Document and Entity Information
Document and Entity Information - shares | 3 Months Ended | |
Mar. 31, 2017 | Apr. 24, 2017 | |
Document and Entity Information [Abstract] | ||
Entity Registrant Name | XCEL ENERGY INC | |
Entity Central Index Key | 72,903 | |
Current Fiscal Year End Date | --12-31 | |
Entity Well-known Seasoned Issuer | Yes | |
Entity Voluntary Filers | No | |
Entity Current Reporting Status | Yes | |
Entity Filer Category | Large Accelerated Filer | |
Entity Common Stock, Shares Outstanding | 507,762,881 | |
Document Fiscal Year Focus | 2,017 | |
Document Fiscal Period Focus | Q1 | |
Document Type | 10-Q | |
Amendment Flag | false | |
Document Period End Date | Mar. 31, 2017 |
CONSOLIDATED STATEMENTS OF INCO
CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) - USD ($) shares in Thousands, $ in Thousands | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
Operating revenues | ||
Electric | $ 2,299,060 | $ 2,185,119 |
Natural gas | 625,703 | 565,689 |
Other | 21,659 | 21,465 |
Total operating revenues | 2,946,422 | 2,772,273 |
Operating expenses | ||
Electric fuel and purchased power | 925,221 | 861,852 |
Cost of natural gas sold and transported | 365,134 | 312,117 |
Cost of sales — other | 8,587 | 8,245 |
Operating and maintenance expenses | 586,430 | 577,410 |
Conservation and demand side management program expenses | 67,533 | 57,436 |
Depreciation and amortization | 365,204 | 320,020 |
Taxes (other than income taxes) | 142,094 | 145,323 |
Total operating expenses | 2,460,203 | 2,282,403 |
Operating income | 486,219 | 489,870 |
Other income, net | 6,446 | 4,250 |
Equity earnings of unconsolidated subsidiaries | 7,875 | 13,182 |
Allowance for funds used during construction — equity | 14,313 | 13,113 |
Interest charges and financing costs | ||
Interest charges — includes other financing costs of $5,858 and $6,336, respectively | 165,934 | 156,443 |
Allowance for funds used during construction — debt | (7,022) | (5,990) |
Total interest charges and financing costs | 158,912 | 150,453 |
Income before income taxes | 355,941 | 369,962 |
Income taxes | 116,664 | 128,650 |
Net income | $ 239,277 | $ 241,312 |
Weighted average common shares outstanding: | ||
Basic (in shares) | 508,278 | 508,667 |
Diluted (in shares) | 508,774 | 509,150 |
Earnings per average common share: | ||
Basic (in dollars per share) | $ 0.47 | $ 0.47 |
Diluted (in dollars per share) | 0.47 | 0.47 |
Cash dividends declared per common share (in dollars per share) | $ 0.36 | $ 0.34 |
CONSOLIDATED STATEMENTS OF INC3
CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) (Parenthetical) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
Interest charges and financing costs | ||
Other financing costs | $ 5,858 | $ 6,336 |
CONSOLIDATED STATEMENTS OF COMP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
Comprehensive income: | ||
Net income | $ 239,277 | $ 241,312 |
Pension and retiree medical benefits: | ||
Amortization of losses included in net periodic benefit cost, net of tax of $615 and $142, respectively | 948 | 211 |
Derivative instruments: | ||
Net fair value decrease, net of tax of $0 and $(2), respectively | 0 | (4) |
Reclassification of losses to net income, net of tax of $534 and $604, respectively | 825 | 938 |
Total derivative instruments, net of tax | 825 | 934 |
Other comprehensive income | 1,773 | 1,145 |
Comprehensive income | $ 241,050 | $ 242,457 |
CONSOLIDATED STATEMENTS OF COM5
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) (Parenthetical) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
Pension and retiree medical benefits: | ||
Amortization of losses included in net periodic benefit cost, tax | $ 615 | $ 142 |
Derivative instruments: | ||
Net fair value increase (decrease), tax | 0 | (2) |
Reclassification of losses to net income, tax | 534 | 604 |
Marketable securities: | ||
Net fair value increase (decrease), tax | $ 0 | $ 0 |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
Operating activities | ||
Net income | $ 239,277 | $ 241,312 |
Adjustments to reconcile net income to cash provided by operating activities: | ||
Depreciation and amortization | 368,880 | 323,761 |
Conservation and demand side management program amortization | 755 | 1,162 |
Nuclear fuel amortization | 30,852 | 25,750 |
Deferred income taxes | 193,740 | 160,379 |
Amortization of investment tax credits | (1,278) | (1,307) |
Allowance for equity funds used during construction | (14,313) | (13,113) |
Equity earnings of unconsolidated subsidiaries | (7,875) | (13,182) |
Dividends from unconsolidated subsidiaries | 11,754 | 11,481 |
Share-based compensation expense | 17,953 | 13,099 |
Net realized and unrealized hedging and derivative transactions | 4,177 | 5,576 |
Other | 0 | (388) |
Changes in operating assets and liabilities: | ||
Accounts receivable | (4,959) | (4,780) |
Accrued unbilled revenues | 174,387 | 129,444 |
Inventories | 88,355 | 88,570 |
Other current assets | (76,758) | (16,635) |
Accounts payable | (121,390) | (22,063) |
Net regulatory assets and liabilities | 17,863 | 34,404 |
Other current liabilities | (42,270) | (32,442) |
Pension and other employee benefit obligations | (148,565) | (118,774) |
Change in other noncurrent assets | 263 | (1,196) |
Change in other noncurrent liabilities | (12,693) | (8,508) |
Net cash provided by operating activities | 718,155 | 802,550 |
Investing activities | ||
Utility capital/construction expenditures | (749,073) | (700,319) |
Allowance for equity funds used during construction | 14,313 | 13,113 |
Purchases of investment securities | (172,738) | (109,373) |
Proceeds from the sale of investment securities | 167,645 | 104,280 |
Investments in WYCO Development LLC and other | (2,571) | (260) |
Other, net | (5,315) | (1,548) |
Net cash used in investing activities | (747,739) | (694,107) |
Financing activities | ||
Proceeds from (repayments of) short-term borrowings, net | 213,000 | (663,000) |
Proceeds from issuance of long-term debt | 0 | 747,127 |
Repayments of long-term debt | (217) | (333) |
Purchase of common stock for settlement of equity awards | (2,943) | (789) |
Dividends paid | (172,456) | (162,410) |
Proceeds from (Payments for) Other Financing Activities | (18,291) | (12,487) |
Net cash provided by (used in) financing activities | 19,093 | (91,892) |
Net change in cash and cash equivalents | (10,491) | 16,551 |
Cash and cash equivalents at beginning of period | 84,476 | 84,940 |
Cash and cash equivalents at end of period | 73,985 | 101,491 |
Supplemental disclosure of cash flow information: | ||
Cash paid for interest (net of amounts capitalized) | (174,381) | (164,511) |
Cash received for income taxes, net | 0 | 7,414 |
Supplemental disclosure of non-cash investing and financing transactions: | ||
Property, plant and equipment additions in accounts payable | 185,617 | 192,818 |
Issuance of common stock for reinvested dividends and equity awards | $ 11,673 | $ 7,703 |
CONSOLIDATED BALANCE SHEETS (UN
CONSOLIDATED BALANCE SHEETS (UNAUDITED) - USD ($) $ in Thousands | Mar. 31, 2017 | Dec. 31, 2016 |
Current assets | ||
Cash and cash equivalents | $ 73,985 | $ 84,476 |
Accounts receivable, net | 781,248 | 776,289 |
Accrued unbilled revenues | 555,445 | 729,832 |
Inventories | 519,081 | 604,226 |
Regulatory assets | 360,309 | 363,655 |
Derivative instruments | 20,885 | 38,224 |
Prepaid taxes | 176,998 | 106,697 |
Prepayments and other | 145,203 | 138,682 |
Total current assets | 2,633,154 | 2,842,081 |
Property, plant and equipment, net | 33,158,384 | 32,841,750 |
Other assets | ||
Nuclear decommissioning fund and other investments | 2,187,946 | 2,091,858 |
Regulatory assets | 3,009,825 | 3,080,867 |
Derivative instruments | 48,681 | 50,189 |
Other | 247,351 | 248,532 |
Total other assets | 5,493,803 | 5,471,446 |
Total assets | 41,285,341 | 41,155,277 |
Current liabilities | ||
Current portion of long-term debt | 755,448 | 255,529 |
Short-term debt | 605,000 | 392,000 |
Accounts payable | 861,506 | 1,044,959 |
Regulatory liabilities | 186,926 | 220,894 |
Taxes accrued | 544,177 | 457,392 |
Accrued interest | 151,929 | 172,901 |
Dividends payable | 182,795 | 172,456 |
Derivative instruments | 26,706 | 26,959 |
Other | 393,489 | 503,953 |
Total current liabilities | 3,707,976 | 3,247,043 |
Deferred credits and other liabilities | ||
Deferred income taxes | 6,999,546 | 6,784,319 |
Deferred investment tax credits | 61,937 | 63,216 |
Regulatory liabilities | 1,400,234 | 1,383,212 |
Asset retirement obligations | 2,815,677 | 2,782,229 |
Derivative instruments | 143,684 | 148,146 |
Customer advances | 189,984 | 195,214 |
Pension and employee benefit obligations | 964,398 | 1,112,366 |
Other | 235,333 | 223,965 |
Total deferred credits and other liabilities | 12,810,793 | 12,692,667 |
Commitments and contingencies | ||
Capitalization | ||
Long-term debt | 13,696,461 | 14,194,718 |
Common stock — 1,000,000,000 shares authorized of $2.50 par value; 507,762,881 and 507,222,795 shares outstanding at March 31, 2017 and Dec. 31, 2016, respectively | 1,269,407 | 1,268,057 |
Additional paid in capital | 5,872,933 | 5,881,494 |
Retained earnings | 4,036,352 | 3,981,652 |
Accumulated other comprehensive loss | (108,581) | (110,354) |
Total common stockholders’ equity | 11,070,111 | 11,020,849 |
Total liabilities and equity | $ 41,285,341 | $ 41,155,277 |
CONSOLIDATED BALANCE SHEETS (U8
CONSOLIDATED BALANCE SHEETS (UNAUDITED) (Parenthetical) - $ / shares | Mar. 31, 2017 | Dec. 31, 2016 |
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) | 507,762,881 | 507,222,795 |
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, 2015 | $ 10,600,920 | $ 1,268,839 | $ 5,889,106 | $ 3,552,728 | $ (109,753) |
Balance (in shares) at Dec. 31, 2015 | 507,536,000 | ||||
Increase (Decrease) in Stockholders' Equity | |||||
Net income | 241,312 | 241,312 | |||
Other comprehensive income | 1,145 | 1,145 | |||
Dividends declared on common stock | (173,619) | (173,619) | |||
Issuances of common stock (in shares) | 417,000 | ||||
Issuances of common stock | (2,712) | $ (1,043) | (3,755) | ||
Purchase of common stock for settlement of equity awards | (789) | 789 | |||
Share-based compensation | 5,377 | 5,377 | |||
Ending balance at Mar. 31, 2016 | 10,671,634 | $ 1,269,882 | 5,889,939 | 3,620,421 | (108,608) |
Balance (in shares) at Mar. 31, 2016 | 507,953,000 | ||||
Beginning balance at Dec. 31, 2016 | $ 11,020,849 | $ 1,268,057 | 5,881,494 | 3,981,652 | (110,354) |
Balance (in shares) at Dec. 31, 2016 | 507,222,795 | 507,223,000 | |||
Increase (Decrease) in Stockholders' Equity | |||||
Net income | $ 239,277 | 239,277 | |||
Other comprehensive income | 1,773 | 1,773 | |||
Dividends declared on common stock | (183,815) | (183,815) | |||
Issuances of common stock (in shares) | 611,000 | ||||
Issuances of common stock | (5,037) | $ (1,527) | (3,510) | ||
Purchase of common stock for settlement of equity awards | (2,943) | ||||
Purchase of common stock (in shares) | (71,000) | ||||
Repurchases of common stock | (3,120) | $ (177) | (2,943) | ||
Share-based compensation | (9,890) | (9,128) | (762) | ||
Ending balance at Mar. 31, 2017 | $ 11,070,111 | $ 1,269,407 | $ 5,872,933 | $ 4,036,352 | $ (108,581) |
Balance (in shares) at Mar. 31, 2017 | 507,762,881 | 507,763,000 |
Management's Opinion
Management's Opinion | 3 Months Ended |
Mar. 31, 2017 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Management's Opinion | In the opinion of management, the accompanying unaudited consolidated financial statements contain all adjustments necessary to present fairly, in accordance with accounting principles generally accepted in the United States of America (GAAP), the financial position of Xcel Energy Inc. and its subsidiaries as of March 31, 2017 and Dec. 31, 2016 ; the results of its operations, including the components of net income and comprehensive income, and changes in stockholders’ equity for the three months ended March 31, 2017 and 2016 ; and its cash flows for the three months ended March 31, 2017 and 2016 . All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after March 31, 2017 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, 2016 balance sheet information has been derived from the audited 2016 consolidated financial statements included in the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, 2016 . 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, 2016 , filed with the SEC on Feb. 24, 2017. 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 | 3 Months Ended |
Mar. 31, 2017 | |
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, 2016 , appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference. |
Accounting Pronouncements
Accounting Pronouncements | 3 Months Ended |
Mar. 31, 2017 | |
New Accounting Pronouncements and Changes in Accounting Principles [Abstract] | |
Accounting Pronouncements | Accounting Pronouncements Recently Issued Revenue Recognition — In May 2014, the Financial Accounting Standards Board (FASB) issued Revenue from Contracts with Customers, Topic 606 (Accounting Standards Update (ASU) No. 2014-09) , which provides a new framework for the recognition of revenue. Xcel Energy expects its adoption will result in increased disclosures regarding revenue, cash flows and obligations related to arrangements with customers, as well as separate presentation of alternative revenue programs. Xcel Energy has not yet fully determined the impacts of adoption for several aspects of the standard, including a determination whether and how much an evaluation of the collectability of regulated electric and gas revenues will impact the amounts of revenue recognized upon delivery. Xcel Energy currently expects to implement the standard on a modified retrospective basis, which requires application to contracts with customers effective Jan. 1, 2018, with the cumulative impact on contracts not yet completed as of Dec. 31, 2017 recognized as an adjustment to the opening balance of retained earnings. 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 eliminates the available-for-sale classification for marketable equity securities, and also replaces 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 to be recognized in earnings. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2017. Xcel Energy expects that 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, currently classified as available-for-sale, will continue to be deferred to a regulatory asset, and that the overall impacts of the Jan. 1, 2018 adoption will not be material. Leases — I n February 2016, the FASB issued Leases, Topic 842 (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. As such, agreements entered prior to Jan. 1, 2017 that are currently considered leases are expected to be recognized on the consolidated balance sheet, including contracts for use of office space, equipment and natural gas storage assets, as well as certain purchased power agreements (PPAs) for natural gas-fueled generating facilities. Xcel Energy expects that similar agreements entered after Dec. 31, 2016 will generally qualify as leases under the new standard, but has not yet completed its evaluation of certain other contracts, including arrangements for the secondary use of assets, such as land easements. 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. Xcel Energy has not yet fully determined the impacts of adoption of the standard, but expects that as a result of application of accounting principles for rate regulated entities, a similar amount of pension cost, including non-service components, will be recognized consistent with the current ratemaking treatment, and that the impacts of adoption will be limited to changes in classification of non-service costs in the consolidated statement of income. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2017. Recently Adopted Stock Compensation — I n March 2016, the FASB issued Improvements to Employee Share-Based Payment Accounting, Topic 718 (ASU No. 2016-09), which simplifies accounting and financial statement presentation for share-based payment transactions. The guidance requires that the difference between the tax deduction available upon settlement of share-based equity awards and the tax benefit accumulated over the vesting period be recognized as an adjustment to income tax expense. Xcel Energy adopted the guidance in 2016, resulting in immaterial 2016 adjustments to income tax expense and changes in classification of cash flows related to tax withholding in the consolidated statements of cash flows for the years ended Dec. 31, 2016, 2015 and 2014. |
Selected Balance Sheet Data
Selected Balance Sheet Data | 3 Months Ended |
Mar. 31, 2017 | |
Balance Sheet Related Disclosures [Abstract] | |
Selected Balance Sheet Data | Selected Balance Sheet Data (Thousands of Dollars) March 31, 2017 Dec. 31, 2016 Accounts receivable, net Accounts receivable $ 832,540 $ 827,112 Less allowance for bad debts (51,292 ) (50,823 ) $ 781,248 $ 776,289 (Thousands of Dollars) March 31, 2017 Dec. 31, 2016 Inventories Materials and supplies $ 321,518 $ 312,430 Fuel 150,025 181,752 Natural gas 47,538 110,044 $ 519,081 $ 604,226 (Thousands of Dollars) March 31, 2017 Dec. 31, 2016 Property, plant and equipment, net Electric plant $ 38,412,137 $ 38,220,765 Natural gas plant 5,365,655 5,317,717 Common and other property 1,897,263 1,888,518 Plant to be retired (a) 22,202 31,839 Construction work in progress 1,596,909 1,373,380 Total property, plant and equipment 47,294,166 46,832,219 Less accumulated depreciation (14,576,320 ) (14,381,603 ) Nuclear fuel 2,652,026 2,571,770 Less accumulated amortization (2,211,488 ) (2,180,636 ) $ 33,158,384 $ 32,841,750 (a) In the fourth quarter of 2017, PSCo expects to both early retire Valmont Unit 5 and convert 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 | 3 Months Ended |
Mar. 31, 2017 | |
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, 2016 appropriately represents, in all material respects, the current status of other income tax matters, and are incorporated herein by reference. Federal Tax Loss Carryback Claims — In 2012-2015, Xcel Energy identified certain expenses related to 2009, 2010, 2011, 2013, 2014 and 2015 that qualify for an extended carryback beyond the typical two -year carryback period. As a result of a higher tax rate in prior years, Xcel Energy recognized a tax benefit of approximately $5 million in 2015, $17 million in 2014, $12 million in 2013 and $15 million in 2012. Federal Audit — Xcel Energy files a consolidated federal income tax return. In 2012, the Internal Revenue Service (IRS) commenced an examination of tax years 2010 and 2011 , including the 2009 carryback claim. As of March 31, 2017, the IRS had proposed an adjustment to the federal tax loss carryback claims that would result in $14 million of income tax expense for the 2009 through 2011 claims, and the 2013 through 2015 claims. In the fourth quarter of 2015, the IRS forwarded the issue to the Office of Appeals (Appeals). In 2016 the IRS audit team and Xcel Energy presented their case to Appeals; however, the outcome and timing of a resolution is uncertain. The statute of limitations applicable to Xcel Energy’s 2009 through 2011 federal income tax returns, following extensions, expires in December 2017. Xcel Energy has recognized its best estimate of income tax expense that will result from a final resolution of the IRS’s proposed adjustment of the carryback claims. In the third quarter of 2015, the IRS commenced an examination of tax years 2012 and 2013 . In the first quarter of 2017, the IRS proposed an adjustment to tax years 2012 and 2013 that could have impacted Xcel Energy’s net operating loss (NOL) and tax credit carryforwards and effective tax rate (ETR). After additional review, the IRS withdrew their proposed adjustment. As of March 31, 2017, the IRS had not proposed any other material adjustments to tax years 2012 and 2013. State Audits — Xcel Energy files consolidated state tax returns based on income in its major operating jurisdictions of Colorado, Minnesota, Texas, and Wisconsin, and various other state income-based tax returns. As of March 31, 2017, 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, Texas began an audit of years 2009 and 2010 . As of March 31, 2017, Texas had not proposed any adjustments; • In 2016, Minnesota began an audit of years 2010 through 2014 . As of March 31, 2017, Minnesota had not proposed any adjustments; • In 2016, Wisconsin began an audit of years 2012 and 2013 . As of March 31, 2017, Wisconsin had not proposed any adjustments; and • As of March 31, 2017, there were no other state income tax audits in progress. Unrecognized Tax Benefits — The unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the annual ETR. In addition, the unrecognized tax benefit balance includes temporary tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. A change in the period of deductibility would not affect the ETR but would impact the timing of cash payment to the taxing authority. A reconciliation of the amount of unrecognized tax benefit is as follows: (Millions of Dollars) March 31, 2017 Dec. 31, 2016 Unrecognized tax benefit — Permanent tax positions $ 30.1 $ 29.6 Unrecognized tax benefit — Temporary tax positions 105.3 104.1 Total unrecognized tax benefit $ 135.4 $ 133.7 The unrecognized tax benefit amounts were reduced by the tax benefits associated with NOL and tax credit carryforwards. The amounts of tax benefits associated with NOL and tax credit carryforwards are as follows: (Millions of Dollars) March 31, 2017 Dec. 31, 2016 NOL and tax credit carryforwards $ (45.6 ) $ (43.8 ) 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 and audit progress, the Minnesota, Texas and Wisconsin audits progress, and other state audits resume. As the IRS Appeals and IRS, Minnesota, Texas and Wisconsin audits progress, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $60 million . The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. A reconciliation of the amount of the payable for interest related to unrecognized tax benefits reported are as follows: (Millions of Dollars) March 31, 2017 Dec. 31, 2016 Payable for interest related to unrecognized tax benefits at beginning of period $ (3.4 ) $ (0.1 ) Interest expense related to unrecognized tax benefits recorded during the period (0.9 ) (3.3 ) Payable for interest related to unrecognized tax benefits at end of period $ (4.3 ) $ (3.4 ) No amounts were accrued for penalties related to unrecognized tax benefits as of March 31, 2017 or Dec. 31, 2016. |
Rate Matters
Rate Matters | 3 Months Ended |
Mar. 31, 2017 | |
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, 2016, appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference. NSP-Minnesota Pending Regulatory Proceeding — Minnesota Public Utilities Commission ( MPUC) Minnesota 2016 Multi-Year Electric Rate Case — In November 2015, NSP-Minnesota filed a three -year electric rate case with the MPUC. The rate case is based on a requested return on equity (ROE) of 10.0 percent and a 52.50 percent equity ratio. In December 2015, the MPUC approved interim rates for 2016. The request is detailed in the table below: Request (Millions of Dollars) 2016 2017 2018 Rate request $ 194.6 $ 52.1 $ 50.4 Increase percentage 6.4 % 1.7 % 1.7 % Interim request $ 163.7 $ 44.9 N/A Rate base $ 7,800 $ 7,700 $ 7,700 Settlement Agreement In August 2016, NSP-Minnesota and various parties reached a settlement which resolves all revenue requirement issues in dispute. The settlement agreement requires the approval of the MPUC. Key terms of the settlement are listed below: • Four -year period covering 2016-2019; • Annual sales true-up; • ROE of 9.2 percent and an equity ratio of 52.5 percent ; • Nuclear related costs will not be considered provisional; • Continued use of all existing riders, however no new riders may be utilized during the four -year term; • Deferral of incremental 2016 property tax expense above a fixed threshold to 2018 and 2019; • Four -year stay out provision for rate cases; • Property tax true-up mechanism for 2017-2019; and • Capital expenditure true-up mechanism for 2016-2019. (Millions of Dollars, incremental) 2016 2017 2018 2019 Total Settlement revenues $ 74.99 $ 59.86 $ — $ 50.12 $ 184.97 NSP-Minnesota’s sales true-up 59.95 — — (0.20 ) 59.75 Total rate impact $ 134.94 $ 59.86 $ — $ 49.92 $ 244.72 In March 2017, the Administrative Law Judge (ALJ) recommended that the MPUC approve the settlement as it will contribute to just and reasonable rates and that no objections to the settlement are sufficient to merit rejection. The ALJ also provided recommendations for a majority of the revenue requirement issues in the event the MPUC decides to reject the settlement. The MPUC is anticipated to hold deliberations on the rate case in May 2017 and issue an order in June 2017. PSCo Recently Concluded Regulatory Proceeding — Colorado Public Utilities Commission (CPUC) Annual Electric Earnings Test — PSCo must share with customers earnings that exceed the authorized ROE of 9.83 percent for 2015 through 2017, as part of an annual earnings test. The 2016 earnings test did not result in a material customer refund obligation as of Dec. 31, 2016. PSCo filed its 2016 earnings test with the CPUC in April 2017. The final sharing obligation will be based on the CPUC approved tariff and could vary from the current estimate. SPS Pending Regulatory Proceedings — Public Utility Commission of Texas (PUCT) Appeal of the Texas 2015 Electric Rate Case Decision — SPS had requested an overall retail electric revenue rate increase of $42.1 million . In 2015, the PUCT approved an overall rate decrease of approximately $4.0 million , net of rate case expenses. In April 2016, SPS filed an appeal, with the Texas State District Court, of the PUCT’s order that had denied SPS’ request for rehearing on certain items in SPS’ Texas 2015 electric rate case related to capital structure, incentive compensation and wholesale load reductions. On March 6, 2017, the Travis County District Court denied SPS’s appeal. On April 4, 2017, SPS appealed the District Court’s decision to the Court of Appeals. Texas 2016 Electric Rate Case — In February 2016, SPS filed a retail electric rate case in Texas requesting an overall increase in annual base rate revenue of approximately $71.9 million , or 14.4 percent . The filing is based on a historic test year ended Sept. 30, 2015, a requested ROE of 10.25 percent , an electric rate base of approximately $1.7 billion , and an equity ratio of 53.97 percent . In September 2016, SPS revised its requested rate increase to $61.5 million , along with recovery of rate case expenses, for an overall revised request of $65.5 million . In December 2016, SPS reached a settlement that resolves all issues in the rate case. The total estimated rate impact is $51.8 million . The final rates established in the case are effective retroactive to July 20, 2016. In December 2016, an ALJ approved interim rates, effective as of Dec. 10, 2016. In the fourth quarter of 2016, SPS deferred certain costs associated with this rate case. In January 2017, the PUCT approved the settlement and no refund of interim rates was necessary. In April 2017, SPS filed a surcharge to recover $13.8 million for the additional revenue recovered by applying the final rates to customer billing units for the period of July 20, 2016 through Dec. 9, 2016. Texas 2016 Transmission Cost Recovery Factor (TCRF) Application — In February 2017, SPS filed with the PUCT to recover additional annual revenue of approximately $16.1 million through its TCRF, or 1.8 percent . The filing is based upon capital transmission additions made during 2016. SPS expects a PUCT decision and implementation of TCRF rates by mid-2017. Pending Regulatory Proceeding — New Mexico Public Regulation Commission (NMPRC) New Mexico 2016 Electric Rate Case — In November 2016, SPS filed an electric rate case with the NMPRC seeking an increase in base rates of approximately $41.4 million , representing a total revenue increase of approximately 10.9 percent . The rate filing is 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. SPS has excluded fuel and purchased power costs from base rates. This base rate case also takes into account the decline in sales of 380 MW in 2017 from certain wholesale customers and seeks to adjust the service life of SPS’ Tolk power plant to a remaining life through 2030 based on the investments to provide cooling water and the risks of investments in additional environmental controls. The major components of the requested rate increase are summarized below: (Millions of Dollars) Request Capital expenditures $ 20.1 Allocator changes, including wholesale load reductions 11.5 Transmission expense, net of revenue, including charges paid to Southwest Power Pool, Inc. (SPP) for construction of regionally shared transmission projects 4.7 Depreciation, including adjustment of service life for the Tolk generating station 3.6 Rate case expenses 1.1 Other, net 0.4 Requested rate increase $ 41.4 On April 10, 2017, the hearing examiner determined that SPS’ rate filing was deficient, and recommended the NMPRC extend the procedural schedule by one month and restart the suspension period once it is determined that the deficiencies are resolved. On April 19, 2017, the NMPRC ruled to dismiss SPS’ rate case and required SPS to refile a future test year rate case. SPS filed a motion for reconsideration on April 21, 2017 and the NMPRC is expected to consider that motion on May 10, 2017. Pending Regulatory Proceedings — Federal Energy Regulatory Commission (FERC) Midcontinent Independent System Operator, Inc. (MISO) ROE Complaints/ROE Adder — In November 2013, a group of customers filed a complaint at the FERC against MISO transmission owners (TOs), including NSP-Minnesota and NSP-Wisconsin. The complaint argued for a reduction in the ROE in transmission formula rates in the MISO region from 12.38 percent to 9.15 percent , a prohibition on capital structures in excess of 50 percent equity, and the removal of ROE adders (including those for Regional Transmission Organization (RTO) membership and for being an independent transmission company), effective Nov. 12, 2013. In December 2015, an ALJ recommended the FERC approve a ROE of 10.32 percent using a FERC ROE methodology adopted in June 2014, which the FERC upheld in an order issued in September 2016. This ROE is 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 is 10.82 percent , which includes a 50 basis point adder for RTO membership. In February 2015, a second complaint seeking to reduce the MISO ROE from 12.38 percent to 8.67 percent prior to any adder was filed with the FERC, resulting in a second period of potential refund from Feb. 12, 2015 to May 11, 2016. The MPUC, the North Dakota Public Service Commission (NDPSC), the South Dakota Public Utilities Commission and the Minnesota Department of Commerce joined a joint complainant/intervenor initial brief recommending an ROE of approximately 8.81 percent . FERC staff recommended a ROE of 8.78 percent . The MISO TOs recommended a ROE of 10.92 percent . In June 2016, the ALJ recommended a ROE of 9.7 percent , the midpoint of the upper half of the discounted cash flow (DCF) range, applying the June 2014 FERC ROE methodology. A decision was expected later in 2017, but could be delayed by the lack of a quorum at the FERC. On April 14, 2017 the D.C. Circuit Court of Appeals vacated and remanded the June 2014 FERC decision, previously made in a New England ROE case. The court decision found that the FERC in that case had not established that the prior ROE was unjust and unreasonable, and that the FERC also failed to adequately support the newly approved ROE. The New England ROE ruling was then the basis for the ROE methodology used in the MISO complaint cases. The court found that the ROE methodology used in the New England ROE case was inadequate because it relied on approaches other than the DCF model. The impact of this court decision on the pending MISO complaint cases is uncertain. As of March 2017, NSP-Minnesota has recognized a current liability for the Nov. 12, 2013 to Feb. 11, 2015 complaint period based on the 10.32 percent ROE provided in the FERC order. This liability is net of refunds processed during the first quarter of 2017. NSP-Minnesota has also recognized a current liability representing the best estimate of the final ROE for the Feb. 12, 2015 to May 11, 2016 complaint period. 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 collect charges since 2008, but SPP had not been charging its customers for these upgrades. In April 2016, SPP filed a request with the FERC for a waiver that would allow SPP to recover the charges not billed since 2008. The FERC approved the request in July 2016. SPS and certain other parties requested rehearing of the FERC order. In November 2016, SPP billed SPS a net amount, for the period from 2008 through August 2016, of $12.8 million for these charges, to be paid over a five -year period commencing November 2016. In October 2016, SPS filed applications for deferred accounting and future recovery of related costs in Texas and New Mexico. In December 2016, SPS’ New Mexico application was consolidated with its base rate case and in March 2017, SPS withdrew its Texas application and will address the issue in its next base rate case. SPS anticipates these SPP charges authorized by FERC will be recoverable through regulatory mechanisms. |
Commitments and Contingencies
Commitments and Contingencies | 3 Months Ended |
Mar. 31, 2017 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | Commitments and Contingencies Except to the extent noted below and in Note 5 above, the circumstances set forth in Notes 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, 2016 , 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 Under certain PPAs, NSP-Minnesota, PSCo and SPS purchase power from independent power producing entities for which the utility subsidiaries are required to reimburse natural gas or biomass fuel costs, or to participate in tolling arrangements under which the utility subsidiaries procure the natural gas required to produce the energy that they purchase. These specific PPAs create a variable interest in the associated independent power producing entity. The Xcel Energy utility subsidiaries had approximately 3,537 megawatts (MW) of capacity under long-term PPAs as of March 31, 2017 and Dec. 31, 2016 , with entities that have been determined to be variable interest entities. Xcel Energy has concluded that these entities are not required to be consolidated in its consolidated financial statements because it does not have the power to direct the activities that most significantly impact the entities’ economic performance. These agreements have expiration dates through 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. As a result, Xcel Energy Inc.’s exposure under the guarantees and bond indemnities is based upon the net liability of the relevant subsidiary under the specified agreements or transactions. Most of the guarantees and bond indemnities issued by Xcel Energy Inc. and its subsidiaries have a stated maximum guarantee or indemnity amount. As of March 31, 2017 and Dec. 31, 2016 , 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) March 31, 2017 Dec. 31, 2016 Guarantees issued and outstanding $ 18.6 $ 18.8 Current exposure under these guarantees 0.1 0.1 Bonds with indemnity protection 43.6 43.0 Other Indemnification Agreements Xcel Energy Inc. and its subsidiaries provide indemnifications through contracts entered into in the normal course of business. These are primarily indemnifications against adverse litigation outcomes in connection with underwriting agreements, as well as breaches of representations and warranties, including corporate existence, transaction authorization and income tax matters with respect to assets sold. Xcel Energy Inc.’s and its subsidiaries’ obligations under these agreements may be limited in terms of duration and amount. The maximum 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 has been named a potentially responsible party (PRP) for contamination at a site in Ashland, Wis. The Ashland/Northern States Power Lakefront Superfund Site (the Site) includes NSP-Wisconsin property, previously operated as a MGP facility (the Upper Bluff), and two other properties: an adjacent city lakeshore park area (Kreher Park); and an area of Lake Superior’s Chequamegon Bay adjoining the park. In 2012, NSP-Wisconsin agreed to remediate the Phase I Project Area (which includes the Upper Bluff and Kreher Park areas of the Site), under a settlement agreement with the United States Environmental Protection Agency (EPA). The current cost estimate for the cleanup of the Phase I Project Area is approximately $77.2 million , of which approximately $57.2 million has been spent. NSP-Wisconsin performed a wet dredge pilot study in 2016 and demonstrated that a wet dredge remedy can meet the performance standards for remediation of the Sediments. As a result, the EPA authorized NSP-Wisconsin to extend the wet dredge pilot to additional areas of the Site. In January 2017, NSP-Wisconsin agreed to remediate the Phase II Project Area (the Sediments), under a settlement agreement with the EPA. The settlement was approved by the U.S. District Court for the Western District of Wisconsin. NSP-Wisconsin has initiated field activities to perform a full scale wet dredge remedy of the Sediments in 2017, with performance of restoration activities in 2018. At March 31, 2017 and Dec. 31, 2016, NSP-Wisconsin had recorded a total liability of $62.1 million and $64.3 million , respectively, for the entire site. NSP-Wisconsin has deferred the unrecovered portion of the estimated Site remediation costs as a regulatory asset. The Public Service Commission of Wisconsin (PSCW) has consistently 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 April 2016, NSP-Wisconsin filed a limited natural gas rate case for recovery of additional expenses associated with remediating the Site. In December 2016, the PSCW issued a written order approving the requested increase in annual recovery of MGP clean-up costs from $7.6 million in 2016 to $12.4 million in 2017. 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 from the right-of-way and commenced an investigation of the historic MGP and adjacent properties (the Fargo MGP Site). NSP-Minnesota has recommended that targeted source removal of impacted soils and historic MGP infrastructure should be performed. The North Dakota Department of Health approved NSP-Minnesota’s proposed cleanup plan in January 2017. The timing and final scope of remediation is dependent on whether current property owners will agree to provide reasonable access to NSP-Minnesota to perform and implement the approved cleanup plan. NSP-Minnesota has initiated insurance recovery litigation in North Dakota. The U.S. District Court for the District of North Dakota agreed to the parties’ request for a stay of the litigation until May 2017. As of March 31, 2017 and Dec. 31, 2016, NSP-Minnesota had recorded a liability of $11.1 million and $11.3 million , respectively, for the Fargo MGP Site. In December 2015, the NDPSC approved NSP-Minnesota’s request to defer costs associated with the Fargo MGP Site, resulting in deferral of all investigation and response costs with the exception of approximately 12 percent allocable to the Minnesota jurisdiction. Uncertainties related to the liability recognized include obtaining access to perform the approved remediation, final designs that will be developed to implement the approved cleanup plan and the potential for contributions from entities that may be identified as PRPs. Other MGP and Landfill Sites — Xcel Energy is currently involved in investigating and/or remediating several other MGP and landfill sites. Xcel Energy has identified nine sites across its service territories in addition to the sites in Ashland, Wis. and Fargo, N.D., where former MGP or landfill disposal activities have or may have resulted in site contamination and are under current investigation and/or remediation. At some or all of these sites, there are other parties that may have responsibility for some portion of any remediation. Xcel Energy anticipates that the majority of the investigation or remediation at these sites will continue through at least 2018. Xcel Energy had accrued $2.9 million and $2.0 million for these sites at March 31, 2017 and Dec. 31, 2016, respectively. There may be insurance recovery and/or recovery from other PRPs to offset any costs incurred. Xcel Energy anticipates that any significant amounts incurred will be recovered from customers. Environmental Requirements Water and Waste Federal Clean Water Act (CWA) Waters of the United States Rule — In 2015, the EPA and the U.S. Army Corps of Engineers (Corps) published a final rule that significantly expands the types of water bodies regulated under the CWA and broadens the scope of waters subject to federal jurisdiction. The final rule will subject more utility projects to federal CWA jurisdiction, thereby potentially delaying the siting of new generation projects, pipelines, transmission lines and distribution lines, as well as increasing project costs and expanding permitting and reporting requirements. In October 2015, the U.S. Court of Appeals for the Sixth Circuit issued a nationwide stay of the final rule and subsequently ruled that it, rather than the federal district courts, had jurisdiction over challenges to the rule. In January 2017, the U.S. Supreme Court agreed to resolve the dispute as to which court should hear challenges to the rule. A ruling is expected by the end of 2017. In February 2017, President Trump issued an executive order requiring the EPA and the Corps to review and revise the final rule. The executive order directs the agencies to consider interpreting the term “Waters of the U.S.” in a manner that is more narrow than the final rule. In March 2017, the EPA and the Corps published formal notice of the agencies’ intent to review the final rule and engage in further rulemaking. Federal CWA Effluent Limitations Guidelines (ELG) — In 2015, the EPA issued a final ELG rule for power plants that use coal, natural gas, oil or nuclear materials as fuel and discharge treated effluent to surface waters as well as utility-owned landfills that receive coal combustion residuals. • Xcel Energy estimates that the capital cost to comply with the ELG rule for Colorado will range from $21 million to $32 million ; • The estimated compliance cost for NSP-Minnesota’s Allen S. King Plant is approximately $10 million ; • Xcel Energy continues to evaluate the cost of compliance at its other NSP-Minnesota and NSP-Wisconsin facilities potentially affected by this rule; and • The anticipated costs of compliance with the final rule at SPS are not expected to have a material impact on the results of operations, financial position or cash flows. Xcel Energy believes that compliance costs would be recoverable through regulatory mechanisms. Consolidated challenges to the rule are being heard by the Fifth Circuit Court of Appeals. On April 12, 2017, the EPA issued an administrative stay to delay the ELG rule’s compliance deadlines during the pendency of the ongoing litigation in order to give the agency the opportunity to reconsider and review the rule. Air Greenhouse Gas (GHG) Emission Standard for Existing Sources (Clean Power Plan or CPP) — In 2015, the EPA issued its final rule for existing power plants. Among other things, the rule requires that state plans include enforceable measures to ensure emissions from existing power plants achieve the EPA’s state-specific interim (2022-2029) and final (2030 and thereafter) emission performance targets. The CPP was challenged by multiple parties in the D.C. Circuit Court. In February 2016, the U.S. Supreme Court issued an order staying the final CPP rule. In September 2016, the D.C. Circuit Court heard oral arguments in the consolidated challenges to the CPP. The stay will remain in effect until the D.C. Circuit Court reaches its decision and the U.S. Supreme Court either declines to review the lower court’s decision or reaches a decision of its own. In March 2017, President Trump signed an executive order requiring the EPA Administrator to review the CPP rule and if appropriate, publish proposed rules suspending, revising or rescinding it. Accordingly, the EPA has requested that the D.C. Circuit Court hold the litigation in abeyance until the EPA completes its work under the executive order. Parties in the litigation, who support the CPP, have filed briefs opposing the EPA’s motion. A court ruling on the EPA’s motion is expected in the second quarter of 2017. Xcel Energy has undertaken a number of initiatives that reduce GHG emissions and respond to state renewable and energy efficiency goals. The CPP could require additional emission reductions in states in which Xcel Energy operates. If state plans do not provide credit for the investments Xcel Energy has already made to reduce GHG emissions, or if they require additional initiatives or emission reductions, then their requirements would potentially impose additional substantial costs. Xcel Energy cannot predict the costs of compliance with the final rule once it takes effect due to the uncertainty about what, if anything, the final rules may require. Xcel Energy believes compliance costs will be recoverable through regulatory mechanisms. If Xcel Energy’s regulators do not allow recovery of all or a part of the cost of capital investment or the operating and maintenance (O&M) costs incurred to comply with the CPP or cost recovery is not provided in a timely manner, it could have a material impact on results of operations, financial position or cash flows. Regional Haze Rules — The regional haze program is designed to address widespread haze that results from emissions from a multitude of sources. The Best Available Retrofit Technology (BART) requirements of the EPA’s regional haze rules require the installation and operation of emission controls for industrial facilities emitting air pollutants that reduce visibility in national parks and wilderness areas. Under BART, regional haze plans identify facilities that will have to reduce Sulfur Dioxide (SO 2) , Nitrogen Oxide (NOx) and Particulate Matter (PM) emissions and set emission limits for those facilities. BART requirements can also be met through participation in interstate emission trading programs such as the Clean Air Interstate Rule (CAIR) and its successor, Cross-State Air Pollution Rule (CSAPR). The regional haze plans developed by Minnesota and Colorado have been fully approved and are being implemented in those states. States are required to revise their plans every ten years . The next plans for Minnesota and Colorado will be due in 2021. Texas’ first regional haze plan is still undergoing federal review as described below. President Trump’s Administration has not yet taken any public position regarding its views of the proposed and final regional haze regulations affecting SPS facilities in Texas. Actions affecting Harrington Units: Texas developed a State Implementation Plan (SIP) that finds the CAIR equal to BART for electric generating units (EGUs). As a result, no additional controls beyond CAIR compliance would be required. In 2014, the EPA proposed to approve the BART portion of the SIP, with substitution of CSAPR compliance for Texas’ reliance on CAIR. In January 2016, the EPA adopted a final rule that defers its approval of CSAPR compliance as BART until the EPA considers further adjustments to CSAPR emission budgets under the D.C. Circuit Court’s remand of the Texas SO 2 emission budgets. In June 2016, the EPA issued a memorandum which allows Texas to voluntarily adopt the CSAPR emission budgets limiting annual SO 2 and NOx emissions and rely on those emission budgets to satisfy Texas’ BART obligations under the regional haze rules. The Texas Commission on Environmental Quality (TCEQ) has not utilized this option. The EPA then published a proposed rule in January 2017 that could have the effect of requiring installation of dry scrubbers to reduce SO 2 emissions from Harrington Units 1 and 2. Investment costs associated with dry scrubbers for Harrington Units 1 and 2 could be approximately $400 million . The EPA’s deadline to issue a final rule for Texas is September 2017. Actions affecting Tolk units: In January 2016, the EPA adopted a final rule establishing a federal implementation plan for the state of Texas, which imposed SO 2 emission limitations that reflect the installation of dry scrubbers on Tolk Units 1 and 2, with compliance required by February 2021. Investment costs associated with dry scrubbers could be approximately $600 million . SPS appealed the EPA’s decision and requested a stay of the final rule. The United States Court of Appeals for the Fifth Circuit (Fifth Circuit) granted the stay and decided that they are the appropriate venue for this case. In March 2017, the Fifth Circuit remanded the rule to the EPA for reconsideration, while leaving the stay in effect. The Fifth Circuit is now holding the case in abeyance until the EPA completes its reconsideration of the rule. It is likely that Texas and other affected entities including SPS would continue to challenge the determinations to date. The risk of these controls being imposed along with the risk of investments to provide cooling water to Tolk have caused SPS to seek to decrease the remaining depreciable life of the Tolk units. 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. The cases were consolidated in U.S. District Court in Nevada. Five of the cases have since been settled and seven remain active, which include one multi-district litigation (MDL) matter consisting of a Colorado class (Breckenridge), a Wisconsin class (NSP-Wisconsin), a Kansas class, and two other cases identified as “Sinclair Oil” and “Farmland.” In November 2016, the MDL judge dismissed e prime and Xcel Energy from the Farmland lawsuit, and Farmland has appealed the dismissal. Motions for summary judgment were filed by defendants, including e prime, in all of the remaining lawsuits. In March 2017 the U.S. District Court issued an order dismissing the claims against e prime in the Sinclair lawsuit and denied plaintiffs motions for class certification in the other lawsuits. The U.S. District Court did not grant e prime’s summary judgment motions in the Wisconsin or Colorado cases. 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 Denver State Court, stating PSCo failed to award proper allowances and refunds for line extensions to new developments pursuant to the terms of electric service agreements entered into by PSCo and various developers. The dispute involves assigned interests in those claims by over fifty developers. In May 2016, the district court granted PSCo’s motion to dismiss the lawsuit, concluding that jurisdiction over this dispute resides with the CPUC. In June 2016, DRC filed a notice of appeal. The matter has been fully briefed and plaintiff has requested oral arguments. DRC also brought a proceeding before the CPUC as assignee on behalf of two developers, Ryland Homes and Richmond Homes of Colorado. In March 2016, the ALJ issued an order rejecting DRC’s claims for additional allowances and refunds. In June 2016, the ALJ’s determination was approved by the CPUC. DRC did not file a request for reconsideration before the CPUC contesting the decision, but filed an appeal in Denver District Court in August 2016. DRC filed its brief in February 2017 and PSCo’s answer brief was filed in March 2017. 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 | 3 Months Ended |
Mar. 31, 2017 | |
Debt Disclosure [Abstract] | |
Borrowings and Other Financing Instruments | Borrowings and Other Financing Instruments Short-Term Borrowings Money Pool — Xcel Energy Inc. and its utility subsidiaries have established a money pool arrangement that allows for short-term investments in and borrowings between the utility subsidiaries. NSP-Wisconsin does not participate in the money pool. Xcel Energy Inc. may make investments in the utility subsidiaries at market-based interest rates; however, the money pool arrangement does not allow the utility subsidiaries to make investments in Xcel Energy Inc. The money pool balances are eliminated in consolidation. Commercial Paper — Xcel Energy Inc. and its utility subsidiaries meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under their credit facilities. Commercial paper outstanding for Xcel Energy was as follows: (Amounts in Millions, Except Interest Rates) Three Months Ended Year Ended Borrowing limit $ 2,750 $ 2,750 Amount outstanding at period end 605 392 Average amount outstanding 557 485 Maximum amount outstanding 719 1,183 Weighted average interest rate, computed on a daily basis 0.97 % 0.74 % Weighted average interest rate at period end 1.18 0.95 Letters of Credit — Xcel Energy Inc. and its subsidiaries use letters of credit, generally with terms of one year , to provide financial guarantees for certain operating obligations. At March 31, 2017 and Dec. 31, 2016 , there were $16 million and $19 million , respectively, of letters of credit outstanding under the credit facilities. The contract amounts of these letters of credit approximate their fair value and are subject to fees. Credit Facilities — In order to use their commercial paper programs to fulfill short-term funding needs, Xcel Energy Inc. and its utility subsidiaries must have revolving credit facilities in place at least equal to the amount of their respective commercial paper borrowing limits and cannot issue commercial paper in an aggregate amount exceeding available capacity under these credit facilities. The lines of credit provide short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings. At March 31, 2017 , Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available: (Millions of Dollars) Credit Facility (a) Drawn (b) Available Xcel Energy Inc. $ 1,000 $ 391 $ 609 PSCo 700 34 666 NSP-Minnesota 500 47 453 SPS 400 116 284 NSP-Wisconsin 150 33 117 Total $ 2,750 $ 621 $ 2,129 (a) These credit facilities mature in June 2021 . (b) Includes outstanding commercial paper and letters of credit. All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the respective credit facilities. Xcel Energy Inc. and its subsidiaries had no direct advances on the credit facilities outstanding at March 31, 2017 and Dec. 31, 2016 . |
Fair Value of Financial Assets
Fair Value of Financial Assets and Liabilities | 3 Months Ended |
Mar. 31, 2017 | |
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. When contractual settlements extend to periods beyond those readily observable on active exchanges or quoted by brokers, the significance of the use of less observable forecasts of long-term forward prices and volatilities on a valuation is evaluated, and may result in Level 3 classification. Electric commodity derivatives held by NSP-Minnesota include transmission congestion instruments, generally referred to as financial transmission rights (FTRs), purchased from MISO. Electric commodity derivatives held by SPS include FTRs purchased from SPP. FTRs purchased from a RTO are financial instruments that entitle or obligate the holder to monthly revenues or charges based on transmission congestion across a given transmission path. The value of an FTR is derived from, and designed to offset, the cost of 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 complex iterative modeling to predict the impacts of forecasted changes in these drivers of transmission system congestion on the historical pricing of FTR purchases. If forecasted costs of electric transmission congestion increase or decrease for a given FTR path, the value of that particular FTR instrument will likewise increase or decrease. Fair value measurements for FTRs have been assigned a Level 3 given the limited observability of management’s forecasts for several of the inputs to this complex valuation model. 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 numerous unobservable quantitative inputs to the complex model used for valuation of FTRs are insignificant to the consolidated financial statements of Xcel Energy. Non-Derivative Instruments Fair Value Measurements 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 purpose of decommissioning the Monticello and Prairie Island (PI) nuclear generating plants. The fund contains cash equivalents, debt securities, equity securities and other investments – all classified as available-for-sale. NSP-Minnesota plans to reinvest matured securities until decommissioning begins. NSP-Minnesota uses the MPUC approved asset allocation for the escrow and investment targets by asset class for both the escrow and qualified trust. NSP-Minnesota recognizes the costs of funding the decommissioning of its nuclear generating plants over the lives of the plants, assuming rate recovery of all costs. Given the purpose and legal restrictions on the use of nuclear decommissioning fund assets, realized and unrealized gains on fund investments over the life of the fund are deferred as an offset of NSP-Minnesota’s regulatory asset for nuclear decommissioning costs. Consequently, any realized and unrealized gains and losses on securities in the nuclear decommissioning fund, including any other-than-temporary impairments, are deferred as a component of the regulatory asset for nuclear decommissioning. Unrealized gains for the nuclear decommissioning fund were $428.2 million and $378.6 million at March 31, 2017 and Dec. 31, 2016 , respectively, and unrealized losses and amounts recorded as other-than-temporary impairments were $31.7 million and $46.9 million at March 31, 2017 and Dec. 31, 2016 , respectively. The following tables present the cost and fair value of Xcel Energy’s non-derivative instruments with recurring fair value measurements in the nuclear decommissioning fund at March 31, 2017 and Dec. 31, 2016 : March 31, 2017 Fair Value (Thousands of Dollars) Cost Level 1 Level 2 Level 3 Investments Measured at NAV (b) Total Nuclear decommissioning fund (a) Cash equivalents $ 24,161 $ 24,161 $ — $ — $ — $ 24,161 Commingled funds: Non U.S. equities 272,437 178,990 — — 98,876 277,866 Emerging market debt funds 94,772 — — — 101,269 101,269 Commodity funds 106,571 — — — 88,749 88,749 Private equity investments 137,176 — — — 194,912 194,912 Real estate 125,410 — — — 187,609 187,609 Other commingled funds 151,048 — — — 161,936 161,936 Debt securities: Government securities 27,369 — 27,199 — — 27,199 U.S. corporate bonds 127,841 — 128,799 — — 128,799 Non U.S. corporate bonds 25,345 — 25,556 — — 25,556 Municipal bonds 5 — 5 — — 5 Equity securities: U.S. equities 275,101 501,543 — — — 501,543 Non U.S. equities 188,763 232,851 — — — 232,851 Total $ 1,555,999 $ 937,545 $ 181,559 $ — $ 833,351 $ 1,952,455 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $131.9 million of equity investments in unconsolidated subsidiaries and $103.6 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, 2016 Fair Value (Thousands of Dollars) Cost Level 1 Level 2 Level 3 Investments Measured at NAV (b) Total Nuclear decommissioning fund (a) Cash equivalents $ 20,379 $ 20,379 $ — $ — $ — $ 20,379 Commingled funds: Non U.S. equities 260,877 133,126 — — 112,233 245,359 Emerging market debt funds 93,597 — — — 97,543 97,543 Commodity funds 106,571 — — — 92,091 92,091 Private equity investments 132,190 — — — 190,462 190,462 Real estate 128,630 — — — 187,647 187,647 Other commingled funds 151,048 — — — 159,489 159,489 Debt securities: Government securities 32,764 — 31,965 — — 31,965 U.S. corporate bonds 104,913 — 105,772 — — 105,772 Non U.S. corporate bonds 21,751 — 21,672 — — 21,672 Municipal bonds 13,609 — 13,786 — — 13,786 Mortgage-backed securities 2,785 — 2,816 — — 2,816 Equity securities: U.S. equities 270,779 473,400 — — — 473,400 Non U.S. equities 189,100 218,381 — — — 218,381 Total $ 1,528,993 $ 845,286 $ 176,011 $ — $ 839,465 $ 1,860,762 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $132.8 million of equity investments in unconsolidated subsidiaries and $98.3 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 months ended March 31, 2017 and 2016 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, at March 31, 2017 : Final Contractual Maturity (Thousands of Dollars) Due in 1 Year or Less Due in 1 to 5 Years Due in 5 to 10 Years Due after 10 Years Total Government securities $ — $ 1,100 $ 3,017 $ 23,082 $ 27,199 U.S. corporate bonds 354 38,741 74,617 15,087 128,799 International corporate bonds — 8,085 13,443 4,028 25,556 Municipal bonds — — 5 — 5 Debt securities $ 354 $ 47,926 $ 91,082 $ 42,197 $ 181,559 Rabbi Trusts In June 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 at March 31, 2017 and Dec. 31, 2016: March 31, 2017 Fair Value (Thousands of Dollars) Cost Level 1 Level 2 Level 3 Total Rabbi Trusts (a) Cash equivalents $ 9,575 $ 9,575 $ — $ — $ 9,575 Mutual funds 39,965 40,264 — — 40,264 Total $ 49,540 $ 49,839 $ — $ — $ 49,839 Dec. 31, 2016 Fair Value (Thousands of Dollars) Cost Level 1 Level 2 Level 3 Total Rabbi Trusts (a) Cash equivalents $ 47,831 $ 47,831 $ — $ — $ 47,831 Mutual funds 1,663 1,901 — — 1,901 Total $ 49,494 $ 49,732 $ — $ — $ 49,732 (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. At March 31, 2017 , accumulated other comprehensive losses related to interest rate derivatives included $3.1 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. 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 months ended March 31, 2016 . Additionally, Xcel Energy enters into commodity derivative instruments for trading purposes not directly related to commodity price risks associated with serving its electric and natural gas customers. Changes in the fair value of these commodity derivatives are recorded in electric operating revenues, net of amounts credited to customers under margin-sharing mechanisms. The following table details the gross notional amounts of commodity forwards, options and FTRs at March 31, 2017 and Dec. 31, 2016 : (Amounts in Thousands) (a)(b) March 31, 2017 Dec. 31, 2016 Megawatt hours of electricity 31,838 46,773 Million British thermal units of natural gas 92,801 121,978 (a) Amounts are not reflective of net positions in the underlying commodities. (b) Notional amounts for options are included on a gross basis, but are weighted for the probability of exercise. The following tables detail the impact of derivative activity during the three months ended March 31, 2017 and 2016, on accumulated other comprehensive loss, regulatory assets and liabilities, and income: Three Months Ended March 31, 2017 Pre-Tax Fair Value Gains (Losses) Recognized During the Period in: Pre-Tax (Gains) Losses Reclassified into Income During the Period from: Pre-Tax Gains (Losses) Recognized (Thousands of Dollars) Accumulated Other Regulatory Accumulated Other Regulatory Assets and (Liabilities) Derivatives designated as cash flow hedges Interest rate $ — $ — $ 1,359 (a) $ — $ — Total $ — $ — $ 1,359 $ — $ — Other derivative instruments Commodity trading $ — $ — $ — $ — $ 1,001 (c) Electric commodity — 794 — (3,998 ) (d) — Natural gas commodity — (6,161 ) — 1,075 (e) (4,070 ) (e) Total $ — $ (5,367 ) $ — $ (2,923 ) $ (3,069 ) Three Months Ended March 31, 2016 Pre-Tax Fair Value Losses Recognized During the Period in: Pre-Tax Losses Reclassified into Income During the Period from: Pre-Tax Gains (Losses) Recognized (Thousands of Dollars) Accumulated Other Regulatory Accumulated Other Regulatory Derivatives designated as cash flow hedges Interest rate $ — $ — $ 1,485 (a) $ — $ — Vehicle fuel and other commodity (6 ) — 57 (b) — — Total $ (6 ) $ — $ 1,542 $ — $ — Other derivative instruments Commodity trading $ — $ — $ — $ — $ 1,009 (c) Electric commodity — (265 ) — 8,631 (d) — Natural gas commodity — (2,702 ) — 11,666 (e) (5,024 ) (e) Total $ — $ (2,967 ) $ — $ 20,297 $ (4,015 ) (a) Amounts are recorded to interest charges. (b) Amounts are recorded to O&M expenses. (c) Amounts are recorded to electric operating revenues. Portions of these gains and losses are subject to sharing with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate. (d) Amounts are recorded to electric fuel and purchased power. These derivative settlement gain and loss amounts are shared with electric customers through fuel and purchased energy cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate. (e) Amounts for the three months ended March 31, 2017 included $0.9 million of settlement gains and an immaterial amount of settlement losses for the three months ended March 31, 2016 on derivatives entered to mitigate natural gas price risk for electric generation, recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate. The remaining derivative settlement gains and losses for the three months ended March 31, 2017 and 2016 relate to natural gas operations and are recorded to cost of natural gas sold and transported. These gains and losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset or liability, as appropriate. Xcel Energy had no derivative instruments designated as fair value hedges during the three months ended March 31, 2017 and 2016 . Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for these periods. Consideration of Credit Risk and Concentrations — Xcel Energy continuously monitors the creditworthiness of the counterparties to its interest rate derivatives and commodity derivative contracts prior to settlement, and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. Given this assessment, as well as an assessment of the impact of Xcel Energy’s own credit risk when determining the fair value of derivative liabilities, the impact of considering credit risk was immaterial to the fair value of unsettled commodity derivatives presented in the consolidated balance sheets. Xcel Energy Inc. and its subsidiaries employ additional credit risk control mechanisms when appropriate, such as letters of credit, parental guarantees, standardized master netting agreements and termination provisions that allow for offsetting of positive and negative exposures. Credit exposure is monitored and, when necessary, the activity with a specific counterparty is limited until credit enhancement is provided. Xcel Energy’s utility subsidiaries’ most significant concentrations of credit risk with particular entities or industries are contracts with counterparties to their wholesale, trading and non-trading commodity activities. At March 31, 2017 , two of Xcel Energy’s 10 most significant counterparties for these activities, comprising $24.1 million or ten percent of this credit exposure, had investment grade credit ratings from S&P’s, Moody’s or Fitch Ratings. Eight of the 10 most significant counterparties, comprising $79.1 million or 34 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. All ten 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 recorded to the consolidated balance sheet at fair value, as well as those accounted for as normal purchase-normal sale contracts and therefore not reflected on the balance sheet, may require the posting of collateral or settlement of the contracts for various reasons, including if the applicable utility subsidiary is unable to maintain its credit ratings. At March 31, 2017 and Dec. 31, 2016, there were no derivative instruments in a liability position with underlying contract provisions that required the posting of collateral or settlement of applicable outstanding contracts if the credit ratings of Xcel Energy Inc.’s utility subsidiaries were downgraded below investment grade. Certain derivative instruments are also subject to contract provisions that contain adequate assurance clauses. These provisions allow counterparties to seek performance assurance, including cash collateral, in the event that a given utility subsidiary’s ability to fulfill its contractual obligations is reasonably expected to be impaired. Xcel Energy had no collateral posted related to adequate assurance clauses in derivative contracts as of March 31, 2017 and Dec. 31, 2016 . Recurring Fair Value Measurements — The following table presents for each of the fair value hierarchy levels, Xcel Energy’s derivative assets and liabilities measured at fair value on a recurring basis at March 31, 2017 : March 31, 2017 Fair Value Fair Value Total Counterparty Netting (b) Total (Thousands of Dollars) Level 1 Level 2 Level 3 Current derivative assets Other derivative instruments: Commodity trading $ 4,706 $ 14,850 $ — $ 19,556 $ (12,126 ) $ 7,430 Electric commodity — — 8,443 8,443 (1,814 ) 6,629 Natural gas commodity — 1,334 — 1,334 — 1,334 Total current derivative assets $ 4,706 $ 16,184 $ 8,443 $ 29,333 $ (13,940 ) 15,393 PPAs (a) 5,492 Current derivative instruments $ 20,885 Noncurrent derivative assets Other derivative instruments: Commodity trading $ 198 $ 32,272 $ — $ 32,470 $ (7,295 ) $ 25,175 Total noncurrent derivative assets $ 198 $ 32,272 $ — $ 32,470 $ (7,295 ) 25,175 PPAs (a) 23,506 Noncurrent derivative instruments $ 48,681 March 31, 2017 Fair Value Fair Value Total Counterparty Netting (b) Total (Thousands of Dollars) Level 1 Level 2 Level 3 Current derivative liabilities Other derivative instruments: Commodity trading $ 5,224 $ 12,064 $ — $ 17,288 $ (13,416 ) $ 3,872 Electric commodity — — 1,814 1,814 (1,814 ) — Total current derivative liabilities $ 5,224 $ 12,064 $ 1,814 $ 19,102 $ (15,230 ) 3,872 PPAs (a) 22,834 Current derivative instruments $ 26,706 Noncurrent derivative liabilities Other derivative instruments: Commodity trading $ 204 $ 23,435 $ 793 $ 24,432 $ (10,463 ) $ 13,969 Total noncurrent derivative liabilities $ 204 $ 23,435 $ 793 $ 24,432 $ (10,463 ) 13,969 PPAs (a) 129,715 Noncurrent derivative instruments $ 143,684 (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 will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities. (b) Xcel Energy nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at March 31, 2017 . At March 31, 2017 , derivative assets and liabilities include no obligations to return cash collateral and the rights to reclaim cash collateral of $4.5 million . The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements. The following table presents for each of the fair value hierarchy levels, Xcel Energy’s derivative assets and liabilities measured at fair value on a recurring basis at Dec. 31, 2016 : Dec. 31, 2016 Fair Value Fair Value Total Counterparty Netting (b) Total (Thousands of Dollars) Level 1 Level 2 Level 3 Current derivative assets Other derivative instruments: Commodity trading $ 13,179 $ 14,105 $ — $ 27,284 $ (20,637 ) $ 6,647 Electric commodity — — 19,251 19,251 (1,976 ) 17,275 Natural gas commodity — 8,839 — 8,839 — 8,839 Total current derivative assets $ 13,179 $ 22,944 $ 19,251 $ 55,374 $ (22,613 ) 32,761 PPAs (a) 5,463 Current derivative instruments $ 38,224 Noncurrent derivative assets Other derivative instruments: Commodity trading $ 100 $ 31,029 $ — $ 31,129 $ (7,323 ) $ 23,806 Natural gas commodity — 1,652 — 1,652 — 1,652 Total noncurrent derivative assets $ 100 $ 32,681 $ — $ 32,781 $ (7,323 ) 25,458 PPAs (a) 24,731 Noncurrent derivative instruments $ 50,189 Dec. 31, 2016 Fair Value Fair Value Total Counterparty Netting (b) Total (Thousands of Dollars) Level 1 Level 2 Level 3 Current derivative liabilities Other derivative instruments: Commodity trading $ 13,787 $ 11,320 $ 22 $ 25,129 $ (20,974 ) $ 4,155 Electric commodity — — 1,976 1,976 (1,976 ) — Total current derivative liabilities $ 13,787 $ 11,320 $ 1,998 $ 27,105 $ (22,950 ) 4,155 PPAs (a) 22,804 Current derivative instruments $ 26,959 Noncurrent derivative liabilities Other derivative instruments: Commodity trading $ 89 $ 23,424 $ — $ 23,513 $ (10,727 ) $ 12,786 Total noncurrent derivative liabilities $ 89 $ 23,424 $ — $ 23,513 $ (10,727 ) 12,786 PPAs (a) 135,360 Noncurrent derivative instruments $ 148,146 (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 will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities. (b) Xcel Energy nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2016 . At Dec. 31, 2016 , derivative assets and liabilities include no obligations to return cash collateral and rights to reclaim cash collateral of $3.7 million . The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements. The following table presents the changes in Level 3 commodity derivatives for the three months ended March 31, 2017 and 2016 : Three Months Ended March 31 (Thousands of Dollars) 2017 2016 Balance at Jan. 1 $ 17,253 $ 18,028 Purchases 3,792 1,843 Settlements (19,802 ) (18,256 ) Net transactions recorded during the period: Losses recognized in earnings (a) (794 ) (24 ) Net gains recognized as regulatory assets and liabilities 5,387 5,263 Balance at March 31 $ 5,836 $ 6,854 (a) These amounts relate to commodity derivatives held at the end of the period. Xcel Energy recognizes transfers between levels as of the beginning of each period. There were no transfers of amounts between levels for derivative instruments for the three months ended March 31, 2017 and 2016. Fair Value of Long-Term Debt As of March 31, 2017 and Dec. 31, 2016 , other financial instruments for which the carrying amount did not equal fair value were as follows: March 31, 2017 Dec. 31, 2016 (Thousands of Dollars) Carrying Amount Fair Value Carrying Amount Fair Value Long-term debt, including current portion $ 14,451,909 $ 15,492,978 $ 14,450,247 $ 15,513,209 The fair value of Xcel Energy’s long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities. The fair value estimates are based on information available to management as of March 31, 2017 and Dec. 31, 2016 , and given the observability of the inputs to these estimates, the fair values presented for long-term debt have been assigned a Level 2. |
Other Income, Net
Other Income, Net | 3 Months Ended |
Mar. 31, 2017 | |
Other Income and Expenses [Abstract] | |
Other Income, Net | Other Income, Net Other income, net consisted of the following: Three Months Ended March 31 (Thousands of Dollars) 2017 2016 Interest income $ 3,800 $ 4,070 Other nonoperating income 3,645 680 Insurance policy expense (999 ) (500 ) Other income, net $ 6,446 $ 4,250 |
Segment Information
Segment Information | 3 Months Ended |
Mar. 31, 2017 | |
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 $131.9 million and $132.8 million as of March 31, 2017 and Dec. 31, 2016 , respectively, included in the regulated natural gas utility segment. Asset and capital expenditure information is not provided for Xcel Energy’s reportable segments because as an integrated electric and natural gas utility, Xcel Energy operates significant assets that are not dedicated to a specific business segment, and reporting assets and capital expenditures by business segment would require arbitrary and potentially misleading allocations which may not necessarily reflect the assets that would be required for the operation of the business segments on a stand-alone basis. To report income from operations for regulated electric and regulated natural gas utility segments, the majority of costs are directly assigned to each segment. However, some costs, such as common depreciation, common O&M expenses and interest expense are allocated based on cost causation allocators. A general allocator is used for certain general and administrative expenses, including office supplies, rent, property insurance and general advertising. (Thousands of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total Three Months Ended March 31, 2017 Operating revenues from external customers $ 2,299,060 $ 625,703 $ 21,659 $ — $ 2,946,422 Intersegment revenues 297 264 — (561 ) — Total revenues $ 2,299,357 $ 625,967 $ 21,659 $ (561 ) $ 2,946,422 Net income (loss) $ 194,153 $ 62,927 $ (17,803 ) $ — $ 239,277 (Thousands of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total Three Months Ended March 31, 2016 Operating revenues from external customers $ 2,185,119 $ 565,689 $ 21,465 $ — $ 2,772,273 Intersegment revenues 335 287 — (622 ) — Total revenues $ 2,185,454 $ 565,976 $ 21,465 $ (622 ) $ 2,772,273 Net income (loss) $ 178,237 $ 78,338 $ (15,263 ) $ — $ 241,312 |
Earnings Per Share
Earnings Per Share | 3 Months Ended |
Mar. 31, 2017 | |
Earnings Per Share [Abstract] | |
Earnings Per Share | Earnings Per Share Basic earnings per share (EPS) was computed by dividing the earnings available to Xcel Energy Inc.’s common shareholders by the weighted average number of common shares outstanding during the period. Diluted EPS was computed by dividing the earnings available to Xcel Energy Inc.’s common shareholders by the diluted weighted average number of common shares outstanding during the period. Diluted EPS reflects the potential dilution that could occur if securities or other agreements to issue common stock (i.e., common stock equivalents) were settled. The weighted average number of potentially dilutive shares outstanding used to calculate Xcel Energy Inc.’s diluted EPS is calculated using the treasury stock method. Common Stock Equivalents — Xcel Energy Inc. currently has common stock equivalents related to certain equity awards in share-based compensation arrangements. Common stock equivalents causing dilutive impact to EPS include commitments to issue common stock related to time based equity compensation awards and time based employer matching contributions to certain 401(k) plan participants. Stock equivalent units granted to Xcel Energy Inc.’s Board of Directors are included in common shares outstanding upon grant date as there is no further service, performance or market condition associated with these awards. Restricted stock, granted to settle amounts due to certain employees under the Xcel Energy Inc. Executive Annual Incentive Award Plan, is included in common shares outstanding when granted. Share-based compensation arrangements for which there is currently no dilutive impact to EPS include the following: • Equity awards subject to a performance condition; included in common shares outstanding when all necessary conditions for settlement have been satisfied by the end of the reporting period. • Liability awards subject to a performance condition; any portions settled in shares are included in common shares outstanding upon settlement. The dilutive impact of common stock equivalents affecting EPS was as follows: Three Months Ended March 31, 2017 Three Months Ended March 31, 2016 (Amounts in thousands, except per share data) Income Shares Per Share Amount Income Shares Per Share Amount Net income $ 239,277 — — $ 241,312 — — Basic EPS: Earnings available to common shareholders 239,277 508,278 $ 0.47 241,312 508,667 $ 0.47 Effect of dilutive securities: Time based equity awards — 496 — — 483 — Diluted EPS: Earnings available to common shareholders $ 239,277 508,774 $ 0.47 $ 241,312 509,150 $ 0.47 |
Benefit Plans and Other Postret
Benefit Plans and Other Postretirement Benefits | 3 Months Ended |
Mar. 31, 2017 | |
Compensation and Retirement Disclosure [Abstract] | |
Benefit Plans and Other Postretirement Benefits | Benefit Plans and Other Postretirement Benefits Components of Net Periodic Benefit Cost (Credit) Three Months Ended March 31 2017 2016 2017 2016 (Thousands of Dollars) Pension Benefits Postretirement Health Service cost $ 23,547 $ 22,920 $ 465 $ 432 Interest cost 36,702 40,023 5,984 6,527 Expected return on plan assets (52,317 ) (52,575 ) (6,156 ) (6,249 ) Amortization of prior service credit (442 ) (484 ) (2,671 ) (2,672 ) Amortization of net loss 26,670 24,385 1,672 1,011 Net periodic benefit cost (credit) 34,160 34,269 (706 ) (951 ) Costs not recognized due to the effects of regulation (4,015 ) (4,452 ) — — Net benefit cost (credit) recognized for financial reporting $ 30,145 $ 29,817 $ (706 ) $ (951 ) In January 2017, contributions of $150.0 million were made across four of Xcel Energy’s pension plans. Xcel Energy does not expect additional pension contributions during 2017. |
Other Comprehensive Income
Other Comprehensive Income | 3 Months Ended |
Mar. 31, 2017 | |
Stockholders' Equity Note [Abstract] | |
Other Comprehensive Income | Other Comprehensive Income Changes in accumulated other comprehensive (loss) income, net of tax, for the three months ended March 31, 2017 and 2016 were as follows: Three Months Ended March 31, 2017 (Thousands of Dollars) Gains and Losses on Cash Flow Hedges Unrealized Gains and Losses on Marketable Securities Defined Benefit Pension and Postretirement Items Total Accumulated other comprehensive (loss) income at Jan. 1 $ (51,151 ) $ 110 $ (59,313 ) $ (110,354 ) Losses reclassified from net accumulated other comprehensive loss 825 — 948 1,773 Net current period other comprehensive income 825 — 948 1,773 Accumulated other comprehensive (loss) income at March 31 $ (50,326 ) $ 110 $ (58,365 ) $ (108,581 ) Three Months Ended March 31, 2016 (Thousands of Dollars) Gains and Losses on Cash Flow Hedges Unrealized Gains and Losses on Marketable Securities Defined Benefit Pension and Postretirement Items Total Accumulated other comprehensive (loss) income at Jan. 1 $ (54,862 ) $ 110 $ (55,001 ) $ (109,753 ) Other comprehensive loss before reclassifications (4 ) — (653 ) (657 ) Losses reclassified from net accumulated other comprehensive loss 938 — 864 1,802 Net current period other comprehensive income 934 — 211 1,145 Accumulated other comprehensive (loss) income at March 31 $ (53,928 ) $ 110 $ (54,790 ) $ (108,608 ) Reclassifications from accumulated other comprehensive loss for the three months ended March 31, 2017 and 2016 were as follows: Amounts Reclassified from Accumulated Other Comprehensive Loss (Thousands of Dollars) Three Months Ended March 31, 2017 Three Months Ended March 31, 2016 Losses on cash flow hedges: Interest rate derivatives $ 1,359 (a) $ 1,485 (a) Vehicle fuel derivatives — (b) 57 (b) Total, pre-tax 1,359 1,542 Tax benefit (534 ) (604 ) Total, net of tax 825 938 Defined benefit pension and postretirement losses: Amortization of net loss 1,623 (c) 1,478 (c) Prior service credit (60 ) (c) (64 ) (c) Total, pre-tax 1,563 1,414 Tax benefit (615 ) (550 ) Total, net of tax 948 864 Total amounts reclassified, net of tax $ 1,773 $ 1,802 (a) Included in interest charges. (b) Included in O&M expenses. (c) Included in the computation of net periodic pension and postretirement benefit costs. See Note 12 for details regarding these benefit plans. |
Selected Balance Sheet Data (Ta
Selected Balance Sheet Data (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
Balance Sheet Related Disclosures [Abstract] | |
Accounts Receivable, Net | (Thousands of Dollars) March 31, 2017 Dec. 31, 2016 Accounts receivable, net Accounts receivable $ 832,540 $ 827,112 Less allowance for bad debts (51,292 ) (50,823 ) $ 781,248 $ 776,289 |
Inventories | (Thousands of Dollars) March 31, 2017 Dec. 31, 2016 Inventories Materials and supplies $ 321,518 $ 312,430 Fuel 150,025 181,752 Natural gas 47,538 110,044 $ 519,081 $ 604,226 |
Property, Plant and Equipment, Net | (Thousands of Dollars) March 31, 2017 Dec. 31, 2016 Property, plant and equipment, net Electric plant $ 38,412,137 $ 38,220,765 Natural gas plant 5,365,655 5,317,717 Common and other property 1,897,263 1,888,518 Plant to be retired (a) 22,202 31,839 Construction work in progress 1,596,909 1,373,380 Total property, plant and equipment 47,294,166 46,832,219 Less accumulated depreciation (14,576,320 ) (14,381,603 ) Nuclear fuel 2,652,026 2,571,770 Less accumulated amortization (2,211,488 ) (2,180,636 ) $ 33,158,384 $ 32,841,750 (a) In the fourth quarter of 2017, PSCo expects to both early retire Valmont Unit 5 and convert 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) | 3 Months Ended |
Mar. 31, 2017 | |
Income Tax Disclosure [Abstract] | |
Earliest Open Tax Years Subject to Examination by State Taxing Authorities in the Major Operating Jurisdictions | State Audits — Xcel Energy files consolidated state tax returns based on income in its major operating jurisdictions of Colorado, Minnesota, Texas, and Wisconsin, and various other state income-based tax returns. As of March 31, 2017, 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) March 31, 2017 Dec. 31, 2016 Unrecognized tax benefit — Permanent tax positions $ 30.1 $ 29.6 Unrecognized tax benefit — Temporary tax positions 105.3 104.1 Total unrecognized tax benefit $ 135.4 $ 133.7 |
Tax Benefits Associated with NOL and Tax Credit Carryforwards | The unrecognized tax benefit amounts were reduced by the tax benefits associated with NOL and tax credit carryforwards. The amounts of tax benefits associated with NOL and tax credit carryforwards are as follows: (Millions of Dollars) March 31, 2017 Dec. 31, 2016 NOL and tax credit carryforwards $ (45.6 ) $ (43.8 ) |
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. A reconciliation of the amount of the payable for interest related to unrecognized tax benefits reported are as follows: (Millions of Dollars) March 31, 2017 Dec. 31, 2016 Payable for interest related to unrecognized tax benefits at beginning of period $ (3.4 ) $ (0.1 ) Interest expense related to unrecognized tax benefits recorded during the period (0.9 ) (3.3 ) Payable for interest related to unrecognized tax benefits at end of period $ (4.3 ) $ (3.4 ) |
Rate Matters (Tables)
Rate Matters (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
Public Utilities, General Disclosures [Abstract] | |
NSP-Minnesota's 2016 Multi-Year Electric Rate Case - Rate Request | In December 2015, the MPUC approved interim rates for 2016. The request is detailed in the table below: Request (Millions of Dollars) 2016 2017 2018 Rate request $ 194.6 $ 52.1 $ 50.4 Increase percentage 6.4 % 1.7 % 1.7 % Interim request $ 163.7 $ 44.9 N/A Rate base $ 7,800 $ 7,700 $ 7,700 |
NSP-Minnesota 2016 Rate Case Settlement | (Millions of Dollars, incremental) 2016 2017 2018 2019 Total Settlement revenues $ 74.99 $ 59.86 $ — $ 50.12 $ 184.97 NSP-Minnesota’s sales true-up 59.95 — — (0.20 ) 59.75 Total rate impact $ 134.94 $ 59.86 $ — $ 49.92 $ 244.72 |
SPS' New Mexico 2016 Electric Rate Case [Table Text Block] | The major components of the requested rate increase are summarized below: (Millions of Dollars) Request Capital expenditures $ 20.1 Allocator changes, including wholesale load reductions 11.5 Transmission expense, net of revenue, including charges paid to Southwest Power Pool, Inc. (SPP) for construction of regionally shared transmission projects 4.7 Depreciation, including adjustment of service life for the Tolk generating station 3.6 Rate case expenses 1.1 Other, net 0.4 Requested rate increase $ 41.4 |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
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) March 31, 2017 Dec. 31, 2016 Guarantees issued and outstanding $ 18.6 $ 18.8 Current exposure under these guarantees 0.1 0.1 Bonds with indemnity protection 43.6 43.0 |
Borrowings and Other Financin28
Borrowings and Other Financing Instruments (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
Debt Disclosure [Abstract] | |
Commercial Paper | Commercial paper outstanding for Xcel Energy was as follows: (Amounts in Millions, Except Interest Rates) Three Months Ended Year Ended Borrowing limit $ 2,750 $ 2,750 Amount outstanding at period end 605 392 Average amount outstanding 557 485 Maximum amount outstanding 719 1,183 Weighted average interest rate, computed on a daily basis 0.97 % 0.74 % Weighted average interest rate at period end 1.18 0.95 |
Credit Facilities | At March 31, 2017 , Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available: (Millions of Dollars) Credit Facility (a) Drawn (b) Available Xcel Energy Inc. $ 1,000 $ 391 $ 609 PSCo 700 34 666 NSP-Minnesota 500 47 453 SPS 400 116 284 NSP-Wisconsin 150 33 117 Total $ 2,750 $ 621 $ 2,129 (a) These credit facilities mature in June 2021 . (b) Includes outstanding commercial paper and letters of credit. |
Fair Value of Financial Asset29
Fair Value of Financial Assets and Liabilities (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
Fair Value Disclosures [Abstract] | |
Cost and Fair Value of Nuclear Decommissioning Fund Investments | The following tables present the cost and fair value of Xcel Energy’s non-derivative instruments with recurring fair value measurements in the nuclear decommissioning fund at March 31, 2017 and Dec. 31, 2016 : March 31, 2017 Fair Value (Thousands of Dollars) Cost Level 1 Level 2 Level 3 Investments Measured at NAV (b) Total Nuclear decommissioning fund (a) Cash equivalents $ 24,161 $ 24,161 $ — $ — $ — $ 24,161 Commingled funds: Non U.S. equities 272,437 178,990 — — 98,876 277,866 Emerging market debt funds 94,772 — — — 101,269 101,269 Commodity funds 106,571 — — — 88,749 88,749 Private equity investments 137,176 — — — 194,912 194,912 Real estate 125,410 — — — 187,609 187,609 Other commingled funds 151,048 — — — 161,936 161,936 Debt securities: Government securities 27,369 — 27,199 — — 27,199 U.S. corporate bonds 127,841 — 128,799 — — 128,799 Non U.S. corporate bonds 25,345 — 25,556 — — 25,556 Municipal bonds 5 — 5 — — 5 Equity securities: U.S. equities 275,101 501,543 — — — 501,543 Non U.S. equities 188,763 232,851 — — — 232,851 Total $ 1,555,999 $ 937,545 $ 181,559 $ — $ 833,351 $ 1,952,455 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $131.9 million of equity investments in unconsolidated subsidiaries and $103.6 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, 2016 Fair Value (Thousands of Dollars) Cost Level 1 Level 2 Level 3 Investments Measured at NAV (b) Total Nuclear decommissioning fund (a) Cash equivalents $ 20,379 $ 20,379 $ — $ — $ — $ 20,379 Commingled funds: Non U.S. equities 260,877 133,126 — — 112,233 245,359 Emerging market debt funds 93,597 — — — 97,543 97,543 Commodity funds 106,571 — — — 92,091 92,091 Private equity investments 132,190 — — — 190,462 190,462 Real estate 128,630 — — — 187,647 187,647 Other commingled funds 151,048 — — — 159,489 159,489 Debt securities: Government securities 32,764 — 31,965 — — 31,965 U.S. corporate bonds 104,913 — 105,772 — — 105,772 Non U.S. corporate bonds 21,751 — 21,672 — — 21,672 Municipal bonds 13,609 — 13,786 — — 13,786 Mortgage-backed securities 2,785 — 2,816 — — 2,816 Equity securities: U.S. equities 270,779 473,400 — — — 473,400 Non U.S. equities 189,100 218,381 — — — 218,381 Total $ 1,528,993 $ 845,286 $ 176,011 $ — $ 839,465 $ 1,860,762 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $132.8 million of equity investments in unconsolidated subsidiaries and $98.3 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, at March 31, 2017 : Final Contractual Maturity (Thousands of Dollars) Due in 1 Year or Less Due in 1 to 5 Years Due in 5 to 10 Years Due after 10 Years Total Government securities $ — $ 1,100 $ 3,017 $ 23,082 $ 27,199 U.S. corporate bonds 354 38,741 74,617 15,087 128,799 International corporate bonds — 8,085 13,443 4,028 25,556 Municipal bonds — — 5 — 5 Debt securities $ 354 $ 47,926 $ 91,082 $ 42,197 $ 181,559 |
Rabbi Trust Securities Amortized Cost and Fair Value Measured on Recurrring Basis [Table Text Block] | In June 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 at March 31, 2017 and Dec. 31, 2016: March 31, 2017 Fair Value (Thousands of Dollars) Cost Level 1 Level 2 Level 3 Total Rabbi Trusts (a) Cash equivalents $ 9,575 $ 9,575 $ — $ — $ 9,575 Mutual funds 39,965 40,264 — — 40,264 Total $ 49,540 $ 49,839 $ — $ — $ 49,839 Dec. 31, 2016 Fair Value (Thousands of Dollars) Cost Level 1 Level 2 Level 3 Total Rabbi Trusts (a) Cash equivalents $ 47,831 $ 47,831 $ — $ — $ 47,831 Mutual funds 1,663 1,901 — — 1,901 Total $ 49,494 $ 49,732 $ — $ — $ 49,732 (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 at March 31, 2017 and Dec. 31, 2016 : (Amounts in Thousands) (a)(b) March 31, 2017 Dec. 31, 2016 Megawatt hours of electricity 31,838 46,773 Million British thermal units of natural gas 92,801 121,978 (a) Amounts are not reflective of net positions in the underlying commodities. (b) Notional amounts for options are included on a gross basis, but are weighted for the probability of exercise. |
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income | The following tables detail the impact of derivative activity during the three months ended March 31, 2017 and 2016, on accumulated other comprehensive loss, regulatory assets and liabilities, and income: Three Months Ended March 31, 2017 Pre-Tax Fair Value Gains (Losses) Recognized During the Period in: Pre-Tax (Gains) Losses Reclassified into Income During the Period from: Pre-Tax Gains (Losses) Recognized (Thousands of Dollars) Accumulated Other Regulatory Accumulated Other Regulatory Assets and (Liabilities) Derivatives designated as cash flow hedges Interest rate $ — $ — $ 1,359 (a) $ — $ — Total $ — $ — $ 1,359 $ — $ — Other derivative instruments Commodity trading $ — $ — $ — $ — $ 1,001 (c) Electric commodity — 794 — (3,998 ) (d) — Natural gas commodity — (6,161 ) — 1,075 (e) (4,070 ) (e) Total $ — $ (5,367 ) $ — $ (2,923 ) $ (3,069 ) Three Months Ended March 31, 2016 Pre-Tax Fair Value Losses Recognized During the Period in: Pre-Tax Losses Reclassified into Income During the Period from: Pre-Tax Gains (Losses) Recognized (Thousands of Dollars) Accumulated Other Regulatory Accumulated Other Regulatory Derivatives designated as cash flow hedges Interest rate $ — $ — $ 1,485 (a) $ — $ — Vehicle fuel and other commodity (6 ) — 57 (b) — — Total $ (6 ) $ — $ 1,542 $ — $ — Other derivative instruments Commodity trading $ — $ — $ — $ — $ 1,009 (c) Electric commodity — (265 ) — 8,631 (d) — Natural gas commodity — (2,702 ) — 11,666 (e) (5,024 ) (e) Total $ — $ (2,967 ) $ — $ 20,297 $ (4,015 ) (a) Amounts are recorded to interest charges. (b) Amounts are recorded to O&M expenses. (c) Amounts are recorded to electric operating revenues. Portions of these gains and losses are subject to sharing with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate. (d) Amounts are recorded to electric fuel and purchased power. These derivative settlement gain and loss amounts are shared with electric customers through fuel and purchased energy cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate. (e) Amounts for the three months ended March 31, 2017 included $0.9 million of settlement gains and an immaterial amount of settlement losses for the three months ended March 31, 2016 on derivatives entered to mitigate natural gas price risk for electric generation, recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate. The remaining derivative settlement gains and losses for the three months ended March 31, 2017 and 2016 relate to natural gas operations and are recorded to cost of natural gas sold and transported. These gains and losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset or liability, as appropriate. |
Derivative Assets and Liabilities Measured at Fair Value on a Recurring Basis by Hierarchy Level | Recurring Fair Value Measurements — The following table presents for each of the fair value hierarchy levels, Xcel Energy’s derivative assets and liabilities measured at fair value on a recurring basis at March 31, 2017 : March 31, 2017 Fair Value Fair Value Total Counterparty Netting (b) Total (Thousands of Dollars) Level 1 Level 2 Level 3 Current derivative assets Other derivative instruments: Commodity trading $ 4,706 $ 14,850 $ — $ 19,556 $ (12,126 ) $ 7,430 Electric commodity — — 8,443 8,443 (1,814 ) 6,629 Natural gas commodity — 1,334 — 1,334 — 1,334 Total current derivative assets $ 4,706 $ 16,184 $ 8,443 $ 29,333 $ (13,940 ) 15,393 PPAs (a) 5,492 Current derivative instruments $ 20,885 Noncurrent derivative assets Other derivative instruments: Commodity trading $ 198 $ 32,272 $ — $ 32,470 $ (7,295 ) $ 25,175 Total noncurrent derivative assets $ 198 $ 32,272 $ — $ 32,470 $ (7,295 ) 25,175 PPAs (a) 23,506 Noncurrent derivative instruments $ 48,681 March 31, 2017 Fair Value Fair Value Total Counterparty Netting (b) Total (Thousands of Dollars) Level 1 Level 2 Level 3 Current derivative liabilities Other derivative instruments: Commodity trading $ 5,224 $ 12,064 $ — $ 17,288 $ (13,416 ) $ 3,872 Electric commodity — — 1,814 1,814 (1,814 ) — Total current derivative liabilities $ 5,224 $ 12,064 $ 1,814 $ 19,102 $ (15,230 ) 3,872 PPAs (a) 22,834 Current derivative instruments $ 26,706 Noncurrent derivative liabilities Other derivative instruments: Commodity trading $ 204 $ 23,435 $ 793 $ 24,432 $ (10,463 ) $ 13,969 Total noncurrent derivative liabilities $ 204 $ 23,435 $ 793 $ 24,432 $ (10,463 ) 13,969 PPAs (a) 129,715 Noncurrent derivative instruments $ 143,684 (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 will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities. (b) Xcel Energy nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at March 31, 2017 . At March 31, 2017 , derivative assets and liabilities include no obligations to return cash collateral and the rights to reclaim cash collateral of $4.5 million . The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements. The following table presents for each of the fair value hierarchy levels, Xcel Energy’s derivative assets and liabilities measured at fair value on a recurring basis at Dec. 31, 2016 : Dec. 31, 2016 Fair Value Fair Value Total Counterparty Netting (b) Total (Thousands of Dollars) Level 1 Level 2 Level 3 Current derivative assets Other derivative instruments: Commodity trading $ 13,179 $ 14,105 $ — $ 27,284 $ (20,637 ) $ 6,647 Electric commodity — — 19,251 19,251 (1,976 ) 17,275 Natural gas commodity — 8,839 — 8,839 — 8,839 Total current derivative assets $ 13,179 $ 22,944 $ 19,251 $ 55,374 $ (22,613 ) 32,761 PPAs (a) 5,463 Current derivative instruments $ 38,224 Noncurrent derivative assets Other derivative instruments: Commodity trading $ 100 $ 31,029 $ — $ 31,129 $ (7,323 ) $ 23,806 Natural gas commodity — 1,652 — 1,652 — 1,652 Total noncurrent derivative assets $ 100 $ 32,681 $ — $ 32,781 $ (7,323 ) 25,458 PPAs (a) 24,731 Noncurrent derivative instruments $ 50,189 Dec. 31, 2016 Fair Value Fair Value Total Counterparty Netting (b) Total (Thousands of Dollars) Level 1 Level 2 Level 3 Current derivative liabilities Other derivative instruments: Commodity trading $ 13,787 $ 11,320 $ 22 $ 25,129 $ (20,974 ) $ 4,155 Electric commodity — — 1,976 1,976 (1,976 ) — Total current derivative liabilities $ 13,787 $ 11,320 $ 1,998 $ 27,105 $ (22,950 ) 4,155 PPAs (a) 22,804 Current derivative instruments $ 26,959 Noncurrent derivative liabilities Other derivative instruments: Commodity trading $ 89 $ 23,424 $ — $ 23,513 $ (10,727 ) $ 12,786 Total noncurrent derivative liabilities $ 89 $ 23,424 $ — $ 23,513 $ (10,727 ) 12,786 PPAs (a) 135,360 Noncurrent derivative instruments $ 148,146 (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 will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities. (b) Xcel Energy nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2016 . At Dec. 31, 2016 , derivative assets and liabilities include no obligations to return cash collateral and rights to reclaim cash collateral of $3.7 million . The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements. |
Changes in Level 3 Commodity Derivatives | The following table presents the changes in Level 3 commodity derivatives for the three months ended March 31, 2017 and 2016 : Three Months Ended March 31 (Thousands of Dollars) 2017 2016 Balance at Jan. 1 $ 17,253 $ 18,028 Purchases 3,792 1,843 Settlements (19,802 ) (18,256 ) Net transactions recorded during the period: Losses recognized in earnings (a) (794 ) (24 ) Net gains recognized as regulatory assets and liabilities 5,387 5,263 Balance at March 31 $ 5,836 $ 6,854 (a) These amounts relate to commodity derivatives held at the end of the period. |
Carrying Amount and Fair Value of Long-term Debt | As of March 31, 2017 and Dec. 31, 2016 , other financial instruments for which the carrying amount did not equal fair value were as follows: March 31, 2017 Dec. 31, 2016 (Thousands of Dollars) Carrying Amount Fair Value Carrying Amount Fair Value Long-term debt, including current portion $ 14,451,909 $ 15,492,978 $ 14,450,247 $ 15,513,209 |
Other Income, Net (Tables)
Other Income, Net (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
Other Income and Expenses [Abstract] | |
Other Income, Net | Other income, net consisted of the following: Three Months Ended March 31 (Thousands of Dollars) 2017 2016 Interest income $ 3,800 $ 4,070 Other nonoperating income 3,645 680 Insurance policy expense (999 ) (500 ) Other income, net $ 6,446 $ 4,250 |
Segment Information (Tables)
Segment Information (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
Segment Reporting [Abstract] | |
Results from Operations by Reportable Segment | (Thousands of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total Three Months Ended March 31, 2017 Operating revenues from external customers $ 2,299,060 $ 625,703 $ 21,659 $ — $ 2,946,422 Intersegment revenues 297 264 — (561 ) — Total revenues $ 2,299,357 $ 625,967 $ 21,659 $ (561 ) $ 2,946,422 Net income (loss) $ 194,153 $ 62,927 $ (17,803 ) $ — $ 239,277 (Thousands of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total Three Months Ended March 31, 2016 Operating revenues from external customers $ 2,185,119 $ 565,689 $ 21,465 $ — $ 2,772,273 Intersegment revenues 335 287 — (622 ) — Total revenues $ 2,185,454 $ 565,976 $ 21,465 $ (622 ) $ 2,772,273 Net income (loss) $ 178,237 $ 78,338 $ (15,263 ) $ — $ 241,312 |
Earnings Per Share (Tables)
Earnings Per Share (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
Earnings Per Share [Abstract] | |
Dilutive Impact of Common Stock Equivalents | The dilutive impact of common stock equivalents affecting EPS was as follows: Three Months Ended March 31, 2017 Three Months Ended March 31, 2016 (Amounts in thousands, except per share data) Income Shares Per Share Amount Income Shares Per Share Amount Net income $ 239,277 — — $ 241,312 — — Basic EPS: Earnings available to common shareholders 239,277 508,278 $ 0.47 241,312 508,667 $ 0.47 Effect of dilutive securities: Time based equity awards — 496 — — 483 — Diluted EPS: Earnings available to common shareholders $ 239,277 508,774 $ 0.47 $ 241,312 509,150 $ 0.47 |
Benefit Plans and Other Postr33
Benefit Plans and Other Postretirement Benefits (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
Compensation and Retirement Disclosure [Abstract] | |
Components of Net Periodic Benefit Cost (Credit) | Components of Net Periodic Benefit Cost (Credit) Three Months Ended March 31 2017 2016 2017 2016 (Thousands of Dollars) Pension Benefits Postretirement Health Service cost $ 23,547 $ 22,920 $ 465 $ 432 Interest cost 36,702 40,023 5,984 6,527 Expected return on plan assets (52,317 ) (52,575 ) (6,156 ) (6,249 ) Amortization of prior service credit (442 ) (484 ) (2,671 ) (2,672 ) Amortization of net loss 26,670 24,385 1,672 1,011 Net periodic benefit cost (credit) 34,160 34,269 (706 ) (951 ) Costs not recognized due to the effects of regulation (4,015 ) (4,452 ) — — Net benefit cost (credit) recognized for financial reporting $ 30,145 $ 29,817 $ (706 ) $ (951 ) |
Other Comprehensive Income (Tab
Other Comprehensive Income (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
Stockholders' Equity Note [Abstract] | |
Changes in Accumulated Other Comprehensive Income (Loss), Net of Tax | Changes in accumulated other comprehensive (loss) income, net of tax, for the three months ended March 31, 2017 and 2016 were as follows: Three Months Ended March 31, 2017 (Thousands of Dollars) Gains and Losses on Cash Flow Hedges Unrealized Gains and Losses on Marketable Securities Defined Benefit Pension and Postretirement Items Total Accumulated other comprehensive (loss) income at Jan. 1 $ (51,151 ) $ 110 $ (59,313 ) $ (110,354 ) Losses reclassified from net accumulated other comprehensive loss 825 — 948 1,773 Net current period other comprehensive income 825 — 948 1,773 Accumulated other comprehensive (loss) income at March 31 $ (50,326 ) $ 110 $ (58,365 ) $ (108,581 ) Three Months Ended March 31, 2016 (Thousands of Dollars) Gains and Losses on Cash Flow Hedges Unrealized Gains and Losses on Marketable Securities Defined Benefit Pension and Postretirement Items Total Accumulated other comprehensive (loss) income at Jan. 1 $ (54,862 ) $ 110 $ (55,001 ) $ (109,753 ) Other comprehensive loss before reclassifications (4 ) — (653 ) (657 ) Losses reclassified from net accumulated other comprehensive loss 938 — 864 1,802 Net current period other comprehensive income 934 — 211 1,145 Accumulated other comprehensive (loss) income at March 31 $ (53,928 ) $ 110 $ (54,790 ) $ (108,608 ) |
Reclassifications out of Accumulated Other Comprehensive Loss | Reclassifications from accumulated other comprehensive loss for the three months ended March 31, 2017 and 2016 were as follows: Amounts Reclassified from Accumulated Other Comprehensive Loss (Thousands of Dollars) Three Months Ended March 31, 2017 Three Months Ended March 31, 2016 Losses on cash flow hedges: Interest rate derivatives $ 1,359 (a) $ 1,485 (a) Vehicle fuel derivatives — (b) 57 (b) Total, pre-tax 1,359 1,542 Tax benefit (534 ) (604 ) Total, net of tax 825 938 Defined benefit pension and postretirement losses: Amortization of net loss 1,623 (c) 1,478 (c) Prior service credit (60 ) (c) (64 ) (c) Total, pre-tax 1,563 1,414 Tax benefit (615 ) (550 ) Total, net of tax 948 864 Total amounts reclassified, net of tax $ 1,773 $ 1,802 (a) Included in interest charges. (b) Included in O&M expenses. (c) Included in the computation of net periodic pension and postretirement benefit costs. See Note 12 for details regarding these benefit plans. |
Balance Sheet Data, Accounts Re
Balance Sheet Data, Accounts Receivable (Details) - USD ($) $ in Thousands | Mar. 31, 2017 | Dec. 31, 2016 |
Accounts receivable, net | ||
Accounts receivable | $ 832,540 | $ 827,112 |
Less allowance for bad debts | (51,292) | (50,823) |
Accounts receivable, net | $ 781,248 | $ 776,289 |
Balance Sheet Related Disclosur
Balance Sheet Related Disclosures, Inventories (Details) - USD ($) $ in Thousands | Mar. 31, 2017 | Dec. 31, 2016 |
Public Utilities, Inventory [Line Items] | ||
Inventories | $ 519,081 | $ 604,226 |
Materials and supplies | ||
Public Utilities, Inventory [Line Items] | ||
Inventories | 321,518 | 312,430 |
Fuel | ||
Public Utilities, Inventory [Line Items] | ||
Inventories | 150,025 | 181,752 |
Natural gas | ||
Public Utilities, Inventory [Line Items] | ||
Inventories | $ 47,538 | $ 110,044 |
Balance Sheet Related Disclos37
Balance Sheet Related Disclosures, Property, Plant and Equipment (Details) - USD ($) $ in Thousands | Mar. 31, 2017 | Dec. 31, 2016 | |
Public Utility, Property, Plant and Equipment [Line Items] | |||
Property, plant and equipment, gross | $ 47,294,166 | $ 46,832,219 | |
Less accumulated depreciation | (14,576,320) | (14,381,603) | |
Property, plant and equipment, net | 33,158,384 | 32,841,750 | |
Electric plant | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Property, plant and equipment, gross | 38,412,137 | 38,220,765 | |
Natural gas plant | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Property, plant and equipment, gross | 5,365,655 | 5,317,717 | |
Common and other property | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Property, plant and equipment, gross | 1,897,263 | 1,888,518 | |
Plant to be retired | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Property, plant and equipment, gross | [1] | 22,202 | 31,839 |
Construction work in progress | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Property, plant and equipment, gross | 1,596,909 | 1,373,380 | |
Nuclear fuel | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Property, plant and equipment, gross | 2,652,026 | 2,571,770 | |
Less accumulated depreciation | $ (2,211,488) | $ (2,180,636) | |
[1] | In the fourth quarter of 2017, PSCo expects to both early retire Valmont Unit 5 and convert 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 ($) | 1 Months Ended | 3 Months Ended | 12 Months Ended | |||||||
Aug. 31, 2016 | Jun. 30, 2016 | Feb. 29, 2016 | Mar. 31, 2017 | Sep. 30, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Income Tax Examination [Line Items] | ||||||||||
Number Of Years Of Tax Loss Carryback Period | 2 years | |||||||||
Tax Adjustments, Settlements, and Unusual Provisions | $ 5,000,000 | $ 17,000,000 | $ 12,000,000 | $ 15,000,000 | ||||||
Unrecognized Tax Benefits, Interest on Income Taxes Accrued | $ (4,300,000) | $ (3,400,000) | $ (100,000) | |||||||
Interest Expense (Income) related to unrecognized tax benefits | (900,000) | (3,300,000) | ||||||||
Unrecognized Tax Benefits [Abstract] | ||||||||||
Unrecognized tax benefit — Permanent tax positions | 30,100,000 | 29,600,000 | ||||||||
Unrecognized tax benefit — Temporary tax positions | 105,300,000 | 104,100,000 | ||||||||
Total unrecognized tax benefit | 135,400,000 | 133,700,000 | ||||||||
NOL and tax credit carryforwards | (45,600,000) | (43,800,000) | ||||||||
Upper bound of decrease in unrecognized tax benefit that is reasonably possible | 60,000,000 | |||||||||
Amounts accrued for penalties related to unrecognized tax benefits | 0 | $ 0 | ||||||||
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 | |||||||||
Potential Tax Adjustments | $ 14,000,000 | |||||||||
Earliest year subject to 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] | ||||||||||
Year(s) under examination | 2009 and 2010 | |||||||||
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) - NSP-Minnesota - USD ($) $ in Thousands | 1 Months Ended | 3 Months Ended | ||||||
Sep. 30, 2016 | Aug. 31, 2016 | Jun. 30, 2016 | Dec. 31, 2015 | Nov. 30, 2015 | Feb. 28, 2015 | Nov. 30, 2013 | Mar. 31, 2017 | |
MPUC Proceeding - Minnesota 2016 Multi-Year Electric Rate Case | ||||||||
Rate Matters [Abstract] | ||||||||
Public Utilities, Number Of Years Rate Case Is Applicable For | 3 years | |||||||
Public Utilities, Requested Return on Equity, Percentage | 10.00% | |||||||
Public Utilities, Requested Equity Capital Structure, Percentage | 52.50% | |||||||
MPUC Proceeding - Minnesota 2016 Multi-Year Electric Rate Case, Rates 2016 | ||||||||
Rate Matters [Abstract] | ||||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 194,600 | |||||||
Public Utilities, Requested Rate Increase (Decrease), Percentage | 6.40% | |||||||
Public Utilities, Requested Rate Base, Amount | $ 7,800,000 | |||||||
MPUC Proceeding - Minnesota 2016 Multi-Year Electric Rate Case, Rates 2017 | ||||||||
Rate Matters [Abstract] | ||||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 52,100 | |||||||
Public Utilities, Requested Rate Increase (Decrease), Percentage | 1.70% | |||||||
Public Utilities, Requested Interim Rate Increase (Decrease), Amount | $ 44,900 | |||||||
Public Utilities, Requested Rate Base, Amount | 7,700,000 | |||||||
MPUC Proceeding - Minnesota 2016 Multi-Year Electric Rate Case, Rates 2018 | ||||||||
Rate Matters [Abstract] | ||||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 50,400 | |||||||
Public Utilities, Requested Rate Increase (Decrease), Percentage | 1.70% | |||||||
Public Utilities, Requested Rate Base, Amount | $ 7,700,000 | |||||||
FERC Proceeding, MISO ROE Complaint [Member] | ||||||||
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% | ||||||
Public Utilities, Maximum Equity Capital Structure Percentage Allowed Per The Complaint | 50.00% | |||||||
Minnesota Public Utilities Commission | MPUC Proceeding - Minnesota 2016 Multi-Year Electric Rate Case, Rates 2016 | ||||||||
Rate Matters [Abstract] | ||||||||
Public Utilities, Approved Interim Rate Increase (Decrease), Amount | $ 163,700 | |||||||
Settlement Group | MPUC Proceeding - Minnesota 2016 Multi-Year Electric Rate Case | ||||||||
Rate Matters [Abstract] | ||||||||
Public Utilities, Number Of Years Rate Case Is Applicable For | 4 years | |||||||
Public Utilities, Requested Return on Equity, Percentage | 9.20% | |||||||
Public Utilities, Requested Equity Capital Structure, Percentage | 52.50% | |||||||
Public Utilities, Length of Stay-out Provision, In Years | 4 years | |||||||
Public Utilities, Rate Increase Under the Settlement | $ 184,970 | |||||||
Public Utilities, Increase (Decrease) Related to Sales True-up | 59,750 | |||||||
Public Utilities, Rate Impact | 244,720 | |||||||
Settlement Group | MPUC Proceeding - Minnesota 2016 Multi-Year Electric Rate Case, Rates 2016 | ||||||||
Rate Matters [Abstract] | ||||||||
Public Utilities, Rate Increase Under the Settlement | 74,990 | |||||||
Public Utilities, Increase (Decrease) Related to Sales True-up | 59,950 | |||||||
Public Utilities, Rate Impact | 134,940 | |||||||
Settlement Group | MPUC Proceeding - Minnesota 2016 Multi-Year Electric Rate Case, Rates 2017 | ||||||||
Rate Matters [Abstract] | ||||||||
Public Utilities, Rate Increase Under the Settlement | 59,860 | |||||||
Public Utilities, Increase (Decrease) Related to Sales True-up | 0 | |||||||
Public Utilities, Rate Impact | 59,860 | |||||||
Settlement Group | MPUC Proceeding - Minnesota 2016 Multi-Year Electric Rate Case, Rates 2018 | ||||||||
Rate Matters [Abstract] | ||||||||
Public Utilities, Rate Increase Under the Settlement | 0 | |||||||
Public Utilities, Increase (Decrease) Related to Sales True-up | 0 | |||||||
Public Utilities, Rate Impact | 0 | |||||||
Settlement Group | MPUC Proceeding - Minnesota 2016 Multi-Year Electric Rate Case, Rates 2019 | ||||||||
Rate Matters [Abstract] | ||||||||
Public Utilities, Rate Increase Under the Settlement | 50,120 | |||||||
Public Utilities, Increase (Decrease) Related to Sales True-up | (200) | |||||||
Public Utilities, Rate Impact | $ 49,920 | |||||||
Administrative Law Judge | FERC Proceeding, MISO ROE Complaint [Member] | ||||||||
Rate Matters [Abstract] | ||||||||
Public Utilities, ROE Applicable To Transmission Formula Rates In The MISO Region, Recommended By Third Parties | 9.70% | |||||||
MPUC, NDPSC, SDPUC, and DOC | FERC Proceeding, MISO ROE Complaint [Member] | ||||||||
Rate Matters [Abstract] | ||||||||
Public Utilities, ROE Applicable To Transmission Formula Rates In The MISO Region, Recommended By Third Parties | 8.81% | |||||||
MISO TOs | FERC Proceeding, MISO ROE Complaint [Member] | ||||||||
Rate Matters [Abstract] | ||||||||
Public Utilities, ROE Applicable To Transmission Formula Rates In The MISO Region, Recommended By Third Parties | 10.92% | |||||||
FERC Staff | FERC Proceeding, MISO ROE Complaint [Member] | ||||||||
Rate Matters [Abstract] | ||||||||
Public Utilities, ROE Applicable To Transmission Formula Rates In The MISO Region, Recommended By Third Parties | 8.78% | |||||||
Federal Energy Regulatory Commission (FERC) | FERC Proceeding, MISO ROE Complaint [Member] | ||||||||
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 Basis Point Adder, Approved | 50 | |||||||
Public Utilities, ROE Applicable To Transmission Formula Rates In The MISO Region, with RTO Adder, Approved | 10.82% |
Rate Matters Rate Matters - PSC
Rate Matters Rate Matters - PSCo (Details) | 3 Months Ended |
Mar. 31, 2017 | |
PSCo | CPUC Proceeding - Annual Electric Earnings Test 2015 through 2017 | |
Public Utilities, General Disclosures [Line Items] | |
Public Utilities, Return on equity threshold for earnings sharing | 9.83% |
Rate Matters, SPS (Details)
Rate Matters, SPS (Details) - SPS $ in Millions | 1 Months Ended | 12 Months Ended | ||||||
Apr. 30, 2017USD ($) | Feb. 28, 2017USD ($) | Dec. 31, 2016USD ($) | Nov. 30, 2016USD ($)MW | Sep. 30, 2016USD ($) | Feb. 29, 2016USD ($) | Jun. 30, 2015USD ($) | Dec. 31, 2015USD ($) | |
PUCT Proceeding - Appeal of the Texas 2015 Electric Rate Case Decision | ||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||
Public Utilities, Revised Requested Rate Increase | $ 42.1 | |||||||
PUCT Proceeding - Texas 2016 Electric Rate Case | ||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||
Public Utilities, Revised Requested Rate Increase | $ 61.5 | |||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 71.9 | |||||||
Public Utilities, Requested Rate Increase (Decrease), Percentage | 14.40% | |||||||
Public Utilities, Requested Return on Equity, Percentage | 10.25% | |||||||
Public Utilities, Requested Rate Base, Amount | $ 1,700 | |||||||
Public Utilities, Requested Equity Capital Structure, Percentage | 53.97% | |||||||
Public Utilities, Revised requested rate increase, including rate case expenses | $ 65.5 | |||||||
Public Utilities, Total Estimated Impact of Stipulation | $ 51.8 | |||||||
Texas 2016 TCRF Application [Member] | ||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 16.1 | |||||||
Public Utilities, Requested Rate Increase (Decrease), Percentage | 1.80% | |||||||
NMPRC Proceeding - New Mexico 2016 Electric Rate Case | ||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 41.4 | |||||||
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% | |||||||
Public Utilities, Future Decline in MW Sales from Certain Wholesale Customers included in Rate Case | MW | 380 | |||||||
Public Utilities, Capital Expenditures | $ 20.1 | |||||||
Public Utilities, Changes in Allocator, Including Wholesale Load Reductions | 11.5 | |||||||
Public Utilities, Transmission Expenses | 4.7 | |||||||
Public Utilities, Depreciation, Including Adjustment of Tolk Service Life | 3.6 | |||||||
Public Utilities, Rate Case Expenses | 1.1 | |||||||
Public Utilities, Other net | 0.4 | |||||||
SPP Open Access Transmission Tariff Upgrade Costs | ||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||
Public Utilities, Billed Charges For Transmission Service Upgrades | $ 12.8 | |||||||
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 | |||||||
Southwest Power Pool (SPP) | SPP Open Access Transmission Tariff Upgrade Costs | ||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||
Public Utilities, Length of Payment Period Requested, In Years | 5 years | |||||||
Subsequent Event [Member] | PUCT Proceeding - Texas 2016 Electric Rate Case | ||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||
Public Utilities, Mechanism Ensuring Recovery of Revenue Using Final Rates | $ 13.8 |
Commitments and Contingencies,
Commitments and Contingencies, Purchased Power Agreements (Details) - Independent Power Producing Entities | 9 Months Ended |
Sep. 30, 2016MW | |
Purchased Power Agreements [Abstract] | |
Generating capacity under long term purchased power agreements (in MW) | 3,537 |
Purchase Power Agreement Expiration (Year) | 2,041 |
Commitments and Contingencies43
Commitments and Contingencies, Guarantees and Indemnifications (Details) - USD ($) | Mar. 31, 2017 | Dec. 31, 2016 |
Guarantees [Abstract] | ||
Assets held as collateral | $ 0 | $ 0 |
Payment or Performance Guarantee | ||
Guarantees [Abstract] | ||
Guarantees issued and outstanding | 18,600,000 | 18,800,000 |
Current exposure under these guarantees | 100,000 | 100,000 |
Payment or Performance Guarantee | Surety Bonds | ||
Guarantees [Abstract] | ||
Guarantees issued and outstanding | $ 43,600,000 | $ 43,000,000 |
Commitments and Contingencies44
Commitments and Contingencies, Environmental Contingencies - Site Contingencies (Details) $ in Millions | 3 Months Ended | 12 Months Ended |
Mar. 31, 2017USD ($)Site | Dec. 31, 2016USD ($) | |
Other MGP Sites [Member] | ||
Manufactured Gas Plant (MGP) Site [Abstract] | ||
Accrual for Environmental Loss Contingencies, Gross | $ 2.9 | $ 2 |
Number of identified MGP sites under current investigation and/or remediation | 9 | |
NSP-Wisconsin | Ashland MGP Site | ||
Manufactured Gas Plant (MGP) Site [Abstract] | ||
Number of properties not owned included in superfund site | Site | 2 | |
Accrual for Environmental Loss Contingencies, Gross | $ 62.1 | 64.3 |
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-Wisconsin | Ashland MGP Site - Phase I Project Area | ||
Manufactured Gas Plant (MGP) Site [Abstract] | ||
Accrual for Environmental Loss Contingencies, Gross | $ 77.2 | |
Estimated amount spent on cleanup | 57.2 | |
NSP-Minnesota | Fargo MGP Site | ||
Manufactured Gas Plant (MGP) Site [Abstract] | ||
Accrual for Environmental Loss Contingencies, Gross | $ 11.1 | 11.3 |
Percentage of Response Costs Allocable to the Minnesota Jurisdiction | 12.00% | |
PSCW Proceeding - Electric and Gas Rate Case 2016 - Gas Rates 2016 | NSP-Wisconsin | Ashland MGP Site | ||
Manufactured Gas Plant (MGP) Site [Abstract] | ||
Public Utilities, Approved annual recovery collected through base rates | 7.6 | |
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 | $ 12.4 |
Commitments and Contingencies45
Commitments and Contingencies, Environmental Contingencies - Unrecorded Unconditional Purchase Obligation (Details) $ in Millions | 3 Months Ended |
Mar. 31, 2017USD ($) | |
Regional Haze Rules | |
Environmental Requirements [Abstract] | |
Length of Time States Are Required to Revise Plans (in Years) | 10 years |
Capital Commitments | NSP Minnesota | Federal Clean Water Act Effluent Limitations Guidelines [Member] | |
Environmental Requirements [Abstract] | |
Liability for Estimated Cost to Comply with Regulation | $ 10 |
Minimum | Capital Commitments | Federal Clean Water Act Effluent Limitations Guidelines [Member] | |
Environmental Requirements [Abstract] | |
Liability for Estimated Cost to Comply with Regulation | 21 |
Maximum | Capital Commitments | Federal Clean Water Act Effluent Limitations Guidelines [Member] | |
Environmental Requirements [Abstract] | |
Liability for Estimated Cost to Comply with Regulation | 32 |
Harrington Units 1 and 2 [Member] | Capital Commitments | SPS | Regional Haze Rules | |
Environmental Requirements [Abstract] | |
Liability for Estimated Cost to Comply with Regulation | 400 |
Tolk Units 1 and 2 [Member] | Capital Commitments | SPS | Regional Haze Rules | |
Environmental Requirements [Abstract] | |
Liability for Estimated Cost to Comply with Regulation | $ 600 |
Commitments and Contingencies46
Commitments and Contingencies, Legal Contingencies (Details) | 1 Months Ended | 3 Months Ended | |
Dec. 31, 2015 | Mar. 31, 2017 | Dec. 31, 2009 | |
Gas Trading Litigation | |||
Legal Contingencies [Abstract] | |||
Loss Contingency, Pending Claims, Number | 1 | 13 | |
Loss Contingency, Claims Settled, Number | 5 | ||
Loss Contingency, Claims Dismissed, Number | 7 | ||
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 | ||
PSCo | Line Extension Disputes | |||
Legal Contingencies [Abstract] | |||
Loss Contingency, Number of Plaintiffs | 2 | ||
Minimum | PSCo | Line Extension Disputes | |||
Legal Contingencies [Abstract] | |||
Loss Contingency, Number of Plaintiffs | 50 |
Borrowings and Other Financin47
Borrowings and Other Financing Instruments, Commercial Paper (Details) - USD ($) | 3 Months Ended | 12 Months Ended |
Mar. 31, 2017 | Dec. 31, 2016 | |
Short-term Debt [Line Items] | ||
Amount outstanding at period end | $ 605,000,000 | $ 392,000,000 |
Commercial Paper | ||
Short-term Debt [Line Items] | ||
Borrowing limit | 2,750,000,000 | 2,750,000,000 |
Amount outstanding at period end | 605,000,000 | 392,000,000 |
Average amount outstanding | 557,000,000 | 485,000,000 |
Maximum amount outstanding | $ 719,000,000 | $ 1,183,000,000 |
Weighted average interest rate, computed on a daily basis (percentage) | 0.97% | 0.74% |
Weighted average interest rate at period end (percentage) | 1.18% | 0.95% |
Borrowings and Other Financin48
Borrowings and Other Financing Instruments, Letters of Credit (Details) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2017 | Dec. 31, 2016 | |
Line of Credit Facility [Line Items] | ||
Amount outstanding at period end | $ 605,000 | $ 392,000 |
Letter of Credit | ||
Line of Credit Facility [Line Items] | ||
Amount outstanding at period end | $ 16,000 | $ 19,000 |
Letter of Credit | Letter of Credit | ||
Line of Credit Facility [Line Items] | ||
Term of letters of credit (in years) | 1 year |
Borrowings and Other Financin49
Borrowings and Other Financing Instruments, Credit Facilities (Details) - Credit Facilities - USD ($) | 3 Months Ended | ||
Mar. 31, 2017 | Dec. 31, 2016 | ||
Line of Credit Facility [Line Items] | |||
Credit Facility | [1] | $ 2,750,000,000 | |
Drawn | [2] | 621,000,000 | |
Available | 2,129,000,000 | ||
Direct advances on the credit facility outstanding | $ 0 | $ 0 | |
Xcel Energy Inc. | |||
Line of Credit Facility [Line Items] | |||
Maturity Date | Jun. 30, 2021 | ||
Credit Facility | [1] | $ 1,000,000,000 | |
Drawn | [2] | 391,000,000 | |
Available | 609,000,000 | ||
PSCo | |||
Line of Credit Facility [Line Items] | |||
Credit Facility | [1] | 700,000,000 | |
Drawn | [2] | 34,000,000 | |
Available | 666,000,000 | ||
NSP-Minnesota | |||
Line of Credit Facility [Line Items] | |||
Credit Facility | [1] | 500,000,000 | |
Drawn | [2] | 47,000,000 | |
Available | 453,000,000 | ||
SPS | |||
Line of Credit Facility [Line Items] | |||
Credit Facility | [1] | 400,000,000 | |
Drawn | [2] | 116,000,000 | |
Available | 284,000,000 | ||
NSP-Wisconsin | |||
Line of Credit Facility [Line Items] | |||
Credit Facility | [1] | 150,000,000 | |
Drawn | [2] | 33,000,000 | |
Available | $ 117,000,000 | ||
[1] | These credit facilities mature in June 2021. | ||
[2] | Includes outstanding commercial paper and letters of credit. |
Fair Value of Financial Asset50
Fair Value of Financial Assets and Liabilities (Details) | 9 Months Ended |
Sep. 30, 2016 | |
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 Asset51
Fair Value of Financial Assets and Liabilities, Cost and Fair Value of Nuclear Decommissioning Fund (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||
Mar. 31, 2017 | Dec. 31, 2016 | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Available-for-sale Securities, Gross Unrealized Gain | $ 428,200 | $ 378,600 | |||
Available-for-sale Securities, Gross Unrealized Loss | 31,700 | 46,900 | |||
Investments [Abstract] | |||||
Equity investments in unconsolidated subsidiaries | 131,900 | 132,800 | |||
Miscellaneous investments | 103,600 | 98,300 | |||
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 | 24,161 | [1] | 20,379 | [2] | |
Available-for-sale Securities [Abstract] | |||||
Available-for-sale Securities | 1,555,999 | [1] | 1,528,993 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Non U.S. equities | |||||
Available-for-sale Securities [Abstract] | |||||
Available-for-sale Securities | 272,437 | [1] | 260,877 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Emerging market debt funds | |||||
Available-for-sale Securities [Abstract] | |||||
Available-for-sale Securities | 94,772 | [1] | 93,597 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Commodity funds | |||||
Available-for-sale Securities [Abstract] | |||||
Available-for-sale Securities | 106,571 | [1] | 106,571 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Private equity investments | |||||
Available-for-sale Securities [Abstract] | |||||
Available-for-sale Securities | 137,176 | [1] | 132,190 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Real estate | |||||
Available-for-sale Securities [Abstract] | |||||
Available-for-sale Securities | 125,410 | [1] | 128,630 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Other commingled funds | |||||
Available-for-sale Securities [Abstract] | |||||
Available-for-sale Securities | 151,048 | [1] | 151,048 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Government securities | |||||
Available-for-sale Securities [Abstract] | |||||
Available-for-sale Securities, Debt Securities | 27,369 | [1] | 32,764 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | U.S. corporate bonds | |||||
Available-for-sale Securities [Abstract] | |||||
Available-for-sale Securities, Debt Securities | 127,841 | [1] | 104,913 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Non U.S. corporate bonds | |||||
Available-for-sale Securities [Abstract] | |||||
Available-for-sale Securities, Debt Securities | 25,345 | [1] | 21,751 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Municipal bonds | |||||
Available-for-sale Securities [Abstract] | |||||
Available-for-sale Securities, Debt Securities | 5 | [1] | 13,609 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Mortgage-backed securities | |||||
Available-for-sale Securities [Abstract] | |||||
Available-for-sale Securities, Debt Securities | [2] | 2,785 | |||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | U.S. equities | |||||
Available-for-sale Securities [Abstract] | |||||
Available-for-sale Securities, Equity Securities | 275,101 | [1] | 270,779 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Non U.S. equities | |||||
Available-for-sale Securities [Abstract] | |||||
Available-for-sale Securities, Equity Securities | 188,763 | [1] | 189,100 | [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 | 24,161 | [1] | 20,379 | [2] | |
Alternative Investments, Fair Value Disclosure | 833,351 | [1],[3] | 839,465 | [2],[4] | |
Available-for-sale Securities [Abstract] | |||||
Available-for-sale Securities | 1,952,455 | [1] | 1,860,762 | [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 Investments, 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 Investments, Fair Value Disclosure | 98,876 | [1],[3] | 112,233 | [2],[4] | |
Available-for-sale Securities [Abstract] | |||||
Available-for-sale Securities | 277,866 | [1] | 245,359 | [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 Investments, Fair Value Disclosure | 101,269 | [1],[3] | 97,543 | [2],[4] | |
Available-for-sale Securities [Abstract] | |||||
Available-for-sale Securities | 101,269 | [1] | 97,543 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Commodity funds | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Alternative Investments, Fair Value Disclosure | 88,749 | [1],[3] | 92,091 | [2],[4] | |
Available-for-sale Securities [Abstract] | |||||
Available-for-sale Securities | 88,749 | [1] | 92,091 | [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 Investments, Fair Value Disclosure | 194,912 | [1],[3] | 190,462 | [2],[4] | |
Available-for-sale Securities [Abstract] | |||||
Available-for-sale Securities | 194,912 | [1] | 190,462 | [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 Investments, Fair Value Disclosure | 187,609 | [1],[3] | 187,647 | [2],[4] | |
Available-for-sale Securities [Abstract] | |||||
Available-for-sale Securities | 187,609 | [1] | 187,647 | [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 Investments, Fair Value Disclosure | 161,936 | [1],[3] | 159,489 | [2],[4] | |
Available-for-sale Securities [Abstract] | |||||
Available-for-sale Securities | 161,936 | [1] | 159,489 | [2] | |
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 Investments, Fair Value Disclosure | 0 | [1],[3] | 0 | [2],[4] | |
Available-for-sale Securities [Abstract] | |||||
Available-for-sale Securities, Debt Securities | 27,199 | [1] | 31,965 | [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 Investments, Fair Value Disclosure | 0 | [1],[3] | 0 | [2],[4] | |
Available-for-sale Securities [Abstract] | |||||
Available-for-sale Securities, Debt Securities | 128,799 | [1] | 105,772 | [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 Investments, Fair Value Disclosure | 0 | [1],[3] | 0 | [2],[4] | |
Available-for-sale Securities [Abstract] | |||||
Available-for-sale Securities, Debt Securities | 25,556 | [1] | 21,672 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Municipal bonds | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Alternative Investments, Fair Value Disclosure | 0 | [1],[3] | 0 | [2],[4] | |
Available-for-sale Securities [Abstract] | |||||
Available-for-sale Securities, Debt Securities | 5 | [1] | 13,786 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Mortgage-backed securities | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Alternative Investments, Fair Value Disclosure | [2],[4] | 0 | |||
Available-for-sale Securities [Abstract] | |||||
Available-for-sale Securities, Debt Securities | [2] | 2,816 | |||
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 Investments, Fair Value Disclosure | 0 | [1],[3] | 0 | [2],[4] | |
Available-for-sale Securities [Abstract] | |||||
Available-for-sale Securities, Equity Securities | 501,543 | [1] | 473,400 | [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 Investments, Fair Value Disclosure | 0 | [1],[3] | 0 | [2],[4] | |
Available-for-sale Securities [Abstract] | |||||
Available-for-sale Securities, Equity Securities | 232,851 | [1] | 218,381 | [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 | 24,161 | [1] | 20,379 | [2] | |
Available-for-sale Securities [Abstract] | |||||
Available-for-sale Securities | 937,545 | [1] | 845,286 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Non U.S. equities | |||||
Available-for-sale Securities [Abstract] | |||||
Available-for-sale Securities | 178,990 | [1] | 133,126 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Emerging market debt funds | |||||
Available-for-sale Securities [Abstract] | |||||
Available-for-sale Securities | 0 | [1] | 0 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Commodity funds | |||||
Available-for-sale Securities [Abstract] | |||||
Available-for-sale Securities | 0 | [1] | 0 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Private equity investments | |||||
Available-for-sale Securities [Abstract] | |||||
Available-for-sale Securities | 0 | [1] | 0 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Real estate | |||||
Available-for-sale Securities [Abstract] | |||||
Available-for-sale Securities | 0 | [1] | 0 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Other commingled funds | |||||
Available-for-sale Securities [Abstract] | |||||
Available-for-sale Securities | 0 | [1] | 0 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Government securities | |||||
Available-for-sale Securities [Abstract] | |||||
Available-for-sale Securities, Debt Securities | 0 | [1] | 0 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | U.S. corporate bonds | |||||
Available-for-sale Securities [Abstract] | |||||
Available-for-sale Securities, Debt Securities | 0 | [1] | 0 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Non U.S. corporate bonds | |||||
Available-for-sale Securities [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 | Municipal bonds | |||||
Available-for-sale Securities [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 | Mortgage-backed securities | |||||
Available-for-sale Securities [Abstract] | |||||
Available-for-sale Securities, Debt Securities | [2] | 0 | |||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | U.S. equities | |||||
Available-for-sale Securities [Abstract] | |||||
Available-for-sale Securities, Equity Securities | 501,543 | [1] | 473,400 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Non U.S. equities | |||||
Available-for-sale Securities [Abstract] | |||||
Available-for-sale Securities, Equity Securities | 232,851 | [1] | 218,381 | [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] | |
Available-for-sale Securities [Abstract] | |||||
Available-for-sale Securities | 181,559 | [1] | 176,011 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Non U.S. equities | |||||
Available-for-sale Securities [Abstract] | |||||
Available-for-sale Securities | 0 | [1] | 0 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Emerging market debt funds | |||||
Available-for-sale Securities [Abstract] | |||||
Available-for-sale Securities | 0 | [1] | 0 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Commodity funds | |||||
Available-for-sale Securities [Abstract] | |||||
Available-for-sale Securities | 0 | [1] | 0 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Private equity investments | |||||
Available-for-sale Securities [Abstract] | |||||
Available-for-sale Securities | 0 | [1] | 0 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Real estate | |||||
Available-for-sale Securities [Abstract] | |||||
Available-for-sale Securities | 0 | [1] | 0 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Other commingled funds | |||||
Available-for-sale Securities [Abstract] | |||||
Available-for-sale Securities | 0 | [1] | 0 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Government securities | |||||
Available-for-sale Securities [Abstract] | |||||
Available-for-sale Securities, Debt Securities | 27,199 | [1] | 31,965 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | U.S. corporate bonds | |||||
Available-for-sale Securities [Abstract] | |||||
Available-for-sale Securities, Debt Securities | 128,799 | [1] | 105,772 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Non U.S. corporate bonds | |||||
Available-for-sale Securities [Abstract] | |||||
Available-for-sale Securities, Debt Securities | 25,556 | [1] | 21,672 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Municipal bonds | |||||
Available-for-sale Securities [Abstract] | |||||
Available-for-sale Securities, Debt Securities | 5 | [1] | 13,786 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Mortgage-backed securities | |||||
Available-for-sale Securities [Abstract] | |||||
Available-for-sale Securities, Debt Securities | [2] | 2,816 | |||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | U.S. equities | |||||
Available-for-sale Securities [Abstract] | |||||
Available-for-sale Securities, Equity Securities | 0 | [1] | 0 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Non U.S. equities | |||||
Available-for-sale Securities [Abstract] | |||||
Available-for-sale Securities, 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] | |
Available-for-sale Securities [Abstract] | |||||
Available-for-sale Securities | 0 | [1] | 0 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Non U.S. equities | |||||
Available-for-sale Securities [Abstract] | |||||
Available-for-sale Securities | 0 | [1] | 0 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Emerging market debt funds | |||||
Available-for-sale Securities [Abstract] | |||||
Available-for-sale Securities | 0 | [1] | 0 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Commodity funds | |||||
Available-for-sale Securities [Abstract] | |||||
Available-for-sale Securities | 0 | [1] | 0 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Private equity investments | |||||
Available-for-sale Securities [Abstract] | |||||
Available-for-sale Securities | 0 | [1] | 0 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Real estate | |||||
Available-for-sale Securities [Abstract] | |||||
Available-for-sale Securities | 0 | [1] | 0 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Other commingled funds | |||||
Available-for-sale Securities [Abstract] | |||||
Available-for-sale Securities | 0 | [1] | 0 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Government securities | |||||
Available-for-sale Securities [Abstract] | |||||
Available-for-sale Securities, Debt Securities | 0 | [1] | 0 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | U.S. corporate bonds | |||||
Available-for-sale Securities [Abstract] | |||||
Available-for-sale Securities, Debt Securities | 0 | [1] | 0 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Non U.S. corporate bonds | |||||
Available-for-sale Securities [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 | Municipal bonds | |||||
Available-for-sale Securities [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 | Mortgage-backed securities | |||||
Available-for-sale Securities [Abstract] | |||||
Available-for-sale Securities, Debt Securities | [2] | 0 | |||
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | U.S. equities | |||||
Available-for-sale Securities [Abstract] | |||||
Available-for-sale Securities, Equity Securities | 0 | [1] | 0 | [2] | |
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Non U.S. equities | |||||
Available-for-sale Securities [Abstract] | |||||
Available-for-sale Securities, Equity Securities | $ 0 | [1] | $ 0 | [2] | |
[1] | Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $131.9 million of equity investments in unconsolidated subsidiaries and $103.6 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 $132.8 million of equity investments in unconsolidated subsidiaries and $98.3 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 Asset52
Fair Value of Financial Assets and Liabilities, Final Contractual Maturity Dates of Debt Securities in Nuclear Decommissioning Fund (Details) $ in Thousands | Mar. 31, 2017USD ($) |
Final Contractual Maturity [Abstract] | |
Due in 1 Year or Less | $ 354 |
Due in 1 to 5 Years | 47,926 |
Due in 5 to 10 Years | 91,082 |
Due after 10 Years | 42,197 |
Total | 181,559 |
Government securities | |
Final Contractual Maturity [Abstract] | |
Due in 1 Year or Less | 0 |
Due in 1 to 5 Years | 1,100 |
Due in 5 to 10 Years | 3,017 |
Due after 10 Years | 23,082 |
Total | 27,199 |
U.S. corporate bonds | |
Final Contractual Maturity [Abstract] | |
Due in 1 Year or Less | 354 |
Due in 1 to 5 Years | 38,741 |
Due in 5 to 10 Years | 74,617 |
Due after 10 Years | 15,087 |
Total | 128,799 |
Non U.S. corporate bonds | |
Final Contractual Maturity [Abstract] | |
Due in 1 Year or Less | 0 |
Due in 1 to 5 Years | 8,085 |
Due in 5 to 10 Years | 13,443 |
Due after 10 Years | 4,028 |
Total | 25,556 |
Municipal bonds | |
Final Contractual Maturity [Abstract] | |
Due in 1 Year or Less | 0 |
Due in 1 to 5 Years | 0 |
Due in 5 to 10 Years | 5 |
Due after 10 Years | 0 |
Total | $ 5 |
Fair Value of Financial Asset53
Fair Value of Financial Assets and Liabilities Fair Value of Financial Assets and Liabilities, Cost and Fair Value of Rabbi Trust (Details) - Fair Value, Measurements, Recurring [Member] - USD ($) $ in Thousands | Mar. 31, 2017 | Dec. 31, 2016 | |
Cost | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Trading Securities | [1] | $ 49,540 | $ 49,494 |
Cost | Rabbi Trust [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Cash Equivalents | [1] | 9,575 | 47,831 |
Cost | Mutual Funds [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Trading Securities | [1] | 39,965 | 1,663 |
Fair Value | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Trading Securities | [1] | 49,839 | 49,732 |
Fair Value | Level 1 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Trading Securities | [1] | 49,839 | 49,732 |
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] | 9,575 | 47,831 |
Fair Value | Rabbi Trust [Member] | Level 1 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Cash Equivalents | [1] | 9,575 | 47,831 |
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] | 40,264 | 1,901 |
Fair Value | Mutual Funds [Member] | Level 1 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Trading Securities | [1] | 40,264 | 1,901 |
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 Asset54
Fair Value of Financial Assets and Liabilities, Derivative Instruments (Details) MWh in Thousands, MMBTU in Thousands, $ in Millions | Mar. 31, 2017USD ($)MMBTUMWhCounterparty | Dec. 31, 2016MMBTUMWh | |
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 | 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 | 10 | ||
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 | 8 | ||
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties | $ | $ 79.1 | ||
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths) | 34.00% | ||
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 | 2 | ||
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties | $ | $ 24.1 | ||
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths) | 10.00% | ||
Interest Rate Swap | |||
Interest Rate Derivatives [Abstract] | |||
Amount of accumulated other comprehensive gains (losses) related to interest rate derivatives expected to be reclassified into earnings within the next twelve months | $ | $ (3.1) | ||
Electric Commodity (in megawatt hours) | |||
Gross Notional Amounts of Commodity Forwards, Options and FTRs [Abstract] | |||
Derivative, Nonmonetary Notional amount | MWh | [1],[2] | 31,838 | 46,773 |
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] | 92,801 | 121,978 |
[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 Asset55
Fair Value of Financial Assets and Liabilities, Impact of Derivative Activity (Details) - USD ($) | 3 Months Ended | ||
Mar. 31, 2017 | Mar. 31, 2016 | ||
Financial Impact of Qualifying Fair Value Hedges on Earnings [Abstract] | |||
Derivative instruments designated as fair value hedges | $ 0 | $ 0 | |
Recognized gains (losses) from fair value hedges or related hedged transactions | 0 | 0 | |
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 | (6,000) | |
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities | 0 | 0 | |
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss | 1,359,000 | 1,542,000 | |
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities) | 0 | 0 | |
Pre-tax gains (losses) recognized during the period in income | 0 | 0 | |
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 | |
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities | 0 | 0 | |
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss | [1] | 1,359,000 | 1,485,000 |
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities) | 0 | 0 | |
Pre-tax gains (losses) recognized during the period in income | 0 | 0 | |
Designated as Hedging Instrument | Cash Flow Hedges | Vehicle Fuel And Other Commodity | |||
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract] | |||
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss | (6,000) | ||
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities | 0 | ||
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss | [2] | 57,000 | |
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities) | 0 | ||
Pre-tax gains (losses) recognized during the period in income | 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 | |
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities | (5,367,000) | (2,967,000) | |
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss | 0 | 0 | |
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities) | (2,923,000) | 20,297,000 | |
Pre-tax gains (losses) recognized during the period in income | (3,069,000) | (4,015,000) | |
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 | |
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities | 0 | 0 | |
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss | 0 | 0 | |
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities) | 0 | 0 | |
Pre-tax gains (losses) recognized during the period in income | [3] | 1,001,000 | 1,009,000 |
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 | |
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities | 794,000 | (265,000) | |
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss | 0 | 0 | |
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities) | [4] | (3,998,000) | 8,631,000 |
Pre-tax gains (losses) recognized during the period in income | 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 | |
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities | (6,161,000) | (2,702,000) | |
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss | 0 | 0 | |
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities) | [5] | 1,075,000 | 11,666,000 |
Pre-tax gains (losses) recognized during the period in income | [5] | (4,070,000) | $ (5,024,000) |
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 | $ 900,000 | ||
[1] | Amounts are recorded to interest charges. | ||
[2] | Amounts are recorded to O&M expenses. | ||
[3] | Amounts are recorded to electric operating revenues. Portions of these gains and losses are subject to sharing with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate. | ||
[4] | Amounts are recorded to electric fuel and purchased power. These derivative settlement gain and loss amounts are shared with electric customers through fuel and purchased energy cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate. | ||
[5] | Amounts for the three months ended March 31, 2017 included $0.9 million of settlement gains and an immaterial amount of settlement losses for the three months ended March 31, 2016 on derivatives entered to mitigate natural gas price risk for electric generation, recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate. The remaining derivative settlement gains and losses for the three months ended March 31, 2017 and 2016 relate to natural gas operations and are recorded to cost of natural gas sold and transported. These gains and losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset or liability, as appropriate. |
Fair Value of Financial Asset56
Fair Value of Financial Assets and Liabilities, Credit Related Contingent Features (Details) - USD ($) | Mar. 31, 2017 | Dec. 31, 2016 |
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 Asset57
Fair Value of Financial Assets and Liabilities, Derivative Assets and Liabilities at Fair Value (Details) - USD ($) $ in Thousands | Mar. 31, 2017 | Dec. 31, 2016 | |||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Collateral, Obligation to Return Cash, Offset | $ 0 | $ 0 | |||
Derivative Liability, Collateral, Right to Reclaim Cash, Offset | 4,500 | 3,700 | |||
Other Current Assets | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 20,885 | 38,224 | |||
Other Noncurrent Assets | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 48,681 | 50,189 | |||
Other Current Liabilities | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 26,706 | 26,959 | |||
Other Noncurrent Liabilities | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 143,684 | 148,146 | |||
Fair Value Measured on a Recurring Basis | Other Current Assets | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 15,393 | 32,761 | |||
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset | (13,940) | [1] | (22,613) | [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 | 7,430 | 6,647 | |||
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset | (12,126) | [1] | (20,637) | [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 | 6,629 | 17,275 | |||
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset | (1,814) | [1] | (1,976) | [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 | 1,334 | 8,839 | |||
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset | 0 | [1] | 0 | [2] | |
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 25,175 | 25,458 | |||
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset | (7,295) | [1] | (7,323) | [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 | 25,175 | 23,806 | |||
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset | (7,295) | [1] | (7,323) | [2] | |
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 1,652 | ||||
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset | [2] | 0 | |||
Fair Value Measured on a Recurring Basis | Other Current Liabilities | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 3,872 | 4,155 | |||
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset | (15,230) | [1] | (22,950) | [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 | 3,872 | 4,155 | |||
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset | (13,416) | [1] | (20,974) | [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 | (1,814) | [1] | (1,976) | [2] | |
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 13,969 | 12,786 | |||
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset | (10,463) | [1] | (10,727) | [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 | 13,969 | 12,786 | |||
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset | (10,463) | [1] | (10,727) | [2] | |
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 4,706 | 13,179 | |||
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 | 4,706 | 13,179 | |||
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets | Other Derivative Instruments | Electric Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Assets | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 198 | 100 | |||
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 | 198 | 100 | |||
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent 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 Current Liabilities | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 5,224 | 13,787 | |||
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 | 5,224 | 13,787 | |||
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 Noncurrent Liabilities | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 204 | 89 | |||
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 | 204 | 89 | |||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 16,184 | 22,944 | |||
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 | 14,850 | 14,105 | |||
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 | 1,334 | 8,839 | |||
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Assets | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 32,272 | 32,681 | |||
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 | 32,272 | 31,029 | |||
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Assets | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 1,652 | ||||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 12,064 | 11,320 | |||
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 | 12,064 | 11,320 | |||
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 Noncurrent Liabilities | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 23,435 | 23,424 | |||
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 | 23,435 | 23,424 | |||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 8,443 | 19,251 | |||
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 | 0 | 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 | 8,443 | 19,251 | |||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Assets | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Assets | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent 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 Current Liabilities | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 1,814 | 1,998 | |||
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 | 0 | 22 | |||
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 | 1,814 | 1,976 | |||
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Liabilities | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 793 | 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 | 793 | 0 | |||
Fair Value, Measurements, Nonrecurring | Other Current Assets | Purchased Power Agreements | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 5,492 | [3] | 5,463 | [4] | |
Fair Value, Measurements, Nonrecurring | Other Noncurrent Assets | Purchased Power Agreements | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 23,506 | [3] | 24,731 | [4] | |
Fair Value, Measurements, Nonrecurring | Other Current Liabilities | Purchased Power Agreements | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 22,834 | [3] | 22,804 | [4] | |
Fair Value, Measurements, Nonrecurring | Other Noncurrent Liabilities | Purchased Power Agreements | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 129,715 | [3] | 135,360 | [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 | 29,333 | 55,374 | |||
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 | 19,556 | 27,284 | |||
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 | 8,443 | 19,251 | |||
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 | 1,334 | 8,839 | |||
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 | 32,470 | 32,781 | |||
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 | 32,470 | 31,129 | |||
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 1,652 | ||||
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 | 19,102 | 27,105 | |||
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 | 17,288 | 25,129 | |||
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 | 1,814 | 1,976 | |||
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 | 24,432 | 23,513 | |||
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 | $ 24,432 | $ 23,513 | |||
[1] | Xcel Energy nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at March 31, 2017. At March 31, 2017, derivative assets and liabilities include no obligations to return cash collateral and the rights to reclaim cash collateral of $4.5 million. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements. | ||||
[2] | Xcel Energy nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2016. At Dec. 31, 2016, derivative assets and liabilities include no obligations to return cash collateral and rights to reclaim cash collateral of $3.7 million. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements. | ||||
[3] | During 2006, Xcel Energy qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities. | ||||
[4] | During 2006, Xcel Energy qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities. |
Fair Value of Financial Asset58
Fair Value of Financial Assets and Liabilities, Changes in Level 3 Commodity Derivatives (Details) - Commodity Contract - USD ($) | 3 Months Ended | ||
Mar. 31, 2017 | Mar. 31, 2016 | ||
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward] | |||
Balance at beginning of period | $ 17,253,000 | $ 18,028,000 | |
Purchases | 3,792,000 | 1,843,000 | |
Settlements | (19,802,000) | (18,256,000) | |
(Losses) recognized in earnings | [1] | (794,000) | (24,000) |
Net gains recognized as regulatory assets and liabilities | 5,387,000 | 5,263,000 | |
Balance at end of period | 5,836,000 | 6,854,000 | |
Transfers into Level 3 | 0 | 0 | |
Transfers out of Level 3 | $ 0 | $ 0 | |
[1] | (a) These amounts relate to commodity derivatives held at the end of the period. |
Fair Value of Financial Asset59
Fair Value of Financial Assets and Liabilities, Fair Value of Long-Term Debt (Details) - USD ($) $ in Thousands | Mar. 31, 2017 | Dec. 31, 2016 |
Carrying Amount | ||
Financial Liabilities, Balance Sheet Groupings [Abstract] | ||
Long-term Debt, Including Current Portion | $ 14,451,909 | $ 14,450,247 |
Fair Value | ||
Financial Liabilities, Balance Sheet Groupings [Abstract] | ||
Long-term Debt, Including Current Portion | $ 15,492,978 | $ 15,513,209 |
Other Income, Net (Details)
Other Income, Net (Details) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
Other Income and Expenses [Abstract] | ||
Interest income | $ 3,800 | $ 4,070 |
Other nonoperating income | 3,645 | 680 |
Insurance policy expense | (999) | (500) |
Other income, net | $ 6,446 | $ 4,250 |
Segment Information (Details)
Segment Information (Details) - USD ($) $ in Thousands | 3 Months Ended | ||
Mar. 31, 2017 | Mar. 31, 2016 | Dec. 31, 2016 | |
Segment Reporting Information [Line Items] | |||
Equity investments in unconsolidated subsidiaries | $ 131,900 | $ 132,800 | |
Operating revenues | 2,946,422 | $ 2,772,273 | |
Net income (loss) | 239,277 | 241,312 | |
Regulated Electric | |||
Segment Reporting Information [Line Items] | |||
Operating revenues | 2,299,357 | 2,185,454 | |
Net income (loss) | 194,153 | 178,237 | |
Regulated Natural Gas | |||
Segment Reporting Information [Line Items] | |||
Equity investments in unconsolidated subsidiaries | 131,900 | $ 132,800 | |
Operating revenues | 625,967 | 565,976 | |
Net income (loss) | 62,927 | 78,338 | |
All Other | |||
Segment Reporting Information [Line Items] | |||
Operating revenues | 21,659 | 21,465 | |
Net income (loss) | (17,803) | (15,263) | |
Operating Segments | |||
Segment Reporting Information [Line Items] | |||
Operating revenues | 2,946,422 | 2,772,273 | |
Operating Segments | Regulated Electric | |||
Segment Reporting Information [Line Items] | |||
Operating revenues | 2,299,060 | 2,185,119 | |
Operating Segments | Regulated Natural Gas | |||
Segment Reporting Information [Line Items] | |||
Operating revenues | 625,703 | 565,689 | |
Operating Segments | All Other | |||
Segment Reporting Information [Line Items] | |||
Operating revenues | 21,659 | 21,465 | |
Intersegment Eliminations | |||
Segment Reporting Information [Line Items] | |||
Operating revenues | (561) | (622) | |
Net income (loss) | 0 | 0 | |
Intersegment Eliminations | Regulated Electric | |||
Segment Reporting Information [Line Items] | |||
Operating revenues | 297 | 335 | |
Intersegment Eliminations | Regulated Natural Gas | |||
Segment Reporting Information [Line Items] | |||
Operating revenues | 264 | 287 | |
Intersegment Eliminations | All Other | |||
Segment Reporting Information [Line Items] | |||
Operating revenues | $ 0 | $ 0 |
Earnings Per Share (Details)
Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
Dilutive Impact of Common Stock Equivalents on Earnings per Share (Abstract] | ||
Net income | $ 239,277 | $ 241,312 |
Basic earnings per share [Abstract] | ||
Earnings available to common shareholders | $ 239,277 | $ 241,312 |
Weighted average common shares outstanding - basic (in shares) | 508,278 | 508,667 |
Earnings available to common shareholders - basic (in dollars per share) | $ 0.47 | $ 0.47 |
Effect of dilutive securities [Abstract] | ||
Time based equity awards (in shares) | 496 | 483 |
Diluted earnings per share [Abstract] | ||
Earnings available to common shareholders | $ 239,277 | $ 241,312 |
Weighted average common shares outstanding - diluted (in shares) | 508,774 | 509,150 |
Earnings available to common shareholders - diluted (in dollars per share) | $ 0.47 | $ 0.47 |
Benefit Plans and Other Postr63
Benefit Plans and Other Postretirement Benefits (Details) $ in Thousands | 1 Months Ended | 3 Months Ended | |
Jan. 31, 2017USD ($)Plan | Mar. 31, 2017USD ($) | Mar. 31, 2016USD ($) | |
Pension Benefits | |||
Components of Net Periodic Benefit Cost [Abstract] | |||
Service cost | $ 23,547 | $ 22,920 | |
Interest cost | 36,702 | 40,023 | |
Expected return on plan assets | (52,317) | (52,575) | |
Amortization of prior service credit | (442) | (484) | |
Amortization of net loss | 26,670 | 24,385 | |
Net periodic benefit cost (credit) | 34,160 | 34,269 | |
Costs not recognized due to the effects of regulation | (4,015) | (4,452) | |
Net benefit cost (credit) recognized for financial reporting | 30,145 | 29,817 | |
Total contributions to Xcel Energy's pension plans during the period | $ 150,000 | ||
Number of pension plans to which contributions were made | Plan | 4 | ||
Postretirement Health Care Benefits | |||
Components of Net Periodic Benefit Cost [Abstract] | |||
Service cost | 465 | 432 | |
Interest cost | 5,984 | 6,527 | |
Expected return on plan assets | (6,156) | (6,249) | |
Amortization of prior service credit | (2,671) | (2,672) | |
Amortization of net loss | 1,672 | 1,011 | |
Net periodic benefit cost (credit) | (706) | (951) | |
Costs not recognized due to the effects of regulation | 0 | 0 | |
Net benefit cost (credit) recognized for financial reporting | $ (706) | $ (951) |
Other Comprehensive Income (Det
Other Comprehensive Income (Details) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | ||
Accumulated other comprehensive income (loss) at beginning of period | $ 11,020,849 | |
(Gains) losses reclassified from net accumulated other comprehensive loss | 1,773 | $ 1,802 |
Accumulated other comprehensive income (loss) at end of period | 11,070,111 | |
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 | (51,151) | (54,862) |
Other comprehensive income (loss) before reclassifications | (4) | |
(Gains) losses reclassified from net accumulated other comprehensive loss | 825 | 938 |
Net current period other comprehensive income (loss) | 825 | 934 |
Accumulated other comprehensive income (loss) at end of period | (50,326) | (53,928) |
Unrealized Gains and Losses on Marketable Securities | ||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | ||
Accumulated other comprehensive income (loss) at beginning of period | 110 | 110 |
Other comprehensive income (loss) before reclassifications | 0 | |
(Gains) losses reclassified from net accumulated other comprehensive loss | 0 | 0 |
Net current period other comprehensive income (loss) | 0 | 0 |
Accumulated other comprehensive income (loss) at end of period | 110 | 110 |
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 | (59,313) | (55,001) |
Other comprehensive income (loss) before reclassifications | (653) | |
(Gains) losses reclassified from net accumulated other comprehensive loss | 948 | 864 |
Net current period other comprehensive income (loss) | 948 | 211 |
Accumulated other comprehensive income (loss) at end of period | (58,365) | (54,790) |
Total | ||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | ||
Accumulated other comprehensive income (loss) at beginning of period | (110,354) | (109,753) |
Other comprehensive income (loss) before reclassifications | (657) | |
(Gains) losses reclassified from net accumulated other comprehensive loss | 1,773 | 1,802 |
Net current period other comprehensive income (loss) | 1,773 | 1,145 |
Accumulated other comprehensive income (loss) at end of period | $ (108,581) | $ (108,608) |
Other Comprehensive Income (Rec
Other Comprehensive Income (Reclassifications from AOCI) (Details) - USD ($) $ in Thousands | 3 Months Ended | ||
Mar. 31, 2017 | Mar. 31, 2016 | ||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||
Operating and maintenance expenses | $ 586,430 | $ 577,410 | |
Total, pre-tax | (355,941) | (369,962) | |
Tax benefit | 116,664 | 128,650 | |
Total amounts reclassified, net of tax | 1,773 | 1,802 | |
Gains and Losses on Cash Flow Hedges | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||
Total amounts reclassified, net of tax | 825 | 938 | |
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 | 1,359 | 1,542 | |
Tax benefit | (534) | (604) | |
Total, net of tax | 825 | 938 | |
Prior service credit | Amounts Reclassified from Accumulated Other Comprehensive Loss | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||
Total, pre-tax | [1] | 1,623 | 1,478 |
Amortization of net loss | Amounts Reclassified from Accumulated Other Comprehensive Loss | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||
Total, pre-tax | [1] | (60) | (64) |
Defined Benefit Pension and Postretirement Items | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||
Total amounts reclassified, net of tax | 948 | 864 | |
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 | 1,563 | 1,414 | |
Tax benefit | (615) | (550) | |
Total amounts reclassified, net of tax | 948 | 864 | |
Interest Rate Swap | Gains and Losses on Cash Flow Hedges | Amounts Reclassified from Accumulated Other Comprehensive Loss | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||
Interest charges | [2] | 1,359 | 1,485 |
Vehicle Fuel Derivatives | Gains and Losses on Cash Flow Hedges | Amounts Reclassified from Accumulated Other Comprehensive Loss | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||
Operating and maintenance expenses | [3] | $ 0 | $ 57 |
[1] | Included in the computation of net periodic pension and postretirement benefit costs. See Note 12 for details regarding these benefit plans. | ||
[2] | Included in interest charges. | ||
[3] | Included in O&M expenses. |