Document and Entity Information
Document and Entity Information - shares | 9 Months Ended | |
Sep. 30, 2015 | Nov. 02, 2015 | |
Document and Entity Information [Abstract] | ||
Entity Registrant Name | NORTHERN STATES POWER CO /WI/ | |
Entity Central Index Key | 72,909 | |
Current Fiscal Year End Date | --12-31 | |
Entity Filer Category | Non-accelerated Filer | |
Document Type | 10-Q | |
Document Period End Date | Sep. 30, 2015 | |
Document Fiscal Year Focus | 2,015 | |
Document Fiscal Period Focus | Q3 | |
Amendment Flag | false | |
Entity Common Stock, Shares Outstanding | 933,000 | |
Entity Well-known Seasoned Issuer | No | |
Entity Voluntary Filers | No | |
Entity Current Reporting Status | Yes |
CONSOLIDATED STATEMENTS OF INCO
CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | |
Operating revenues | ||||
Electric | $ 224,666 | $ 216,289 | $ 634,571 | $ 625,663 |
Natural gas | 11,088 | 14,484 | 91,273 | 117,814 |
Other | 407 | 273 | 1,090 | 825 |
Total operating revenues | 236,161 | 231,046 | 726,934 | 744,302 |
Operating expenses | ||||
Electric fuel and purchased power, non-affiliates | 2,624 | 2,707 | 5,066 | 11,887 |
Purchased power, affiliates | 102,297 | 105,092 | 318,542 | 321,550 |
Cost of natural gas sold and transported | 4,375 | 7,854 | 54,933 | 78,190 |
Operating and maintenance expenses | 46,292 | 47,899 | 134,126 | 140,563 |
Conservation program expenses | 2,977 | 3,005 | 8,821 | 8,692 |
Depreciation and amortization | 23,019 | 19,940 | 66,908 | 59,121 |
Taxes (other than income taxes) | 7,045 | 7,009 | 21,151 | 20,458 |
Loss on Monticello life cycle management/extended power uprate project | 0 | 0 | 5,237 | 0 |
Total operating expenses | 188,629 | 193,506 | 614,784 | 640,461 |
Operating income | 47,532 | 37,540 | 112,150 | 103,841 |
Other income (expense), net | 100 | (9) | 384 | 45 |
Allowance for funds used during construction — equity | 1,929 | 1,576 | 5,926 | 4,915 |
Interest charges and financing costs | ||||
Interest charges — includes other financing costs of $461, $408, $1,273 and $1,159, respectively | 8,625 | 7,701 | 24,152 | 21,536 |
Allowance for funds used during construction — debt | (931) | (733) | (2,865) | (2,341) |
Total interest charges and financing costs | 7,694 | 6,968 | 21,287 | 19,195 |
Income before income taxes | 41,867 | 32,139 | 97,173 | 89,606 |
Income taxes | 15,635 | 12,109 | 36,162 | 33,319 |
Net income | $ 26,232 | $ 20,030 | $ 61,011 | $ 56,287 |
CONSOLIDATED STATEMENTS OF INC3
CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) (Parenthetical) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | |
Interest charges and financing costs | ||||
Other financing costs | $ 461 | $ 408 | $ 1,273 | $ 1,159 |
CONSOLIDATED STATEMENTS OF COMP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | |
Comprehensive income: | ||||
Net income | $ 26,232 | $ 20,030 | $ 61,011 | $ 56,287 |
Derivative instruments: | ||||
Reclassification of losses to net income, net of tax of $13, $12, $37 and $38 for each of the three and nine months ended Sept. 30, 2015 and 2014, respectively | 19 | 20 | 57 | 57 |
Other comprehensive income | 19 | 20 | 57 | 57 |
Comprehensive income | $ 26,251 | $ 20,050 | $ 61,068 | $ 56,344 |
CONSOLIDATED STATEMENTS OF COM5
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) (Parenthetical) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | |
Derivative instruments: | ||||
Reclassification of losses to net income, net of tax | $ 13 | $ 12 | $ 37 | $ 38 |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) - USD ($) $ in Thousands | 9 Months Ended | |
Sep. 30, 2015 | Sep. 30, 2014 | |
Operating activities | ||
Net income | $ 61,011 | $ 56,287 |
Adjustments to reconcile net income to cash provided by operating activities: | ||
Depreciation and amortization | 67,936 | 60,017 |
Deferred income taxes | 38,595 | 28,691 |
Amortization of Investment Tax Credits | (396) | (504) |
Allowance for equity funds used during construction | (5,926) | (4,915) |
Loss on Monticello life cycle management/extended power uprate project | 5,237 | 0 |
Net derivative losses (gains) | 338 | (356) |
Changes in operating assets and liabilities: | ||
Accounts receivable | 10,026 | 7,761 |
Accrued unbilled revenues | 12,657 | 13,009 |
Inventories | 2,847 | (5,172) |
Other current assets | 14,471 | 11,693 |
Accounts payable | (25,023) | (9,910) |
Net regulatory assets and liabilities | (13,962) | (35,546) |
Other current liabilities | 5,948 | 955 |
Pension and other employee benefit obligations | (3,931) | (6,882) |
Change in other noncurrent assets | 11 | (46) |
Change in other noncurrent liabilities | 595 | 1,013 |
Net cash provided by operating activities | 170,434 | 116,095 |
Investing activities | ||
Utility capital/construction expenditures | (171,586) | (194,886) |
Allowance for equity funds used during construction | 5,926 | 4,915 |
Other, net | (90) | (13) |
Net cash used in investing activities | (165,750) | (189,984) |
Financing activities | ||
Proceeds from short-term borrowings, net | (78,000) | (60,000) |
Proceeds from notes payable to affiliate | 0 | 30 |
Proceeds from Issuance of Long-term Debt | 98,038 | 98,625 |
Repayments of long-term debt | 0 | (54) |
Capital contributions from parent | 25,060 | 68,011 |
Dividends paid to parent | (40,265) | (32,331) |
Net cash provided by financing activities | 4,833 | 74,281 |
Net change in cash and cash equivalents | 9,517 | 392 |
Cash and cash equivalents at beginning of period | 1,285 | 1,349 |
Cash and cash equivalents at end of period | 10,802 | 1,741 |
Supplemental disclosure of cash flow information: | ||
Cash paid for interest (net of amounts capitalized) | (18,647) | (17,313) |
Cash received for income taxes, net | 9,662 | 915 |
Supplemental disclosure of non-cash investing transactions: | ||
Property, plant and equipment additions in accounts payable | $ 13,520 | $ 28,693 |
CONSOLIDATED BALANCE SHEETS (UN
CONSOLIDATED BALANCE SHEETS (UNAUDITED) - USD ($) $ in Thousands | Sep. 30, 2015 | Dec. 31, 2014 |
Current assets | ||
Cash and cash equivalents | $ 10,802 | $ 1,285 |
Accounts receivable, net | 50,370 | 60,396 |
Accrued unbilled revenues | 40,910 | 53,567 |
Inventories | 21,838 | 24,685 |
Regulatory assets | 14,626 | 20,036 |
Prepaid taxes | 18,421 | 28,628 |
Deferred income taxes | 7,724 | 8,201 |
Prepayments and other | 2,872 | 6,918 |
Total current assets | 167,563 | 203,716 |
Property, plant and equipment, net | 1,789,334 | 1,674,281 |
Other assets | ||
Regulatory assets | 276,552 | 280,693 |
Other investments | 3,908 | 3,818 |
Other | 5,415 | 4,612 |
Total other assets | 285,875 | 289,123 |
Total assets | 2,242,772 | 2,167,120 |
Current liabilities | ||
Current portion of long-term debt | 1,196 | 1,235 |
Short-term debt | 0 | 78,000 |
Notes payable to affiliates | 500 | 500 |
Accounts payable | 32,777 | 61,530 |
Accounts payable to affiliates | 26,471 | 26,524 |
Dividends payable to parent | 13,664 | 14,957 |
Regulatory liabilities | 10,765 | 16,940 |
Environmental liabilities | 16,689 | 29,116 |
Other | 24,379 | 19,923 |
Total current liabilities | 126,441 | 248,725 |
Deferred credits and other liabilities | ||
Deferred income taxes | 390,095 | 348,180 |
Deferred investment tax credits | 8,692 | 9,089 |
Regulatory liabilities | 141,659 | 132,674 |
Environmental liabilities | 79,153 | 78,620 |
Customer advances | 18,080 | 17,623 |
Pension and employee benefit obligations | 47,336 | 51,313 |
Other | 16,330 | 16,151 |
Total deferred credits and other liabilities | $ 701,345 | $ 653,650 |
Commitments and contingencies | ||
Capitalization | ||
Long-term debt | $ 666,379 | $ 567,056 |
Common stock — 1,000,000 shares authorized of $100 par value; 933,000 shares outstanding at Sept. 30, 2015 and Dec. 31, 2014, respectively | 93,300 | 93,300 |
Additional paid in capital | 351,097 | 322,276 |
Retained earnings | 304,438 | 282,398 |
Accumulated other comprehensive loss | (228) | (285) |
Total common stockholder’s equity | 748,607 | 697,689 |
Total liabilities and equity | $ 2,242,772 | $ 2,167,120 |
CONSOLIDATED BALANCE SHEETS (U8
CONSOLIDATED BALANCE SHEETS (UNAUDITED) (Parenthetical) - $ / shares | Sep. 30, 2015 | Dec. 31, 2014 |
Capitalization | ||
Common stock, shares authorized (in shares) | 1,000,000 | 1,000,000 |
Common stock, par value (in dollars per share) | $ 100 | $ 100 |
Common stock, shares outstanding (in shares) | 933,000 | 933,000 |
Management's Opinion
Management's Opinion | 9 Months Ended |
Sep. 30, 2015 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Management's Opinion | In the opinion of management, the accompanying unaudited consolidated financial statements contain all adjustments necessary to present fairly, in accordance with accounting principles generally accepted in the United States of America (GAAP), the financial position of NSP-Wisconsin and its subsidiaries as of Sept. 30, 2015 and Dec. 31, 2014 ; the results of its operations, including the components of net income and comprehensive income, for the three months and nine months ended Sept. 30, 2015 and 2014; and its cash flows for the nine months ended Sept. 30, 2015 and 2014. All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after Sept. 30, 2015 up to the date of issuance of these consolidated financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation. The Dec. 31, 2014 balance sheet information has been derived from the audited 2014 consolidated financial statements included in the NSP-Wisconsin Annual Report on Form 10-K for the year ended Dec. 31, 2014 . These notes to the consolidated financial statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with GAAP on an annual basis have been condensed or omitted pursuant to such rules and regulations. For further information, refer to the consolidated financial statements and notes thereto, included in the NSP-Wisconsin Annual Report on Form 10-K for the year ended Dec. 31, 2014 , filed with the SEC on Feb. 23, 2014. Due to the seasonality of NSP-Wisconsin’s electric and natural gas sales, interim results are not necessarily an appropriate base from which to project annual results. |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 9 Months Ended |
Sep. 30, 2015 | |
Accounting Policies [Abstract] | |
Summary of Significant Accounting Policies | Summary of Significant Accounting Policies The significant accounting policies set forth in Note 1 to the consolidated financial statements in the NSP-Wisconsin Annual Report on Form 10-K for the year ended Dec. 31, 2014, appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference. |
Accounting Pronouncements
Accounting Pronouncements | 9 Months Ended |
Sep. 30, 2015 | |
New Accounting Pronouncements and Changes in Accounting Principles [Abstract] | |
Accounting Pronouncements | Accounting Pronouncements Recently Issued Revenue Recognition — In May 2014, the Financial Accounting Standards Board (FASB) issued Revenue from Contracts with Customers, Topic 606 (Accounting Standards Update (ASU) No. 2014-09) , which provides a framework for the recognition of revenue, with the objective that recognized revenues properly reflect amounts an entity is entitled to receive in exchange for goods and services. The new guidance also includes additional disclosure requirements regarding revenue, cash flows and obligations related to contracts with customers. As a result of the FASB’s deferral of the standard’s required implementation date in July 2015, the guidance is effective for interim and annual reporting periods beginning after Dec. 15, 2017. NSP-Wisconsin is currently evaluating the impact of adopting ASU 2014-09 on its consolidated financial statements. Consolidation — In February 2015, the FASB issued Amendments to the Consolidation Analysis, Topic 810 (ASU No. 2015-02) , which reduces the number of consolidation models and amends certain consolidation principles related to variable interest entities. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15. 2015, and early adoption is permitted. NSP-Wisconsin does not expect the implementation of ASU 2015-02 to have a material impact on its consolidated financial statements. Presentation of Debt Issuance Costs — In April 2015, the FASB issued Simplifying the Presentation of Debt Issuance Costs, Subtopic 835-30 (ASU No. 2015-03) , which amends existing guidance to require the presentation of debt issuance costs on the balance sheet as a deduction from the carrying amount of the related debt, instead of an asset. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2015, and early adoption is permitted. Other than the prescribed reclassification of assets to an offset of debt on the consolidated balance sheets, NSP-Wisconsin does not expect the implementation of ASU 2015-03 to have a material impact on its consolidated financial statements. Fair Value Measurement — In May 2015, the FASB issued Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share (or Its Equivalent), Topic 820 (ASU No. 2015-07), which removes the requirement to categorize within the fair value hierarchy the fair values for investments measured using a net asset value methodology. This guidance will be effective on a retrospective basis for interim and annual reporting periods beginning after Dec. 15, 2015, and early adoption is permitted. Other than the reduced disclosure requirements, NSP-Wisconsin does not expect the implementation of ASU 2015-07 to have a material impact on its consolidated financial statements. |
Selected Balance Sheet Data
Selected Balance Sheet Data | 9 Months Ended |
Sep. 30, 2015 | |
Balance Sheet Related Disclosures [Abstract] | |
Selected Balance Sheet Data | Selected Balance Sheet Data (Thousands of Dollars) Sept. 30, 2015 Dec. 31, 2014 Accounts receivable, net (a) Accounts receivable $ 55,204 $ 66,217 Less allowance for bad debts (4,834 ) (5,821 ) $ 50,370 $ 60,396 (Thousands of Dollars) Sept. 30, 2015 Dec. 31, 2014 Inventories Materials and supplies $ 6,865 $ 6,494 Fuel 6,376 6,654 Natural gas 8,597 11,537 $ 21,838 $ 24,685 (Thousands of Dollars) Sept. 30, 2015 Dec. 31, 2014 Property, plant and equipment, net Electric plant $ 2,332,155 $ 2,061,669 Natural gas plant 264,390 255,465 Common and other property 124,584 125,938 Construction work in progress 112,108 231,413 Total property, plant and equipment 2,833,237 2,674,485 Less accumulated depreciation (1,043,903 ) (1,000,204 ) $ 1,789,334 $ 1,674,281 (a) Accounts receivable, net includes an immaterial amount due from affiliates as of Sept. 30, 2015 and Dec. 31, 2014, respectively. |
Income Taxes
Income Taxes | 9 Months Ended |
Sep. 30, 2015 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | Income Taxes Except to the extent noted below, Note 6 to the consolidated financial statements included in NSP-Wisconsin’s Annual Report on Form 10-K for the year ended Dec. 31, 2014 appropriately represents, in all material respects, the current status of other income tax matters, and are incorporated herein by reference. Federal Audit — NSP-Wisconsin is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. In the third quarter of 2012, the Internal Revenue Service (IRS) commenced an examination of tax years 2010 and 2011 , including the 2009 carryback claim. As of Sept. 30, 2015, the IRS had proposed an adjustment to the federal tax loss carryback claims that would result in $13 million of income tax expense for the 2009 through 2011 claims, the recently filed 2013 claim, and the anticipated claim for 2014. NSP-Wisconsin is not expected to accrue any income tax expense related to this adjustment. As of Sept. 30, 2015, the IRS had begun the appeals process; however, the outcome and timing of a resolution is uncertain. The statute of limitations applicable to Xcel Energy’s 2009-2011 federal income tax returns expires in December 2016 following an extension to allow additional time for the appeals process. In the third quarter of 2015, the IRS commenced an examination of tax years 2012 and 2013 . As of Sept. 30, 2015, the IRS had not proposed any material adjustments to tax years 2012 and 2013. State Audits — NSP-Wisconsin is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of Sept. 30, 2015, NSP-Wisconsin’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2011 . As of Sept. 30, 2015, there were no state income tax audits in progress. Unrecognized Tax Benefits — The unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the annual effective tax rate (ETR). In addition, the unrecognized tax benefit balance includes temporary tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. A change in the period of deductibility would not affect the ETR but would accelerate the payment of cash to the taxing authority to an earlier period. A reconciliation of the amount of unrecognized tax benefit is as follows: (Millions of Dollars) Sept. 30, 2015 Dec. 31, 2014 Unrecognized tax benefit — Permanent tax positions $ 0.2 $ 0.1 Unrecognized tax benefit — Temporary tax positions 2.9 2.9 Total unrecognized tax benefit $ 3.1 $ 3.0 The unrecognized tax benefit amounts were reduced by the tax benefits associated with net operating loss (NOL) and tax credit carryforwards. The amounts of tax benefits associated with NOL and tax credit carryforwards are as follows: (Millions of Dollars) Sept. 30, 2015 Dec. 31, 2014 NOL and tax credit carryforwards $ (1.0 ) $ (0.9 ) It is reasonably possible that NSP-Wisconsin’s amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS appeals process and audit progress and state audits resume. As the IRS appeals process moves closer to completion, the change in the unrecognized tax benefit is not expected to be material. The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. The payables for interest related to unrecognized tax benefits at Sept. 30, 2015 and Dec. 31, 2014 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of Sept. 30, 2015 or Dec. 31, 2014. |
Rate Matters Rate Matters (Note
Rate Matters Rate Matters (Notes) | 9 Months Ended |
Sep. 30, 2015 | |
Public Utilities, General Disclosures [Abstract] | |
Rate Matters | Rate Matters Except to the extent noted below, the circumstances set forth in Note 10 to the consolidated financial statements included in NSP-Wisconsin’s Annual Report on Form 10-K for the year ended Dec. 31, 2014 and in Note 5 to the consolidated financial statements included in NSP-Wisconsin’s Quarterly Reports on Form 10-Q for the quarterly periods ended March 31, 2015 and June 30, 2015, appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference. Pending Regulatory Proceedings — Public Service Commission of Wisconsin (PSCW) Wisconsin 2016 Electric and Gas Rate Case — In May 2015, NSP-Wisconsin filed a request with the PSCW to increase rates for electric and natural gas service effective Jan. 1, 2016. NSP-Wisconsin requested an overall increase in annual electric rates of $27.4 million , or 3.9 percent , and an increase in natural gas rates of $5.9 million , or 5.0 percent . The rate filing is based on a 2016 forecast test year, a return on equity (ROE) of 10.2 percent , an equity ratio of 52.5 percent and a forecasted average net investment rate base of approximately $1.2 billion for the electric utility and $111.2 million for the natural gas utility. On Oct. 1, 2015, the PSCW Staff and other intervenors, including the Citizens Utility Board, filed their direct testimony in the case. The PSCW Staff recommended an electric rate increase of $10.4 million , or 1.5 percent , and a gas rate increase of $3.0 million , or 2.5 percent , based on a ROE of 10.0 percent and an equity ratio of 52.5 percent . The Citizens Utility Board recommended a ROE of 8.75 percent . None of the intervenors presented a complete revenue requirements analysis. The majority of the Staff adjustments relate to ROE, compensation issues and capital related forecast disputes. Key dates in the procedural schedule are as follows: • Initial Brief — Nov. 12, 2015; • Reply Brief — Nov. 19, 2015; • A PSCW decision is anticipated in December 2015; and • New rates effective on or about Jan.1, 2016. Recently Concluded Regulatory Proceedings — Minnesota Public Utilities Commission (MPUC) Nuclear Project Prudence Investigation — In 2013, NSP-Minnesota completed the Monticello life cycle management (LCM)/extended power uprate (EPU) project. The multi-year project extended the life of the facility and increased the capacity from 600 to 671 megawatts (MW). Monticello LCM/EPU project expenditures were approximately $665 million . Total capitalized costs were approximately $748 million , which includes allowance for funds used during construction (AFUDC). In 2008, project expenditures were initially estimated at approximately $320 million , excluding AFUDC. In 2013, the MPUC initiated an investigation to determine whether the final costs for the Monticello LCM/EPU project were prudent. In March 2015, the MPUC voted to allow for full recovery, including a return, on approximately $415 million of the total plant costs (inclusive of AFUDC), but only allow recovery of the remaining $333 million of costs with no return on this portion of the investment over the remaining life of the plant. Further, the MPUC determined that only 50 percent of the investment was considered used and useful for 2014. As a result of these determinations and assuming the other state commissions within the NSP System jurisdictions adopt the MPUC’s decisions, Xcel Energy recorded an estimated pre-tax loss of $129 million in the first quarter of 2015. The remaining book value of the Monticello project represents the present value of the estimated future cash flows allowed for by the MPUC. As NSP-Wisconsin shares in the costs of the Monticello plant through the Interchange Agreement with NSP-Minnesota, the MPUC decision also affects NSP-Wisconsin. NSP-Wisconsin’s portion of the $129 million pre-tax loss, recorded in the first quarter of 2015, was approximately $5 million . 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 certain MISO transmission owners (TOs), including NSP-Minnesota and NSP-Wisconsin. The complaint argued for a reduction in the ROE in transmission formula rates in the MISO region from 12.38 percent to 9.15 percent , a prohibition on capital structures in excess of 50 percent equity, and the removal of ROE adders (including those for regional transmission organization (RTO) membership and being an independent transmission company), effective Nov. 12, 2013. Subsequently, the FERC issued and upheld an order adopting a new ROE methodology, which requires electric utilities to use a two -step discounted cash flow analysis that incorporates both short-term and long-term growth projections to estimate the cost of equity. The ROE complaint was set for full hearing procedures. The complainants and intervenors filed testimony recommending a ROE between 8.67 percent and 9.54 percent . The FERC staff recommended a ROE of 8.68 percent . The MISO TOs recommended a ROE not less than 10.8 percent . An administrative law judge (ALJ) initial decision is anticipated to be issued by November 2015 and a FERC order is expected to be issued no earlier than 2016. Certain MISO TOs requested FERC approval of a 50 basis point RTO membership ROE adder, which was approved effective Jan. 6, 2015, subject to the outcome of the ROE complaint. The total ROE, including the RTO membership adder, may not exceed the top of the discounted cash flow range under the new ROE methodology. Certain intervenors sought rehearing of the FERC order granting the ROE adder; FERC action is pending. Certain intervenors filed a second complaint in February 2015 to reduce the MISO region ROE to 8.67 percent , prior to an adder. A hearing has been set, and a refund effective date of Feb. 12, 2015 was established. The complainants and intervenors filed direct testimony in September 2015 recommending ROEs between 8.72 percent and 9.13 percent . The MISO TOs filed answering testimony on Oct. 20, 2015, recommending a ROE of not less than 10.75 percent . FERC staff is expected to file testimony in November 2015, and a hearing is scheduled for February 2016. An ALJ initial decision is expected in June 2016 with a FERC decision in late 2016 or in 2017. Currently, the ROE refund obligation initiated under the November 2013 complaint is effective through May 2016. The MISO TOs sought rehearing of the FERC decision to allow back-to-back complaints. NSP-Minnesota and NSP-Wisconsin sought rehearing of the FERC’s decision not to order changes to the ROE used by non-jurisdictional MISO transmission owners (more than 20 municipal, cooperative and other utilities who are not respondents to the ROE complaints), which equals the ROE presently used by the jurisdictional MISO TOs. FERC action is pending. NSP-Minnesota recorded a current liability representing the current best estimate of a refund obligation associated with the new ROE as of Sept. 30, 2015. The new FERC ROE methodology is estimated to reduce transmission revenue, net of expense, between $7 million and $9 million annually for the NSP System. |
Commitments and Contingencies
Commitments and Contingencies | 9 Months Ended |
Sep. 30, 2015 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | Commitments and Contingencies Except to the extent noted below and in Note 5 above, the circumstances set forth in Notes 10 and 11 to the consolidated financial statements included in NSP-Wisconsin’s Annual Report on Form 10-K for the year ended Dec. 31, 2014 and in Notes 5 and 6 to the consolidated financial statements included in NSP-Wisconsin’s Quarterly Reports on Form 10-Q for the quarterly periods ended March 31, 2015 and June 30, 2015, appropriately represent, in all material respects, the current status of commitments and contingent liabilities, and are incorporated herein by reference. The following include commitments, contingencies and unresolved contingencies that are material to NSP-Wisconsin’s financial position. Guarantees NSP-Wisconsin provides a guarantee for payment of customer loans related to NSP-Wisconsin’s farm rewiring program. NSP-Wisconsin’s exposure under the guarantee is based upon the net liability under the agreement. The guarantee issued by NSP-Wisconsin limits its exposure to a maximum amount stated in the guarantee. The guarantee contains no recourse provisions and requires no collateral. The following table presents the guarantee issued and outstanding for NSP-Wisconsin: (Millions of Dollars) Sept. 30, 2015 Dec. 31, 2014 Guarantees issued and outstanding $ 1.0 $ 1.0 Current exposure under these guarantees 0.1 0.2 Environmental Contingencies Ashland Manufactured Gas Plant (MGP) Site — NSP-Wisconsin has been named a potentially responsible party (PRP) for contamination at a site in Ashland, Wis. The Ashland/Northern States Power Lakefront Superfund Site (the Ashland site) includes property owned by NSP-Wisconsin, which was a site previously operated by a predecessor company as a MGP facility (the Upper Bluff), and two other properties: an adjacent city lakeshore park area (Kreher Park), on which an unaffiliated third party previously operated a sawmill and where NSP-Wisconsin believes wood treating operations were conducted; and an area of Lake Superior’s Chequamegon Bay adjoining the park (the Sediments). The U.S. Environmental Protection Agency (EPA) issued its Record of Decision (ROD) in 2010, which describes the preferred remedy the EPA has selected for the cleanup of the Ashland site. For the Sediments at the Ashland site, the ROD preferred remedy is a hybrid remedy involving both dry excavation and wet conventional dredging methodologies (the Hybrid Remedy). The ROD also identifies the possibility of a wet conventional dredging only remedy for the Sediments (the Wet Dredge), contingent upon the completion of a successful Wet Dredge pilot study. In 2011, the EPA issued special notice letters identifying several entities, including NSP-Wisconsin, as PRPs, for future remediation at the Ashland site. As a result of settlement negotiations with NSP-Wisconsin, the EPA agreed to segment the Ashland site into separate areas. The first area (Phase I Project Area) includes soil and groundwater in Kreher Park and the Upper Bluff. The second area includes the Sediments. In October 2012, a settlement among the EPA, the Wisconsin Department of Natural Resources, the Bad River and Red Cliff Bands of the Lake Superior Tribe of Chippewa Indians and NSP-Wisconsin was approved by the U.S. District Court for the Western District of Wisconsin. This settlement resolves claims against NSP-Wisconsin for its alleged responsibility for the remediation of the Phase I Project Area. Under the terms of the settlement, NSP-Wisconsin agreed to perform the remediation of the Phase I Project Area, but does not admit any liability with respect to the Ashland site. Fieldwork to address the Phase I Project Area at the Ashland site began at the end of 2012 and continues. Demolition activities occurred at the Ashland site in 2013. Soil, including excavation and treatment, as well as containment wall remedies were completed in early 2015. In fall 2015, the ground water remedy was initiated at the site with the installation of groundwater wells and the start of construction on the groundwater treatment plant. The final design for the Phase I remedy was approved by the EPA in September 2015. The current cost estimate for the cleanup of the Phase I Project Area is approximately $57 million , of which approximately $39 million has already been spent. The settlement also resolves claims by the federal, state and tribal trustees against NSP-Wisconsin for alleged natural resource damages at the Ashland site, including both the Phase I Project Area and the Sediments. Negotiations are ongoing between the EPA and NSP-Wisconsin regarding who will pay for or perform the cleanup of the Sediments and what remedy will be implemented at the site to address the Sediments. It is NSP-Wisconsin’s view that the Hybrid Remedy is not safe or feasible to implement. The EPA’s ROD for the Ashland site includes estimates that the cost of the Hybrid Remedy is between $63 million and $77 million , with a potential deviation in such estimated costs of up to 50 percent higher to 30 percent lower. In November 2013, NSP-Wisconsin submitted a revised Wet Dredge pilot study work plan proposal to the EPA. In May 2014, NSP-Wisconsin entered into a final administrative order on consent (AOC) for the Wet Dredge pilot study with the EPA. In early 2015, NSP-Wisconsin entered into an AOC to construct a breakwater at the site to serve as wave attenuation and containment for a wet dredge pilot study and full scale sediment remedy at the site. Construction of the breakwater is underway with anticipated completion in early 2016. A wet dredge pilot study is anticipated to commence in summer 2016. In August 2012, NSP-Wisconsin also filed litigation against other PRPs for their share of the cleanup costs for the Ashland site. A final settlement has been reached between NSP-Wisconsin, along with the EPA, and two of the PRPs, Wisconsin Central Ltd. and Soo Line Railroad Co. (collectively, the “Railroad PRPs”) resolving claims relating to the Railroad PRPs’ share of the costs of cleanup at the Ashland site. NSP-Wisconsin also entered into a second private party settlement agreement with LE Myers Co. Under the agreements, the Railroad PRPs contributed $10.5 million and LE Myers Co. contributed $5.4 million to the costs of the cleanup at the Ashland site. The agreements for the Railroad PRPs and LE Myers Co. were approved by the U.S. District Court for the Western District of Wisconsin in 2015 and payment has been received. As discussed below, existing PSCW policy requires that any payments received from PRPs be used to reduce the amount of the cleanup costs ultimately recovered from customers. Trial with the remaining PRPs for this matter, County of Ashland and City of Ashland, took place in May 2015. In September 2015, the Court ruled that the County of Ashland is not a liable party and the City of Ashland, although a liable party, is not required to contribute any funds to the cleanup of the site. NSP-Wisconsin filed a notice of appeal with the Seventh Circuit Court of Appeals in October 2015. At Sept. 30, 2015 and Dec. 31, 2014, NSP-Wisconsin had recorded a liability of $95.7 million and $107.6 million , respectively, for the Ashland site based upon potential remediation and design costs together with estimated outside legal and consultant costs; of which $16.6 million and $28.9 million , respectively, was considered a current liability. NSP-Wisconsin’s potential liability, the actual cost of remediation and the time frame over which the amounts may be paid are subject to change. NSP-Wisconsin also continues to work to identify and access state and federal funds to apply to the ultimate remediation cost of the entire site. Unresolved issues or factors that could result in higher or lower NSP-Wisconsin remediation costs for the Ashland site include the cleanup approach implemented for the Sediments, which party implements the cleanup, the timing of when the cleanup is implemented and whether federal or state funding may be directed to help offset remediation costs at the Ashland site. NSP-Wisconsin has deferred the estimated site remediation costs, as a regulatory asset, based on an expectation that the PSCW will continue to allow NSP-Wisconsin to recover payments for environmental remediation from its customers. The PSCW has consistently authorized NSP-Wisconsin rate recovery for all remediation costs incurred at the Ashland site, and has authorized recovery of MGP remediation costs by other Wisconsin utilities. Under the established PSCW policy, once deferred MGP remediation costs are determined by the PSCW to be prudent, utilities are allowed to recover those deferred costs in natural gas rates, typically over a four - to six -year amortization period. The PSCW historically has not allowed utilities to recover their carrying costs on unamortized regulatory assets for MGP remediation. The PSCW reviewed the existing MGP cost recovery policy as it applied to the Ashland site in the context of NSP-Wisconsin’s 2013 general rate case. In December 2012, the PSCW recognized the potential magnitude of the future liability for the cleanup at the Ashland site and granted an exception to its existing policy at the request of NSP-Wisconsin. The elements of this exception include: (1) approval to begin recovery of estimated Phase 1 Project costs beginning on Jan. 1, 2013; (2) approval to amortize these estimated costs over a ten -year period; and (3) approval to apply a three percent carrying cost to the unamortized regulatory asset. In a 2014 rate case decision, the PSCW continued the cost recovery treatment with respect to the 2013 and 2014 cleanup costs for the Phase I Project Area and allowed NSP-Wisconsin to increase its 2014 amortization expense related to the cleanup by an additional $1.1 million to offset the need for a rate decrease for the natural gas utility. Cost recovery will continue at the level set in the 2014 rate case through 2015. In May 2015, NSP-Wisconsin filed its 2016 rate case, in which it requested an increase to the annual recovery for MGP clean-up costs from $4.7 million to $7.6 million . A decision is anticipated in December 2015. Environmental Requirements Water Federal Clean Water Act (CWA) Effluent Limitations Guidelines (ELG) — In September 2015, the EPA issued a final ELG rule for power plants that use coal, natural gas, oil or nuclear materials as fuel and discharge treated effluent to surface waters as well as utility-owned landfills that receive coal combustion residuals. NSP-Wisconsin is currently reviewing the final rule and cannot predict, at this time, whether the costs of compliance with the final rule will have a material impact on the results of operations, financial position or cash flows. NSP-Wisconsin believes that compliance costs would be recoverable through regulatory mechanisms. Federal CWA Waters of the United States Rule — In June 2015, the EPA and the U.S. Army Corps of Engineers published a final rule that significantly expands the types of water bodies regulated under the CWA and broadens the scope of waters subject to federal jurisdiction. The expansion of the term “Waters of the U.S.” will subject more utility projects to federal CWA jurisdiction, thereby potentially delaying the siting of new generation projects, pipelines, transmission lines and distribution lines, as well as increasing project costs and expanding permitting and reporting requirements. The rule went into effect in August 2015. On Oct. 9, 2015, the U.S. Court of Appeals for the Sixth Circuit issued a nationwide stay of the final rule, pending further legal proceedings. Air Green House Gas (GHG) Emission Standard for Existing Sources — In June 2014, the EPA published its proposed rule on GHG emission standards for existing power plants. A final rule was published in October 2015. States must develop implementation plans by September 2016, with the possibility of an extension to September 2018. If a state decides not to submit a plan, the EPA will prepare a federal plan for the state. In addition, the EPA published a proposed model federal plan and will provide a 90 -day public comment period on the federal plan once it has been published in the Federal Register. Among other things, the rule requires that state plans include enforceable measures to ensure emissions from existing power plants in the state achieve the EPA’s state-specific interim (2022-2029) and final (2030 and thereafter) emission performance targets. The plan will likely require additional emission reductions in states in which NSP-Wisconsin operates. Until NSP-Wisconsin has reviewed the final rule and has more information about state implementation plans, NSP-Wisconsin cannot predict whether the costs of compliance with the final rule will have a material impact on the results of operations, financial position or cash flows. NSP-Wisconsin believes that compliance costs will be recoverable through regulatory mechanisms. GHG New Source Performance Standard (NSPS) Proposal — In January 2014, the EPA re-proposed a GHG NSPS for newly constructed power plants which would set performance standards (maximum carbon dioxide emission rates) for coal- and natural gas-fired power plants. For coal power plants, the NSPS requires an emissions level equivalent to partial carbon capture and storage (CCS) technology; for natural gas-fired power plants, the NSPS reflects emissions levels from combined cycle technology with no CCS. The NSPS does not apply to modified or reconstructed existing power plants. In addition, installation of control equipment on existing plants would not constitute a “modification” to those plants under the NSPS program. The final rule was published in October 2015. NSP-Wisconsin does not anticipate the costs of compliance with the final rule will have a material impact on the results of operations, financial position or cash flows. GHG NSPS for Modified and Reconstructed Power Plants — In June 2014, the EPA published a proposed NSPS that would apply to GHG emissions from power plants that are modified or reconstructed. A final rule was published in October 2015. A modification is a change to an existing source that increases the maximum achievable hourly rate of emissions. A reconstruction involves the replacement of components at a unit to the extent that the capital cost of the new components exceeds 50 percent of the capital cost of an entirely new comparable unit. The standards do not require installation of CCS technology. Instead, the standard for coal-fired power plants requires a combination of best operating practices and equipment upgrades. The standards for natural gas-fired power plants require emissions standards based on efficient combined cycle technology. These requirements would only apply if NSP-Wisconsin were to modify or reconstruct an existing power plant in the future in a way that triggers applicability of this rule. Cross-State Air Pollution Rule (CSAPR) — CSAPR addresses long range transport of particulate matter and ozone by requiring reductions in sulfur dioxide (SO 2) and nitrous oxide (NOx) from utilities in the eastern half of the United States, including Wisconsin, using an emissions trading program. In August 2012, the United States District Court of Appeals for the District of Columbia Circuit (D.C. Circuit) vacated the CSAPR and remanded it back to the EPA. The D.C. Circuit stated the EPA must continue administering the Clean Air Interstate Rule pending adoption of a valid replacement. In April 2014, the U.S. Supreme Court reversed and remanded the case to the D.C. Circuit. The Supreme Court held that the EPA’s rule design did not violate the Clean Air Act and that states had received adequate opportunity to develop their own plans. Because the D.C. Circuit overturned the CSAPR on two over-arching issues, there are many other issues the D.C. Circuit did not rule on that were considered on remand. In July 2015, the D.C. Circuit issued an opinion which found the reduction budgets exceed what is necessary for Texas to reduce its impact on downwind states that do not meet ambient air quality standards. The D.C. Circuit remanded the matter to the EPA to reconsider the emission budgets. While the EPA reconsiders emission budgets, the D.C. Circuit left CSAPR in effect. In October 2014, the D.C. Circuit granted the EPA’s request to begin to implement CSAPR by imposing its 2012 compliance obligations starting in January 2015. While the litigation continues, the EPA is administering the CSAPR in 2015. NSP-Wisconsin can operate within its CSAPR emission allowance allocation for SO 2 . NSP-Wisconsin is complying with the CSAPR for NOx in 2015 through operational changes or allowance purchases. CSAPR compliance in 2015 is not having a material impact on the results of operations, financial position or cash flows. Electric Generating Unit (EGU) Mercury and Air Toxics Standards (MATS) Rule — The final EGU MATS rule became effective in April 2012. The EGU MATS rule sets emission limits for acid gases, mercury and other hazardous air pollutants and requires coal-fired utility facilities greater than 25 MW to demonstrate compliance within three to four years of the effective date. In 2014, the U.S. Supreme Court decided to review the D.C. Circuit’s decision that upheld the MATS standard. By April 2015, the MATS compliance deadline, NSP-Wisconsin had met the EGU MATS rule by ending use of coal at Bay Front Unit 5. In June 2015, the U.S. Supreme Court found that the EPA acted unreasonably by not considering the cost to regulate mercury and other hazardous air pollutants. The D.C. Circuit, on remand, will decide whether to leave MATS in effect while the EPA considers such costs in making a new determination. NSP-Wisconsin believes EGU MATS costs will be recoverable through regulatory mechanisms and does not anticipate a material impact on the results of operations, financial position or cash flows. Industrial Boiler (IB) Maximum Achievable Control Technology (MACT) Rules — In 2011, the EPA finalized IB MACT rules to regulate boilers and process heaters fueled with coal, biomass and liquid fuels, which would apply to NSP-Wisconsin’s Bay Front Units 1 and 2. The project to meet the requirements was completed in September 2015 with an estimated cost of approximately $20 million . Revisions to the NAAQS for Ozone — In October 2015, the EPA revised the NAAQS for ozone by lowering the eight -hour standard from 75 parts per billion (ppb) to 70 ppb. Current monitored air quality concentrations in areas of Wisconsin, where NSP-Wisconsin operates, are below the new standard. Therefore, NSP-Wisconsin does not expect a material impact on results of operations, financial position or cash flows. Legal Contingencies NSP-Wisconsin 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 NSP-Wisconsin’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. In 2009, five of the cases were settled and one was dismissed. The U.S. District Court in 2011 issued an order dismissing entirely six of the remaining seven lawsuits, and partially dismissing the seventh. Plaintiffs appealed the dismissals to the U.S. Court of Appeals for the Ninth Circuit, which reversed the District Court. The matter was ultimately heard by the U.S. Supreme Court in early 2015, which agreed with the Ninth Circuit and remanded the matter to the U.S. District Court. In September 2015, the District Court held a status conference and set deadlines for certain litigation related activities in 2016. A trial date has not yet been set, but is not expected to occur prior to late 2016 or early 2017. Xcel Energy and e prime have concluded that a loss is remote with respect to this matter. |
Borrowings and Other Financing
Borrowings and Other Financing Instruments | 9 Months Ended |
Sep. 30, 2015 | |
Debt Disclosure [Abstract] | |
Borrowings and Other Financing Instruments | Borrowings and Other Financing Instruments Commercial Paper — NSP-Wisconsin meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facility. Commercial paper outstanding for NSP-Wisconsin was as follows: (Amounts in Millions, Except Interest Rates) Three Months Ended Sept. 30, 2015 Twelve Months Ended Dec. 31, 2014 Borrowing limit $ 150 $ 150 Amount outstanding at period end — 78 Average amount outstanding — 46 Maximum amount outstanding — 101 Weighted average interest rate, computed on a daily basis N/A 0.27 % Weighted average interest rate at period end N/A 0.55 Letters of Credit — NSP-Wisconsin uses letters of credit, generally with terms of one year , to provide financial guarantees for certain operating obligations. At Sept. 30, 2015 and Dec. 31, 2014 , there were no letters of credit outstanding. Credit Facility — In order to use its commercial paper program to fulfill short-term funding needs, NSP-Wisconsin must have a revolving credit facility in place at least equal to the amount of its commercial paper borrowing limit and cannot issue commercial paper in an aggregate amount exceeding available capacity under this credit facility. The line of credit provides short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings. At Sept. 30, 2015 , NSP-Wisconsin had the following committed credit facility available (in millions of dollars): Credit Facility (a) Drawn (b) Available $ 150 $ — $ 150 (a) This credit facility expires in October 2019. (b) Includes outstanding commercial paper. All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facility. NSP-Wisconsin had no direct advances on the credit facility outstanding at Sept. 30, 2015 and Dec. 31, 2014 . Other Short-Term Borrowings — The following table presents the notes payable of Clearwater Investments, Inc., a NSP-Wisconsin subsidiary, to Xcel Energy Inc.: (Amounts in Millions, Except Interest Rates) Sept. 30, 2015 Dec. 31, 2014 Notes payable to affiliates $ 0.5 $ 0.5 Weighted average interest rate at period end 0.38 % 0.51 % Long-Term Borrowings In June 2015 , NSP-Wisconsin issued $100 million of 3.3 percent first mortgage bonds due June 15, 2024. |
Fair Value of Financial Assets
Fair Value of Financial Assets and Liabilities | 9 Months Ended |
Sep. 30, 2015 | |
Fair Value Disclosures [Abstract] | |
Fair Value of Financial Assets and Liabilities | Fair Value of Financial Assets and Liabilities Fair Value Measurements The accounting guidance for fair value measurements and disclosures provides a single definition of fair value and requires certain disclosures about assets and liabilities measured at fair value. A hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value is established by this guidance. The three levels in the hierarchy are as follows: Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices. Level 2 — Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reporting date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts or priced with models using highly observable inputs. Level 3 — Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 are those valued with models requiring significant management judgment or estimation. Specific valuation methods include the following: Cash equivalents — The fair values of cash equivalents are generally based on cost plus accrued interest; money market funds are measured using quoted net asset values. 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. Derivative Instruments Fair Value Measurements NSP-Wisconsin 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 and utility commodity prices. Interest Rate Derivatives — NSP-Wisconsin enters into various instruments that effectively fix the interest payments on certain floating rate debt obligations or effectively fix the yield or price on a specified benchmark interest rate for an anticipated debt issuance for a specific period. These derivative instruments are generally designated as cash flow hedges for accounting purposes. At Sept. 30, 2015 , accumulated other comprehensive loss related to interest rate derivatives included $0.1 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. Commodity Derivatives — NSP-Wisconsin may enter 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 natural gas to generate electric energy and natural gas for resale. The following table details the gross notional amounts of commodity options at Sept. 30, 2015 and Dec. 31, 2014 : (Amounts in Thousands) (a)(b) Sept. 30, 2015 Dec. 31, 2014 Million British thermal units of natural gas 642 18 (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 Activities on Income and Accumulated Other Comprehensive Loss — There were immaterial pre-tax losses related to interest rate derivatives reclassified from accumulated other comprehensive loss into earnings during the three months ended Sept. 30, 2015 and 2014 , and $0.1 million of net losses reclassified from accumulated other comprehensive loss into earnings during the nine months ended Sept. 30, 2015 and 2014. During the three months and nine months ended Sept. 30, 2015 , changes in the fair value of natural gas commodity derivatives resulted in immaterial and $0.1 million of net losses recognized as regulatory assets and liabilities, respectively. For the three and nine months ended Sept. 30, 2014 , changes in the fair value of natural gas commodity derivatives resulted in immaterial net losses and net gains of $0.7 million , respectively, recognized as regulatory assets and liabilities. The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. Natural gas commodity derivatives settlement losses of $1.0 million and gains of $0.5 million were recognized for the nine months ended Sept. 30, 2015 and 2014, respectively, and were subject to purchased natural gas cost recovery mechanisms, which result in reclassifications of derivative settlement gains and losses out of income to a regulatory asset or liability, as appropriate. There were immaterial natural gas commodity derivatives settlement losses recognized during the three months ended Sept. 30, 2015 and 2014, respectively. NSP-Wisconsin had no derivative instruments designated as fair value hedges during the three and nine months ended Sept. 30, 2015 and 2014 . Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for these periods. Consideration of Credit Risk and Concentrations — NSP-Wisconsin 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 NSP-Wisconsin’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. NSP-Wisconsin employs 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. Recurring Fair Value Measurements — The following tables present for each of the fair value hierarchy levels, NSP-Wisconsin’s derivative assets and liabilities measured at fair value on a recurring basis: Sept. 30, 2015 Fair Value Fair Value Total Counterparty Netting (a) Total (b) (Thousands of Dollars) Level 1 Level 2 Level 3 Current derivative assets Natural gas commodity $ — $ 292 $ — $ 292 $ (22 ) $ 270 Total current derivative assets $ — $ 292 $ — $ 292 $ (22 ) $ 270 Current derivative liabilities Natural gas commodity $ — $ 94 $ — $ 94 $ (22 ) $ 72 Total current derivative liabilities $ — $ 94 $ — $ 94 $ (22 ) $ 72 Dec. 31, 2014 Fair Value Fair Value Total Counterparty Netting (a) Total (b) (Thousands of Dollars) Level 1 Level 2 Level 3 Current derivative assets Natural gas commodity $ — $ 52 $ — $ 52 $ — $ 52 (a) NSP-Wisconsin nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Sept. 30, 2015 and Dec. 31, 2014 . The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements. (b) Included in prepayments and other assets balance of $2.9 million and $6.9 million at Sept. 30, 2015 and Dec. 31, 2014, respectively, and other current liabilities balance of $24.4 million at Sept. 30, 2015, in the consolidated balance sheets. Fair Value of Long-Term Debt As of Sept. 30, 2015 and Dec. 31, 2014 , other financial instruments for which the carrying amount did not equal fair value were as follows: Sept. 30, 2015 Dec. 31, 2014 (Thousands of Dollars) Carrying Amount Fair Value Carrying Amount Fair Value Long-term debt, including current portion $ 667,575 $ 749,183 $ 568,291 $ 670,665 The fair value of NSP-Wisconsin’s long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities. The fair value estimates are based on information available to management as of Sept. 30, 2015 and Dec. 31, 2014 , 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 (Expense) Income, Net
Other (Expense) Income, Net | 9 Months Ended |
Sep. 30, 2015 | |
Other Income and Expenses [Abstract] | |
Other (Expense) Income, Net | Other Income (Expense), Net Other income (expense), net consisted of the following: Three Months Ended Sept. 30 Nine Months Ended Sept. 30 (Thousands of Dollars) 2015 2014 2015 2014 Interest income $ 11 $ 21 $ 299 $ 237 Other nonoperating income 72 29 202 108 Insurance policy income (expense) 20 (56 ) (109 ) (292 ) Other nonoperating expense (3 ) (3 ) (8 ) (8 ) Other income (expense), net $ 100 $ (9 ) $ 384 $ 45 |
Segment Information
Segment Information | 9 Months Ended |
Sep. 30, 2015 | |
Segment Reporting [Abstract] | |
Segment Information | Segment Information Operating results from the regulated electric utility and regulated natural gas utility are each separately and regularly reviewed by NSP-Wisconsin’s chief operating decision maker. NSP-Wisconsin evaluates performance 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. NSP-Wisconsin has the following reportable segments: regulated electric utility, regulated natural gas utility and all other. • NSP-Wisconsin’s regulated electric utility segment generates, transmits and distributes electricity primarily in portions of Wisconsin and Michigan. • NSP-Wisconsin’s regulated natural gas utility segment purchases, transports, stores and distributes natural gas primarily in portions of Wisconsin and Michigan. • 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 investments in rental housing projects that qualify for low-income housing tax credits. Asset and capital expenditure information is not provided for NSP-Wisconsin’s reportable segments because as an integrated electric and natural gas utility, NSP-Wisconsin operates significant assets that are not dedicated to a specific business segment, and reporting assets and capital expenditures by business segment would require arbitrary and potentially misleading allocations which may not necessarily reflect the assets that would be required for the operation of the business segments on a stand-alone basis. To report income from operations for regulated electric and regulated natural gas utility segments, the majority of costs are directly assigned to each segment. However, some costs, such as common depreciation, common operating and maintenance (O&M) expenses and interest expense are allocated based on cost causation allocators. A general allocator is used for certain general and administrative expenses, including office supplies, rent, property insurance and general advertising. (Thousands of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total Three Months Ended Sept. 30, 2015 Operating revenues (a) $ 224,666 $ 11,088 $ 407 $ — $ 236,161 Intersegment revenues 101 177 (278 ) — Total revenues $ 224,767 $ 11,265 $ 407 $ (278 ) $ 236,161 Net income (loss) $ 28,285 $ (1,993 ) $ (60 ) $ — $ 26,232 (Thousands of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total Three Months Ended Sept. 30, 2014 Operating revenues (a) $ 216,289 $ 14,484 $ 273 $ — $ 231,046 Intersegment revenues 93 425 — (518 ) — Total revenues $ 216,382 $ 14,909 $ 273 $ (518 ) $ 231,046 Net income (loss) $ 21,227 $ (2,003 ) $ 806 $ — $ 20,030 (a) Operating revenues include $42 million and $33 million of affiliate electric revenue for the three months ended Sept. 30, 2015 and 2014 , respectively. (Thousands of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total Nine Months Ended Sept. 30, 2015 Operating revenues (a)(b) $ 634,571 $ 91,273 $ 1,090 $ — $ 726,934 Intersegment revenues 308 475 — (783 ) — Total revenues $ 634,879 $ 91,748 $ 1,090 $ (783 ) $ 726,934 Net income (loss) $ 57,586 (b) $ 3,714 $ (289 ) $ — $ 61,011 (Thousands of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total Nine Months Ended Sept. 30, 2014 Operating revenues (a) $ 625,663 $ 117,814 $ 825 $ — $ 744,302 Intersegment revenues 308 4,191 — (4,499 ) — Total revenues $ 625,971 $ 122,005 $ 825 $ (4,499 ) $ 744,302 Net income $ 48,092 $ 5,565 $ 2,630 $ — $ 56,287 (a) Operating revenues include $121 million and $97 million of affiliate electric revenue for the nine months ended Sept. 30, 2015 and 2014 , respectively. (b) Includes a net of tax charge related to the Monticello LCM/EPU project. See Note 5. |
Benefit Plans and Other Postret
Benefit Plans and Other Postretirement Benefits | 9 Months Ended |
Sep. 30, 2015 | |
Compensation and Retirement Disclosure [Abstract] | |
Benefit Plans and Other Postretirement Benefits | Benefit Plans and Other Postretirement Benefits Components of Net Periodic Benefit Cost Three Months Ended Sept. 30 2015 2014 2015 2014 (Thousands of Dollars) Pension Benefits Postretirement Health Care Benefits Service cost $ 1,190 $ 1,132 $ 7 $ 9 Interest cost 1,630 1,814 164 198 Expected return on plan assets (2,371 ) (2,411 ) (8 ) (13 ) Amortization of prior service cost (credit) 27 28 (87 ) (88 ) Amortization of net loss 1,701 1,654 114 167 Net benefit cost recognized for financial reporting $ 2,177 $ 2,217 $ 190 $ 273 Nine Months Ended Sept. 30 2015 2014 2015 2014 (Thousands of Dollars) Pension Benefits Postretirement Health Care Benefits Service cost $ 3,570 $ 3,396 $ 21 $ 26 Interest cost 4,890 5,442 490 593 Expected return on plan assets (7,113 ) (7,232 ) (23 ) (39 ) Amortization of prior service cost (credit) 83 84 (263 ) (263 ) Amortization of net loss 5,103 4,962 342 500 Net benefit cost recognized for financial reporting $ 6,533 $ 6,652 $ 567 $ 817 In January 2015, contributions of $90.0 million were made across four of Xcel Energy’s pension plans, of which $4.9 million was attributable to NSP-Wisconsin. Xcel Energy does not expect additional pension contributions during 2015. |
Other Comprehensive Income
Other Comprehensive Income | 9 Months Ended |
Sep. 30, 2015 | |
Stockholders' Equity Note [Abstract] | |
Other Comprehensive Income | Other Comprehensive Income Changes in accumulated other comprehensive loss, net of tax, for the three and nine months ended Sept. 30, 2015 and 2014 were as follows: Gains and Losses on Cash Flow Hedges (Thousands of Dollars) Three Months Ended Sept. 30, 2015 Three Months Ended Sept. 30, 2014 Accumulated other comprehensive loss at July 1 $ (247 ) $ (324 ) Losses reclassified from net accumulated other comprehensive loss 19 20 Net current period other comprehensive income 19 20 Accumulated other comprehensive loss at Sept. 30 $ (228 ) $ (304 ) Gains and Losses on Cash Flow Hedges (Thousands of Dollars) Nine Months Ended Sept. 30, 2015 Nine Months Ended Sept. 30, 2014 Accumulated other comprehensive loss at Jan. 1 $ (285 ) $ (361 ) Losses reclassified from net accumulated other comprehensive loss 57 57 Net current period other comprehensive income 57 57 Accumulated other comprehensive loss at Sept. 30 $ (228 ) $ (304 ) Reclassifications from accumulated other comprehensive loss for the three and nine months ended Sept. 30, 2015 and 2014 were as follows: Amounts Reclassified from Accumulated Other Comprehensive Loss (Thousands of Dollars) Three Months Ended Sept. 30, 2015 Three Months Ended Sept. 30, 2014 Losses on cash flow hedges: Interest rate derivatives $ 32 (a) $ 32 (a) Total, pre-tax 32 32 Tax benefit (13 ) (12 ) Total amounts reclassified, net of tax $ 19 $ 20 Amounts Reclassified from Accumulated Other Comprehensive Loss (Thousands of Dollars) Nine Months Ended Sept. 30, 2015 Nine Months Ended Sept. 30, 2014 Losses on cash flow hedges: Interest rate derivatives $ 94 (a) $ 95 (a) Total, pre-tax 94 95 Tax benefit (37 ) (38 ) Total amounts reclassified, net of tax $ 57 $ 57 (a) Included in interest charges. |
Selected Balance Sheet Data (Ta
Selected Balance Sheet Data (Tables) | 9 Months Ended | |
Sep. 30, 2015 | ||
Balance Sheet Related Disclosures [Abstract] | ||
Accounts Receivable, Net | (Thousands of Dollars) Sept. 30, 2015 Dec. 31, 2014 Accounts receivable, net (a) Accounts receivable $ 55,204 $ 66,217 Less allowance for bad debts (4,834 ) (5,821 ) $ 50,370 $ 60,396 | [1] |
Inventories | (Thousands of Dollars) Sept. 30, 2015 Dec. 31, 2014 Inventories Materials and supplies $ 6,865 $ 6,494 Fuel 6,376 6,654 Natural gas 8,597 11,537 $ 21,838 $ 24,685 | |
Property, Plant and Equipment, Net | (Thousands of Dollars) Sept. 30, 2015 Dec. 31, 2014 Property, plant and equipment, net Electric plant $ 2,332,155 $ 2,061,669 Natural gas plant 264,390 255,465 Common and other property 124,584 125,938 Construction work in progress 112,108 231,413 Total property, plant and equipment 2,833,237 2,674,485 Less accumulated depreciation (1,043,903 ) (1,000,204 ) $ 1,789,334 $ 1,674,281 | |
[1] | Accounts receivable, net includes an immaterial amount due from affiliates as of Sept. 30, 2015 and Dec. 31, 2014, respectively. |
Income Taxes (Tables)
Income Taxes (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Income Tax Disclosure [Abstract] | |
Reconciliation of Unrecognized Tax Benefits | A reconciliation of the amount of unrecognized tax benefit is as follows: (Millions of Dollars) Sept. 30, 2015 Dec. 31, 2014 Unrecognized tax benefit — Permanent tax positions $ 0.2 $ 0.1 Unrecognized tax benefit — Temporary tax positions 2.9 2.9 Total unrecognized tax benefit $ 3.1 $ 3.0 |
Tax Benefits Associated with NOL and Tax Credit Carryforwards | The unrecognized tax benefit amounts were reduced by the tax benefits associated with net operating loss (NOL) and tax credit carryforwards. The amounts of tax benefits associated with NOL and tax credit carryforwards are as follows: (Millions of Dollars) Sept. 30, 2015 Dec. 31, 2014 NOL and tax credit carryforwards $ (1.0 ) $ (0.9 ) |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Commitments and Contingencies Disclosure [Abstract] | |
Guarantees Issued and Outstanding | The following table presents the guarantee issued and outstanding for NSP-Wisconsin: (Millions of Dollars) Sept. 30, 2015 Dec. 31, 2014 Guarantees issued and outstanding $ 1.0 $ 1.0 Current exposure under these guarantees 0.1 0.2 |
Borrowings and Other Financin25
Borrowings and Other Financing Instruments (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Borrowings and Other Financing Instruments [Abstract] | |
Credit Facilities | At Sept. 30, 2015 , NSP-Wisconsin had the following committed credit facility available (in millions of dollars): Credit Facility (a) Drawn (b) Available $ 150 $ — $ 150 (a) This credit facility expires in October 2019. (b) Includes outstanding commercial paper. |
Commercial Paper | |
Borrowings and Other Financing Instruments [Abstract] | |
Short-Term Borrowings | Commercial paper outstanding for NSP-Wisconsin was as follows: (Amounts in Millions, Except Interest Rates) Three Months Ended Sept. 30, 2015 Twelve Months Ended Dec. 31, 2014 Borrowing limit $ 150 $ 150 Amount outstanding at period end — 78 Average amount outstanding — 46 Maximum amount outstanding — 101 Weighted average interest rate, computed on a daily basis N/A 0.27 % Weighted average interest rate at period end N/A 0.55 |
Notes Payable To Affiliates | |
Borrowings and Other Financing Instruments [Abstract] | |
Short-Term Borrowings | Other Short-Term Borrowings — The following table presents the notes payable of Clearwater Investments, Inc., a NSP-Wisconsin subsidiary, to Xcel Energy Inc.: (Amounts in Millions, Except Interest Rates) Sept. 30, 2015 Dec. 31, 2014 Notes payable to affiliates $ 0.5 $ 0.5 Weighted average interest rate at period end 0.38 % 0.51 % |
Fair Value of Financial Asset26
Fair Value of Financial Assets and Liabilities (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Fair Value Disclosures [Abstract] | |
Gross Notional Amounts of Commodity Forwards and Options | The following table details the gross notional amounts of commodity options at Sept. 30, 2015 and Dec. 31, 2014 : (Amounts in Thousands) (a)(b) Sept. 30, 2015 Dec. 31, 2014 Million British thermal units of natural gas 642 18 (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. |
Derivative Assets and Liabilities Measured at Fair Value on a Recurring Basis by Hierarchy Level | Recurring Fair Value Measurements — The following tables present for each of the fair value hierarchy levels, NSP-Wisconsin’s derivative assets and liabilities measured at fair value on a recurring basis: Sept. 30, 2015 Fair Value Fair Value Total Counterparty Netting (a) Total (b) (Thousands of Dollars) Level 1 Level 2 Level 3 Current derivative assets Natural gas commodity $ — $ 292 $ — $ 292 $ (22 ) $ 270 Total current derivative assets $ — $ 292 $ — $ 292 $ (22 ) $ 270 Current derivative liabilities Natural gas commodity $ — $ 94 $ — $ 94 $ (22 ) $ 72 Total current derivative liabilities $ — $ 94 $ — $ 94 $ (22 ) $ 72 Dec. 31, 2014 Fair Value Fair Value Total Counterparty Netting (a) Total (b) (Thousands of Dollars) Level 1 Level 2 Level 3 Current derivative assets Natural gas commodity $ — $ 52 $ — $ 52 $ — $ 52 (a) NSP-Wisconsin nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Sept. 30, 2015 and Dec. 31, 2014 . The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements. (b) Included in prepayments and other assets balance of $2.9 million and $6.9 million at Sept. 30, 2015 and Dec. 31, 2014, respectively, and other current liabilities balance of $24.4 million at Sept. 30, 2015, in the consolidated balance sheets. |
Carrying Amount and Fair Value of Long-term Debt | As of Sept. 30, 2015 and Dec. 31, 2014 , other financial instruments for which the carrying amount did not equal fair value were as follows: Sept. 30, 2015 Dec. 31, 2014 (Thousands of Dollars) Carrying Amount Fair Value Carrying Amount Fair Value Long-term debt, including current portion $ 667,575 $ 749,183 $ 568,291 $ 670,665 |
Other (Expense) Income, Net (Ta
Other (Expense) Income, Net (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Other Income and Expenses [Abstract] | |
Other (Expense) Income, Net | Other income (expense), net consisted of the following: Three Months Ended Sept. 30 Nine Months Ended Sept. 30 (Thousands of Dollars) 2015 2014 2015 2014 Interest income $ 11 $ 21 $ 299 $ 237 Other nonoperating income 72 29 202 108 Insurance policy income (expense) 20 (56 ) (109 ) (292 ) Other nonoperating expense (3 ) (3 ) (8 ) (8 ) Other income (expense), net $ 100 $ (9 ) $ 384 $ 45 |
Segment Information (Tables)
Segment Information (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Segment Reporting [Abstract] | |
Results by Reportable Segment | (Thousands of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total Three Months Ended Sept. 30, 2015 Operating revenues (a) $ 224,666 $ 11,088 $ 407 $ — $ 236,161 Intersegment revenues 101 177 (278 ) — Total revenues $ 224,767 $ 11,265 $ 407 $ (278 ) $ 236,161 Net income (loss) $ 28,285 $ (1,993 ) $ (60 ) $ — $ 26,232 (Thousands of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total Three Months Ended Sept. 30, 2014 Operating revenues (a) $ 216,289 $ 14,484 $ 273 $ — $ 231,046 Intersegment revenues 93 425 — (518 ) — Total revenues $ 216,382 $ 14,909 $ 273 $ (518 ) $ 231,046 Net income (loss) $ 21,227 $ (2,003 ) $ 806 $ — $ 20,030 (a) Operating revenues include $42 million and $33 million of affiliate electric revenue for the three months ended Sept. 30, 2015 and 2014 , respectively. (Thousands of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total Nine Months Ended Sept. 30, 2015 Operating revenues (a)(b) $ 634,571 $ 91,273 $ 1,090 $ — $ 726,934 Intersegment revenues 308 475 — (783 ) — Total revenues $ 634,879 $ 91,748 $ 1,090 $ (783 ) $ 726,934 Net income (loss) $ 57,586 (b) $ 3,714 $ (289 ) $ — $ 61,011 (Thousands of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total Nine Months Ended Sept. 30, 2014 Operating revenues (a) $ 625,663 $ 117,814 $ 825 $ — $ 744,302 Intersegment revenues 308 4,191 — (4,499 ) — Total revenues $ 625,971 $ 122,005 $ 825 $ (4,499 ) $ 744,302 Net income $ 48,092 $ 5,565 $ 2,630 $ — $ 56,287 (a) Operating revenues include $121 million and $97 million of affiliate electric revenue for the nine months ended Sept. 30, 2015 and 2014 , respectively. (b) Includes a net of tax charge related to the Monticello LCM/EPU project. See Note 5. |
Benefit Plans and Other Postr29
Benefit Plans and Other Postretirement Benefits (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Compensation and Retirement Disclosure [Abstract] | |
Components of Net Periodic Benefit Cost | Components of Net Periodic Benefit Cost Three Months Ended Sept. 30 2015 2014 2015 2014 (Thousands of Dollars) Pension Benefits Postretirement Health Care Benefits Service cost $ 1,190 $ 1,132 $ 7 $ 9 Interest cost 1,630 1,814 164 198 Expected return on plan assets (2,371 ) (2,411 ) (8 ) (13 ) Amortization of prior service cost (credit) 27 28 (87 ) (88 ) Amortization of net loss 1,701 1,654 114 167 Net benefit cost recognized for financial reporting $ 2,177 $ 2,217 $ 190 $ 273 Nine Months Ended Sept. 30 2015 2014 2015 2014 (Thousands of Dollars) Pension Benefits Postretirement Health Care Benefits Service cost $ 3,570 $ 3,396 $ 21 $ 26 Interest cost 4,890 5,442 490 593 Expected return on plan assets (7,113 ) (7,232 ) (23 ) (39 ) Amortization of prior service cost (credit) 83 84 (263 ) (263 ) Amortization of net loss 5,103 4,962 342 500 Net benefit cost recognized for financial reporting $ 6,533 $ 6,652 $ 567 $ 817 |
Other Comprehensive Income (Tab
Other Comprehensive Income (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Stockholders' Equity Note [Abstract] | |
Changes in Accumulated Other Comprehensive Loss, Net of Tax | Changes in accumulated other comprehensive loss, net of tax, for the three and nine months ended Sept. 30, 2015 and 2014 were as follows: Gains and Losses on Cash Flow Hedges (Thousands of Dollars) Three Months Ended Sept. 30, 2015 Three Months Ended Sept. 30, 2014 Accumulated other comprehensive loss at July 1 $ (247 ) $ (324 ) Losses reclassified from net accumulated other comprehensive loss 19 20 Net current period other comprehensive income 19 20 Accumulated other comprehensive loss at Sept. 30 $ (228 ) $ (304 ) Gains and Losses on Cash Flow Hedges (Thousands of Dollars) Nine Months Ended Sept. 30, 2015 Nine Months Ended Sept. 30, 2014 Accumulated other comprehensive loss at Jan. 1 $ (285 ) $ (361 ) Losses reclassified from net accumulated other comprehensive loss 57 57 Net current period other comprehensive income 57 57 Accumulated other comprehensive loss at Sept. 30 $ (228 ) $ (304 ) |
Reclassifications out of Accumulated Other Comprehensive Loss | Reclassifications from accumulated other comprehensive loss for the three and nine months ended Sept. 30, 2015 and 2014 were as follows: Amounts Reclassified from Accumulated Other Comprehensive Loss (Thousands of Dollars) Three Months Ended Sept. 30, 2015 Three Months Ended Sept. 30, 2014 Losses on cash flow hedges: Interest rate derivatives $ 32 (a) $ 32 (a) Total, pre-tax 32 32 Tax benefit (13 ) (12 ) Total amounts reclassified, net of tax $ 19 $ 20 Amounts Reclassified from Accumulated Other Comprehensive Loss (Thousands of Dollars) Nine Months Ended Sept. 30, 2015 Nine Months Ended Sept. 30, 2014 Losses on cash flow hedges: Interest rate derivatives $ 94 (a) $ 95 (a) Total, pre-tax 94 95 Tax benefit (37 ) (38 ) Total amounts reclassified, net of tax $ 57 $ 57 (a) Included in interest charges. |
Selected Balance Sheet Data, Ac
Selected Balance Sheet Data, Accounts Receivable (Details) - USD ($) $ in Thousands | Sep. 30, 2015 | Dec. 31, 2014 |
Accounts Receivable, Net | ||
Accounts receivable | $ 55,204 | $ 66,217 |
Less allowance for bad debts | (4,834) | (5,821) |
Accounts receivable, net | $ 50,370 | $ 60,396 |
Selected Balance Sheet Data, In
Selected Balance Sheet Data, Inventory (Details) - USD ($) $ in Thousands | Sep. 30, 2015 | Dec. 31, 2014 |
Public Utilities, Inventory [Line Items] | ||
Inventories | $ 21,838 | $ 24,685 |
Materials and supplies | ||
Public Utilities, Inventory [Line Items] | ||
Inventories | 6,865 | 6,494 |
Fuel | ||
Public Utilities, Inventory [Line Items] | ||
Inventories | 6,376 | 6,654 |
Natural gas | ||
Public Utilities, Inventory [Line Items] | ||
Inventories | $ 8,597 | $ 11,537 |
Selected Balance Sheet Data, Pr
Selected Balance Sheet Data, Property, Plant and Equipment (Details) - USD ($) $ in Thousands | Sep. 30, 2015 | Dec. 31, 2014 |
Public Utility, Property, Plant and Equipment [Line Items] | ||
Property, Plant and Equipment, Gross | $ 2,833,237 | $ 2,674,485 |
Less accumulated depreciation | (1,043,903) | (1,000,204) |
Property, plant and equipment, net | 1,789,334 | 1,674,281 |
Electric plant | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Property, Plant and Equipment, Gross | 2,332,155 | 2,061,669 |
Natural gas plant | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Property, Plant and Equipment, Gross | 264,390 | 255,465 |
Common and other property | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Property, Plant and Equipment, Gross | 124,584 | 125,938 |
Construction work in progress | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Property, Plant and Equipment, Gross | $ 112,108 | $ 231,413 |
Income Taxes (Details)
Income Taxes (Details) - USD ($) | 3 Months Ended | 9 Months Ended | |
Sep. 30, 2012 | Sep. 30, 2015 | Dec. 31, 2014 | |
Unrecognized Tax Benefits [Abstract] | |||
Unrecognized tax benefit — Permanent tax positions | $ 200,000 | $ 100,000 | |
Unrecognized tax benefit — Temporary tax positions | 2,900,000 | 2,900,000 | |
Total unrecognized tax benefit | 3,100,000 | 3,000,000 | |
NOL and tax credit carryforwards | (1,000,000) | (900,000) | |
Amounts accrued for penalties related to unrecognized tax benefits | $ 0 | $ 0 | |
Internal Revenue Service (IRS) | |||
Tax Audits [Abstract] | |||
Year(s) under examination | 2010 and 2011 | 2012 and 2013 | |
Year of carryback claim under examination | 2,009 | ||
Potential Tax Adjustments | $ 13,000,000 | ||
State Jurisdiction (Wisconsin) | |||
Tax Audits [Abstract] | |||
Earliest year subject to examination | 2,011 |
Rate Matters Rate Matters (Deta
Rate Matters Rate Matters (Details) $ in Thousands | Oct. 20, 2015 | Oct. 01, 2015USD ($) | Sep. 30, 2015 | May. 31, 2015USD ($) | Mar. 31, 2015USD ($) | Feb. 28, 2015 | Nov. 30, 2013 | Sep. 30, 2015USD ($) | Mar. 31, 2015USD ($) | Sep. 30, 2014USD ($) | Sep. 30, 2015USD ($)MW | Sep. 30, 2014USD ($) | Dec. 31, 2013USD ($) | Dec. 31, 2008USD ($) |
Public Utilities, General Disclosures [Line Items] | ||||||||||||||
Loss on Monticello life cycle management/extended power uprate project | $ 0 | $ 0 | $ 5,237 | $ 0 | ||||||||||
FERC Proceeding, MISO ROE Complaint [Member] | Federal Energy Regulatory Commission (FERC) | ||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||
Public Utilities, Number Of Steps Required For Newly Adopted ROE Discounted Cash Flow Methodology | 2 | |||||||||||||
NSP-Minnesota | MPUC Proceeding - Nuclear Project Prudency Investigation | ||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||
Nuclear Project Expenditures, Amount | $ 665,000 | |||||||||||||
Total Capitalized Nuclear Project Costs | $ 748,000 | |||||||||||||
Initial Estimated Nuclear Project Expenditures | $ 320,000 | |||||||||||||
NSP-Minnesota | MPUC Proceeding - Nuclear Project Prudency Investigation | Minnesota Public Utilities Commission [Member] | ||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||
Public Utilities, Amount Of Recoverable Investment, With Return | $ 415,000 | |||||||||||||
Public Utilities, Amount Of Recoverable Investment, Without A Return | $ 333,000 | |||||||||||||
Public Utilities, Percentage Of Investment Considered Used And Useful | 50.00% | |||||||||||||
NSP-Minnesota | FERC Proceeding, MISO ROE Complaint [Member] | ||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||
Public Utilities, Base Return On Equity Charged To Customers Through Transmission Formula Rates | 12.38% | |||||||||||||
Public Utilities, ROE Applicable To Transmission Formula Rates In The Regional Transmission Operator's Region, Recommended By Third Parties | 8.67% | 9.15% | ||||||||||||
Public Utilities, Maximum Equity Capital Structure Percentage Allowed Per The Complaint | 50.00% | |||||||||||||
Public Utilities, ROE Applicable To Transmission Formula Rates In The Regional Transmission Operator's Region, Lower Bound, Percentage | 8.72% | 8.67% | ||||||||||||
Public Utilities, ROE Applicable To Transmission Formula Rates In The Regional Transmission Operator's Region, Upper Bound, Percentage | 9.13% | 9.54% | ||||||||||||
NSP-Minnesota | FERC Proceeding, MISO ROE Complaint [Member] | Federal Energy Regulatory Commission (FERC) | ||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||
Public Utilities, ROE Basis Point Adder Requested By Third Parties | 50 | |||||||||||||
NSP-Minnesota | FERC Proceeding, MISO ROE Complaint [Member] | FERC Staff [Member] | ||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||
Public Utilities, ROE Applicable To Transmission Formula Rates In The Regional Transmission Operator's Region, Recommended By Third Parties | 8.68% | |||||||||||||
NSP-Minnesota | FERC Proceeding, MISO ROE Complaint [Member] | MISO TOs [Member] | ||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||
Public Utilities, ROE Applicable To Transmission Formula Rates In The Regional Transmission Operator's Region, Lower Bound, Percentage | 10.80% | |||||||||||||
Xcel Energy Inc. | MPUC Proceeding - Nuclear Project Prudency Investigation | ||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||
Loss on Monticello life cycle management/extended power uprate project | $ 129,000 | |||||||||||||
NSP-Wisconsin | PSCW Proceeding - Electric and Gas Rate Case 2016 - Electric Rates 2016 [Member] | ||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 27,400 | |||||||||||||
Public Utilities, Requested Rate Increase (Decrease), Percentage | 3.90% | |||||||||||||
Public Utilities, Requested Rate Base, Amount | $ 1,200,000 | |||||||||||||
NSP-Wisconsin | PSCW Proceeding - Electric and Gas Rate Case 2016 - Gas Rates 2016 [Member] | ||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 5,900 | |||||||||||||
Public Utilities, Requested Rate Increase (Decrease), Percentage | 5.00% | |||||||||||||
Public Utilities, Requested Rate Base, Amount | $ 111,200 | |||||||||||||
NSP-Wisconsin | PSCW Proceeding - Electric and Gas Rate Case 2016 [Member] | ||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||
Public Utilities, Requested Return on Equity, Percentage | 10.20% | |||||||||||||
Public Utilities, Requested Equity Capital Structure, Percentage | 52.50% | |||||||||||||
NSP-Wisconsin | MPUC Proceeding - Nuclear Project Prudency Investigation | ||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||
Loss on Monticello life cycle management/extended power uprate project | $ 5,000 | |||||||||||||
Minimum | NSP-Minnesota | MPUC Proceeding - Nuclear Project Prudency Investigation | ||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||
Facility Generating Capacity, In MW | MW | 600 | |||||||||||||
Minimum | NSP-Minnesota | FERC Proceeding, MISO ROE Complaint [Member] | ||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||
Public Utilities, Decrease In Transmission Revenue, Net Of Expense, Due To New ROE Methodology | $ 7,000 | |||||||||||||
Maximum | NSP-Minnesota | MPUC Proceeding - Nuclear Project Prudency Investigation | ||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||
Facility Generating Capacity, In MW | MW | 671 | |||||||||||||
Maximum | NSP-Minnesota | FERC Proceeding, MISO ROE Complaint [Member] | ||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||
Public Utilities, Decrease In Transmission Revenue, Net Of Expense, Due To New ROE Methodology | $ 9,000 | |||||||||||||
Subsequent Event | NSP-Minnesota | FERC Proceeding, MISO ROE Complaint [Member] | MISO TOs [Member] | ||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||
Public Utilities, ROE Applicable To Transmission Formula Rates In The Regional Transmission Operator's Region, Lower Bound, Percentage | 10.75% | |||||||||||||
Subsequent Event | NSP-Wisconsin | PSCW Proceeding - Electric and Gas Rate Case 2016 - Electric Rates 2016 [Member] | Public Service Commission of Wisconsin (PSCW) [Member] | ||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||
Public Utilities, Recommended Rate Increase (Decrease), Amount | $ 10,400 | |||||||||||||
Public Utilities, Recommended Rate Increase, Percentage | 1.50% | |||||||||||||
Subsequent Event | NSP-Wisconsin | PSCW Proceeding - Electric and Gas Rate Case 2016 - Gas Rates 2016 [Member] | Public Service Commission of Wisconsin (PSCW) [Member] | ||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||
Public Utilities, Recommended Rate Increase (Decrease), Amount | $ 3,000 | |||||||||||||
Public Utilities, Recommended Rate Increase, Percentage | 2.50% | |||||||||||||
Subsequent Event | NSP-Wisconsin | PSCW Proceeding - Electric and Gas Rate Case 2016 [Member] | Public Service Commission of Wisconsin (PSCW) [Member] | ||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||
Public Utilities, Recommended Return on Equity, Percentage | 10.00% | |||||||||||||
Public Utilities, Recommended Equity Capital Structure, Percentage | 52.50% | |||||||||||||
Subsequent Event | NSP-Wisconsin | PSCW Proceeding - Electric and Gas Rate Case 2016 [Member] | Citizens Utility Board [Member] | ||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||
Public Utilities, Requested Return on Equity, Percentage | 8.75% |
Commitments and Contingencies,
Commitments and Contingencies, Guarantees and Indemnifications (Details) - USD ($) | Sep. 30, 2015 | Dec. 31, 2014 |
Guarantor Obligations [Line Items] | ||
Assets Held As Collateral | $ 0 | $ 0 |
Payment or Performance Guarantee | Customer Loans for Farm Rewiring Program | ||
Guarantees [Abstract] | ||
Guarantees issued and outstanding | 1,000,000 | 1,000,000 |
Current exposure under these guarantees | $ 100,000 | $ 200,000 |
Commitments and Contingencies37
Commitments and Contingencies, Environmental Contingencies - Site Contingencies (Details) $ in Thousands | 1 Months Ended | 9 Months Ended | |
May. 31, 2015USD ($) | Sep. 30, 2015USD ($)SiteParties | Dec. 31, 2014USD ($) | |
Ashland Manufactured Gas Plant (MGP) Site [Abstract] | |||
Liability for estimated cost of remediating sites, current | $ 16,689 | $ 29,116 | |
Ashland MGP Site | |||
Ashland Manufactured Gas Plant (MGP) Site [Abstract] | |||
Number of properties not owned included in superfund site | Site | 2 | ||
Accrual for Environmental Loss Contingencies, Gross | $ 95,700 | 107,600 | |
Number of PRPs that have reached a settlement in principle | Parties | 2 | ||
Liability for estimated cost of remediating sites, current | $ 16,600 | $ 28,900 | |
Amortization period for recovery of remediation costs in natural gas rates, low end of range (in years) | 4 years | ||
Amortization period for recovery of remediation costs in natural gas rates, high end of range (in years) | 6 years | ||
Public Utilities, Annual recovery collected through base rates | $ 4,700 | ||
Ashland MGP Site - Phase I Project Area | |||
Ashland Manufactured Gas Plant (MGP) Site [Abstract] | |||
Accrual for Environmental Loss Contingencies, Gross | $ 57,000 | ||
Estimated amount spent on cleanup | $ 39,000 | ||
Approved amortization period for recovery of remediation costs in natural gas rates (in years) | 10 years | ||
Carrying cost percentage to be applied to the unamortized regulatory asset for MGP remediation (in hundredths) | 3.00% | ||
Approved increase (decrease) in amortization expense granted by a regulatory body | $ 1,100 | ||
Ashland MGP Site - Sediments | |||
Ashland Manufactured Gas Plant (MGP) Site [Abstract] | |||
Estimated cost of remediating site, low end of range | 63,000 | ||
Estimated cost of remediating site, high end of range | $ 77,000 | ||
Potential percent of increase to the high end of the range of estimated site remediation costs (in hundredths) | 50.00% | ||
Potential percent of decrease to the low end of the range of estimated site remediation costs (in hundredths) | 30.00% | ||
Railroad PRPs [Member] | Ashland MGP Site | |||
Ashland Manufactured Gas Plant (MGP) Site [Abstract] | |||
Site Contingency, Recovery from Third Party of Environmental Remediation Cost | $ 10,500 | ||
LE Myers Co. [Member] | Ashland MGP Site | |||
Ashland Manufactured Gas Plant (MGP) Site [Abstract] | |||
Site Contingency, Recovery from Third Party of Environmental Remediation Cost | $ 5,400 | ||
PSCW Proceeding - Electric and Gas Rate Case 2016 - Gas Rates 2016 [Member] | Ashland MGP Site | |||
Ashland Manufactured Gas Plant (MGP) Site [Abstract] | |||
Public Utilities, Requested annual recovery collected through base rates | $ 7,600 |
Commitments and Contingencies38
Commitments and Contingencies, Environmental Contingencies - Unrecorded Unconditional Purchase Obligation (Details) $ in Millions | 1 Months Ended | ||||
Oct. 31, 2015 | Sep. 30, 2015USD ($) | Apr. 30, 2012MW | Oct. 30, 2015Period | Apr. 30, 2014Issue | |
Electric Generating Unit Mercury and Air Toxics Standards Rule | |||||
Unrecorded Unconditional Purchase Obligation [Line Items] | |||||
Generating capacity (in MW) | MW | 25 | ||||
Industrial Boiler Maximum Achievable Control Technology Rules | |||||
Unrecorded Unconditional Purchase Obligation [Line Items] | |||||
Estimated cost to comply with regulation | $ | $ 20 | ||||
Cross-State Air Pollution Rule | |||||
Unrecorded Unconditional Purchase Obligation [Line Items] | |||||
Number of issues on which the D.C. Circuit overturned the CSAPR | Issue | 2 | ||||
Subsequent Event | Green House Gas Emission Standard for Existing Sources | |||||
Unrecorded Unconditional Purchase Obligation [Line Items] | |||||
Duration for public comment (in days) | 90 days | ||||
Percentage of a comparable new plant's capital cost which would have to be exceeded to consider a project as a reconstruction under the proposed GHG NSPS for Modified and Reconstructed Power Plants | 50.00% | ||||
Subsequent Event | National Ambient Air Quality Standards for Ozone [Member] | |||||
Unrecorded Unconditional Purchase Obligation [Line Items] | |||||
Number of hours measured for standard | 8 | ||||
Current level of air quality concentrations (in parts per billion) | 75 | ||||
Proposed level of air quality concentrations (in parts per billion) | 70 | ||||
Minimum | Electric Generating Unit Mercury and Air Toxics Standards Rule | |||||
Unrecorded Unconditional Purchase Obligation [Line Items] | |||||
Number of years before affected facilities must demonstrate compliance | 3 years | ||||
Maximum | Electric Generating Unit Mercury and Air Toxics Standards Rule | |||||
Unrecorded Unconditional Purchase Obligation [Line Items] | |||||
Number of years before affected facilities must demonstrate compliance | 4 years |
Commitments and Contingencies C
Commitments and Contingencies Commitments and Contingencies - Legal Contingencies (Details) - Gas Trading Litigation [Member] | 12 Months Ended | 84 Months Ended | |
Dec. 31, 2011 | Dec. 31, 2009 | Dec. 31, 2009 | |
Loss Contingencies [Line Items] | |||
Loss Contingency, Number of Plaintiffs | 7 | 13 | |
Loss Contingency, Claims Settled, Number | 5 | ||
Loss Contingency, Claims Dismissed, Number | 6 | 1 | |
NSP-Wisconsin | |||
Loss Contingencies [Line Items] | |||
Loss Contingency, Number of Plaintiffs | 2 |
Borrowings and Other Financin40
Borrowings and Other Financing Instruments, Commercial Paper (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended |
Sep. 30, 2015 | Dec. 31, 2014 | |
Short-term Debt [Line Items] | ||
Amount outstanding at period end | $ 0 | $ 78,000 |
Commercial Paper | ||
Short-term Debt [Line Items] | ||
Borrowing limit | 150,000 | 150,000 |
Amount outstanding at period end | 0 | 78,000 |
Average amount outstanding | 0 | 46,000 |
Maximum amount outstanding | $ 0 | $ 101,000 |
Weighted average interest rate, computed on a daily basis (percentage) | 0.27% | |
Weighted average interest rate at period end (percentage) | 0.55% |
Borrowings and Other Financin41
Borrowings and Other Financing Instruments, Letters of Credit (Details) - USD ($) $ in Thousands | 9 Months Ended | |
Sep. 30, 2015 | Dec. 31, 2014 | |
Line of Credit Facility [Line Items] | ||
Amount outstanding at period end | $ 0 | $ 78,000 |
Letter of Credit | ||
Line of Credit Facility [Line Items] | ||
Amount outstanding at period end | $ 0 | $ 0 |
Letter of Credit | Letter of Credit | ||
Line of Credit Facility [Line Items] | ||
Term of letters of credit (in years) | 1 year |
Borrowings and Other Financin42
Borrowings and Other Financing Instruments, Credit Facility (Details) - Credit Facility - USD ($) | Sep. 30, 2015 | Dec. 31, 2014 | |
Line of Credit Facility [Line Items] | |||
Credit Facility | [1] | $ 150,000,000 | |
Drawn | [2] | 0 | |
Available | 150,000,000 | ||
Direct advances on the credit facility outstanding | $ 0 | $ 0 | |
[1] | This credit facility expires in October 2019. | ||
[2] | Includes outstanding commercial paper. |
Borrowings and Other Financin43
Borrowings and Other Financing Instruments, Intercompany Borrowing Arrangement and Other Short-Term Borrowings (Details) - USD ($) $ in Thousands | Sep. 30, 2015 | Dec. 31, 2014 |
Short-term Debt [Line Items] | ||
Notes payable to affiliates | $ 500 | $ 500 |
Notes Payable To Affiliates | ||
Short-term Debt [Line Items] | ||
Notes payable to affiliates | $ 500 | $ 500 |
Weighted average interest rate at period end (percentage) | 0.38% | 0.51% |
Borrowings and Other Financin44
Borrowings and Other Financing Instruments Borrowings and Other Financing Instruments, Long-Term Borrowings (Details) - NSP-Wisconsin - Bonds [Member] - Series Due June 15, 2024 [Member] $ in Millions | Jun. 30, 2015USD ($) |
Debt Instrument [Line Items] | |
Debt Instrument, Face Amount | $ 100 |
Debt Instrument, Interest Rate, Stated Percentage | 3.30% |
Fair Value of Financial Asset45
Fair Value of Financial Assets and Liabilities, Derivative Instruments (Details) MMBTU in Thousands, $ in Millions | Sep. 30, 2015USD ($)MMBTU | Dec. 31, 2014MMBTU | |
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 | $ (0.1) | ||
Natural Gas Commodity (in million British thermal units) | |||
Gross Notional Amounts of Commodity Options [Abstract] | |||
Derivative, Nonmonetary Notional amount | MMBTU | [1],[2] | 642 | 18 |
[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 Asset46
Fair Value of Financial Assets and Liabilities, Impact of Derivative Activity (Details) - USD ($) | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | |
Financial Impact of Qualifying Fair Value Hedges on Earnings [Abstract] | ||||
Derivative instruments designated as fair value hedges | $ 0 | $ 0 | $ 0 | $ 0 |
Recognized gains (losses) from fair value hedges or related hedged transactions | $ 0 | $ 0 | 0 | 0 |
Designated as Hedging Instrument | Cash Flow Hedges | Interest Rate | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss | 100,000 | 100,000 | ||
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 regulatory (assets) and liabilities | (100,000) | 700,000 | ||
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities) | $ 1,000,000 | $ (500,000) |
Fair Value of Financial Asset47
Fair Value of Financial Assets and Liabilities, Derivative Assets and Liabilities at Fair Value (Details) - USD ($) $ in Thousands | Sep. 30, 2015 | Dec. 31, 2014 | ||
Derivatives, Fair Value [Line Items] | ||||
Prepayments and other | $ 2,872 | $ 6,918 | ||
Other Liabilities, Current | 24,379 | 19,923 | ||
Fair Value Measured on a Recurring Basis | Other Current Assets | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | [1] | 270 | ||
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | 0 | |||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | 292 | |||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | 0 | |||
Fair Value Measured on a Recurring Basis | Fair Value Total | ||||
Derivatives, Fair Value [Line Items] | ||||
Prepayments and other | 2,900 | 6,900 | ||
Other Liabilities, Current | 24,400 | |||
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Assets | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | 292 | |||
Fair Value Measured on a Recurring Basis | Netting | Other Current Assets | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | [2] | (22) | ||
Other Derivative Instruments | Fair Value Measured on a Recurring Basis | Other Current Assets | Natural Gas Commodity | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | 270 | 52 | [1] | |
Other Derivative Instruments | Fair Value Measured on a Recurring Basis | Other Current Liabilities | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Fair Value, Gross Liability | [1] | 72 | ||
Other Derivative Instruments | Fair Value Measured on a Recurring Basis | Other Current Liabilities | Natural Gas Commodity | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Fair Value, Gross Liability | 72 | |||
Other Derivative Instruments | Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets | Natural Gas Commodity | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 | ||
Other Derivative Instruments | Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Fair Value, Gross Liability | 0 | |||
Other Derivative Instruments | Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities | Natural Gas Commodity | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Fair Value, Gross Liability | 0 | |||
Other Derivative Instruments | Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets | Natural Gas Commodity | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | 292 | 52 | ||
Other Derivative Instruments | Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Fair Value, Gross Liability | 94 | |||
Other Derivative Instruments | Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities | Natural Gas Commodity | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Fair Value, Gross Liability | 94 | |||
Other Derivative Instruments | Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets | Natural Gas Commodity | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 | ||
Other Derivative Instruments | Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Fair Value, Gross Liability | 0 | |||
Other Derivative Instruments | Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities | Natural Gas Commodity | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Fair Value, Gross Liability | 0 | |||
Other Derivative Instruments | Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Assets | Natural Gas Commodity | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | 292 | 52 | ||
Other Derivative Instruments | Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Liabilities | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Fair Value, Gross Liability | 94 | |||
Other Derivative Instruments | Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Liabilities | Natural Gas Commodity | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Fair Value, Gross Liability | 94 | |||
Other Derivative Instruments | Fair Value Measured on a Recurring Basis | Netting | Other Current Assets | Natural Gas Commodity | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | [2] | (22) | $ 0 | |
Other Derivative Instruments | Fair Value Measured on a Recurring Basis | Netting | Other Current Liabilities | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Fair Value, Gross Liability | [2] | (22) | ||
Other Derivative Instruments | Fair Value Measured on a Recurring Basis | Netting | Other Current Liabilities | Natural Gas Commodity | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Fair Value, Gross Liability | [2] | $ (22) | ||
[1] | Included in prepayments and other assets balance of $2.9 million and $6.9 million at Sept. 30, 2015 and Dec. 31, 2014, respectively, and other current liabilities balance of $24.4 million at Sept. 30, 2015, in the consolidated balance sheets. | |||
[2] | NSP-Wisconsin nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Sept. 30, 2015 and Dec. 31, 2014. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements. |
Fair Value of Financial Asset48
Fair Value of Financial Assets and Liabilities, Fair Value of Long-Term Debt (Details) - USD ($) $ in Thousands | Sep. 30, 2015 | Dec. 31, 2014 |
Carrying Amount | ||
Financial Liabilities, Balance Sheet Groupings [Abstract] | ||
Long-term debt, including current portion | $ 667,575 | $ 568,291 |
Fair Value | ||
Financial Liabilities, Balance Sheet Groupings [Abstract] | ||
Long-term debt, including current portion | $ 749,183 | $ 670,665 |
Other (Expense) Income, Net (De
Other (Expense) Income, Net (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | |
Other Income and Expenses [Abstract] | ||||
Interest income | $ 11 | $ 21 | $ 299 | $ 237 |
Other nonoperating income | 72 | 29 | 202 | 108 |
Insurance policy income (expense) | 20 | (56) | (109) | (292) |
Other nonoperating expense | (3) | (3) | (8) | (8) |
Other income (expense), net | $ 100 | $ (9) | $ 384 | $ 45 |
Segment Information (Details)
Segment Information (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||||||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | |||||
Segment Reporting Information [Line Items] | ||||||||
Operating revenues | $ 236,161 | $ 231,046 | $ 726,934 | $ 744,302 | ||||
Net income (loss) | 26,232 | 20,030 | 61,011 | 56,287 | ||||
Affiliate electric revenue | 42,000 | 33,000 | 121,000 | 97,000 | ||||
Regulated Electric | ||||||||
Segment Reporting Information [Line Items] | ||||||||
Operating revenues | 224,767 | 216,382 | 634,879 | 625,971 | ||||
Net income (loss) | 28,285 | 21,227 | 57,586 | [1] | 48,092 | |||
Regulated Natural Gas | ||||||||
Segment Reporting Information [Line Items] | ||||||||
Operating revenues | 11,265 | 14,909 | 91,748 | 122,005 | ||||
Net income (loss) | (1,993) | (2,003) | 3,714 | 5,565 | ||||
All Other | ||||||||
Segment Reporting Information [Line Items] | ||||||||
Operating revenues | 407 | 273 | 1,090 | 825 | ||||
Net income (loss) | (60) | 806 | (289) | 2,630 | ||||
Operating Segments | ||||||||
Segment Reporting Information [Line Items] | ||||||||
Operating revenues | 236,161 | [2] | 231,046 | [2] | 726,934 | [3] | 744,302 | [3] |
Operating Segments | Regulated Electric | ||||||||
Segment Reporting Information [Line Items] | ||||||||
Operating revenues | 224,666 | [2] | 216,289 | [2] | 634,571 | [3] | 625,663 | [3] |
Operating Segments | Regulated Natural Gas | ||||||||
Segment Reporting Information [Line Items] | ||||||||
Operating revenues | 11,088 | 14,484 | 91,273 | 117,814 | ||||
Operating Segments | All Other | ||||||||
Segment Reporting Information [Line Items] | ||||||||
Operating revenues | 407 | 273 | 1,090 | 825 | ||||
Intersegment Eliminations | ||||||||
Segment Reporting Information [Line Items] | ||||||||
Operating revenues | (278) | (518) | (783) | (4,499) | ||||
Net income (loss) | 0 | 0 | 0 | 0 | ||||
Intersegment Eliminations | Regulated Electric | ||||||||
Segment Reporting Information [Line Items] | ||||||||
Operating revenues | 101 | 93 | 308 | 308 | ||||
Intersegment Eliminations | Regulated Natural Gas | ||||||||
Segment Reporting Information [Line Items] | ||||||||
Operating revenues | $ 177 | 425 | 475 | 4,191 | ||||
Intersegment Eliminations | All Other | ||||||||
Segment Reporting Information [Line Items] | ||||||||
Operating revenues | $ 0 | $ 0 | $ 0 | |||||
[1] | Includes a net of tax charge related to the Monticello LCM/EPU project. See Note 5. | |||||||
[2] | Operating revenues include $42 million and $33 million of affiliate electric revenue for the three months ended Sept. 30, 2015 and 2014 | |||||||
[3] | Operating revenues include $121 million and $97 million of affiliate electric revenue for the nine months ended Sept. 30, 2015 and 2014, respectively. |
Benefit Plans and Other Postr51
Benefit Plans and Other Postretirement Benefits (Details) $ in Thousands | 1 Months Ended | 3 Months Ended | 9 Months Ended | ||
Jan. 31, 2015USD ($)Plan | Sep. 30, 2015USD ($) | Sep. 30, 2014USD ($) | Sep. 30, 2015USD ($) | Sep. 30, 2014USD ($) | |
Pension Benefits | |||||
Components of Net Periodic Benefit Cost [Abstract] | |||||
Service cost | $ 1,190 | $ 1,132 | $ 3,570 | $ 3,396 | |
Interest cost | 1,630 | 1,814 | 4,890 | 5,442 | |
Expected return on plan assets | (2,371) | (2,411) | (7,113) | (7,232) | |
Amortization of prior service cost (credit) | 27 | 28 | 83 | 84 | |
Amortization of net loss | 1,701 | 1,654 | 5,103 | 4,962 | |
Net benefit cost recognized for financial reporting | 2,177 | 2,217 | 6,533 | 6,652 | |
Total contributions to the pension plans during the period | $ 4,900 | ||||
Postretirement Health Care Benefits | |||||
Components of Net Periodic Benefit Cost [Abstract] | |||||
Service cost | 7 | 9 | 21 | 26 | |
Interest cost | 164 | 198 | 490 | 593 | |
Expected return on plan assets | (8) | (13) | (23) | (39) | |
Amortization of prior service cost (credit) | (87) | (88) | (263) | (263) | |
Amortization of net loss | 114 | 167 | 342 | 500 | |
Net benefit cost recognized for financial reporting | $ 190 | $ 273 | $ 567 | $ 817 | |
Xcel Energy Inc. | Pension Benefits | |||||
Components of Net Periodic Benefit Cost [Abstract] | |||||
Total contributions to the pension plans during the period | $ 90,000 | ||||
Number of Xcel Energy's pension plans to which contributions were made | Plan | 4 |
Other Comprehensive Income (Det
Other Comprehensive Income (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | ||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||||
Accumulated other comprehensive loss at beginning of period | $ (285) | ||||
Accumulated other comprehensive loss at end of period | $ (228) | (228) | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||||
Total, pre-tax | (41,867) | $ (32,139) | (97,173) | $ (89,606) | |
Tax benefit | 15,635 | 12,109 | 36,162 | 33,319 | |
Gains and Losses on Cash Flow Hedges | |||||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||||
Accumulated other comprehensive loss at beginning of period | (247) | (324) | (285) | (361) | |
Losses reclassified from net accumulated other comprehensive loss | 19 | 20 | 57 | 57 | |
Net current period other comprehensive income | 19 | 20 | 57 | 57 | |
Accumulated other comprehensive loss at end of period | (228) | (304) | (228) | (304) | |
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 | 32 | 32 | 94 | 95 | |
Tax benefit | (13) | (12) | (37) | (38) | |
Total, net of tax | 19 | 20 | 57 | 57 | |
Gains and Losses on Cash Flow Hedges | Interest Rate Derivatives | Amounts Reclassified from Accumulated Other Comprehensive Loss | |||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||||
Interest charges | [1] | $ 32 | $ 32 | $ 94 | $ 95 |
[1] | Included in interest charges. |