fair Value Measurement [Member] | 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 | $ 27 | $ 24 | |||
[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 June 30, 2018. At June 30, 2018, derivative assets and liabilities include no obligations to return cash collateral and the rights to reclaim cash collateral of $8 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, 2017. At Dec. 31, 2017, derivative assets and liabilities include no obligations to return cash collateral and rights to reclaim cash collateral of $3 million. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agre | ||||
[3] | During 2006, Xcel Energy qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts is being amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities. | ||||
[4] | During 2006, Xcel Energy qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts is being amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities |
Fair Value of Financial Asset63
Fair Value of Financial Assets and Liabilities, Changes in Level 3 Commodity Derivatives (Details) - Commodity Contract - USD ($) | 3 Months Ended | 6 Months Ended | |||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | ||
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward] | |||||
Balance at beginning of period | $ 19,000,000 | $ 6,000,000 | $ 35,000,000 | $ 17,000,000 | |
Purchases | 45,000,000 | 76,000,000 | 46,000,000 | 80,000,000 | |
Settlements | (20,000,000) | (22,000,000) | (32,000,000) | (42,000,000) | |
Gains (losses) recognized in earnings | [1] | (2,000,000) | 6,000,000 | 0 | 5,000,000 |
Net gains recognized as regulatory assets and liabilities | 22,000,000 | 3,000,000 | 15,000,000 | 9,000,000 | |
Balance at end of period | 64,000,000 | 69,000,000 | 64,000,000 | 69,000,000 | |
Transfers into Level 3 | 0 | 0 | 0 | 0 | |
Transfers out of Level 3 | $ 0 | $ 0 | $ 0 | $ 0 | |
[1] | These amounts relate to commodity derivatives held at the end of the period. |
Fair Value of Financial Asset64
Fair Value of Financial Assets and Liabilities, Fair Value of Long-Term Debt (Details) - USD ($) $ in Millions | Jun. 30, 2018 | Dec. 31, 2017 |
Carrying Amount | ||
Financial Liabilities, Balance Sheet Groupings [Abstract] | ||
Long-term Debt, Including Current Portion | $ 16,167 | $ 14,977 |
Fair Value | ||
Financial Liabilities, Balance Sheet Groupings [Abstract] | ||
Long-term Debt, Including Current Portion | $ 16,750 | $ 16,531 |
Other Income, Net (Details)
Other Income, Net (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | |
Other Income and Expenses [Abstract] | ||||
Interest income | $ 3 | $ 2 | $ 7 | $ 6 |
Other nonoperating income | 1 | 2 | 2 | 5 |
Insurance Policy Expense (Income), Net | (2) | (1) | (1) | (2) |
Defined Benefit Plan, Non-service Costs | (4) | (7) | (9) | (13) |
Other expense, net | $ (2) | $ (4) | $ (1) | $ (4) |
Segment Information (Details)
Segment Information (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | |||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | Dec. 31, 2017 | |
Segment Reporting Information [Line Items] | |||||
Equity investments in unconsolidated subsidiaries | $ 138,000 | $ 138,000 | $ 140,000 | ||
Operating revenues | 2,658,000 | $ 2,645,000 | 5,609,000 | $ 5,591,000 | |
Net income (loss) | 265,000 | 227,000 | 556,000 | 467,000 | |
Regulated Electric | |||||
Segment Reporting Information [Line Items] | |||||
Operating revenues | 2,348,000 | 2,339,000 | 4,618,000 | 4,638,000 | |
Net income (loss) | 264,000 | 227,000 | 483,000 | 422,000 | |
Regulated Natural Gas | |||||
Segment Reporting Information [Line Items] | |||||
Equity investments in unconsolidated subsidiaries | 138,000 | 138,000 | $ 140,000 | ||
Operating revenues | 292,000 | 290,000 | 955,000 | 916,000 | |
Net income (loss) | 27,000 | 13,000 | 121,000 | 76,000 | |
All Other | |||||
Segment Reporting Information [Line Items] | |||||
Operating revenues | 18,000 | 17,000 | 38,000 | 39,000 | |
Net income (loss) | (26,000) | (13,000) | (48,000) | (31,000) | |
Operating Segments | |||||
Segment Reporting Information [Line Items] | |||||
Operating revenues | 2,658,000 | 2,645,000 | 5,609,000 | 5,591,000 | |
Operating Segments | Regulated Electric | |||||
Segment Reporting Information [Line Items] | |||||
Operating revenues | 2,348,000 | 2,338,000 | 4,617,000 | 4,637,000 | |
Operating Segments | Regulated Natural Gas | |||||
Segment Reporting Information [Line Items] | |||||
Operating revenues | 292,000 | 290,000 | 954,000 | 915,000 | |
Operating Segments | All Other | |||||
Segment Reporting Information [Line Items] | |||||
Operating revenues | 18,000 | 17,000 | 38,000 | 39,000 | |
Intersegment Eliminations | |||||
Segment Reporting Information [Line Items] | |||||
Operating revenues | 0 | (1,000) | (2,000) | (2,000) | |
Net income (loss) | 0 | 0 | 0 | 0 | |
Intersegment Eliminations | Regulated Electric | |||||
Segment Reporting Information [Line Items] | |||||
Operating revenues | 0 | 1,000 | 1,000 | 1,000 | |
Intersegment Eliminations | Regulated Natural Gas | |||||
Segment Reporting Information [Line Items] | |||||
Operating revenues | 0 | 0 | 1,000 | 1,000 | |
Intersegment Eliminations | All Other | |||||
Segment Reporting Information [Line Items] | |||||
Operating revenues | $ 0 | $ 0 | $ 0 | $ 0 |
Earnings Per Share (Details)
Earnings Per Share (Details) - USD ($) $ / shares in Units, $ in Thousands, shares in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | |
Dilutive Impact of Common Stock Equivalents on Earnings per Share (Abstract] | ||||
Net income | $ 265,000 | $ 227,000 | $ 556,000 | $ 467,000 |
Basic earnings per share [Abstract] | ||||
Earnings available to common shareholders | $ 265,000 | $ 227,000 | $ 556,000 | $ 467,000 |
Weighted average common shares outstanding - basic (in shares) | 509.6 | 509 | 509.3 | 508.4 |
Earnings available to common shareholders - basic (in dollars per share) | $ 0.52 | $ 0.45 | $ 1.09 | $ 0.92 |
Effect of dilutive securities [Abstract] | ||||
Time based equity awards (in shares) | 0.4 | 0.6 | 0.4 | 0.6 |
Diluted earnings per share [Abstract] | ||||
Earnings available to common shareholders | $ 265,000 | $ 227,000 | $ 556,000 | $ 467,000 |
Weighted average common shares outstanding - diluted (in shares) | 510 | 509.1 | 509.7 | 509 |
Earnings available to common shareholders - diluted (in dollars per share) | $ 0.52 | $ 0.45 | $ 1.09 | $ 0.92 |
Benefit Plans and Other Postr68
Benefit Plans and Other Postretirement Benefits (Details) $ in Millions | 1 Months Ended | 3 Months Ended | 6 Months Ended | ||
Jan. 31, 2018USD ($)Plan | Jun. 30, 2018USD ($) | Jun. 30, 2017USD ($) | Jun. 30, 2018USD ($) | Jun. 30, 2017USD ($) | |
Pension Plan [Member] | |||||
Components of Net Periodic Benefit Cost [Abstract] | |||||
Service cost | $ 24 | $ 24 | $ 47 | $ 48 | |
Interest cost (a) | 33 | 36 | 67 | 72 | |
Expected return on plan assets (a) | (52) | (52) | (104) | (104) | |
Amortization of prior service credit (a) | (1) | 0 | (2) | (1) | |
Amortization of net loss (a) | 27 | 26 | 55 | 53 | |
Net periodic benefit cost (credit) | 31 | 34 | 63 | 68 | |
Costs not recognized due to the effects of regulation | (1) | (4) | (2) | (8) | |
Net benefit cost (credit) recognized for financial reporting | 30 | 30 | 61 | 60 | |
Total contributions to Xcel Energy's pension plans during the period | $ 150 | ||||
Number of pension plans to which contributions were made | Plan | 4 | ||||
Other Postretirement Benefits Plan [Member] | |||||
Components of Net Periodic Benefit Cost [Abstract] | |||||
Service cost | 1 | 1 | 1 | 2 | |
Interest cost (a) | 5 | 6 | 11 | 12 | |
Expected return on plan assets (a) | (6) | (6) | (13) | (12) | |
Amortization of prior service credit (a) | (3) | (3) | (5) | (5) | |
Amortization of net loss (a) | 2 | 1 | 3 | 2 | |
Net periodic benefit cost (credit) | (1) | (1) | (3) | (1) | |
Costs not recognized due to the effects of regulation | 0 | 0 | 0 | 0 | |
Net benefit cost (credit) recognized for financial reporting | $ (1) | $ (1) | $ (3) | $ (1) |
Other Comprehensive Income (Det
Other Comprehensive Income (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | |
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | ||||
Accumulated other comprehensive income (loss) at beginning of period | $ 11,455 | |||
(Gains) losses reclassified from net accumulated other comprehensive loss | $ 2 | $ 2 | 3 | $ 3 |
Accumulated other comprehensive income (loss) at end of period | 11,650 | 11,650 | ||
Gains and Losses on Cash Flow Hedges | ||||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | ||||
Accumulated other comprehensive income (loss) at beginning of period | (58) | (51) | (58) | (51) |
(Gains) losses reclassified from net accumulated other comprehensive loss | 1 | 1 | 1 | 1 |
Net current period other comprehensive income (loss) | 1 | 1 | 1 | 1 |
Accumulated other comprehensive income (loss) at end of period | (57) | (50) | (57) | (50) |
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 | (66) | (58) | (67) | (59) |
(Gains) losses reclassified from net accumulated other comprehensive loss | 1 | 1 | 2 | 2 |
Net current period other comprehensive income (loss) | 1 | 1 | 2 | 2 |
Accumulated other comprehensive income (loss) at end of period | (65) | (57) | (65) | (57) |
Total | ||||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | ||||
Accumulated other comprehensive income (loss) at beginning of period | (124) | (109) | (125) | (110) |
(Gains) losses reclassified from net accumulated other comprehensive loss | 2 | 2 | 3 | 3 |
Net current period other comprehensive income (loss) | 2 | 2 | 3 | 3 |
Accumulated other comprehensive income (loss) at end of period | $ (122) | $ (107) | $ (122) | $ (107) |
Other Comprehensive Income (Rec
Other Comprehensive Income (Reclassifications from AOCI) (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | ||||||
Total, pre-tax | $ (319) | $ (329) | $ (670) | $ (686) | ||
Income Tax Expense (Benefit) | 54 | 102 | 114 | 219 | ||
Total amounts reclassified, net of tax | 2 | 2 | 3 | 3 | ||
Gains and Losses on Cash Flow Hedges | ||||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | ||||||
Total amounts reclassified, net of tax | 1 | 1 | 1 | 1 | ||
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 | 2 | 1 | 2 | ||
Income Tax Expense (Benefit) | 0 | (1) | 0 | (1) | ||
Total, net of tax | 1 | 1 | 1 | 1 | ||
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 | 2 | [1] | 1 | 2 | [1] |
Amortization of net loss | Amounts Reclassified from Accumulated Other Comprehensive Loss | ||||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | ||||||
Total, pre-tax | 2 | 2 | 3 | 3 | ||
Defined Benefit Pension and Postretirement Items | ||||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | ||||||
Total amounts reclassified, net of tax | 1 | 1 | 2 | 2 | ||
Defined Benefit Pension and Postretirement Items | Amounts Reclassified from Accumulated Other Comprehensive Loss | ||||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | ||||||
Total, pre-tax | 2 | 2 | 3 | 3 | ||
Tax benefit | (1) | (1) | (1) | (1) | ||
Total amounts reclassified, net of tax | $ 1 | $ 1 | $ 2 | $ 2 | ||
[1] | Included in interest charges |
Revenues (Details)
Revenues (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | |
Disaggregation of Revenue [Line Items] | ||||
Total revenue from contracts with customers | $ 2,545 | $ 2,540 | $ 5,370 | $ 5,344 |
Alternative revenue and other | 113 | 105 | 239 | 247 |
Total operating revenues | 2,658 | 2,645 | $ 5,609 | 5,591 |
Maximum number of months following end of annual period in which revenues are earned to be included in incentive programs | 24 months | |||
Retail | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenue from contracts with customers | 2,172 | 2,192 | $ 4,619 | 4,645 |
Retail | Residential | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenue from contracts with customers | 844 | 826 | 1,930 | 1,893 |
Retail | Commercial and industrial (C&I) | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenue from contracts with customers | 1,293 | 1,332 | 2,619 | 2,684 |
Retail | Other | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenue from contracts with customers | 35 | 34 | 70 | 68 |
Wholesale | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenue from contracts with customers | 194 | 172 | 382 | 353 |
Transmission | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenue from contracts with customers | 132 | 126 | 255 | 247 |
Other | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenue from contracts with customers | 47 | 50 | 114 | 99 |
Regulated Electric | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenue from contracts with customers | 2,267 | 2,255 | 4,449 | 4,447 |
Alternative revenue and other | 81 | 83 | 168 | 190 |
Total operating revenues | 2,348 | 2,339 | 4,618 | 4,638 |
Regulated Electric | Retail | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenue from contracts with customers | 1,917 | 1,930 | 3,749 | 3,795 |
Regulated Electric | Retail | Residential | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenue from contracts with customers | 678 | 654 | 1,365 | 1,339 |
Regulated Electric | Retail | Commercial and industrial (C&I) | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenue from contracts with customers | 1,206 | 1,243 | 2,318 | 2,391 |
Regulated Electric | Retail | Other | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenue from contracts with customers | 33 | 33 | 66 | 65 |
Regulated Electric | Wholesale | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenue from contracts with customers | 194 | 172 | 382 | 353 |
Regulated Electric | Transmission | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenue from contracts with customers | 132 | 126 | 255 | 247 |
Regulated Electric | Other | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenue from contracts with customers | 24 | 27 | 63 | 52 |
Regulated Natural Gas | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenue from contracts with customers | 262 | 271 | 887 | 864 |
Alternative revenue and other | 30 | 19 | 67 | 51 |
Total operating revenues | 292 | 290 | 955 | 916 |
Regulated Natural Gas | Retail | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenue from contracts with customers | 239 | 248 | 836 | 817 |
Regulated Natural Gas | Retail | Residential | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenue from contracts with customers | 157 | 163 | 547 | 537 |
Regulated Natural Gas | Retail | Commercial and industrial (C&I) | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenue from contracts with customers | 82 | 85 | 289 | 280 |
Regulated Natural Gas | Retail | Other | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenue from contracts with customers | 0 | 0 | 0 | 0 |
Regulated Natural Gas | Wholesale | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenue from contracts with customers | 0 | 0 | 0 | 0 |
Regulated Natural Gas | Transmission | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenue from contracts with customers | 0 | 0 | 0 | 0 |
Regulated Natural Gas | Other | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenue from contracts with customers | 23 | 23 | 51 | 47 |
All Other | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenue from contracts with customers | 16 | 14 | 34 | 33 |
Alternative revenue and other | 2 | 3 | 4 | 6 |
Total operating revenues | 18 | 17 | 38 | 39 |
All Other | Retail | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenue from contracts with customers | 16 | 14 | 34 | 33 |
All Other | Retail | Residential | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenue from contracts with customers | 9 | 9 | 18 | 17 |
All Other | Retail | Commercial and industrial (C&I) | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenue from contracts with customers | 5 | 4 | 12 | 13 |
All Other | Retail | Other | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenue from contracts with customers | 2 | 1 | 4 | 3 |
All Other | Wholesale | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenue from contracts with customers | 0 | 0 | 0 | 0 |
All Other | Transmission | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenue from contracts with customers | 0 | 0 | 0 | 0 |
All Other | Other | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenue from contracts with customers | 0 | 0 | 0 | 0 |
Operating Segments | ||||
Disaggregation of Revenue [Line Items] | ||||
Total operating revenues | 2,658 | 2,645 | 5,609 | 5,591 |
Operating Segments | Regulated Electric | ||||
Disaggregation of Revenue [Line Items] | ||||
Total operating revenues | 2,348 | 2,338 | 4,617 | 4,637 |
Operating Segments | Regulated Natural Gas | ||||
Disaggregation of Revenue [Line Items] | ||||
Total operating revenues | 292 | 290 | 954 | 915 |
Operating Segments | All Other | ||||
Disaggregation of Revenue [Line Items] | ||||
Total operating revenues | $ 18 | $ 17 | $ 38 | $ 39 |